AXIOM OIL & GAS CORP. - FORM 8-K

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EX-10.4 - AXIOM OIL & GAS CORP.	exhibit10-4.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report: October 14, 2014

AXIOM OIL AND GAS CORP.

(Exact name of registrant as specified in its charter)


Nevada	000-53232	27-0686445
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

1846 E. Innovation Park Dr.

Oro Valley, AZ 85755

(Address of principal executive offices) (Zip Code)

(303) 872-7814

Company’s telephone number, including area code

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:


[_]	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)


[_]	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)


[_]	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))


[_]	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

FORWARD-LOOKING STATEMENTS

This report and the exhibits attached hereto contain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward looking statements concern anticipated results and developments in the future operations of Axiom Oil and Gas Corp. (“us”, “Axiom” or the “Company”) in future periods, planned exploration and development of its properties, plans related to its business and other matters that may occur in the future. These statements relate to analyses and other information that are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as “expects” or “does not expect”, “is expected”, “anticipates” or “does not anticipate”, “plans”, “estimates” or “intends”, or stating that certain actions, events or results “may”, “could,” “would”, “might” or “will” be taken, occur or be achieved) are not statements of historical fact and may be forward-looking statements. Forward-looking statements are subject to a variety of known and unknown risks, uncertainties and other factors which could cause actual events or results to differ from those expressed or implied by the forward-looking statements, including, without limitation:

• the timing and possible outcome of pending regulatory and permitting matters;

• future financial or operating performances of the Company, its subsidiaries, and its projects;

• the estimation of mineral resources and the realization of mineral reserves, if any, based on mineral resource estimates;

• the timing of exploration, development, and production activities and estimated future production, if any;

• costs related to production, capital, operating and exploration expenditures;

• requirements for additional capital and our ability to raise additional capital;

• government regulation of mining operations, environmental risks, reclamation and rehabilitation expenses;

• title disputes or claims; and

• the future price of oil, natural gas, or other minerals.

Some of the important risks and uncertainties that could affect forward-looking statements are described further under the sections titled “Risk Factors and Uncertainties”, “Description of the Business” and “Management’s Discussion and Analysis” of this report. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated, believed, estimated or expected. We caution readers not to place undue reliance on any such forward-looking statements, which speak only as of the date made. We disclaim any obligation subsequently to revise any forward-looking statements to reflect events or circumstances after the date of such statements or to reflect the occurrence of anticipated or unanticipated events.

We qualify all the forward-looking statements contained in this report by the foregoing cautionary statements.

Item 1.01 Entry into a Material Definitive Agreement.

See ITEM 2.01 Completion of Acquisition or Disposition of Assets included in this report.

Item 1.02 Termination of a Material Definitive Agreement

On October 25, 2013, we entered into a Farmout Agreement with American Midwest Oil and Gas Corp. (“AMOG”). This is a related party transaction as our majority shareholder and director, Robert Knight, is an affiliates of AMOG. AMOG had leases (the “Leases” which are listed below under Description of Property in Item 2.01) to explore and develop approximately 15,315 mineral acres of land located in Toole County, Montana, of which AMOG’s (and its 50/50 partner Alberta Oil and Gas LP) net acres amount to approximately 11,260 acres. The Farmout Agreement with AMOG was terminated. In its place we entered into an agreement with AMOG on April 2, 2014, whereby we agreed to purchase all the issued and outstanding shares of AMOG. The purchase price for the shares of AMOG was $3,480,000 and to be paid by the issuance of 7,400,000 shares of our common stock and payment of $150,000 for a licensing fee for the 3D seismic covering the Leases. The licensing fee was to be paid from production and/or through the raising of drilling funds. This agreement was terminated on September 9, 2014. While there is no formal written agreement for such termination, the parties have executed mutual releases in connection with their prior contractual dealings.

ITEM 2.01 Completion of Acquisition or Disposition of Assets.

On October 1414, 2014, we finalized a Lease Purchase Agreement with Alberta Oil and Gas LP (“LP”) whereby we purchased all of LP’s interests in certain oil and gas leases and the leasehold estates created thereby located in Toole County, Montana totaling 14,916.94 gross acres, 6170.76 net acres which includes a 23.1% working interest in two oil and gas wells drilled on the leases and a 50% working interest in two producing gas wells on the leases. The purchase price for the leases is $3,124,461 ($3,334,180 CDN), of which $46,855 ($50,000 CDN) is to be paid in cash from future cash flow or from future financing, $1,405,650 ($1,500,000 CDN) is to be in the form of the assumption of a debenture secured against the leases (of which $1,327,606 ($1,416,717 CDN) remains owing) and the remainder to be paid in the form of 7,000,000 shares of our common stock valued at $0.25 per share.

On August 29, 2014, we entered into an indemnification agreement with Alberta Oil and Gas LP and its parent, Abexco, Inc. (Nevada) whereby Alberta Oil and Gas LP, and Abexco, Inc. confirmed that our maximum liability to Abexco, Inc. on the assumption of the secured note is limited to $1,405,650 ($1,500,000 CDN) and that we would be indemnified by Alberta Oil and Gas LP and Abexco, Inc. for any amounts greater than $1,405,650 ($1,500,000 CDN).

Tanglewood Energy LLC had a part ownership position in some of the leases we own. We believe that it has forfeited its positions, and the gross acreage and net acreages reported above includes acreage that we believe that Tanglewood Energy LLC forfeited and that American Midwest Oil and Gas (a former operator) registered as defaulted in the court registry in Shelby, Montana. For a more complete description of Tanglewood Energy LLC and our position on the defaults and forfeitures, please see “Description of Business – Legal Proceedings” and “Risk Factors – Risk Associated with Our Business -- Some of our leases are shared 50% with Tanglewood Energy LLC who is insolvent and as such has defaulted on its obligations to maintain its interests in the shared leases” below. If the forfeitures were to be challenged and proved not to have occurred, our net acreage would be reduced by 1,895.53 acres.

The leases we acquired from LP are held in our wholly owned subsidiary Toole Oil and Gas Corp.

No agent, broker, firm or other person acting on behalf of Axiom or Alberta Oil and Gas LP is, or will be, entitled to any investment banking, commission, broker's or finder's fees in connection with any of the transactions contemplated by this acquisitions.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Critical Accounting Policies and Estimates. Our Management's Discussion and Analysis of Financial Condition and Results of Operations section discusses our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an on-going basis, management evaluates its estimates and judgments, including those related to revenue recognition, accrued expenses, financing operations, and contingencies and litigation. Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. The most significant accounting estimates inherent in the preparation of our financial statements include estimates as to the appropriate carrying value of certain assets and liabilities which are not readily apparent from other sources.

Equity-Based Compensation - We account for equity based compensation transactions with employees under the provisions of ASC Topic No. 718, “Compensation: Stock Compensation” (“Topic No. 718”). Topic No. 718 requires the recognition of the fair value of equity-based compensation in net income. The fair value of common stock issued for compensation is measured at the market price on the date of grant. The fair value of our equity instruments, other than common stock, is estimated using a Black-Scholes option valuation model. This model requires the input of highly subjective assumptions and elections including expected stock price volatility and the estimated life of each award. In addition, the calculation of equity-based compensation costs requires that we estimate the number of awards that will be forfeited during the vesting period. The fair value of equity-based awards granted to employees is amortized over the vesting period of the award, and we elected to use the straight-line method for awards granted after the adoption of Topic No. 718.

We account for equity based transactions with non-employees under the provisions of ASC Topic No. 505-50, “Equity-Based Payments to Non-Employees” (“Topic No. 505-50”). Topic No. 505-50 establishes that equity-based payment transactions with non-employees shall be measured at the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable. The fair value of common stock issued for payments to non-employees is measured at the market price on the date of grant. The fair value of equity instruments, other than common stock, is estimated using the Black-Scholes option valuation model. In general, we recognize an asset or expense in the same manner as if we were to pay cash for the goods or services instead of paying with or using the equity instrument.

Other accounting policies are described in the notes to the financial statements included in this Quarterly Report and our Annual Report for the year ended August 31, 2013. The following discussion of our financial condition and results of operations should be read in conjunction with our audited financial statements for the year ended August 31, 2013.

DESCRIPTION OF BUSINESS

Overview

Originally, our business was to concentrate on providing consulting services to private and public entities seeking assessment, development, and implementation of energy generating solutions. We have abandoned this strategy. We then changed our strategy to explore for precious metal properties. On January 13, 2012, we completed our acquisition of all of the outstanding shares of Axiom Mexico whereby through our wholly owned Mexican subsidiary, Axiom Acquisition Corp, acquired all of the issued and outstanding shares of Axiom Mexico, by the issuance of two million (2,000,000) of our common shares. The surviving company was Axiom de Mexico S.A. de C.V., which is a wholly owned Mexican corporation that has options on two mineral concessions in Sonora State, Mexico. On May 31, 2012, we sold all of our interest in Axiom Mexico to an unrelated third party for $100 releasing us from any liabilities in Axiom Mexico. In August 2012, we acquired the 13 Fico claims in the Yukon Territory of Canada. In February 2013 we abandoned the 13 Fico claims. We have abandoned this strategy as well.

Our Current Strategy:

We changed the focus of our Company to the exploration and development of oil and gas leases, mainly in the United States of America. On October 10, 2013 we changed our name to Axiom Oil and Gas Corp.

On March 18, 2014, we entered into a Lease Purchase Agreement with Alberta Oil and Gas LP (“LP”) to purchase its interest in the Leases. On October 1414, 2014, we finalized a Lease Purchase Agreement with Alberta Oil and Gas LP whereby we purchased certain oil and gas leases and the leasehold estates created thereby located in Toole County, Montana totaling 14,916.94 gross acres, 6,170.76 net acres which includes a 23.1% working interest in two oil and gas wells drilled on the leases and a 50% interest in two producing gas wells on the leases. The purchase price for the leases is $3,124,461 ($3,334,180 CDN), of which $46,855 ($50,000 CDN) is to be paid in cash from future cash flow or from future financing, $1,405,650 ($1,500,000 CDN) is to be in the form of the assumption of a note secured against the leases (of which $1,327,606 ($1,416,717 CDN) remains owing) and the remainder to be paid in the form of 7,000,000 shares of our common stock valued at $0.25 per share.

This is a related party transaction as one of our directors and largest shareholders, our Chief Executive Officer and our Chief Financial Officer are affiliates of Alberta Oil and Gas LP.

Our wholly owned subsidiary, Toole Oil and Gas Corp. is the registered owner of our interest in the leases.

Glossary of Terms:

Abandon: (1) The proper plugging and abandoning of a well in compliance with all applicable regulations, and the cleaning up of the well site to the satisfaction of any governmental body having jurisdiction with respect thereto and to the reasonable satisfaction of the operator.(2) To cease efforts to find or produce from a well or field.(3) To plug a well completion and salvage material and equipment.

Acreage: an area, measured in acres, which is subject to ownership or control by those holding total or fractional shares of working interests. Acreage is considered developed when development has been completed. A distinction may be made between “gross” acreage and “net” acreage. “Gross Acreage” means all Acreage covered by any working interest, regardless of the percentage of ownership in the interest.

Anhydrite: is a mineral, anhydrous calcium sulfate.

Average BOPD per year for first year: means the measure of oil output, represented by the number of barrels of oil produced per day, on average per Well, during the First Year Revenue Period.

Barrel: A unit of volume measurement used for petroleum and its products (~42 U.S. gallons: 6.29 barrels = 1 cubic meter). Barrel of Oil Equivalent or BOE: means a unit of energy based on the approximate energy released by burning one barrel (42 U.S. gallons or 159 liters) of crude oil. BOPD: means Barrels of Oil Per Day Borehole: The hole as drilled by the drill bit.
Casing: Pipe cemented in the borehole to seal off formation fluids or keep the hole from caving in. Commercial Well: A well that produces hydrocarbons in commercial quantities (i.e., enough to commence sales to an oil refinery and/or gas pipeline carrier in a profitable way or method).

Completion: The installation of permanent wellhead equipment for the production of oil and gas.

Dolostone: or dolomite rock is a sedimentary carbonate rock that contains a high percentage of the mineral dolomite

Dry Hole or Non-commercial Well: A well that does not produce hydrocarbons in Commercial Well quantities.

EUR: Estimated Ultimate Recovery: That is, the number of barrels of oil that may be produced during the life span of a well.

Exploration drilling: Drilling carried out to determine whether hydrocarbons are present in a particular area or structure.

Exploration phase: The phase of operations which covers the search for oil or gas by carrying out detailed geological and geophysical surveys followed up where appropriate by exploratory drilling.

Exploration well: A well drilled in an unproven area. Also known as a "wildcat well".

Farm in: When a company acquires an interest in a block by taking over all or part of the financial commitment for drilling an exploration well.

Field: A geographical area under which an oil or gas reservoir lies.

40 Acre Spacing: Area of land containing 1 oil well, generally regulated by State regulations.

Fracking or Hydraulic Fracturing: The fracturing of rock by a pressurized liquid. Some hydraulic fractures form naturally—certain veins or dikes are examples. Induced hydraulic fracturing or hydrofracturing, commonly known as fracking, is a technique in which typically water is mixed with sand and chemicals, and the mixture is injected at high pressure into a wellbore to create small fractures (typically less than 1mm), along which fluids such as gas, petroleum, and brine water may migrate to the well. Hydraulic pressure is removed from the well, then small grains of proppant (sand or aluminum oxide) hold these fractures open once the rock achieves equilibrium.

Gas field: A field containing natural gas but no oil.

Gas injection: The process whereby separated associated gas is pumped back into a reservoir for conservation purposes or to maintain the reservoir pressure.

Gross Acreage: means all Acreage covered by any working interest, regardless of the percentage of ownership in the interest.

HBP: Held by production. Term referring to the ownership of leases that no longer need rental payments as the lease has producing oil and/or gas wells and therefore the mineral rights owner receives royalty payments from production.

Horizontal Drilling: A well that is drilled vertically into the oil bearing zone and then turned and drilled horizontally along the zone. The horizontal wellbores allow for far greater exposure to a formation than a conventional vertical wellbore. This is particularly useful in shale formations which do not have sufficient permeability to produce economically with a vertical well. Such wells when drilled onshore are now usually hydraulically fractured in a number of stages, especially in North America. The type of wellbore completion used will affect how many times the formation is fractured, and at what locations along the horizontal section of the wellbore.

Hydrocarbon: A compound containing only the elements hydrogen and carbon. May exist as a solid, a liquid or a gas. The term is mainly used in a catch-all sense for oil, gas and condensate.

Initial Production or IP: The rate at which a well commences initial producing hydrocarbons in Commercial Well quantities.

Lease: The right granted by a landowner to the Company to extract minerals, specifically oil and/or natural gas, from the mineral estate. A lease is a legal document or contract between a landowner (lessor) and a company or individual (lessee) granting exploration and development rights to subsurface oil and gas deposits.

Mud: A mixture of base substance and additives used to lubricate the drill bit and to counteract the natural pressure of the formation.

Natural gas: Mainly Methane Gas but also other flammable gases, occurring naturally, and often found in association with crude petroleum.

Net Acreage: Also known as Net Mineral Acres. It means Gross Acreage adjusted to reflect the percentage of ownership in the working interest in the Acreage.

Oil: A mixture of liquid hydrocarbons of different molecular weights.

Oil field: A geographic area under which an oil reservoir lies.

Operator: The company that has legal authority to drill wells and undertake the production of hydrocarbons that are found. The Operator is often part of a consortium and acts on behalf of this consortium.

Paleostructure: The geologic structure of a region or sequence of rocks in the geologic past.

Permeability: The property of a formation which quantifies the flow of a fluid through the pore spaces and into the wellbore.

Petroleum: A generic name for hydrocarbons, including crude oil, natural gas liquids, natural gas and their products.

Porosity: The percentage of void in a porous rock compared to the solid formation.

Possible reserves: Those reserves which at present cannot be regarded as ‘probable’ but are estimated to have a significant but less than 50% chance of being technically and economically producible.

Primary recovery: Recovery of oil or gas from a reservoir purely by using the natural pressure in the reservoir to force the oil or gas out.

Probable reserves: Those reserves which are not yet proven but which are estimated to have a better than 50% chance of being technically and economically producible.

Proven field: An oil and/or gas field whose physical extent and estimated reserves have been determined.

Proven reserves: Those reserves which on the available evidence are virtually certain to be technically and economically producible (i.e. having a better than 90% chance of being produced).

Recoverable reserves: That proportion of the oil and/gas in a reservoir that can be removed using currently available techniques.

Reserves: Barrels of Oil per Field. It is calculated by multiplying the Lifespan Average BOPD per well by the number of Wells per Field.

Reservoir: The underground formation where oil and gas has accumulated. It consists of a porous rock to hold the oil or gas, and a cap rock that prevents its escape.

Royalty payment: The cash or kind paid to the owner of mineral rights.

Sabkha Enviroments: Sabkha environments are supratidal, forming along arid coastlines and are characterized by evaporite-carbonate deposits with some siliciclastics. Sabkhas form subaerial, prograding and shallowing-upward sequences

Secondary recovery: Recovery of oil or gas from a reservoir by artificially maintaining or enhancing the reservoir pressure by injecting gas, water or other substances into the reservoir rock.

Shut In Well: A well which is capable of producing but is not presently producing. Reasons for a well being shut in may be lack of equipment, market or other.

Surface Location: The location of a well or facility/measurement point.

38 degree API “light” oil: An arbitrary scale expressing the gravity or density of liquid petroleum products. The measuring scale is calibrated in terms of degrees API. The higher the API gravity, the lighter the compound. Light crudes generally exceed 38 degrees API and heavy crudes are commonly labeled as all crudes with an API gravity of 22 degrees or below. Intermediate crudes fall in the range of 22 degrees to 38 degrees API gravity.

3D Seismic Analysis: Similar to 2D, but uses a dense array of geophones to provide a much more detailed set of seismic information. 3D seismic information allows geologists to see a significantly more reliable view of the underground topography of an area. Denser data and improved computer processing ensures that subsurface features are correctly located, and can reveal the previously mentioned DHIs, which indicate the presence of hydrocarbons, rather than merely the structural elements, which could possibly contain hydrocarbons. Time-Lapse 3D seismic (also known as 4D) is also used when needed to provide more data in mature fields to identify where new oil has not yet been tapped.

Total Production: The cumulative Barrels of Oil or Barrels of Oil Equivalent a field produces during its Lifespan.

Vertical Drilling: The traditional method of completing a oil and gas well which is done by drilling vertically into the earth at a selected location.

Well Interest: The interest in a well held by the Company under the terms of a Lease.

Well Log data or Well Logging or Drill Logging: The practice of making a detailed record (a well log) of the geologic formations penetrated by a borehole. The log may be based either on visual inspection of samples brought to the surface (geological logs) or on physical measurements made by instruments lowered into the hole (geophysical logs). Well logging can be done during any phase of a well’s history; drilling, completing, producing and abandoning. Well logging is performed in boreholes drilled for the oil and gas, groundwater, mineral and geothermal exploration, as well as part of environmental and geotechnical studies.

Wildcat well: A well drilled in an unproven area. Also known as an "exploration well".

Nisku Carbonate Project – Toole County Montana:

The oil and gas leases owned by us through Toole Oil and Gas Corp. our wholly owned subsidiary, are located in Toole County, in north central Montana, approximately 16 miles south of the Province of Alberta, Canada and U.S. border. According to state production records, Montana, itself, is a prolific producer of oil and natural gas and we believe that Montana has state legislation that supports the oil and gas industry. First year state tax rates on revenues generated by the sale of hydrocarbons is 0.8% in Montana. The tax rate shifts to rates between 6.1% and 9.3% in subsequent years, depending on the hydrocarbon being produced, the year in which wells were drilled and type of well.

Map showing location of the Kevin-Sunburst Dome where the leases are located.

The Kevin-Sunburst Dome is a geological structure in the area in Toole County and covers approximately 1,000 square miles and is believed to have 850 feet of structural closure. We believe that intense structural compression by the Montana Thrust Belt produced forces and fractures that dispersed the Bakken oil into many rock formations through-out the area. State production records indicate that some formations are located up to a thousand feet above the Bakken zone (Madison, Swift, Cutbank and Sunburst) and others are located only a few hundred feet below the Bakken (Nisku and Duperow). We believe that the Bakken zone oil migrated through many different rock layers and accumulated to form oil fields wherever the oil encountered porosity (the oil reservoir) and a seal (the oil trap). Geological interpretation by our consulting geologist from drilling in the area is that the Kevin-Sunburst Dome was the focal point for Bakken oil migration from the Southern Alberta Basin to the west. According to state production records, the domal area has produced more than 320 million barrels of oil (MMBO) and 650 billion cubic feet of gas (BCFG) from the Devonian Nisku, Mississippian Madison, Jurassic Swift, Cretaceous Cutbank/Sunburst, and four other formations. The primary formation we intend to target, assuming sufficient capital is raised for drilling, is the conventional Nisku carbonate formation. In Toole County, the Nisku formation is found at a depth of approximately 3,000 to 3,200 feet.

Our leases are located on the eastern slope of the Kevin-Sunburst Dome near the producing field called the East Kevin Field and the 9 Mile Field. The East Kevin Field, according to state records, has been in production for approximately 29 years. Generally, state records show that the oil produced from the Nisku formation is 38 degree API “light” oil. The state records also show that the Nisku formation does not produce water. Initially, assuming adequate capital is raised, we plan to drill simple vertical wells into the Nisku zone. Drill logs from surrounding wells do not show any hazardous or complex drilling problems, though no assurance can be given that we would not encounter such problems.

General location of the leases held and the area covered by the 3D Seismic.

In the Kevin-Sunburst Dome there is multi-zone production from seven shallower formations. If and when we drill on the leases, the drill hole has the potential to drill through these formations. If such formations are indicated on the drill logs, we will have the opportunity, if commercial, to produce from these upper zones. No assurance may be given that any of these zones contain commercial amounts of hydrocarbons.

Conceptual Cross section of Kevin-Sunburst Dome illustrating the different formations that are found.

Nisku deposition

State records and drill logs show that the Nisku Formation is about 60 to 70 feet thick across the Kevin Dome. Scientific interpretation by our consulting geologist indicates that the formation was deposited as a shallowing-upward carbonate-evaporate sequence on top of marine limestones and shales of the Devonian Duperow Formation. Fine-grained carbonates (wackestones) make up the bottom 20 to 30 feet of strata. That zone is overlain by a 20-ft thick “Middle Layer” containing wave-dominated grainstone deposits that account for the primary Nisku porosity. The Middle Layer grades into 10 to 15 feet of supratidal laminated dolostones and anhydrites, capped by a 12 foot anhydrite layer. We believe that a Sabkha environment prevailed during the next few million years while an additional 150 feet of dolostones and anhydrites accumulated to form the overlying Potlatch Formation.

Nisku porosity and reservoir variability

The Nisku grainstone deposits formed on paleotopographic features – ancestral island shoals and beaches where wave action left behind the coarser carbonate sand and winnowed away the silt and mud. Primary Nisku porosity developed in the 20-ft thick wave-dominated Middle Layer where skeletal grainstones are preserved. Soon after deposition, the entire Nisku formation was dolomitized. This is a chemical process that enhances the original grainstone porosity present in a limestone reservoir. Records of drill core from surrounding drill holes indicate that the porosity in the Nisku can range from a 0 percent to more than 20 percent.

3D Seismic

3D seismic data were acquired across the area during 2007, about 24 years after the East Kevin Field was discovered. The 3D data and the interpretation of the data by our consulting geologist indicate to us, though no assurance can be given, that the Nisku porosity and oil potential are present not only where wells have already been drilled in the East Kevin Field, but also to the north of the field. We have acquired an interest in leases on what we believe are similar geological locations on the north edge of East Kevin Field and on trend to the 9 Mile Field to the north of the East Kevin Field.

The 3D seismic data has been interpreted by our consulting geologist to establish what we feel are the areas of better Nisku porosity. The seismic data interpretation by our consulting geologist has delineate what we believe are paleostructures where grainstone porosity development has most likely occurred. The red area on the map below indicates a higher structure in the underlying Duperow. We believe that this structure could have impacted the topography of the overlying Nisku Formation, resulting in better porosity development on the structurally higher areas, though, no assurance can be given to this development. Furthermore, we believe that distinct seismic amplitude variations are associated with the Nisku porosity zone and these have been tied to the porosity in previously drilled wells in the area. The red color on the map below correlates with, what we believe is, better Nisku porosity in the existing wells and appears to indicate that good porosity is also present in the area of the two offset wells we drilled on the north flank of the field.

Map showing location of leases overlaying interpretation of the 3D Seismic. Leases in blue are ones in which we have a 25% interest. Leases in green are ones in which we own 50%.*

* This map reflects the forfeitures of interests by Tanglewood Energy LLC. See Risk Factors and Legal Proceedings contained herein.

Operation

Activities on the properties described below are governed by the Operating Agreement entered into with Young Sanders E&P LLC. The Operating Agreement is the standard American Association of Land Professionals 1989 Standard Operating Agreement (the “AAPL Agreement”) with an additional section 16 governing forfeitures and participation. The AAPL describes the rights and obligations of the participants and the operator in conducting all activities on the properties including the drilling, production and the abandonment of wells.

DESCRIPTION OF PROPERTY

We do not own any real estate or other tangible property. Our principal office is located at 1846 E. Innovation Park Dr., Oro Valley, AZ 85755, telephone (303) 872-7814. We lease our office space in Tucson, Arizona on a monthly basis at $125 per month. No debt has accrued on account of rent payments owing. Our office space is sufficient for our current needs. However, we may require additional space in the event that our business operations are successful and we hire employees.

Toole Oil and Gas Corp. our wholly owned subsidiary, also maintains its office at 1846 E. Innovation Park Dr., Oro Valley, AZ 85755, telephone (303) 872-7814.

The following chart is a detailed list of leases held by our wholly owned subsidiary, Toole Oil and Gas Corp.

TWP = Township

RGE = Range

SEC = Section

Toole Oil = Toole Oil and Gas Corp.

Toole Oil Lease No.	Lease Exp. Date:	Gross Acres	Toole Oil Net Acres			Royalty Rate	Twp	Rge	Sec	Description
				Acres Acquired by Forfeiture	Total Toole Oil Net Acres

1	2/22/2016	120	30	-	30	15.00%	35 North	1 East	1	S2NE, SESW, NWSE, S2SE
1	2/22/2016	80	20	-	20	15.00%	35 North	1 East	1	SWSW, NESE
1	2/22/2016	40	10	-	10	15.00%	35 North	1 East	12	N2NE
1	2/22/2016	460	115	-	115	15.00%	35 North	1 East	12	E2SWNE, SENE, W2, N2SE
2	3/9/2016	120	30	-	30	15.00%	35 North	1 East	1	S2NE, SESW, NWSE, S2SE
2	3/9/2016	40	10	-	10	15.00%	35 North	1 East	12	N2NE

3	2/15/2016	20	5	-	5	15.00%	35 North	1 East	12	W2SWNE
4	3/16/2016	160.02	40.01	-	40.01	15.00%	35 North	1 East	1	Lots 1(40.00), 2(40.01), 3(40.01), 4(40.02), S2NW, N2SW
5	3/16/2016	160.02	40	-	40	15.00%	35 North	1 East	1	Lots 1(40.00), 2(40.01), 3(40.01), 4(40.02), S2NW, N2SW
6	10/31/2016	320	80	-	80	15.00%	35 North	1 East	13	E2
7	2/2/2016	320	80	-	80	15.00%	34 North	1 East	30	E2
8	3/1/2021	480	120	120	240	16.67%	35 North	1 East	24	N2, SE
9	3/1/2021	160	40	40	80	16.67%	35 North	1 East	25	NE
10	11/17/2017	320	160	-	160	15.00%	33 North	1 East	11	N2
10	11/17/2017	160	80	-	80	15.00%	33 North	1 East	11	S2
12	2/6/2017	25.9	12.95	-	12.95	15.00%	33 North	1 East	6	Lots 3(39.88), 4(37.34), 5(37.61), 6(37.85), 7(38.08), SENW, E2SW
13	2/6/2017	12.95	6.47	-	6.47	15.00%	33 North	1 East	6	Lots 3(39.88), 4(37.34), 5(37.61), 6(37.85), 7(38.08), SENW, E2SW
14	2/6/2017	12.95	6.47	-	6.47	15.00%	33 North	1 East	6	Lots 3(39.88), 4(37.34), 5(37.61), 6(37.85), 7(38.08), SENW, E2SW
15	2/6/2017	25.9	12.95	-	12.95	15.00%	33 North	1 East	6	Lots 3(39.88), 4(37.34), 5(37.61), 6(37.85), 7(38.08), SENW, E2SW
16	5/12/2015	80	40	-	40	16.66%	33 North	1 East	4	SW4
17	5/12/2015	80	40	-	40	16.66%	33 North	1 East	5	SE4
18	5/12/2015	159.78	79.898	-	79.898	16.66%	33 North	1 East	3	Lots 3(39.79), 4(39.77), S2NW, SW
25	HBP	53.33	21.33	-	21.33	12.50%	33 North	1 East	13	N2
26	HBP	120	48	-	48	12.50%	33 North	1 East	13	N2
27	HBP	8.89	10.66	-	10.66	12.50%	33 North	1 East	13	N2
28	HBP	120	48	-	48	12.50%	33 North	1 East	13	N2
29	HBP	120	48	-	48	12.50%	33 North	1 East	13	S2
30	HBP	120	48	-	48	12.50%	33 North	1 East	13	S2

31	HBP	80	32	-	32	12.50%	33 North	1 East	13	S2
32	SHUT-IN	40	4	-	4	15.00%	33 North	1 East	1	SE4
32	SHUT-IN	40	4	-	4	15.00%	33 North	1 East	12	NE4
33	SHUT-IN	40	4	-	4	15.00%	33 North	1 East	1	SE4
33	SHUT-IN	40	4	-	4	15.00%	33 North	1 East	12	NE4
34	SHUT-IN	160	28.8	-	28.8	15.00%	33 North	1 East	12	S2
35	12/6/2015	79.8	39.9	-	39.9	16.66%	33 North	1 East	6	Lot 2(39.80), SWNE
39	7/10/2017	320	160	-	160	16.66%	33 North	1 East	9	W2
42	7/22/2017	146.34	36.585	36.585	73.17	12.50%	34 North	1 East	7	Lots 3(35.07), 4(35.17), S2NE, E2SW, SE4
42	7/22/2017	45	11.25	11.25	22.5	12.50%	34 North	1 East	8	S2NW, SWNE
43	7/22/2017	68.29	17.07	17.07	34.14	12.50%	34 North	1 East	7	Lots 3(35.07), 4(35.17), S2NE, E2SW, SE4
43	7/22/2017	21	5.25	5.25	10.5	12.50%	34 North	1 East	8	S2NW, SWNE
54	TOP LEASE	-	-	-	0	12.50%	34 North	1 East	18	Lots 3, 4, E2SW, SE4
54	HBP	155.69	155.69	-	155.69	12.50%	34 North	1 East	18	Lots 3(35.61), 4(35.76), E2SW, SE4
55	HBP	77.84	77.84	-	77.84	15.00%	34 North	1 East	18	Lots 3, 4, E2SW, SE4
56	HBP	77.84	38.92	-	38.92	15.00%	34 North	1 East	18	Lots 3, 4, E2SW, SE4
56	TOP LEASE	0	0	-	0	15.00%	34 North	1 East	18	Lots 3, 4, E2SW, SE4
57	5/22/2017	40	10	-	10	12.50%	34 North	1 East	17	SE4
58	5/22/2017	40	10	-	10	12.50%	34 North	1 East	17	SE4
59	8/15/2017	13.33	3.33	-	3.33	12.50%	34 North	1 East	17	SE4
60	8/15/2017	13.33	3.33	-	3.33	12.50%	34 North	1 East	17	SE4
61	8/15/2017	13.33	3.33	-	3.33	12.50%	34 North	1 East	17	SE4
65	7/8/2017	80	40	-	40	15.00%	34 North	1 East	17	N2NE
66	9/3/2017	10	2.5	-	2.5		34 North	1 East	1	SW4
66	9/3/2017	10	2.5	-	2.5		34 North	1 East	12	NW4
68	3/8/2017	10	2.5	-	2.5	15.00%	34 North	1 East	1	SW4
68	3/8/2017	10	2.5	-	2.5	15.00%	34 North	1 East	12	NW4
69	9/3/2017	20	5	-	5	15.00%	34 North	1 East	1	SW4
69	9/3/2017	20	5	-	5	15.00%	34 North	1 East	12	NW4

70	12/6/2016	65.07	16.27	16.27	32.54	12.50%	34 North	1 East	23	S2
70	12/6/2016	65.07	16.27	16.27	32.54	12.50%	34 North	1 East	27	N2
70	12/6/2016	65.07	16.27	16.27	32.54	12.50%	34 North	1 East	28	S2
71	11/18/2017	65.07	16.27	16.27	32.54	12.50%	34 North	1 East	23	S2
71	11/18/2017	65.07	16.27	16.27	32.54	12.50%	34 North	1 East	27	N2
71	11/18/2017	65.07	16.27	16.27	32.54	12.50%	34 North	1 East	28	S2
98	11/22/2015	160	40	40	80	17.00%	34 North	1 East	34	E2
99	4/3/2016	320	80	80	160	12.50%	34 North	1 East	3	S2N2, SE4
100	HBP	317	158.5	-	158.5	15.00%	34 North	1 East	19	E2 Less 3 Acres in NENE
101	4/25/2017	8	2	-	2	12.50%	34 North	1 East	20	NE4
102	4/25/2017	8	2	-	2	12.50%	34 North	1 East	20	NE4
103	4/25/2017	20	5	-	5	12.50%	34 North	1 East	20	NE4
104	4/25/2017	8	2	-	2	12.50%	34 North	1 East	20	NE4
105	4/25/2017	20	5	-	5	12.50%	34 North	1 East	20	NE4
106	4/25/2017	20	5	-	5	12.50%	34 North	1 East	20	NE4
107	4/25/2017	20	5	-	5	12.50%	34 North	1 East	20	NE
108	4/25/2017	40	10	-	10	12.50%	34 North	1 East	20	NE4
109	10/10/2017	8	2	-	2	12.50%	34 North	1 East	20	NE4
110	9/24/2016	160	40	40	80	12.50%	34 North	1 East	10	SW4
110	9/24/2016	160	40	40	80	12.50%	34 North	1 East	17	SW4
110	9/24/2016	480	120	120	240	12.50%	34 North	1 East	20	SE4, W2
111	6/21/2017	80	20	20	40	15.00%	35 North	1 East	28	S2
111	6/21/2017	146	36.5	36.5	73	15.00%	35 North	1 East	29	SE4
112	6/21/2017	80	20	20	40	15.00%	35 North	1 East	28	S2
112	6/21/2017	156	39	39	78	15.00%	35 North	1 East	33	SW4
117	2/4/2016	438.56	109.64	-	109.64	15.00%	35 North	1 East	5	Lots 1(39.40), 2(39.16), S2NE, SE, N2SW, SESW
120	11/22/2015	80	20	20	40	17.00%	35 North	1 East	24	SW4
121	HBP	320	19.2		19.2		35 North	1 East	14	E2
121A	HBP	640	160	160	320	12.50%	35 North	1 East	16	All
122	7/1/2017	640	160	160	320	15.00%	35 North	1 East	17	All
122	7/1/2017	160	40	40	80		35 North	1 East	18	E2SW, SE4
123	7/28/2017	60	15	15	30	15.00%	35 North	1 East	18	E2SW, SE4
123	7/28/2017	20	5	5	10	15.00%	35 North	1 East	19	E2NE
123	7/28/2017	80	20	20	40	15.00%	35 North	1 East	20	N2

124	7/31/2017	20	5	-	5	15.00%	35 North	1 East	18	E2SW, SE
124	7/31/2017	6.67	1.66	-	1.66	15.00%	35 North	1 East	19	E2NE
124	7/31/2017	26.67	6.66	-	6.66	15.00%	35 North	1 East	20	N2
125	7/1/2017	53.33	13.3325	13.3325	26.665	15.00%	35 North	1 East	19	E2NE
125	7/1/2017	213.33	53.3325	53.3325	106.665	15.00%	35 North	1 East	20	N2
126	7/23/2017	34.06	8.515	8.515	17.03	15.00%	35 North	1 East	18	Lots 3(34.01), 4(34.11)
126	7/23/2017	77.13	19.2825	19.2825	38.565	15.00%	35 North	1 East	19	Lot 1(34.26), W2NE, NENW
127	7/23/2017	34.06	8.515	8.515	17.03	15.00%	35 North	1 East	18	Lots 3, 4
127	7/23/2017	77.13	19.2825	19.2825	38.565	15.00%	35 North	1 East	19	Lot 1, W2NE, NENW
128	10/20/2017	303.98	75.99	-	75.99	12.50%	35 North	1 East	19	Lots 2, 3, 4, SENW, E2SW, W2SE
129	7/24/2017	40	10	10	20	12.50%	35 North	1 East	20	S2
130	7/24/2017	160	40	40	80	12.50%	35 North	1 East	20	S2
131	7/24/2017	40	10	10	20	12.50%	35 North	1 East	20	S2
132	2/1/2018	40	10		10	12.50%	35 North	1 East	20	S2
133	7/24/2017	40	10	10	20	12.50%	35 North	1 East	20	S2
136	8/23/2017	8.94	2.28	-	2.28	15.00%	35 North	1 East	23	S2SWNW, West 450' of SWSENW
137	8/23/2017	320	80	80	160	15.00%	35 North	1 East	25	W2
138	12/29/2015	160	40	40	80	12.50%	35 North	1 East	25	SE4
139	6/20/2017	80	20	20	40	15.00%	35 North	1 East	26	W2SW
140	8/23/2017	320	80	80	160	15.00%	35 North	1 East	26	E2
141	8/5/2017	240	60	60	120	15.00%	35 North	1 East	26	E2SW, NW4
142	8/5/2017	80	20	20	40	15.00%	35 North	1 East	27	E2NE
143	6/20/2017	240	60	60	120	15.00%	35 North	1 East	27	E2SW, SE4
144	7/3/2017	80	20	-	20	12.50%	35 North	1 East	27	W2NE, NW4, W2SW
145	7/9/2017	80	20	-	20	12.50%	35 North	1 East	27	W2NE, NW4, W2SW
146	7/3/2017	80	20	-	20		35 North	1 East	27	W2NE, NW4, W2SW
147	7/3/2017	80	20	-	20	12.50%	35 North	1 East	27	W2NE, NW4, W2SW
148	6/10/2018	320	80	80	160	16.66%	35 North	1 East	35	W2E2, E2NW, SESE, NESW
149	HBP	3	1.5	-	1.5	12.50%	34 North	1 East	19	A 3.00 acre tract of land located in the NENE
150	10/11/2016	60.82	15.21	-	15.21	15.00%	34 North	1 East	19	Lots 1, 2, 3, 4, E2W2

151	1/2/2017	8.89	2.22	-	2.22	16.00%	34 North	1 East	15	SW
151	1/2/2017	8.89	2.22	-	2.22	16.00%	34 North	1 East	22	NW
151	1/2/2017	13.33	3.38	-	3.38	16.00%	34 North	1 East	23	N2
151	1/2/2017	6.67	3.16	-	3.16	16.00%	34 North	1 East	24	NE
152	1/2/2017	8.89	2.22	-	2.22	16.00%	34 North	1 East	15	SW
152	1/2/2017	8.89	2.22	-	2.22	16.00%	34 North	1 East	22	NW
152	1/2/2017	13.33	3.38	-	3.38	16.00%	34 North	1 East	23	N2
152	1/2/2017	6.67	1.16	-	1.16	16.00%	34 North	1 East	24	NE
153	1/2/2017	8.89	2.22	-	2.22	16.00%	34 North	1 East	15	SW
153	1/2/2017	8.89	2.22	-	2.22	16.00%	34 North	1 East	22	NW
153	1/2/2017	13.33	3.38	-	3.38	16.00%	34 North	1 East	23	N2
153	1/2/2017	6.67	1.16	-	1.16	16.00%	34 North	1 East	24	NE
154	1/10/2017	4.44	1.11	-	1.11	16.00%	34 North	1 East	15	SW
154	1/10/2017	4.44	1.11	-	1.11	16.00%	34 North	1 East	22	NW
154	1/10/2017	6.67	1.16	-	1.16	16.00%	34 North	1 East	23	N2
154	1/10/2017	3.33	0.83	-	0.83	16.00%	34 North	1 East	24	NE
155	3/6/2017	4.44	1.11	-	1.11	16.00%	34 North	1 East	15	SW
155	3/6/2017	4.44	1.11	-	1.11	16.00%	34 North	1 East	22	NW
155	3/6/2017	6.67	1.16	-	1.16	16.00%	34 North	1 East	23	N2
155	3/6/2017	3.33	0.83	-	0.83	16.00%	34 North	1 East	24	NE
156	1/11/2017	160	40	40	80	15.00%	35 North	1 East	32	NENE, S2NE, SENW
156	1/11/2017	160	40	40	80	15.00%	35 North	1 East	33	NW
157	1/12/2017	320	8	-	8	16.67%	34 North	1 East	11	E2

	Total	14916.94	4275.223	1895.535	6170.758

2. RESERVES REPORTED TO OTHER AGENCIES

We have no reserve reports at this time. Save and except the two gas wells, our acreage is undeveloped.

3. PRODUCTION

A. As part of the acquisition of the lease interests, we have acquired a 50% working interest in two producing gas wells.

i) The average sales price of the production per thousand btus for the 12 month period ending June 30, 2014 is $3.577808. The average sales price of the production per thousand btus for the 2 month period ending August 31, 2014 is $3.998000

ii) The average lifting price per thousand btus for the 12 month period ending June 30, 2014 is $1.257781. The average lifting price per thousand btus for the 2 month period ending August 31, 2014 is $1.299800

4. PRODUCTIVE WELLS AND ACREAGE

As of September 30, 2014, we own 2 gas wells (gross) and 1 gas well net. The total productive area of the two gross wells is 80 acres and the net productive area is 40 acres.

5. UNDEVELOPED ACREAGE

As of September 30, 2014, we own 14,916.94 gross acres and 6,170.76 net acres (which includes 1,895.53 acres forfeited by Tanglewood Energy, LLC).

6. Drilling Activity

In December 2012, we commenced drilling two oil wells. The two wells are awaiting fracking in order to determine whether either or both of such wells should be placed in production or abandoned.

7. PRESENT ACTIVITIES

As of September 30, 2014, we have two oil wells being drilled.

8. DELIVERY COMMITMENTS

American Midwest Oil and Gas Ltd., (“AMOG”) the 50% owner of our two producing gas wells is the operator of these two wells. AMOG has a contract with Ranck Oil Company to sell to them all of the gas produced from these two wells. The gas is sold based on the AECO monthly price minus $1.00 for gathering and is effective until June 30, 2015. .

Principal Products

Our principal product is the exploration for and development of oil and natural gas. Because our properties are in the development stage, there is no guarantee that any hydrocarbons will be found or extracted.

Legal Proceedings

Except as described below, neither Axiom nor its properties are the subject of any pending legal proceedings and no such proceeding is known to be contemplated by any governmental authority. We are not aware of any legal proceedings in which any director, officer or affiliate of Axiom, any owner of record or beneficially of more than 5% of any class of our voting securities, or any associate of any such director, officer, affiliate or security holder of Axiom, is a party adverse to Axiom or any of its subsidiaries or has a material interest adverse to Axiom or any of its subsidiaries.

We believe that Tanglewood Energy LLC has forfeited its part ownership position in some of the Leases we own. Tanglewood Energy LLC, failed to participate in the drilling of the first two oil wells and failed to make certain delay rental payments both of which constitutes defaults under the operating agreement. Accordingly, we believe that Tanglewood Energy forfeited its interests in the leases that pertain to the defaults under the Operating Agreement. American Midwest Oil and Gas (the then operator) registered these defaults in the court registry in Shelby Montana but has not received assignments for the leases from Tanglewood as required under the terms and conditions of the Operating Agreement. We believe our position is strong to have the courts assign our interests in those leases to us through a court application but there is significant risk that these interests will never be assigned to us. If Tanglewood should decide to defend their position in court it may cost us significant legal fees and take much time to perfect our position. If we were to lose any legal challenge regarding the leases we would be obligated to return the forfeited leases to Tanglewood which could significantly affect our land holdings and drilling positions. We anticipate filing an application to the courts to have our interest in the leases assigned to us within the next 6 months.

In the calculation of the net acreage of leases owned by Toole Oil and Gas, Corp., our wholly owned subsidiary, we assume that the defaults under the operating agreement are valid. The net acreage number we have calculated is 6,170.76 net acres. If Tanglewood was successful in defending a court action, then our net acreage position would be reduced by approximately 1,895.53 acres.

Insurance

We do not maintain any general insurance, but we plan to implement standard insurance policies for our company. We do not have directors’ and officers’ liability insurance. Our ability to acquire a general insurance policy relies upon us having the necessary funds to do so. We do not have the necessary funds to implement such insurance policies. Because we do not have any insurance, if we are made a party to a liability action, we may not have sufficient funds to defend the litigation. If that occurs, a judgment could be rendered against us that could cause us to cease operations.

The current operator of our leases, Young Sanders E&P LLC, does carry liability insurance that would cover us against any action pertaining to the leases we hold.

Employees; Identification of Certain Significant Employees

We are an exploration stage company and currently have two full time employees; our CEO and a director and one part time employee, our CFO. We intend to hire additional employees on an as needed basis.

All oil and gas exploration and operations will be contracted out to third parties. In the event that our exploration projects are successful and warrant putting any of our leases into production, such operations may also be contracted out to third parties. We rely on management to handle all matters related to business development and business operations.

Governmental Regulations - Environmental and Occupational Health and Safety Matters

General

Our operations are subject to stringent and complex federal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. Compliance with these laws and regulations may require the acquisition of permits before drilling or other related activity commences, restrict the type, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling and production activities on certain lands lying within wilderness, wetlands and other protected areas, impose specific health and safety criteria addressing worker protection, and impose substantial liabilities for pollution arising from drilling and production operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that may limit or prohibit some or all of our operations.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and, any changes in environmental laws and regulations that result in more stringent and costly well construction, drilling, waste management or completion activities or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our business. While we believe that we are in substantial compliance with current applicable federal and state environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations or financial condition, there is no assurance that we will be able to remain in compliance in the future with such existing or any new laws and regulations or that such future compliance will not have a material adverse effect on our business and operating results.

The following is a summary of the more significant existing environmental laws to which our business operations are subject and with which compliance may have a material adverse effect on our capital expenditures, earnings or competitive position.

Hazardous Substances and Wastes

The Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law and analogous state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred, and companies that disposed or arranged for the disposal of hazardous substances released at the site. Under CERCLA, these persons may be subject to joint and several, strict liabilities for remediation cost at the site, natural resource damages and for the costs of certain health studies. Additionally, it is not uncommon for neighboring landowners and other third parties to file tort claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. We generate materials in the course of our operations that are regulated as hazardous substances.

We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes that impose stringent requirements related to the handling and disposal of non-hazardous and hazardous wastes. There exists an exclusion under RCRA from the definition of hazardous wastes for drilling fluids, produced waters and certain other wastes generated in the exploration, development or production of oil and natural gas, efforts have been made from time to time to remove this exclusion such that those wastes would be regulated under the more rigorous RCRA hazardous waste standards. A loss of this RCRA exclusion could result in increased costs to us and the oil and gas industry in general to manage and dispose of generated wastes.

We intend to own or lease properties that have been used for oil and natural gas exploration and production for many years. Although we believe that we will utilized operating and waste disposal practices that are standard in the industry at the time, hazardous substances, wastes and petroleum hydrocarbons may be released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for recycling or disposal. In addition, some properties may be operated by third parties whose treatment and disposal of hazardous substances, wastes and petroleum hydrocarbons are not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges and Subsurface Injections

The Federal Water Pollution Control Act, as amended, (“Clean Water Act”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into state and federal waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the U.S. Environmental Protection Agency (“EPA”) or an analogous state agency. Spill prevention, control and countermeasure (“SPCC”) plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In addition, the Oil Pollution Act of 1990, as amended (“OPA”), imposes a variety of requirements related to the prevention of oil spills into navigable waters as well as liabilities for oil cleanup costs, natural resource damages and a variety of public and private damages that may result from such oil spills.

The disposal of oil and natural gas wastes into underground injection wells are subject to the federal Safe Drinking Water Act, as amended (“SDWA”), and analogous state laws. Under Part C of the SDWA, the EPA established the Underground Injection Control Program, which establishes requirements for permitting, testing, monitoring, recordkeeping and reporting of injection well activities as well as a prohibition against the migration of fluid containing any contaminants into underground sources of drinking water. State programs may have analogous permitting and operational requirements. Any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource, and imposition of liability by third parties for property damages and personal injury.

Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We would expect to use hydraulic fracturing techniques in our drilling and completion programs. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and has published draft permitting guidance addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking in the Semi-annual Regulatory Agenda published on July 3, 2013, on such disclosure regulations. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states, where we operate, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in any hydraulic fracturing activities we may undertake. Nevertheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we may operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review in 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities in 2014. These studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

Air Emissions

The Federal Clean Air Act, as amended (“CAA”), and comparable state laws, regulate emissions of various air pollutants from many sources in the United States, including crude oil and natural gas production activities through air emissions standards, construction and operating programs and the imposition of other compliance requirements. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions of certain pollutants. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. Over the next several years, we may be required to incur certain capital expenditures for air

pollution control equipment or other air emissions-related issues. For example, in 2012, the EPA published final rules under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare. However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors and from pneumatic controllers and storage vessels. Compliance with these requirements could increase our costs of development and production, which costs could be significant.

Climate Change

Based on findings by the EPA in December 2009 that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes, the EPA has adopted regulations under existing provisions of the CAA that, among things, establish pre-construction and operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. This rule could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources that exceed GHG emission threshold levels. The EPA also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an annual basis, including, among others, certain onshore and offshore oil and natural gas production facilities, which include certain of our operations. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.

Congress has from time to time considered legislation to reduce emissions of GHGs but it has not adopted such legislation in recent years. A number of state and regional efforts have emerged that seek to reduce GHG emissions by means of cap and trade programs that often require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production interests and operations.

Endangered Species

The Federal Endangered Species Act, as amended (“ESA”), and analogous state laws restrict activities that could have an adverse effect on threatened or endangered species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Some of our future operations may be located in or near areas that are designated as habitat for endangered or threatened species. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to our activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of numerous species as endangered or threatened under the ESA before the completion of the agency’s 2017 fiscal year. The presence of protected species or the designation of previously unidentified endangered or threatened species could impair our ability to timely complete well drilling and development and could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

Employee Health and Safety

We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended, (“OSHA”), and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act, as amended, and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws relating to worker health and safety.

Other Laws and Regulations

State statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. In addition, there are state statutes, rules and regulations governing conservation matters, including the unitization or pooling of oil and natural gas properties, establishment of maximum rates of production from oil and natural gas wells and the spacing, plugging and abandonment of such wells. Such statutes and regulations may limit the rate at which oil and natural gas could otherwise be produced from our properties and may restrict the number of wells that may be drilled on a particular lease or in a particular field.

Competition

We compete with other oil and gas companies in connection with the acquisition of oil and gas leases and in connection with the recruitment and retention of qualified employees. Many of these companies are much larger than us, have greater financial resources and have been in the oil and gas business much longer than we have. As such, these competitors may be in a better position through size, finances and experience to acquire suitable exploration properties. We may not be able to compete against these companies in acquiring new leases and/or qualified people to work on any of our leases.

There is significant competition for the limited number of oil and gas lease opportunities available and, as a result, we may be unable to continue to acquire attractive oil and gas leases on terms we consider acceptable.

Given the size of the world market for oil and gas relative to individual producers and consumers of oil and gas, we believe that no single company has sufficient market influence to significantly affect the price or supply of oil and gas in the world market.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct a preliminary review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant title defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with general industry standards. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests that we believe do not materially interfere with the use or affect our carrying value of the properties.

Employees

We currently have two full time employees working for us, our Chief Executive Officer and one of our directors who is also the head of business development. We also have one part time employee, our Chief Financial Officer, who provides services through a consulting agreement between the Company and an entity in which our Chief Financial Officer is a consultant. There are no written employment agreements with any other employees. Those employees are paid pursuant to oral agreements on a month to month basis.

Pro Forma Financial Statements for the nine months ended May 31, 2014 and the year ended August 31, 2013 .

Results of Operations

Revenues. Since inception, we have yet to generate any significant revenues from our business operations. On a pro forma basis, for the nine months ended May 31, 2014 and the year ended August 31, 2013, we have revenues of $17,734 and $11,795, offset by cost of goods sold of $10,552 and $28,389, respectively. Our gross profit (loss) amounted to $7,182 and $(16,594) for the nine months ended May 31, 2014 and the year ended August 31, 2013, respectively. Our ability to generate revenues has been significantly hindered by our lack of capital. We hope to generate revenues as we implement our business plan.

Operating Expenses. On a pro forma basis, for the nine months ended May 31, 2014 and the year ended August 31, 2013, our total operating expenses were $3,727,490 and $3,335,471, which include $3,040,709 and $2,971,763 from the impairment of goodwill created upon the acquisition of the interest in the Leases. Also included in operating expenses is $430,748 and $-0- in stock based compensation in the nine months ended May 31, 2014 and the year ended August 31, 2013, respectively. The balance of our total operating expenses consist primarily of legal expenses, accounting expenses and compensation related to being a public company.

We expect that we will continue to incur significant legal and accounting expenses related to being a public company.

Other Income (Expenses). On a pro forma basis, for the nine months ended May 31, 2014 and the year ended August 31, 2013, our other income (expenses) were $(6,965) and $(62,330). Included in other income (expenses) is $84,445 in interest expense net of $77,480 of forgiveness of debt income in the nine months ended May 31, 2014 and $62,300 in interest expense in the year ended August 31, 2013.

Net Loss. On a pro forma basis, for the nine months ended May 31, 2014 and the year ended August 31, 2013, our net loss was $3,734,455 and $3,397,801, respectively.

Liquidity and Capital Resources

On a pro forma basis, we had cash of $188 as of May 31, 2014 and total assets of $523,108. At August 31, 2013, we had cash of $362 and total assets of $222,282. We are seeking to raise additional funds to meet our working capital needs principally through the sales of our securities. As of the date of this report, during fiscal 2014 we have received additional financing of $75,000 through the issuance of convertible debentures. Additional funding has not been secured and no assurance may be given that we will be able to raise additional funds.

On a pro forma basis, as of May 31, 2014, our total liabilities were $2,537,359 comprised of $575,898 in accounts payable and accrued expenses (including, $211,000 owed to our Chairman for accrued compensation and expenses), $137,000 in notes payable to non-affiliates, $5,000 in notes payable to our Chairman, $105,000 in convertible debentures and $46,855 owed in cash and $1,327,606 in secure debenture resulting from the Leases Carve-out acquisition. On a pro forma basis, as of August 31, 2013, our total liabilities were $2,049,822, comprised of $581,588 in accounts payable and accrued expenses (including $120,000 owed to our Chairman for accrued compensation and expenses), 67,000 in notes payable to non-affiliates, $30,000 in convertible debentures and $46,745 owed in cash and $1,324,489 in secured debenture resulting from the Lease Carve-out acquisition.

As of May 31, 2014 and August 31, 2013, we had outstanding promissory notes in the amount of $142,000 (including $5,000 owed to our Chairman) and $67,000, respectively. Interest on these notes range from -0-% to 15%. As of May 31, 2014 and August 31, 2013, notes in the amount of $80,000 and $10,000, respectively, are past due. We have not repaid these notes and no demand for payment has been made to date. The notes are from unrelated parties (except the $5,000 owed to our Chairman) and are unsecured.

On July 5, 2013, the Board of Directors authorized the issuance of 20% Convertible Redeemable Debentures ("Convertible Debentures") in an aggregate principal amount not exceeding US $250,000. The debentures mature between June 30, 2014 and July 30, 2014 and accrue interest at 20% per annum from the day of initial issuance. As defined in the debenture agreement, the Convertible Debentures, at the option of the holder at any time commencing on December 31, 2013 until maturity, are convertible into shares of common stock of the Company, at a price of $0.25 per share on a post consolidated basis (as to be determined). As of May 31, 2014 and August 31, 2013, $105,000 and $30,000 of Convertible Debentures are outstanding.

At inception, we sold 800,000 shares of common stock to our officers and director for $500 in cash. In 2008, we sold an additional 179,336 shares of common stock through our public offering for proceeds of $112,085. We have used the proceeds from the cash raised in that offering to pay the legal and accounting costs of being a public company. For the year ended August 31, 2011, we sold 172,960 shares of common stock through our public offering for gross proceeds of $1,081,000. We recorded $96,850 of costs related to the offering. We used the proceeds from this offering for general working capital to pay the costs of operations.

In December 2011, we received gross proceeds of $285,904 from the sale of 45,745 shares of common stock at $6.25 per share to one non-U.S. investor pursuant to Regulation S.

Effective August 16, 2012, our current CEO converted $212,218 of accrued and unpaid compensation and reimbursable expenses owed him into 8,488,720 shares of common stock at $0.75 per share. We incurred a charge for share based finance costs of $6,154,322 in the year ended August 31, 2012.

In August 2012, we received gross proceeds of $10,000 from the sale of 16,000 Units at $0.625 per Unit which included 16,000 shares of common stock and warrants to purchase 1,600 shares of common stock at $0.875 per share to a non-US accredited investor pursuant to Regulation S. We incurred offering costs of $1,000 (10% of gross proceeds) plus warrants to purchase 1,143 shares of common stock at $0.875 per share.

In September 2012, we received gross proceeds of $33,750 from the sale of 54,000 Units at $0.625 per Unit which included 54,000 shares of common stock and warrants to purchase 5,400 shares of common stock at $0.875 per share to three non-US accredited investors pursuant to Regulation S. We incurred offering costs of $3,375 (10% of gross proceeds) plus warrants to purchase 3,857 shares of common stock at $0.875 per share.

In December 2012, our former CEO converted $157,500 of accrued and unpaid compensation and reimbursable expenses owed him into 50,000 shares of Company common stock valued at $132,500 and a $25,000 promissory note.

In July and August 2013 we received $30,000 through the sale of convertible debentures to two non-US accredited investors pursuant to Regulation S. The debentures are due and payable between June 30, 2014 and July 30, 2013 and carry an interest rate of 20% per annum and are convertible at $.25 per share any time after December 31, 2013 on a post consolidated basis.

In September 2013 we received $35,000 through the sale of convertible debentures to two non-US accredited investors pursuant to Regulation S. The debentures are due and payable between June 30, 2014 and July 30, 2014, and carry an interest rate of 20% per annum and are convertible at $.25 per share any time after December 31, 2013 on a post consolidated basis.

In October, 2013, we received $15,000 through the sale of convertible debentures to two non-US resident accredited investors pursuant to Regulation S. The debentures are due and payable June 30, 2014 and carry an interest rate of 20% per annum and are convertible at $.25 per share any time after December 31, 2013 on a post consolidated basis.

Effective October 16, 2013, we entered into a consulting agreement for assistance in certain business and corporate matters, such as strategic and business plans, expansion of the Company's shareholder base and financing alternatives. The term of the agreement is for a period of 90 days from the effective date. We issued the consultant a total of 700,000 shares of Company common stock valued at $140,000, the fair value on the effective date, as compensation under the agreement.

On October 30, 2013, we settled an outstanding payable in the amount of approximately $124,000 through the issuance of an 8% promissory note in the amount of $35,000 due January 31, 2014 and 200,000 shares of our common stock with an agreed upon value of $0.01 per share.

In December 2013, we received $20,000 through the sale of a convertible debenture to a non-US accredited investor pursuant to Regulation S. The debenture is due and payable June 30, 2014 and carries an interest rate of 20% per annum and is convertible at $.25 per share any time after December 31, 2013 on a post consolidated basis.

In January 2014, we received $5,000 through the sale of a convertible debenture to a non-US accredited investor pursuant to Regulation S. The debenture is due and payable June 30, 2014 and carries an interest rate of 20% per annum and is convertible at $.25 per share at any time after issuance on a post consolidated basis.

Effective February 4, 2014, we settled an outstanding payable in the amount of approximately $70,000 through the issuance of an 8% promissory note in the amount of $35,000 due April 30, 2014 and 140,000 shares of our common stock with an agreed upon value of $0.01 per share. The common stock was valued at $0.25 per share, $35,000, representing the fair value of the remaining payable balance, which was more reliably measurable.

On February 17, 2014, we entered into a consulting agreement for business advisory and other related services. The agreement is for a term of six months with compensation of $2,000 per month. Pursuant to the agreement we also issued the consultant a total of 300,000 shares of Company common stock for $200. The stock is valued at $153,000, $0.51 per share being the fair value on the effective date of the agreement.

On September 18, 2014 we issued 60,000 shares to our Chief financial Officer for services rendered at a deemed value of $0.25 per share valued at $15,000 the fair value at date of issuance. These shares were issued pursuant to Regulation D.

On September 18, 2014 we issued 100,000 shares to Sanders, Ortoli, Vaughn-Flam and Rosenstadt for services rendered at a deemed value of $0.25 per share valued at $25,000 the fair value at date of issuance. These shares were issued pursuant to Regulation D.

On October 1414, 2014 we issued 7,000,000 shares to Alberta Oil and Gas LP as part of our acquisition agreement for the leases owned by Alberta Oil and Gas LP in Toole County Montana at a deemed value of $0.25 per share valued at $1,750,000 the fair value at date of issuance. These shares were issued pursuant to Regulation D.

During fiscal 2014, we expect that our business plan for exploration of oil and gas will be a significant cost to us and to complete that plan we will need to raise substantial funds. Furthermore, if we find additional leases for acquisitions that may also require significant capital, not only for the actual acquisition but also for any exploration work that may need to be completed. As well, the legal and accounting costs of being a public company will continue to impact our liquidity and we will need to obtain funds to pay those expenses. Other than the anticipated exploration costs, acquisition costs, increases in legal and accounting costs due to the reporting requirements of being a reporting company, we are not aware of any other known trends, events or uncertainties, which may affect our future liquidity.

In the opinion of management, available funds will not satisfy our working capital requirements to operate at our current level of activity for the next twelve months. Our forecast for the period for which our financial resources will be adequate to support our operations involves risks and uncertainties and actual results could fail as a result of a number of factors. In order to implement our business plan in the manner we envision, we will need to raise additional capital. We cannot guaranty that we will be able to raise additional funds. Moreover, in the event that we can raise additional funds, we cannot guaranty that additional funding will be available on favorable terms. In the event that we experience a shortfall in our capital, we hope that our officers, directors and principal shareholders will contribute funds to pay for our expenses to achieve our objectives over the next twelve months. At this time, though, we do not have any arrangement with any of our officers, directors or shareholders to provide any funding for the Company.

Offices

Our administrative offices are currently located at 1846 E. Innovation Park Dr. Oro Valley, AZ 85755. Our telephone number is (303) 872-7814.

Our wholly owned subsidiary, Toole Oil and Gas Corp. maintains its offices at 1846 E. Innovation Park Dr. Oro Valley, AZ 85755. Our telephone number is (303) 872-7814.

RISK FACTORS

You should carefully consider the risks described below as well as other information provided to you in this document, including information in the section of this document entitled “Forward Looking Statements.” The risks and uncertainties described below are not the only ones facing us. Additional risks and uncertainties not presently known to us or that we currently believe are immaterial may also impair our business, financial condition or results of operations. If any of the following risks actually occur, our business, financial condition or results of operations could be materially adversely affected, the value of our common stock could decline, and you may lose all or part of your investment.

Risks associated with our business:

We have no operating history. We expect to incur losses for the foreseeable future. We will go out of business if we fail to generate sufficient revenue or raise additional capital.

We have a limited operating history. We were founded on February 13, 2007, and from the date of inception to May 30, 2014, we have accumulated losses of $14,738,202. We expect to incur additional losses for the foreseeable future and will go out of business if we fail to generate sufficient revenue or raise additional capital. We do not foresee generating revenues in the near future, and we have no commitments at this time to raise additional capital. Additional losses will result from costs and expenses related to implementing our new business strategy and hiring qualified people to carry out the new business strategy.

If sufficient funds are not available, we may not be able to acquire oil and gas leases to implement our new business plan.

Our business may fail if we do not have sufficient funds to enable us to do one or more of the following: acquire oil and gas leases; make default rental payments on our leases in a timely manner, attract qualified personnel to work for our Company; or fund our administrative and corporate expenses. Failure to acquire oil and gas leases or pay delay rental payments will stop our plan for the Company to move ahead with our strategy.

Currently, we do not have any commitments for additional financing. Additional financing is required, and we cannot be certain that it will be available when and to the extent needed. As well, even if financing is available, we cannot be certain that it would be available on acceptable terms or in sufficient quantities.

Removal of Tanglewood Energy LLC as operator.

An original 50% owner of the Leases was Tanglewood Energy LLC (“Tanglewood”). In October 2013, Tanglewood informed its partners in the Leases that it was insolvent. As per the Operating Agreement in place at that time, Tanglewood was removed as operator and replaced by American Midwest Oil and Gas Corp. We have not received any notification from Tanglewood acknowledging such action and as such this removal may be challenged in court by Tanglewood in the future. If Tanglewood was successful in its challenge then they would be reinstated as operator of the leases.

Some of our leases are shared 50% with Tanglewood Energy LLC who is insolvent and as such has defaulted on its obligations to maintain its interests in the shared leases.

We believe that Tanglewood Energy LLC has forfeited its part ownership position in some of the Leases we own. Tanglewood Energy LLC, failed to participate in the drilling of the first two oil wells and failed to make certain delay rental payments both of which constitutes defaults under the operating agreement. Accordingly, we believe that Tanglewood Energy forfeited its interests in the leases that pertain to the defaults under the Operating Agreement. American Midwest Oil and Gas (the then operator) registered these defaults in the court registry in Shelby Montana but has not received assignments for the leases from Tanglewood as required under the operating agreement. We believe our position is strong to have the courts assign our interests in those leases to us through a court application but there is significant risk that these interests will never be assigned to us. At this time we have not made an application to the courts to enforce our rights and we expect to file such an action within the next 6 months. We cannot assure you that we will ever file such a court application. If Tanglewood should decide to defend its position in court it may cost us significant legal fees and take much time to perfect our position. If we were to lose any legal challenge regarding the leases we would be obligated to return the forfeited leases to Tanglewood which could significantly affect our land holdings and drilling positions, including reducing our gross mineral acreage and net mineral acreage by 50%.

Furthermore, in the calculation of the net acreage of leases owned by Toole Oil and Gas, Corp., our wholly owned subsidiary, we assume that the defaults under the operating agreement are valid. The net acreage number we have calculated is 5,630.31 net acres. If Tanglewood was successful in defending a court action, then our net acreage position would be reduced to approximately 2,815.15 acres.

We are significantly dependent upon officers to develop our business. If we lose our officers or if our officers do not adequately develop our business, then we will go out of business.

At the outset, our success will depend entirely on the ability of our officer. We do not carry a “key person” life insurance policy on our officer. We currently have two full time employees and two part time employees. We rely almost exclusively upon our officers to meet our needs.

Our directors and officer also own a controlling interest in our common stock, and, as such, you may have no effective voice in our management.

As of October 14, 2014, our directors and officers own approximately 74.53% of the Company's outstanding common stock. As such, these beneficial owners have the ability to influence all corporate actions required to be taken by majority consent of holders and management. If the interests of these beneficial owners differ from the interests of other shareholders, these beneficial owners may be able to ensure that their interests prevail.

Our current directors, officers and key employees beneficially own a significant percentage of our issued and outstanding shares of common stock. Accordingly, for the foreseeable future, we expect that our directors and officers will exercise control over all matters requiring board and shareholder approval, including the possible election of additional directors and approval of significant corporate transactions. If you purchase shares of our common stock, you may have no effective voice in our management.

The Company's concentration of ownership may harm the market price of the common stock by, among other things: delaying, deferring or preventing a change of control, even at a per share price that is in excess of the then-current price of the common stock; impeding a merger, consolidation, takeover or other business combination involving the Company, even at a per share price that is in excess of the then current price of the common stock; or discouraging a potential acquirer from making a tender offer or otherwise attempting to obtain control of the Company, even at a per share price that is in excess of the then current price of the common stock.

As we undertake exploration and development of any oil and gas leases that we may acquire, we will be subject to compliance with government regulations that may increase the anticipated cost of our exploration program.

There are several governmental regulations that materially restrict oil and gas exploration or exploitation. We expect to be subject to federal, state and local laws and regulations in the United States of America regarding environmental matters, the abstraction of water, and the discharge of wastes and materials and other similar laws and regulations. Amendments to current laws, regulations and permits governing operations and activities of exploration and development companies, or more stringent implementation thereof, could have a material adverse impact on us and our operations increase our expenditures and costs and require abandonment or delays in developing new oil and gas leases. Environmental laws and regulations change frequently, and the implementation of new, or the modification of existing, laws or regulations could harm our business, financial condition or results of operations. We cannot predict how agencies or courts in the United States of America will interpret existing laws and regulations or the effect that these adoptions and interpretations may have on our business, financial condition or results of operations. We may be required to make significant expenditures to comply with governmental laws and regulations.

Any significant oil and gas development that we undertake in the future will have some environmental impact, including land and habitat impact, arising from the use of land for drilling and related activities, and certain impact on water resources near the project sites, resulting from water use. No assurances can be given that such environmental issues will not have a material adverse effect on our business, financial condition or results of operations in the future. While we believe we do not currently have any material environmental obligations, exploration and development activities may give rise in the future to significant liabilities on our part to the government and third parties and may require us to incur substantial costs of remediation.

Because of the speculative nature of exploration and development of oil and gas leases and the unique difficulties and uncertainties inherent in the oil and gas exploration and development business, there is substantial risk that no commercially exploitable hydrocarbons will be found and developed and our business will fail.

Exploration for and development of hydrocarbons is a speculative venture involving substantial risk. Oil and gas exploration and development companies encounter difficulties, and there is a high rate of failure of such enterprises. The expenditures we may make in the exploration of the oil and gas leases may not result in the discovery and development of commercial quantities of hydrocarbons. The likelihood of success must be considered in light of the problems, expenses, difficulties, complications and delays encountered in connection with the exploration and development of the oil and gas leases that we plan to undertake. These potential problems include, but are not limited to, unanticipated problems relating to exploration and development and additional costs and expenses that may exceed current estimates. In such a case, we would be unable to complete our business plan. The search for and development of oil and gas leases also involves numerous hazards. As a result, we may become subject to liability for such hazards, including pollution, explosions, waste disposal, worker safety and other hazards against which we cannot insure or against which we may elect not to insure. The payment of such liabilities may have a material adverse effect on our financial position.

Additionally, we do not maintain insurance against environmental risks. As a result, any claims against us may result in liabilities we will not be able to afford, resulting in the failure of our business. Failure to comply with applicable laws, regulations, and permitting requirements may result in enforcement actions thereunder, including orders issued by regulatory or judicial authorities causing operations to cease or be curtailed, and may include corrective measures requiring capital expenditures, installation of additional equipment, or remedial actions. Parties engaged in exploration and development operations may be required to compensate those suffering loss or damage by reason of the exploration and development activities and may have civil or criminal fines or penalties imposed for violations of applicable laws or regulations and, in particular, environmental laws.

Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

As of August 31, 2014, we have identified approximately 70 potential drilling locations on our leases. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Delays in the development of or production curtailment at our material properties may adversely affect our financial position and results of operations.

The size of our operations and our capital expenditures budget limit the number of properties that we can develop in any given year. Complications in the development of any single major well or infrastructure installation may result in a material adverse effect on our financial condition and results of operations. In addition, we expect that relatively few wells will contribute a substantial portion of our production. If we were to experience operational problems or adverse commodity prices resulting in the curtailment of production in any of these wells, our total production levels would be adversely affected, which would have a material adverse effect on our financial condition and results of operations.

The Kevin-Sunburst Dome oil price differential could have adverse impacts on our revenues.

Generally, oil produced on the Kevin-Sunburst Dome is high quality (characterized by an American Petroleum Institute gravity, or API gravity, between 36 to 44 degrees, which is comparable to West Texas Intermediate, or WTI, oil). However, due to takeaway constraints, oil prices in the area ranged from $5.00 to $15.00 less per Bbl than prices for other areas in the United States during 2013. This discount, or differential, may widen in the future, which would reduce the price we would receive for our production.

We may not be able to develop oil and natural gas reserves on an economically viable basis, and our reserves and production may decline as a result.

If we succeed in discovering oil and natural gas reserves, these reserves may not be capable of the production levels we project or in sufficient quantities to be commercially viable. On a long-term basis, our viability depends on our ability to find or acquire, develop and commercially produce additional oil and natural gas reserves. Without the addition of reserves through acquisition, exploration or development activities, our reserves and production will decline over time as reserves are produced. Our future reserves will depend not only on our ability to develop then-existing properties, but also on our own and our operating partners’ ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we may develop and to effectively distribute our production.

Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions. We will not be able to completely eliminate these conditions in any case. Therefore, these conditions could diminish our revenue and cash flow levels and result in the impairment of our oil and natural gas interests.

We may not be able to drill wells on a substantial portion of our acreage.

We may not be able to drill on a substantial portion of our acreage for various reasons. We may not generate or be able to raise sufficient capital to do so. Future deterioration in commodities pricing may also make drilling some acreage uneconomic. Our actual drilling activities and future drilling budget will depend on drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, lease expirations, gathering system and pipeline transportation constraints, regulatory approvals and other factors. In addition, any drilling activities we are able to conduct may not be successful or add additional proved reserves to our overall proved reserves, which could have a material adverse effect on our future business, financial condition and results of operations.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

A large portion of our acreage is not currently held by production. Unless production in paying quantities is established on units containing these leases during their terms, these leases will expire. If our leases expire, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based upon various factors, many of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.

Shortages of equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers, and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices and activity levels in new regions, causing periodic shortages. During periods of high oil and natural gas prices, the demand for drilling rigs and equipment has increased along with increased activity levels, which may result in shortages of equipment. In addition, there has been a shortage of hydraulic fracturing capacity in many of the areas in which we operate. This shortage in hydraulic fracturing capacity could occur in the future. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services, and personnel. These types of shortages and subsequent price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill those wells and conduct those operations that we currently have planned and budgeted, causing us to miss our forecasts and projections.

Our lack of diversification will increase the risk of an investment in us and our financial condition and results of operations may deteriorate if we fail to diversify.

Our business is focused primarily on a limited number of properties in Montana. We may choose to limit our focus to a single geographic area such as the Kevin-Sunburst Dome, which could limit our flexibility. Our required capital commitments may grow if the opportunity presents itself and will depend upon the results of initial testing and development activities. Larger companies have the ability to manage their risk by diversification. However, we lack diversification in terms of both the nature and geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than if our business was more diversified, enhancing our risk profile. For example, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in the area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of oil or natural gas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Kevin-Sunburst Dome, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. If we cannot diversify our operations, our financial condition and results of operations could deteriorate.

Our ability to sell our production and/or receive market prices for our production may be adversely affected by transportation capacity constraints and interruptions.

If the amount of oil or natural gas being produced by us and others exceeds the capacity of the various transportation pipelines and gathering systems currently available in our operating areas, it will be necessary for new transportation pipelines and gathering systems to be built. In the case of oil and condensate, it may be necessary for us to rely more heavily on trucks to transport our production, which is more expensive and less efficient than transportation via pipeline. The construction of new pipelines and gathering systems is capital intensive and construction may be postponed, interrupted or cancelled in response to changing economic conditions and the availability and cost of capital. In addition, capital constraints could limit our ability to build gathering systems to transport our production to transportation pipelines. In such event, costs to transport our production may increase materially or we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell our production at much lower prices than market or than we currently project, which would adversely affect our results of operations. A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions.

Competition in obtaining rights to explore and develop oil and natural gas reserves and to market our production may impair our business.

The oil and natural gas industry is highly competitive. Other oil and natural gas companies may seek to acquire oil and natural gas leases and other properties and services we intend to target with our investments. This competition is increasingly intense as prices of oil and natural gas rise. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors or in funding joint ventures with our prospective partners. Competitors include a variety of potential investors and larger companies, which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests. If we are unable to compete effectively or adequately respond to competitive pressures, this inability may materially adversely affect our results of operation and financial condition.

We do not carry title insurance and do not plan to secure any in the future. We are therefore, vulnerable to loss of title.

We do not maintain insurance against title. Title on oil and gas leases involves certain inherent risks due to the difficulties of determining the validity of certain leases as well as the potential for problems arising from the frequently ambiguous conveyance history characteristic of many oil and gas leases. We cannot give any assurance that title to any oil and gas leases we may acquire will not be challenged or impugned and cannot be certain that we will have or will acquire valid title to these leases. We cannot assume that counterparties to our title transfer agreements will meet their contractual obligations and transfer title on a timely basis. Furthermore, although we believe that mechanisms exist to integrate the titles of oil and gas leases currently not owned by us, there is a risk that this process could be time consuming and costly. The possibility also exists that title to existing leases or future prospective leases may be lost due to an omission in the claim of title. As a result, any claims against us may result in liabilities we may not be able to afford resulting in the failure of our business.

In the event that we are unable to successfully compete within the oil and gas exploration and development business, we may not be able to achieve profitable operations.

The oil and gas exploration and development business is highly competitive. This industry has a multitude of competitors and many competitors dominate this industry. Many of our competitors have greater financial resources than us. As a result, we may experience difficulty competing with other businesses when conducting oil and gas exploration and development activities or in the retention of qualified personnel. No assurances can be given that we will be able to compete effectively.

In the future, the figures for our reserves and resources will be estimates based on interpretation and assumptions, and they may yield less hydrocarbon production under actual conditions than our independent geologists and engineers may estimate.

Unless otherwise indicated, oil and gas reserve figures presented in our filings with securities regulatory authorities, press releases and other public statements that may be made from time to time will be based upon estimates made by independent geologists, independent engineers and our internal geologists. When making determinations about whether to advance any of our projects to development, we must rely upon such estimated calculations as to the oil and gas reserves on any leases we may acquire. These estimates are imprecise and depend upon geological interpretation and statistical inferences drawn from drilling and sampling analysis, which may prove to be unreliable.

We cannot assure you that:

• these estimates will be accurate;

• reserve estimates will be accurate; or

• this hydrocarbons can be produced profitably.

Any material changes in oil and gas reserve estimates will affect the economic viability of placing a lease into production and a property’s return on capital. In addition, any oil or gas ultimately produced, if any, may differ from that indicated by our technical reports and production test results. There can be no assurance that hydrocarbons recovered in small scale tests will be duplicated in large-scale tests under on-site conditions or in production scale.

Due to numerous factors beyond our control which could affect the marketability of oil and gas, including their respective market price, we may have difficulty selling any hydrocarbons if commercially viable reserves are found to exist.

The availability of markets and the volatility of market prices are beyond our control and represent a significant risk. Even if commercially viable reserves of oil and gas are found to exist on our property interests, a ready market may not exist for the sale of the reserves. Numerous factors beyond our control may affect the marketability of any substances discovered. These factors include market fluctuations, the proximity and capacity of markets and processing equipment, availability of pipelines or other such gathering and transportation systems, government regulations, including regulations relating to prices, taxes, royalties, land tenure, land use, importing and exporting oil and gas and environmental protection. These factors could inhibit our ability to sell the hydrocarbons in the event that commercially viable reserves are found to exist.

Our due diligence activities with respect to our property interests cannot assure that these properties will ultimately prove to be commercially viable.

Our due diligence activities have been limited, and to a great extent, we have relied upon information provided to us by third-party advisors. Accordingly, no assurances can be given that the leases we possess will contain adequate amounts of hydrocarbons for commercialization. Further, even if we recover hydrocarbons from any leases we may acquire, we cannot guarantee that we will make a profit. If we cannot acquire or locate commercially exploitable oil and gas reserves, or if it is not economical to recover the hydrocarbons, our business and operations will be materially adversely affected. At present, we do not have any oil and gas leases.

If we are unable to obtain all of our required governmental permits, our operations could be negatively impacted.

Our future operations, including exploration and development activities, required permits from various governmental authorities. Such operations are and will be governed by laws and regulations governing prospecting, development, production, exports, taxes, labor standards, occupational health, waste disposal, toxic substances, land use, environmental protection, site safety and other matters. There can be no assurance that we will be able to acquire all required licenses or permits or to maintain continued operations at economically justifiable costs.

We are in competition with companies that are larger, more established and better capitalized than we are.

Many of our potential competitors have:

• greater financial and technical resources;

• longer operating histories and greater experience in the oil and gas industry;

We may have difficulty integrating and managing the growth associated with our recent acquisitions.

Our recent acquisitions are expected to result in a significant growth in our assets, reserves and revenues and may place a significant strain on our financial, technical, operational and administrative resources. We may not be able to integrate the operations of the acquired assets without increases in costs, losses in revenues or other difficulties. In addition, we may not be able to realize the operating efficiencies, synergies, costs savings or other benefits expected from such acquisitions. Any unexpected costs or delays incurred in connection with such integration could have an adverse effect on our business, results of operations or financial condition. We have hired and intend to hire new employees that we expect will be required to manage our operations, and we plan to add resources as needed as we scale up our business. However, we may experience difficulties in finding additional qualified personnel. In an effort to stay on schedule with our planned activities, we may supplement our staff with contract and consultant personnel until we are able to hire new employees. Our ability to continue to grow after these acquisitions will depend upon a number of factors, including our ability to identify and acquire new exploratory prospects and other acquisition targets, our ability to develop then existing prospects, our ability to successfully adopt an operated approach, our ability to continue to retain and attract skilled personnel, the results of our drilling program and acquisition efforts, hydrocarbon prices and access to capital. We may not be successful in achieving or managing growth, and any such failure could have a material adverse effect on us.

Acquisitions may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.

Our recent growth is due in large part to acquisitions of properties and undeveloped leasehold. We expect acquisitions to be instrumental to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties that we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems, and does not involve a review of seismic data or independent environmental testing. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and limitations, including any structural, subsurface and environmental problems that may exist or arise. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete future acquisitions on terms that we believe are acceptable or that, even if completed, do not contain problems that reduce the value of acquired property.

Seasonal weather conditions and other factors could adversely affect our ability to conduct drilling activities.

Our operations could be adversely affected by weather conditions and wildlife restrictions on federal leases. In the Kevin-Sunburst Dome, drilling and other oil and natural gas activities cannot be conducted as effectively during the winter months. Winter and severe weather conditions limit and may temporarily halt the ability to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our oil and natural gas operations and materially increase our operating and capital costs, which could have a material adverse effect on our business, financial condition, and results of operations.

Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.

We maintain several types of insurance to cover our operations, including worker’s compensation and comprehensive general liability. Amounts over base coverages are provided by primary and excess umbrella liability policies. Our operator carries operator’s extra expense coverage, which covers the control of drilling or producing wells as well as re-drilling expenses and pollution coverage for wells out of control.

We may not be able to maintain adequate insurance in the future at rates we consider reasonable, or we could experience losses that are not insured or that exceed the maximum limits under our insurance policies. If a significant event that is not fully insured or indemnified occurs, it could materially and adversely affect our financial condition and results of operations.

Risks related to an investment in our common stock

Trading of our common stock may be restricted by the United States Securities and Exchange Commission (“SEC”)

The SEC has adopted regulations which generally define “penny stock” to be any equity security that has a market price, as defined, being less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. If we develop a public market for our shares, then our shares would be covered by the penny stock rules. These penny stock rules impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and “accredited investors”. These additional requirements may have the effect of limiting the development of a public trading market thereby reducing the level of trading activity in the secondary market for stock that is subject to these penny stock rules. Consequently, these penny stock rules may negatively affect our ability to develop a public trading market for our common stock and may negatively affect the ability of broker-dealers to trade our common stock. We believe that the penny stock rules discourage investor interest in, and may limit the marketability of, our common stock.

Additionally, as a “shell company” under the Securities Act of 1933, the ability of certain shareholders to use the resale exemptions for restricted stock under Rule 144 of the Securities Act of 1933 is greatly limited. This could further complicate our current fundraising efforts.

There does not exist a liquid secondary market for our common stock therefore you may not be able to sell your common stock.

There is not, currently, a liquid secondary trading market for our common stock. Therefore, there is no central place, such as a stock exchange or electronic trading system, to sell your common stock. If you do want to sell your common stock, then you will be responsible for locating a buyer and finalizing terms of sale.

Due to the lack of a market for our shares, our share price will be more volatile. Also, our stock is held by a smaller number of investors thus reducing the liquidity of our stock and the likelihood that any active trading market will develop.

There is no market for our common stock and we cannot assure you that any market will ever be developed or maintained. Currently, our stock is listed on the Over-The-Counter-Bulletin-Board (OTCQB) under the trading symbol AXIO. As of the date of this report, our stock has traded on the OTCQB on a very limited basis. We cannot provide any assurance that our stock will continue trading on the OTCQB. The fact that most of our stock is held by a small number of investors further reduces the liquidity of our stock and the likelihood that any active trading market will develop. The market for our common stock, if any, is likely to be volatile and many factors may affect the market. These include, for example: our success, or lack of success, in marketing our services; developing our client base; competition; government regulations; and fluctuating operating results.

Because our common stock is quoted and traded on the OTC Bulletin Board and the Berlin Stock Exchange, short selling could increase the volatility of our stock price.

Short selling occurs when a person sells shares of stock which the person does not yet own and promises to buy stock in the future to cover the sale. The general objective of the person selling the shares short is to make a profit by buying the shares later, at a lower price, to cover the sale. Significant amounts of short selling, or the perception that a significant amount of short sales could occur, could depress the market price of our common stock. In contrast, purchases to cover a short position may have the effect of preventing or retarding a decline in the market price of our common stock, and together with the imposition of the penalty bid, may stabilize, maintain or otherwise affect the market price of our common stock. As a result, the price of our common stock may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued at any time. These transactions may be effected on over-the-counter bulletin board or any other available markets or exchanges. Such short selling if it were to occur could impact the value of our stock in an extreme and volatile manner to the detriment of our shareholders.

Because we do not expect to pay dividends for the foreseeable future, investors seeking cash dividends should not purchase shares of our common stock.

We have never declared or paid any cash dividends on shares of our common stock. We currently intend to retain future earnings, if any, to finance the expansion of our business. As a result, we do not anticipate paying any cash dividends in the foreseeable future. Our payment of any future dividends will be at the discretion of our board of directors after taking into account various factors, including but not limited to our financial condition, operating results, cash needs, growth plans and the terms of any credit agreements that we may be a party to at the time. Accordingly, investors must rely on sales of their own common stock after price appreciation, which may never occur, as the only way to realize their investment. Investors seeking cash dividends should not purchase our common stock.

Because our stock price can be volatile, investors may not be able to recover any of their investment.

Stock prices in general, and stock prices of mineral exploration companies in particular, have experienced extreme volatility that often has been unrelated to the operating performance or any specifics of the company. Factors that may influence the market price of our common stock include:

actual or anticipated changes or milestones in our operations;

our ability or inability to acquire oil and gas leases or interests in such properties;

our ability or inability to generate revenues;

increased competition within United States and elsewhere;

government regulations, including oil and gas exploration regulations that affect our operations;

predictions and trends in the oil and gas industry;

volatility of oil prices;

sales of common stock by “insiders”; and

announcements of significant acquisitions, strategic partnerships, joint ventures or capital commitments by us or our competitors.

Our stock price may also be impacted by factors that are unrelated or disproportionate to our operating performance. These market fluctuations, as well as general economic, political and market conditions, such as, but not limited to, armed hostilities or acts of terrorism, recessions, acts of God, interest rates or international currency fluctuations, may adversely affect the market price of our common stock.

Offers or availability for sale of a substantial number of shares of our common stock may cause the price of our common stock to decline.

If our stockholders sell substantial amounts of our common stock in the public market, including shares being offered for sale pursuant to a prospectus or upon the expiration of any statutory holding period, under Rule 144, or upon expiration of lock-up periods applicable to outstanding shares, or issued upon the exercise of outstanding options or warrants, it could create a circumstance commonly referred to as an “overhang” and in anticipation of which the market price of our common stock could fall. The existence of an overhang, whether or not sales have occurred or are occurring, also could make more difficult our ability to raise additional financing through the sale of equity or equity-related securities in the future at a time and price that we deem reasonable or appropriate. Recent revisions to Rule 144 may result in shares of our common stock that we may issue in the future becoming eligible for resale into the public market without registration in as little as six months after their issuance.

Because our directors and officers may serve as directors or officers of other companies, they may have a conflict of interest in making decisions for our business.

Our directors and officers may serve as directors or officers of other companies or have significant shareholdings in other resource companies and, to the extent that such other companies may participate in ventures in which we may participate, our directors or officers may have a conflict of interest in negotiating and concluding terms respecting the extent of such participation. In the event that such a conflict of interest arises at a meeting of our directors, we expect that the director who has such a conflict will abstain from voting for or against the approval of such participation or such terms. Our directors are required to act honestly, in good faith and in our best interests. In determining whether or not we will participate in a particular program and the interest therein to be acquired by us, we expect that the directors and officers will be guided by their fiduciary duties and take into account such matters as they deem relevant, including considering the degree of risk to which we may be exposed and our financial position at that time.

Because our future officers and directors may allocate their time to other business interests or may be employed by other companies, they may not be able or willing to devote a sufficient amount of time to our business operations, which may adversely affect our business, financial condition or results of operations and cause our business to fail.

It is possible that the demands from other obligations on our officer and director and future officers and directors, could increase, they could no longer be able to devote sufficient time to the management of our operations and business. This conflict of interest could adversely affect our business, financial condition or results of operations and cause our business to fail.

U.S. investors may experience difficulties in attempting to enforce judgments based upon U.S. federal securities laws against us and our non-U.S. resident directors.

Except for our Chief Financial Officer, our directors and officers reside outside of the U.S. As a result, it may be difficult or impossible for U.S. investors to enforce judgments of U.S. courts for civil liabilities against some of our directors and officers.

STOCK OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The following table sets forth, as of October10, 2014, the total number of shares owned beneficially by our directors, officers and key employees, individually and as a group, and the present owners of 5% or more of our total outstanding shares. The stockholders listed below have direct ownership of their shares and possesses sole voting and dispositive power with respect to the shares.

Title of Class	Name of Beneficial Owner	Amount and Nature of Beneficial Owner*	Percent of Class**
Common Stock:	Robert Knight(1)	12,806,246 Shares (5)	66.96%
	Michael Altman (2)	1,159,357 Shares	6.06%
	Frank Lamendola (3)	288,425 Shares	1.51%
Common Stock	All directors and named executive officers as a group (4)	14,254,028 Shares (5)	74.53%

(1)

Robert Knight is a director. Includes options for 12,000 Shares exercisable under the 2010 Stock Option Plan, 300,000 Shares exercisable under the 2013 Stock Option Plan and 3,602,920 Shares being his portion of the 7,000,000 shares issued on the completion of the acquisition of the leases.

(2)

Michael Altman is our Chief Executive Officer, President and a director. Includes option for 200,000 Shares exercisable under the 2013 Stock Option Plan and 959,357 Shares being his portion of the 7,000,000 shares issued on the completion of the acquisition of the leases.

(3)

Frank Lamendola is our Chief Financial Officer and a director. Includes option for 200,000 Shares exercisable under the 2013 Stock Option Plan and 28,425 Shares being his portion of the 7,000,000 shares issued on the completion of the acquisition of the leases.

(4)

Includes options for 12,000 Shares exercisable under the 2010 Stock Option Plan and 700,000 Shares exercisable under the 2013 Stock Option Plan.

*Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and generally includes voting or investment power with respect to securities. In accordance with Securities and Exchange Commission rules, shares of our common stock which may be acquired upon exercise of stock options or warrants which are currently exercisable or which become exercisable within 60 days of the date of the table are deemed beneficially owned by the optionees. Subject to community property laws, where applicable, the persons or entities named in the table above have sole voting and investment power with respect to all shares of our common stock indicated as beneficially owned by them.

** Based on 19,124,774 shares outstanding as of October 14, 2014 (which includes 7,000,000 Shares issuable in acquisition of Alberta Oil and Gas LP and 712,000 Shares issuable under Option Plans).

Directors, Executive Officers and Corporate Governance.

Our officers will serve until his successor is elected and qualified. Our officers are elected by the board of directors to a term of one (1) year and serve until their successor is duly elected and qualified, or until they are removed from office. The board of directors has no nominating, auditing or compensation committees.

The name, age and position of our present officers and director is set forth below:

Name	Age	Position
Robert Knight	57	Director
Frank Lamendola	54	Chief Financial Officer, Director
Michael Altman	62	Chief Executive Officer, Director

Michael Altman

Chief Executive Officer, Director

Mr. Altman is a senior executive with extensive oil and gas experience, having been in the resource business for over 20 years. Mr. Altman was the President of Uniterre Resources from 1996 to 2011 after serving as the Corporate Secretary from 1981 to 1996. In addition, he has been a director and officer of Austpro Energy Company from 1989 to the present date. Mr. Altman was called to the bar as a member of the Law Society of Upper Canada in April 1980 and as a member of the Law Society of British Columbia in May 1981.

Frank Lamendola

Chief Financial Officer and Director

From November 2006 through the present, Mr. Lamendola has been a consultant with Spire Group PC which is a public accounting firm. From 1982 to August 2006, he worked with the firm, Moore Stephens, P.C. and was a partner there from 1996 through August 2006. Mr. Lamendola received his Bachelors of Business Administration from Pace University, New York, NY in 1981.

Robert Knight:

Director

Mr. Knight has served as Chief Executive Officer, Chief Financial Officer and Director since May 2012. Since September 1994, Mr. Knight has been the President of Knight Financial Ltd., where he has organized and participated in many corporate finance transactions. Mr. Knight was awarded an MBA degree from Edinburgh School of Business, Herriot-Watt University in December 1998.

Code of Ethics

We have adopted a corporate code of ethics. We believe our code of ethics is reasonably designed to deter wrongdoing and promote honest and ethical conduct; provide full, fair, accurate, timely and understandable disclosure in public reports; comply with applicable laws; ensure prompt internal reporting of code violations; and provide accountability for adherence to the code. Our code of ethics is incorporated by reference.

Section 16(a) Beneficial Ownership Reporting Compliance

We believe that our former officers, directors, and our principal shareholders have not filed any reports required to be filed on, respectively, a Form 3 (Initial Statement of Beneficial Ownership of Securities), a Form 4 (Statement of Changes of Beneficial Ownership of Securities), or a Form 5 (Annual Statement of Beneficial Ownership of Securities). We believe our current officers and directors have filed all reports required to be filed on, respectively, Form 3, Form 4 and Form 5.

Corporate Governance.

Director Independence. We have no independent members on our Board of Directors as that term is defined in Rule 4200(a)(15) of the Nasdaq Marketplace Rules.

Audit Committee and Charter

We do not have a separately designated audit committee of the board or any other board-designated committee. Audit committee functions are performed by our board of directors.

Audit Committee Financial Expert

We do not have an audit committee financial expert. We do not have an audit committee financial expert because we believe the cost related to retaining a financial expert at this time is prohibitive. Further, because we have not commenced operations, at the present time, we believe the services of a financial expert are not warranted.

EXECUTIVE AND DIRECTOR COMPENSATION

Summary Compensation Table. The table set forth below summarizes the annual and long-term compensation for services in all capacities to us payable to our principal executive officers during the nine months ending May 31, 2014 and the fiscal year ending August 31, 2013. This information includes the dollar value of base salaries, bonus awards and number of stock options granted, and certain other compensation, if any.

Name and Principal Position	Year Ended August 31(2)	Salary $	Bonus $	Stock Awards $(1)	Option Awards $(1)	Non-Equity Incentive Plan Compensation $	Nonqualified Deferred Compensation Earnings $	All Other Compensation $	Total $
Michael Altman, CEO Principal Executive Officer (3)
	2014	20,000	0	0	58,823	0	0	0	78,823
	2013	0	0	0	0	0	0	0	0



Frank
Lamendola	2014	30,000 (5)	0	0	25,001	0	0	0	55,001
Principal	2013	0	0	0	0	0	0	0	0
Accounting
Officer (4)
Robert Knight President, CEO, CFO, Principal Accounting Officer, Secretary, Treasurer, Director Chairman (6)	2014 2013	67,500 90,000	0 0	0 0	41,623 0	0 0	0 0	0 0	109,123 90,000

(1)	Represents the dollar amount recognized for financial statement reporting purposes with respect to the fiscal year in accordance with ASC Topic No. 718. Pursuant to SEC Rules, the amounts shown exclude the impact of estimated forfeitures related to service-based vesting conditions.

(2)	2014 represents the nine months ending May 31, 2014.

(3)	Mr. Altman was appointed CEO effective January 29, 2014.

(4)	Mr. Lamendola was appointed CFO effective November 1, 2013.

(5)	Represents $30,000 of fees paid pursuant to a consulting agreement entered into with an entity affiliated with Mr. Lamendola

(6)	Mr. Knight was appointed President, CEO, CFO, Principal Accounting Officer, Secretary, Treasurer, and Director effective May 18, 2012 and resigned effective January 29, 2014. Mr. Knight remains as Chairman of the Board.

Narrative Disclosure to Summary Compensation Table

Employment Agreements

We have no written employment agreements with our officers. Compensation was determined after discussion about expected time commitments, remuneration paid by comparable organizations and the flexibility provided to the Company by not having extended terms and other terms typical of employment agreements. We have no plans or packages providing for compensation of officers after resignation or retirement.

Stock Option and other Compensation Plans

2010 Stock Option Plan

The Plan, adopted by the Board of Directors on January 31, 2011, is intended to provide an incentive to our executive officers, directors, employees, independent contractors or agents who are responsible for or contribute to our management, growth and/or profitability. The purpose of granting options to such persons under the Plan is to attract them to consider employment with, or service to, us, to encourage their continued employment or service, and to give them incentive to provide their best efforts to us for purposes of enhancing shareholder value.

A total of up to 280,000 shares of our common stock have been reserved for the implementation of the Plan, either through the issuance of options to eligible persons in the form of incentive stock options or non-statutory options which are subject to restricted property treatment under Section 83 of the Internal Revenue Code. Whenever practical, the Plan is to be administered by a committee of not less than two members of the Board of Directors appointed by the full Board, and the Plan has a term of ten years, unless sooner terminated by the Board. During the year ended August 31, 2011, options to purchase 278,000 shares of common stock were granted under the plan and during the year ended August 31, 2012, 266,000 options were subsequently terminated under the plan.

2013 Stock Option Plan

On October 24, 2013, the Board of Directors authorized the implementation of the 2013 Employee and Consultant Stock Option Plan (the "2013 Option Plan"). The 2013 Option Plan is intended to provide an incentive to our executive personnel, directors, key employees or consultants who are responsible for or contribute to our management, growth and/or profitability. The purpose of granting options to such persons under the Plan is to attract them to consider employment with, or service to, us, to encourage their continued employment or service, and to give them incentive to provide their best efforts to us for purposes of enhancing shareholder value. A total of up to 3,000,000 shares of our common stock have been reserved for the 2013 Option Plan. The options can be issued at a strike price set at up to a 10% discount to market. As of May 31, 2014, 1,717,000 shares of common stock are available for issuance under the 2013 Option Plan.

As of August 31, 2014, there are no other stock option plans, stock appreciation rights, retirement, pension, or profit sharing plans for the benefit of our officers and directors.

Grants of Plan Based Awards
				Closing
		Number of	Exercise	Market	Grant Date
		Securities	Price of	Price on	Fair Value of
		Underlying	Options	Date of	Stock Options
Name	Grant Date	Option #	Awards (#/Sh)	Grant	Awards

Robert Knight	October 31, 2013	500,000	$0.25	$0.20	$52,392
Frank Lamendola	November 1, 2013	300,000	$0.25	$0.20	$31,468
Michael Altman	January 29, 2014	300,000	$0.45	$0.51	$91,275

Outstanding Equity Awards at Fiscal Year-end

As of May 31, 2014, the following named executive officers had the following unexercised options, stock that has not vested, and equity incentive plan awards:

Option Awards

Stock Awards

Equity

Incentive

Plan

Equity

Awards

Incentive

Number

Value

Number

Plan

Number

Awards

Unearned

Securities

Number

Market

Shares,

Underlying

Shares of

Value of

Units or

Unexercised

Securities

Units of

Other

Options

Underlying

Option

Stock

Or Units

Rights

Unexercised

Exercise

Expiration

Not

Name

Exercisable

Unexercisable

Options

Price

Date

Vested

Robert Knight

12,000

300,000

200,000

6.25

0.25

1/20/16

10/31/18

Frank

Lamendola

200,000

100,000

0.25

11/1/18

Michael

Altman

150,000

0.45

1/29/19

Compensation of Directors

The following table sets forth information concerning the compensation paid to each of our non-employee directors during the nine months ended May 31, 2014 and fiscal year ended August 31, 2013:

Fee

Non-Equity

Nonqualified

Earned

Incentive

Deferred

Or Paid

Stock

Options

Plan

Compensation

All Other

Name

In Cash

Awards

Compensation

Earnings

Compensation

Total

($)

($) (1)

($)

None

Aggregate Option Exercises in Last Fiscal Year

None of the named executive officers exercised options during the nine months ended May 31, 2014 or year ended August 31, 2013.

Related Person Transactions

Accounting and tax services are provided by an accounting firm in which our Chief Financial Officer (“CFO”) provides consulting services. Accounting and tax fees amounted to $15,000 and $30,000 for the three and nine months ended May 31, 2014, the $30,000 being owed as of May 31, 2014. In February 2014, a payable of $70,000 from prior services rendered was settled through the issuance of a $35,000 8% note payable and 140,000 shares of Company common stock valued at $35,000.

The Company is obligated to its Chairman, who is also the majority stockholder of the Company, for accrued and unpaid compensation and reimbursable expenses as of May 31, 2014 and August 31, 2013 in the amounts of approximately $211,000 and $120,000, respectively. Compensation and expenses amounted to approximately $34,000 and $114,000 for the three and nine months ended May 31, 2014 and $27,000 and $99,000 for the three and nine months ended May 31, 2013, respectively.

On April 11, 2014, we borrowed $5,000 from our chairman for working capital purposes.

The following transaction with Alberta Oil and Gas LP is a related party transaction as our majority shareholder and director, Robert Knight, our Chief Executive Officer/President and director, Michael Altman and our Chief Financial Officer and director, Frank Lamendola are also shareholders of Abexco Inc. owner of Alberta Oil and Gas LP. On October 14, 2014 we issued 7,000,000 shares to Alberta Oil and Gas LP as part of our acquisition agreement for the leases owned by Alberta Oil and Gas LP in Toole County Montana at a deemed value of $0.25 per share valued at $1,750,000 the fair value at date of issuance.

On August 29, 2014, we entered into an indemnification agreement with Alberta Oil and Gas LP and its parent, Abexco, Inc. (Nevada) whereby Alberta Oil and Gas LP and Abexco, Inc. confirmed that our maximum liability is limited to $1,405,650 ($1,500,000 CDN) and that we would be indemnified by Alberta Oil and Gas LP and Abexco, Inc. for any amounts greater than $1,405,650 ($1,500,000 CDN).

With regard to any future related party transaction, we plan to fully disclose any and all related party transactions, including, but not limited to, the following:

●	disclose such transactions in prospectuses where required;
●	disclose in any and all filings with the Securities and Exchange Commission, where required;

●	obtain disinterested directors consent; and
●	obtain shareholder consent where required.

DESCRIPTION OF SECURITIES

Common Stock

We have 300,000,000 shares of $.001 par value common stock authorized, of which 18,412,774 shares are issued and outstanding at October 14, 2014. Each holder of our Common Stock is entitled to one vote for each share held of record on each matter submitted to a vote of stockholders, including the election of directors. Stockholders do not have any right to cumulate votes in the election of directors.

Subject to preferences that may be granted to the holders of preferred stock, each holder of our Common Stock is entitled to share ratably in distributions to stockholders and to receive ratably such dividends as may be declared by our board of directors out of funds legally available therefor. In the event of our liquidation, dissolution or winding up, the holders of our Common Stock will be entitled to receive, after payment of all of our debts and liabilities and of all sums to which holders of any preferred stock may be entitled, the distribution of any of our remaining assets. Holders of our Common Stock have no conversion, exchange, sinking fund, redemption or appraisal rights (other than such as may be determined by our board of directors in its sole discretion) and have no preemptive rights to subscribe for any of our securities.

All of the outstanding shares of our Common Stock are, and the shares of Common Stock issued upon the conversion of any securities convertible into our Common Stock will be, fully paid and non-assessable.

Securities Exchange Listing

Our common stock is listed on the Over-the-Counter Bulletin Board under the symbol “AXIO.

Transfer Agent

We have appointed Island Stock Transfer, Roosevelt Office Center, 15500 Roosevelt Boulevard, Suite 301, Clearwater, Florida 33760 with a telephone number of (727) 289-0010, as transfer agent for our shares of common stock.

Preferred Stock

We are authorized to issue 10,000,000 shares of preferred stock, no par value. Our board of directors is authorized to classify or reclassify any unissued portion of our authorized shares of preferred stock to provide for the issuance of shares of other classes or series, including preferred stock in one or more series. We may issue preferred stock from time to time in one or more class or series, with the exact terms of each class or series established by our board of directors. Our board of directors may issue preferred stock with voting and other rights that could adversely affect the voting power of the holders of our common stock without seeking stockholder approval. Additionally, the issuance of preferred stock may have the effect of decreasing the market price of the common stock and may adversely affect the voting power of holders of common stock and reduce the likelihood that common stockholders will receive dividend payments and payments upon liquidation. The issuance of preferred stock may delay, deter or prevent a change in control.

Warrants

As of October 14, 2014, we did not have any warrants outstanding.

Registration Rights

Caro Capital LLC, an owner of 300,000 shares of common stock of Axiom, issued to them pursuant to a consulting agreement has the right at any time, if the Company files a registration statement with the SEC registering an amount of securities equal to at least $500,000 (“Registration Statement”), such that the Company will provide piggy back registration rights and include their shares in the Registration Statement

Indemnification of Officers and Directors

Our articles of incorporation, as amended, provide that, to the fullest extent permitted by Nevada law, our directors or officers shall not be personally liable to us or our shareholders for damages for breach of such director’s or officer’s fiduciary duty. The effect of this provision of our articles of incorporation, as amended, is to eliminate our rights and our shareholders’ rights (through shareholders’ derivative suits on behalf of our company) to recover damages against a director or officer for breach of the fiduciary duty of care as a director or officer (including breaches resulting from negligent or grossly negligent behavior), except under certain situations defined by statute. We believe that the indemnification provisions in our Articles of Incorporation, as amended, are necessary to attract and retain qualified persons as directors and officers.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 (the “Act” or “Securities Act”) may be permitted to directors, officers or persons controlling us pursuant to the foregoing provisions, or otherwise, we have been advised that in the opinion of the SEC, such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable.

Exclusion of Liability

Pursuant to the Colorado Corporation Code, the Company’s articles of incorporation exclude personal liability for its directors for monetary damages based upon any violation of their fiduciary duties as directors, except as to liability for any breach of the duty of loyalty, acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, acts in violation of Section 7-5-114 of the Colorado Corporation Code, or any transaction from which a director receives an improper personal benefit. This exclusion of liability does not limit any right which a director may have to be indemnified and does not affect any director’s liability under federal or applicable state securities laws.

Conflicts of Interest

On October 25, 2013, we entered into a Farmout Agreement with American Midwest Oil and Gas Corp. (“AMOG”). Subsequently, this Farmout Agreement was cancelled. In its place we entered into an agreement with AMOG on April 2, 2014. whereby we agreed to purchase all the issued and outstanding shares of AMOG. The purchase price for the shares of AMOG was $3,480,000 and to be paid by the issuance of 7,400,000 shares of our common stock and payment of $150,000 for a licensing fee for the 3D seismic covering the Leases, to paid from production and/or through the raising of drilling funds. This agreement was terminated on September 9, 2014.

The following transactions with Alberta Oil and Gas LP are a related party transaction as our majority shareholder and director, Robert Knight, our Chief Executive Officer and director Michael Altman and our Chief Financial Officer and director Frank Lamendola are also shareholders of Abexco Inc., the owner of Alberta Oil and Gas LP. On October 14, 2014, we finalized a Lease Purchase Agreement with Alberta Oil and Gas LP whereby we purchased certain oil and gas leases and the leasehold estates created thereby located in Toole County, Montana totaling 14,916.94 gross acres and 6,170.76 net acres (which includes 1,895.53 acres forfeited by Tanglewood Energy, LLC) which includes a 23.1% working interest in two oil and gas wells drilled on the leases and a 50% interest in two producing gas wells on the leases. The purchase price for the leases is $3,124,160 ($3,334,180 CDN), of which $46,855 ($50,000 CDN) is to be paid in cash from future cash flow or from future financing, $1,405,650 ($1,500,000 CDN) is to be in the form of the assumption of a note secured against the leases (of which $1,327,606 ($1,416,717 CDN) remains owing) and the remainder to be paid in the form of 7,000,000 shares of our common stock valued at $0.30 per share. The purchase price may be reduced if prior to the closing of the purchase it is determined that the seller does not have a defensible title to all of the leases.

On June 18, 2014, we entered into an agreement with Alberta Oil and Gas LP to amend the Lease Purchase Agreement by confirming the transfer of the working interests in the two producing gas wells and the two newly drilled oil wells.

TOOLE COUNTY, MONTANA LEASES

(A Carve-Out of Abexco, Inc. and Alberta Oil and Gas, LP)

Table of Contents

Report of Independent Registered Public Accounting Firm	F-1

Special Purpose Carve-Out Financial Statements - Toole County, Montana Leases

Balance Sheets	F-2

Statements of Operations	F-3

Statements of Comprehensive Income	F-4

Statement of Changes in Investment Deficiency	F-5

Statements of Cash Flows	F-6

Notes to Financial Statements	F-8

Unaudited Pro Forma Combined Financial Statements

Introduction	F- 15

Proforma Combined Balance Sheet	F- 16

Proforma Combined Statements of Operations	F- 17

Notes to Proforma Combined Financial Statements	F- 19

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

Axiom Oil and Gas Corp.

We have audited the accompanying balance sheet of the Special-Purpose Carve-Out Financial Statements of Toole County, Montana Leases (A Carve-Out of Abexco, Inc. and Alberta Oil and Gas, LP) as of December 31, 2013, and the related statements of operations, comprehensive loss, changes in investment deficiency, and cash flows for the year then ended. These financial statements are the responsibility of Abexco, Inc. and Alberta Oil and Gas, LP’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Toole County, Montana Leases is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Toole County, Montana Leases’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Toole County, Montana Leases as of December 31, 2013, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming Toole County, Montana Leases will continue as a going concern. As discussed in Note 2 to the financial statements, Toole County, Montana Leases has incurred an investment deficiency and liabilities exceed assets by $730,298, and there are existing uncertain conditions Toole County, Montana Leases faces relative to its ability to obtain working capital and operate successfully. These conditions raise substantial doubt about its ability to continue as a going concern. Management’s plans regarding these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 1, Toole County, Montana Leases is an integrated business of Abexco, Inc. and Alberta Oil and Gas, LP and is not a stand-alone entity. The financial statements of Toole County, Montana Leases reflect the assets, liabilities, revenue and expenses directly attributable to Toole County, Montana Leases, as well as allocations deemed reasonable by management, to present the financial position, results of operations, changes in investment deficiency and cash flows of Toole County, Montana Leases on a stand-alone basis and do not necessarily reflect the financial position, results of operations, comprehensive loss, changes in investment deficiency and cash flows of Toole County, Montana Leases in the future or what they would have been had Toole County, Montana Leases been a separate, stand-alone entity during the period presented.

/s/ Cowan, Gunteski & Co., P.A.

October 10, 2014

Tinton Falls, NJ

F-1

TOOLE COUNTY, MONTANA LEASES

(A Carve-Out of Abexco, Inc. and Alberta Oil and Gas, LP)

Balance Sheets

	June 30,			December 31,
	2014			2013
	(Unaudited)

ASSETS

Property – successful efforts method
Leases, Toole County Montana	$	665,240		$	665,240
Investment in working interest in wells		301,000			--

Total assets	$	966,240		$	665,240

LIABILITIES AND INVESTMENT DEFICIENCY

Current liabilities
Accrued interest	$	97,768		$	71,049
Due to Abexco		340,000			--

Total current liabilities		437,768			71,049

Long-term liabilities
Secured debenture		1,327,606			1,324,489

Total liabilities		1,765,374			1,395,538

Commitments and contingencies		--			--

Investment deficiency		(799,134	)		(730,298	)

Total liabilities and investment deficiency	$	966,240		$	665,240

See accompanying notes to financial statements.

F-2

TOOLE COUNTY, MONTANA LEASES

(A Carve-Out of Abexco, Inc. and Alberta Oil and Gas, LP)

Statements of Operations



	For the Six Months Ended			For the Year Ended
	June 30,			December 31,
	2014			2013
	(Unaudited)

Revenues – gas sales	$	11,834		$	11,795
Cost of goods sold		7,052			28,389

Gross profit (loss)		4,782			(16,594	)

Expenses
General and administrative		5,912			50,342

Operating loss		(1,130	)		(66,936	)

Interest expense		64,841			57,694

Net loss	$	(65,971	)	$	(124,630	)

See accompanying notes to financial statements.

F-3

TOOLE COUNTY, MONTANA LEASES

(A Carve-Out of Abexco, Inc. and Alberta Oil and Gas, LP)

Statements of Comprehensive Loss



	For the Six Months Ended			For the Year Ended
	June 30,			December 31,
	2014			2013
	(Unaudited)

Net loss	$	(65,971	)	$	(124,630	)

Other comprehensive income (loss)
Foreign currency translation adjustment		(3,996	)		108,475

Comprehensive loss	$	(69,967	)	$	(16,155	)

See accompanying notes to financial statements.

F-4

TOOLE COUNTY, MONTANA LEASES

(A Carve-Out of Abexco, Inc. and Alberta Oil and Gas, LP)

Statement of Changes in Investment Deficiency

January 1, 2013 through June 30, 2014

(Unaudited)

Balance – January 1, 2013	$	(1,527,372	)

Net loss – year ended December 31, 2013		(124,630	)

Foreign currency translation adjustment		108,475

Net contributions Abexco/Alberta LP		813,229

Balance – December 31, 2013		(730,298	)

Net loss – six months ended June 30, 2014		(65,971	)

Foreign currency translation adjustment		(3,996	)

Net contributions Abexco/Alberta LP		1,131

Balance June 30, 2014 (Unaudited)	$	(799,134	)

See accompanying notes to financial statements.

F-5

TOOLE COUNTY, MONTANA LEASES

(A Carve-Out of Abexco, Inc. and Alberta Oil and Gas, LP)

Statements of Cash Flows

	For the Six Months Ended			For the Year Ended
	June 30,			December 31,
	2014			2013
	(Unaudited)
Cash flows from operating activities
Net loss	$	(65,971	)	$	(124,630	)
Adjustment to reconcile net loss to
Net cash used in operating activities:

Changes in assets and liabilities:
Accrued interest		25,841			55,544

Net cash used in operating activities		(40,130	)		(69,086	)

Cash flows from investing activities
Acquisition of Toole County,
Montana leases		--			(665,240	)
Net cash used for investing activities		--			(665,240	)

Cash flows from financing activities
Net contributions –Abexco/Alberta LP		1,130			726,110
Due to Abexco		39,000			--
Net cash provided by financing activities		40,130			726,110

Adjustment for change in exchange rate		--			(8,216	)

Net change in cash		--			--

Cash balance, beginning of periods		--			--

Cash balance, end of periods		--			--

See accompanying notes to financial statements.

F-6

TOOLE COUNTY, MONTANA LEASES

(A Carve-Out of Abexco, Inc. and Alberta Oil and Gas, LP)

Statements of Cash Flows

	For the Six Months Ended		For the Year Ended
	June 30,		December 31,
	2014		2013
	(Unaudited)

Supplementary information:
Cash paid for:
Interest	$	--	$	--
Income taxes	$	--	$	--

Supplemental disclosure of cash flow information: Non-cash investing and financing
activities
Abexco contribution for payment of
secured debentures and accrued
interest through issuance of stock	$	--	$	87,119
Investment in working interest in wells
acquired with funds due to Abexco	$	301,000	$	--

See accompanying notes to financial statements.

F-7

TOOLE COUNTY, MONTANA LEASES

(A Carve-Out of Abexco, Inc. and Alberta Oil and Gas, LP)

Notes to Financial Statements

(Unaudited)

Note 1

Nature of Business and Basis of Financial Statement Presentation

Nature of Business

Abexco Inc. (“Abexco”) is a corporation incorporated under the laws of the State of Nevada in 2014. Alberta Oil and Gas Limited Partnership (“Alberta LP”) is a limited partnership organized under the laws of the State of Oklahoma in December 2009 and is wholly-owned by Abexco. Abexco was formed through the tax-free distribution of its shares from its parent company, Abexco, Inc. – Canada (“Abexco Canada”), to the shareholders of Abexco Canada. Abexco Canada is a corporation incorporated under the laws of the Province of Alberta, Canada in 2011. Abexco, Abexco Canada and Alberta LP are principally involved in the exploration and development of oil and gas properties in Oklahoma and Montana in the United States. Alberta LP holds rights to oil and gas leases, primarily in Toole County, Montana (the “Leases”). Abexco is obligated, in the amount of $1,324,489 (US dollars) ($1,416,717 Canadian dollars) at December 31, 2013 and $1,327,606 (US dollars) ($1,416,717 Canadian dollars) at June 30, 2014 in secured debentures, on certain of those leases in Toole County, Montana (“Secured Debenture”).

In April 2014, Alberta LP entered into an agreement with Axiom Oil and Gas Corporation (“Axiom”), whereby, Axiom would acquire the rights to certain oil and gas leases in Toole County, Montana and assume secured debt obligations related to those leases from Abexco.

The accompanying special purpose financial statements represent the financial position and results of operations for the Leases and Secured Debenture (the “Lease Acquisition”). Within these financial statements the “Company”, ”we”, “us” and “our” refers to the Lease Acquisition.

Basis of Financial Statement Presentation

The accompanying special purpose carve-out financial statements are presented in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The Lease Acquisition represents an integrated business of Abexco and Alberta LP and is not a stand-alone entity. The financial statements of the Lease Acquisition reflect the assets, liabilities, revenues and expenses directly attributable to the Lease Acquisition, as well as allocations deemed reasonable by management, to present the financial position, results of operations, changes in invested deficiency and cash flows of the Lease Acquisition on a stand-alone basis. The allocation methodologies have been described within notes to the financial statements where appropriate, and management considers the allocations to be reasonable. The financial information included herein may not necessarily reflect the financial position, results of operations, changes in invested deficiency and cash flows of the Lease Acquisition in the future or what they would have been had the Lease Acquisition been a separate, stand-alone entity during the period presented.

F-8

TOOLE COUNTY, MONTANA LEASES

(A Carve-Out of Abexco, Inc. and Alberta Oil and Gas, LP)

Notes to Financial Statements

(Unaudited)

Note 2

Going Concern

The accompanying financial statements have been prepared on a basis which assumes that the Company will continue as a going concern and which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. The Company has minimal revenue, and has accumulated significant losses and an investment deficiency since its inception. These circumstances raise substantial doubt about the Company’s ability to continue as a going concern. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Management's plans with respect to alleviating the adverse financial conditions that caused substantial doubt about the Company’s ability to continue as a going concern are as follows:

In order to implement its business plan, the Company needs to raise additional capital through equity or debt financings or through loans from shareholders or others. The ability of the Company to continue as a going concern is dependent upon its ability to successfully raise additional capital and eventually attain profitable operations. There can be no assurance that the Company will be able to raise additional capital or execute its business strategy.

Note 3

Summary of Significant Accounting Policies

Use of Estimates - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“US GAAP”) requires management to make estimates and assumptions that affect certain reported amounts and disclosures. Accordingly, actual results could differ from those estimates.

Foreign Currency Translation – The secured debenture and accrued interest are payable in Canadian dollars (“CAD”). These amounts were translated into US dollars (“USD”) at the period end exchange rates. Interest expense for the period January 1 through June 30, 2014 and the year ended December 31, 2013 was translated into US dollars ("USD") using the average rates during the periods.

F-9

TOOLE COUNTY, MONTANA LEASES

(A Carve-Out of Abexco, Inc. and Alberta Oil and Gas, LP)

Notes to Financial Statements

(Unaudited)

Note 3

Summary of Significant Accounting Policies (Continued)

Cash and Cash Equivalents - The Company considers all highly liquid investments with a maturity of three months or less to be cash equivalents.

Property and Oil and Gas Operations – We account for our crude oil and natural gas exploration and production activities under the successful efforts method of accounting.

Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.

Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether we have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized.

Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.

Oil and gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

F-10

TOOLE COUNTY, MONTANA LEASES

(A Carve-Out of Abexco, Inc. and Alberta Oil and Gas, LP)

Notes to Financial Statements

(Unaudited)

Note 3

Summary of Significant Accounting Policies (Continued)

When circumstances indicate that proved oil and gas properties may be impaired, we compare expected undiscounted future cash flows to the unamortized capitalized cost of the asset. If the undiscounted future cash flows, based on our estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value.

Revenue Recognition – We recognize revenues from crude oil and natural gas sales upon delivery to the buyer.

General and Administrative Expenses - Certain general and administrative expenses were estimated based on operations of Alberta LP.

Recently Issued Accounting Pronouncements – In June 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-10, “Development Stage Entities (Topic 915): Elimination of Certain Financial Reporting Requirements, Including an Amendment to Variable Interest Entities Guidance in Topic 810, Consolidation” (ASU 2014-10). ASU 2014-10 removes all incremental financial reporting requirements regarding development-stage entities, including the removal of Topic 915 from the FASB Accounting Standards Codification. In addition, ASU 2014-10 adds an example disclosure in Risks and Uncertainties (Topic 275) to illustrate one way that an entity that has not begun planned operations could provide information about risks and uncertainties related to the company’s current activities. ASU 2014-10 also removes an exception provided to development-stage entities in Consolidations (Topic 810) for determining whether an entity is a variable interest entity. Effective with the first quarter of our fiscal year ended August 31, 2017, the presentation and disclosure requirements of Topic 915 will no longer be required. The revisions to Consolidation (Topic 810) are effective for the first quarter of our fiscal year ended August 31, 2018. Early adoption is permitted. We have not determined the potential effects on our financial statements.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (Topic 606) (ASU 2014-09), which supersedes the revenue recognition requirements in ASC Topic 605, “Revenue Recognition”, and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. The amendments in ASU 2014-09 will be applied using one of two retrospective methods. The effective date will be the first quarter of our fiscal year ended August 31, 2018. We have not determined the potential effects on our financial statements.

F-11

TOOLE COUNTY, MONTANA LEASES

(A Carve-Out of Abexco, Inc. and Alberta Oil and Gas, LP)

Notes to Financial Statements

(Unaudited)

Note 3

Summary of Significant Accounting Policies (Continued)

There are several other new accounting pronouncements issued or proposed by the FASB. Each of these pronouncements, as applicable, has been or will be adopted by the Company. Management does not believe any of these accounting pronouncements has had or will have a material impact on the Company’s financial position or operating results.

Subsequent Events – In accordance with ASC 855 “Subsequent Events” the Company evaluated subsequent events after the balance sheet date.

Note 4

Leases, Toole County Montana

Effective as amended July 19, 2013, Alberta LP, by and through its general partner, Wayne Oil & Gas, Inc. (an entity wholly owned by Abexco) entered into an agreement with American Midwest Oil and Gas Corp. (“AMOG”) whereby Alberta LP agreed to pay the purchase price of $665,240 to acquire certain oil and gas leases in Toole County Prospect, Montana totaling approximately 15,300 mineral acres (approximately 5,600 net mineral acres), as well as interests in two producing gas wells and two oil wells (the “Toole County Leases”) to which AMOG had the rights (the “Amended Agreement”). In conjunction, AMOG transferred a 50% interest in the leases to Alberta LP and agreed to provide future considerations and jointly operate the leases.

Operating Agreement

As part of the Amended Agreement, the A.A.P.L. FORM 610-1989 MODEL FORM OPERATING AGREEMENT (the “Operating Agreement”) was adopted. In order to give effect to the Operating Agreement, Alberta LP and AMOG formed a Joint Operating Committee, as defined in the Amended Agreement, and agreed that all expenses associated with the closing of the acquisition of the Toole County Leases and going forward would be split 50% to AMOG and 50% to Alberta LP.

Investment in Working Interests in Wells

In March 2014, the Company borrowed $80,000 from Abexco to purchase a 3.69% net revenue interest in each of two oil wells in the leased area of Toole County Montana. The Company has a 12.5% carried interest and a 6.15% working interest in each well (the combined interests equate to a 13.69% Net Revenue Interest).

In April 2014, the Company borrowed $260,000 (which includes $39,000 in finance costs) from Abexco to purchase an additional 17% working interest (10.20% Net Revenue Interest) in each of two oil wells in the leased area of Toole County Montana. The loan is unsecured and payable on demand.

Other

We currently have no proved oil and gas reserve quantities. Capitalized costs relating to oil and gas producing activities, other than our cost of acquiring the leases and investment in working interests in wells (as disclosed herein), are currently maintained by AMOG. Capitalized costs recorded on AMOG, which were covered by invested capital, totaled $1,030,554 as of June 30, 2014.

F-12

TOOLE COUNTY, MONTANA LEASES

(A Carve-Out of Abexco, Inc. and Alberta Oil and Gas, LP)

Notes to Financial Statements

(Unaudited)

Note 5

Related Party Transactions

Alberta LP is wholly-owned by Abexco. Affiliated stockholders of Abexco are also affiliated stockholders of AMOG.

In March and April 2014, the Company borrowed $340,000 from Abexco to purchase net revenue interests in each of two oil wells in the leased area of Toole County, Montana. The loan is unsecured and payable on demand. We incurred a one-time finance charge of $39,000 on the borrowing (see Note 4).

Note 6

Secured Debenture

In August 2012, Abexco acquired Alberta LP from unrelated individuals through the issuance of a $1,405,650 (USD) ($1,500,000 CAD) 4% retractable, redeemable secured debenture, as amended (the “Secured Debenture”). The Secured Debenture is secured by Abexco’s interest in and to its investment in Alberta LP. The Secured Debenture accrues interest at 4% per annum, and the principal and the accrued and unpaid interest becomes due and payable on September 1, 2016, as amended. The Secured Debenture contains certain retraction rights, whereby the holder shall be entitled, at its option, to retract certain principal and accrued interest, at specified dates and amounts and subject to the cash flow of Abexco, as defined in the agreement.

Note 7

Income Taxes

Net deferred tax assets and liabilities consist of the following components:

	June 30,			December 31,
	2014			2013
	(Unaudited)
Deferred tax assets:
Net operating loss carryforward	$	81,000		$	56,000
Valuation allowance		(81,000	)		(56,000	)

Net deferred tax assets	$	--		$	--

The income tax provision differs from the amount of income tax determined by applying the U.S. federal and state income tax rates of 38% to pretax income from continuing operations for the six months ended June 30, 2014 and for the year ended December 31, 2013 due to changes in the valuation allowance.

F-13

TOOLE COUNTY, MONTANA LEASES

(A Carve-Out of Abexco, Inc. and Alberta Oil and Gas, LP)

Notes to Financial Statements

(Unaudited)

Note 7

Income Taxes (Continued)

Based upon historical net losses and a significant investment deficiency since inception, management believes that it is not more likely than not that the deferred tax assets will be realized and has provided a valuation allowance of 100% of the deferred tax asset. The valuation allowance increased by approximately $25,000 and $48,000 in the six months ended June 30, 2014 and the year ended December 31, 2013, respectively.

Note 8

Commitments

As amended June 18, 2014 and April 2, 2014, we entered into a Lease Purchase Agreement with Axiom Oil and Gas Corp. (“Axiom”) whereby Axiom will purchase our interests in certain oil and gas leases and the leasehold estates created thereby located in Toole County, Montana totaling approximately 15,300 mineral acres (approximately 5,600 net mineral acres), as well as the working interest in two producing gas wells and two newly drilled oil wells in which Alberta, LP has a 12.5% carried interest and a 23.15% working interest (the combined interests equate to a 23.89% Net Revenue Interest). The purchase price for the leases, as amended, is $3,124,461USD ($3,334,180 CAD), of which, $46,855 USD ($50,000 CAD) is to be paid in cash, $1,327,606 USD ($1,416,717 CAD) is to be in the form of the assumption of a note secured against the leases and the remainder to be paid in the form of 7,000,000 shares of Axiom common stock valued at $0.25. The purchase price may be reduced if prior to the closing of the purchase it is determined that the seller does not have a defensible title to all of the leases. The closing of the purchase was to take place on May 30, 2014, provided that prior to that time we have cash assets of $1,000,000. This is a related party transaction as the Chairman and CEO of Axiom have an equity interest in each of Abexco and Alberta LP. Closing of this transaction has been extended by mutual agreement.

F-14

AXIOM OIL AND GAS CORP.

(An Exploration Stage Company)

Introduction to Unaudited Pro Forma Combined Financial Statements

The unaudited pro forma combined financial statements reflect the acquisition of Toole County, Montana Leases (“Leases Carve-out”) by Axiom Oil and Gas Corp. (“Axiom”, the “Company”, “we” or “us”) as though it occurred as of the dates indicated herein. Axiom, through its wholly-owned subsidiary, Toole Oil and Gas Corp., acquired certain oil and gas leases and the leasehold estates created thereby as well as certain working interests in two producing gas wells and two newly drilled oil wells located in Toole County, Montana from Alberta Oil and Gas Limited Partnership (“Alberta LP”) through the issuance of 7,000,000 shares of Axiom common stock, $46,855 cash ($50,000 Canadian dollars (CAD)) and the assumption of a note secured against the leases of $1,327,606 ($1,416,717 CAD). The shares were issued to Abexco, Inc. (“Abexco”), which wholly-owns Alberta LP.

The following unaudited pro forma combined financial statements and related notes reflect the pro forma effects of the acquisition of Leases Carve-out assuming it had been consummated as of May 31, 2014 for the balance sheet and as of the beginning of the periods for the nine months ended May 31, 2014 and for the year ended August 31, 2013 for the statements of operations. We accounted for the acquisition as a basic business combination with the Company as the acquirer of Leases Carve-out.

Pro forma data are based on assumptions and include adjustments as explained in the notes to the unaudited pro forma combined financial statements. The pro forma data are not necessarily indicative of the financial results that would have been attained had the acquisition occurred on the dates referenced above and should not be viewed as indicative of operations in future periods.

The unaudited pro forma combined financial statements should be read in conjunction with the notes thereto, and the financial statements of Axiom and Leases Carve-out as of and for the periods ended May 31, 2014 and August 31, 2013 included in this information statement.

The Company was incorporated in the State of Nevada on February 13, 2007. The Company is in the exploration stage and will continue to be in the exploration stage until the Company generates significant revenue from its business operations. To date, the Company has not generated any revenues. It has abandoned its previous businesses of providing consulting services to private and public entities seeking assessment, development, and implementation of energy generating solutions and mineral exploration. Our current business activity is the acquisition and exploration and development of oil and gas properties. We have not yet begun operations. Our plan of operation is forward looking, and we may never begin operations.

We are authorized to issue 300,000,000 shares of common stock and 10,000,000 shares of preferred stock, both with a par value of $0.001. Effective November 1, 2010, we enacted a four-for-one (4:1) forward stock split. On August 27, 2013, we filed a Certificate of Amendment to our Articles of Incorporation and effective October 10, 2013 (i) changed our name to Axiom Oil and Gas Corp. to reflect our new business strategy of acquiring and exploring oil and gas properties; and (ii) enacted a one-for-twenty-five (1:25) reverse stock split. The Company remains an exploration stage company. All share and per share data in these financial statements have been adjusted retroactively to reflect the stock splits.

The pro forma adjustments include the accounting effects of the acquisition assuming it had been consummated as of May 31, 2014 for the balance sheet and as of the beginning of the periods for the nine months ended May 31, 2014 and for the year ended August 31, 2013 for the statements of operations.

F-15

AXIOM OIL AND GAS CORP.

(An Exploration Stage Company)

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

MAY 31, 2014

	Axiom
	Oil and Gas			Toole County,						Pro forma				Pro forma
	Corp.			Montana Leases			Combined			Adjustments				Combined

ASSETS

Current assets:
Cash	$	188		$	--		$	188		$	--			$	188
Total current assets		188			--			188			--				188

Other assets
Security deposit		1,400			--			1,400			--				1,400
Leases - Toole County, Montana		--			665,240			665,240			(444,720	)	(a.)		220,520
Investment in working interest in wells		--			301,000			301,000			--				301,000
Goodwill		--			--			--			3,040,709		(a)
											(3,040,709	)	(c)
Investment - Toole County, Montana Leases Carve-Out		--			--			--			1,796,855		(ac)		--
											(1,796,855	)	(b)

Total assets	$	1,588		$	966,240		$	967,828		$	(444,720	)		$	523,108

LIABILITIES AND STOCKHOLDERS’ DEFICIENCY
Current liabilities
Accounts payable and accrued expenses	$	478,130		$	97,768		$	575,898		$	--			$	575,898
Notes payable		142,000			--			142,000			--				142,000
Convertible debentures		105,000			--			105,000			--				105,000
Due to Abexco		--			340,000			340,000			--				340,000
Promissory note		--			--			--			46,855		(a)		46,855
Total current liabilities		725,130			437,768			1,162,898			46,855				1,209,753

Long-Term Liabilities
Secured debenture		--			1,327,606			1,327,606			--				1,327,606

Total liabilities		725,130			1,765,374			2,490,504			46,855				2,537,359

Commitments and contingencies		--			--			--			--				--

Stockholders’ deficiency
Common stock $0.001 par, 300,000,000 shares authorized,
11,252,774 issued and outstanding		11,253			--			11,253			7,000		(a)		18,253
Additional paid in capital		14,003,407			--			14,003,407			1,743,000		(a)		15,746,407
Investment deficiency		--			(799,134	)		(799,134	)		2,595,989		(a)		--
											(1,796,855	)	(b)
Deficit accumulated from prior operations		(121,862	)		--			(121,862	)		--				(121,862	)
Deficient accumulated during the exploration state		(14,616,340	)		--			(14,616,340	)		(3,040,709	)	(c)		(17,657,049	)
Total stockholders’ deficiency		(723,542	)		(799,134	)		(1,522,676	)		(491,575	)			(2,014,251	)

Total liabilities and stockholders’ deficiency	$	1,588		$	966,240		$	967,828		$	(444,720	)		$	523,108

Notes to pro forma combined balance sheet as of May 31, 2014:

Adjustments to record the following:

(a)	The issuance of 7,000,000 shares of common stock and promissory note to acquire the Leases Carve-out.

(b)	The elimination of Axiom’s investment in Leases Carve-out.

(c)	The impairment of goodwill created upon the acquisition of Leases Carve-out.

F-16

AXIOM OIL AND GAS CORP.

(An Exploration Stage Company)

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

PERIOD ENDED MAY 31, 2014

	Axiom			Toole County
	Oil and Gas			Montana						Pro forma				Pro forma
	Corp.			Leases			Combined			Adjustments				Combined

Revenues - gas sales	$	--		$	11,834		$	11,834		$	5,900		(b)	$	17,734

Cost of goods sold		--			7,052			7,052			3,500		(b)		10,552

Gross profit		--			4,782			4,782			2,400				7,182

Expenses
Compensation		225,448			--			225,448			--				225,448
General and administrative		459,603			5,912			465,515			3,040,709		(a)		3,509,224
											3,000		(b)

Loss before other income (expenses)		(685,051	)		(1,130	)		(686,181	)		(3,041,309	)			(3,727,490	)

Other Income (Expenses)
Interest expense		(19,604	)		(64,841	)		(84,445	)		--				(84,445	)
Forgiveness of debt income		77,480			--			77,480			--				77,480

Net other income (expenses)		57,876			(64,841	)		(6,965	)		--				(6,965	)

Net loss	$	(627,175	)	$	(65,971	)	$	(693,146	)	$	(3,041,309	)		$	(3,734,455	)

Notes to pro forma combined statement of operations as of May 31, 2014

Adjustments to record the following:

(a)	The impairment of goodwill created upon the acquisition of Leases Carve-out of $3,040,709.

(b)	Estimated three months operations of Leases Carve-out.

F-17

AXIOM OIL AND GAS CORP.

(An Exploration Stage Company)

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

PERIOD ENDED AUGUST 31, 2013

	Axiom			Toole County
	Oil and Gas			Montana						Pro forma				Pro forma
	Corp.			Leases			Combined			Adjustments				Combined

Revenues - gas sales	$	--		$	11,795		$	11,795		$	--			$	11,795

Cost of goods sold		--			28,389			28,389			--				28,389

Gross profit (loss)		--			(16,594	)		(16,594	)		--				(16,594	)

Expenses
Compensation		90,000			--			90,000			--				90,000
General and administrative		206,772			50,342			257,114			2,971,763		(a)		3,228,877

Loss before other income (expenses)		(296,772	)		(66,936	)		(363,708	)		(2,971,763	)			(3,335,471	)

Other Income (Expenses)
Interest expense		(4,636	)		(57,694	)		(62,330	)		--				(62,330	)

Net other income (expenses)		(4,636	)		(57,694	)		(62,330	)		--				(62,330	)

Net loss	$	(301,408	)	$	(124,630	)	$	(426,038	)	$	(2,971,763	)		$	(3,397,801	)

Notes to pro forma combined statement of operations as of August 31, 2014

Adjustments to record the following:

(a)	The impairment of goodwill created upon the acquisition of Leases Carve-out of $2,971,763.

F-18

AXIOM OIL AND GAS CORP.

(An Exploration Stage Company)

Notes to Unaudited Pro Forma Combined Financial Statements

As amended June 18, 2014 and April 2, 2014, we entered into a material definitive agreement to acquire, through our wholly-owned subsidiary, Toole Oil and Gas Corp., certain oil and gas leases and the leasehold estates created thereby as well as certain working interests in two producing gas wells and two newly drilled oil wells located in Toole County, Montana from Alberta Oil and Gas Limited Partnership (“Alberta LP”) through the issuance of 7,000,000 shares of our common stock, $46,855 cash ($50,000 CAD) and the assumption of a note secured against the leases of $1,327,606 ($1,416,717 CAD). The shares were issued to Abexco, Inc. (“Abexco”), which wholly-owns Alberta LP.

Unaudited pro forma adjustments reflect the following transactions:

a)	The issuance of 7,000,000 shares of Axiom common stock and promissory note to acquire Leases Carve-out.

b)	The adjustment to record the leases acquired at fair value.

c)	The elimination of Axiom’s investment in Leases Carve-out and related goodwill impairment.

d)	The adjustment to record estimated three months operations of Leases Carve-out.

F-19

Item 3.02 Unregistered Sales of Equity Securities

Recent Sales of Unregistered Securities

On October 14, 2014 we issued 7,000,000 shares to Alberta Oil and Gas LP as part of our acquisition agreement for the leases owned by Alberta Oil and Gas LP in Toole County Montana. The total of these shares is $1,750,000 at $.25 per share, the fair value at the date of issuance. These shares were issued pursuant to Regulation D.

Item 5.01 Changes in Control of Registrant

N/A

Item 5.02 Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangement of Principal Officers.

N/A

Item 5.06 Change in Shell Status

See ITEM 2.01 Completion of Acquisition or Disposition of Assets included in this report.

ITEM 9.01 FINANCIAL STATEMENTS AND EXHIBITS.

(a) Financial Statements of Businesses Acquired

(b) Pro-Forma Financial Information


Exhibit			Description
10.1			Agreement dated March, 2014 Lease Purchase Agreement with Alberta Oil and Gas LP (incorporated by reference in exhibit 10.1 to the Company's Form 8-K filed on March 27, 2014)
10.2			Amendment to Lease Purchase Agreement, dated April 2, 2014, with Alberta Oil and Gas LP (incorporated by reference in exhibit 10.2 to the Company's Form 8-K filed on April 8, 2014)
10.3			Operating Agreement
10.4			Gas Gathering Agreement with Ranck Oil Company
14 21.2			Code of Ethics incorporated by reference filed November 29, 2010 The Company’s sole subsidiary is Toole Oil and Gas Corp. It is 100% owned by the Company.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

Axiom Oil and Gas Corp

Dated: October 14, 2014

By: /s/ Michael Altman

Name: Michael Altman

Title: Chief Executive Officer

Attached files

AXIOM OIL & GAS CORP. Reports

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