DEEP WELL OIL & GAS INC - Annual Report: 2014 (Form 10-K)

Previously, we successfully completed a drilling program and drilled six vertical wells. In addition, we have a working interest in three horizontal wells, and an interest in an additional two wells that we acquired from an unrelated third party. Since then we have been evaluating the options for production available to us to determine the preferable course of action. In August of 2013, we received approval from the AER for our horizontal cyclic steam stimulation thermal recovery project application (“HCSS Project”). It is anticipated that we will develop a thermal demonstration project on our properties followed by a commercial expansion project on one half section of land located on section 10-92-13W5 of our Sawn Lake oil sands properties where we currently have a 90% working interest. This application, submitted in early 2012, was an application to modify our previously approved in-situ demonstration project for a well to test thermal production on our Sawn Lake oil sands leases. This modification changed the vertical cyclical steam stimulation (“CSS”) well earlier approved, into a thermal recovery project to test two wells that use a horizontal application of CSS. We are currently waiting on the production facility performance results from the the SAGD Project in order to fine-tune our HCSS Project facility design before we initiate start-up operations on the ½ section of land where we plan to drill two horizontal wells to test the use of HCSS technology.

Market and Distribution of Product

Currently, on lands where we have a 25% working interest, the operator of the SAGD Project markets and distributes all oil produced from the SAGD Project facility. This production is currently being trucked to market.

On lands where we are the operator, we intend to sell our oil and gas production under both short-term (less than one year) and long-term (one year or more) agreements at prices negotiated with third parties. Under both short-term and long-term contracts, typically either the entire contract (in the case of short-term contracts) or the price provisions of the contract (in the case of long-term contracts) are renegotiated in intervals ranging in frequency from daily to annual. At this time, we have no production on any of the lands where we are the operator and therefore we have no short-term or long-term contracts. We will adopt specific sales and marketing plans once production is achieved on lands where we are designated as the operator.

Market pricing for bitumen is seasonal, with lower prices in and around the calendar year-end being the norm due to lower demand for asphalt and other bitumen-derived products. By necessity, bitumen is regularly blended with diluent in order to facilitate its transportation through pipelines to North American markets. As such, the effective field price for bitumen is also directly impacted by the input cost of the diluent required, the demand and price of which is also seasonal in nature (higher in winter as colder temperatures necessitate more diluent for transportation). Consequently, bitumen pricing is usually weakest in and around December and not reflective of the annual average realized price or the economics of the “business” overall. We have been advised that, to price bitumen, marketers apply formulas that take as a reference point the prices published for crude oil of particular qualities such as “Western Canadian Select”, “Brent Crude Oil”, “Crude Bitumen 9 API Plant Gate”, “Edmonton light”, “Lloydminster blend”, or the more internationally known “West Texas Intermediate” (“WTI”).

The price of oil and natural gas sold is determined by negotiation between buyers and sellers. An order from the National Energy Board (“NEB”) is required for oil and gas exports from Canada. The NEB is a federal agency which was formed in 1959 by the Parliament of Canada to regulate oil, gas and electric utility industries. The NEB monitors the supply and demand of oil, as it does with natural gas, to ensure quantities exported do not exceed the surplus remaining after Canadian requirements have been met. Any oil export to be made pursuant to an export contract that exceeds a certain duration or quantity requires an exporter to obtain authorization from the NEB. Natural gas exported from Canada is also subject to similar regulation by the NEB. Exporters are free to negotiate prices and other terms with purchasers provided that the export contracts meet certain criteria prescribed by the NEB. The government of Alberta also regulates the volume of natural gas, which may be removed from the province for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.

Competitive Business Conditions

We operate in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and natural gas properties as well as for the equipment, labour and materials required to develop and operate those properties. Many of our competitors have longer operating histories and substantially greater financial and other resources. Many of these companies not only explore for and produce crude oil and natural gas, but also carry on refining operations and market petroleum and other products on a worldwide basis. Our larger competitors, by reason of their size and relative financial strength, can more easily access capital markets than we can and may enjoy a competitive advantage, whereas we may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition. Larger competitors may be able to absorb the burden of any changes in laws and regulation in the jurisdictions in which we do business and handle longer periods of reduced prices of gas and oil more easily. Our competitors may also be able to pay more for productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties in the future will depend upon our ability to conduct efficient operations, evaluate and select suitable properties, implement advanced technologies and consummate transactions in a highly competitive environment.

Competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of Canada and other countries as well as other factors beyond our control, including international political stability, overall levels of supply and demand for oil and gas, and the markets for synthetic fuels and alternative energy sources.

Customers

We received our first oil sales revenue late in September of 2014. Currently the operator of the SAGD Project, markets and distributes all of the oil being produced from the SAGD Project. This production is currently being trucked to market.

Royalty Agreements

Through the acquisition of Northern, we potentially became a party to the following:

On December 12, 2003, Nearshore Petroleum Corporation (“Nearshore”) entered into a purported royalty agreement with Mikwec Energy Canada, Ltd. (now known as Northern) that potentially encumbers six oil sands leases covering 23,405 gross acres (9,472 gross hectares) located within our Sawn Lake properties (the “Purported 6.5% Royalty”). Nearshore claimed a Purported 6.5% Royalty from Northern on the leased substances on the land interests which Northern holds in the above six oil sands leases. Nearshore was a private corporation incorporated in Alberta, Canada, and was owned and controlled by Mr. Steven P. Gawne and his wife, Mrs. Rebekah J. Gawne, who each owned 50% of Nearshore. Mr. Steven P. Gawne was the President, Chief Executive Officer and a director of Deep Well from February 6, 2004 to June 29, 2005. Nearshore has subsequently transferred part or all of this Purported 6.5% Royalty to other parties.

On March 18, 2014 and June 27, 2014, through Northern, we entered into and subsequently closed two Acquisition of Royalty Interest Agreements and General Indenture of Conveyance, Assignment and Transfer Agreements (collectively the “Agreements”), with one of our joint venture partners (our “JV Partner”) and one related party, Mr. Malik Youyou, whereby we acquired and cancelled 5.5% of the disputed Purported 6.5% Royalty claim on certain lands owned by us. Our counsel and the vendor’s counsel negotiated the terms and conditions of the Agreements. Pursuant to the terms and conditions of the Agreements, we paid the following consideration:

Although we continue to deny the validity of the Purported 6.5% Royalty, we determined that it was in the best interests of our shareholders to come to an arrangement to acquire and cancel most of the Purported 6.5% Royalty to prevent a potential encumbrance over our land or the possibility of future litigation resulting from these alleged royalty claims.

Government Approval and Crown Royalties

Exploration and Production. Our operations are subject to Canadian federal and provincial governmental regulations. Such regulations include: requiring approval and licenses for the drilling of wells, regulating the location of wells and the method and ability to produce the wells, surface usage and the restoration of land upon which wells have been drilled, the plugging and abandoning of wells and the transportation of production from our wells. Our operations are also subject to various conservation regulations, including the regulation of in-situ recovery processes, the size of spacing units, the number of wells which may be drilled in a unit, the unitization or pooling of oil and gas properties, the rate of production allowable from oil and gas wells and the ability to produce oil and gas.

The North American Free Trade Agreement. The North American Free Trade Agreement (“NAFTA”) grants Canada the freedom to determine whether exports to the United States or Mexico will be allowed. In making this determination, Canada must ensure that export restrictions do not (i) reduce the proportion of energy exported relative to the supply of the energy resource; (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All parties to NAFTA are also prohibited from imposing minimum export or import price requirements.

Investment Canada Act. The Investment Canada Act of 1985, as amended, requires notification and/or review by the government of Canada in certain cases, including but not limited to, the acquisition of control of a Canadian Business by a non-Canadian. In certain circumstances, the acquisition of a working interest in a property that contains recoverable reserves will be treated as the acquisition of an interest in a “business” and may be subject to either notification or review, depending on the size of the interest being acquired and the asset size of the business.

Crown Royalties and Incentives. The governments of each province and the federal government of Canada have enacted legislation and regulations governing land tenure, royalties, production rates and taxes, environmental protection and other matters under their respective jurisdictions. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the parties. Crown royalties are determined by provincial and federal government regulation and are generally calculated as a percentage of the value of the gross production with the royalty rate dependent in part upon prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced. From time to time, the governments of Canada and Alberta have established incentive programs such as royalty rate reductions, royalty holidays, tax credits and drilling royalty credits. These incentives are for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects. These incentives generally increase cash flow.

Effective January 1, 2009, oil sands royalties in Alberta are calculated using a sliding scale for royalty rates ranging from 1% to 9% pre-payout and 25% to 40% post-payout depending on the world oil price. Project “payout” refers to the point in which we earn sufficient revenues to recover all of the allowed costs for the project plus a return allowance. The base royalty starts at 1% and increases for every dollar the world oil price, as reflected by the WTI, is priced above $55 per barrel, to a maximum of 9% when oil is priced at $120 per barrel or greater. The net royalty starts at 25% and increases for every dollar oil is priced above $55 per barrel to 40% when oil is priced at $120 or higher.

Research and Development

We had no material scientific research and development costs for the fiscal years ended September 30, 2014 and 2013.

Environmental Laws and Regulations

The oil and natural gas industry is subject to environmental laws and regulations pursuant to Canadian local, provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites be monitored, abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines and penalties. Under these laws and regulations, we could be liable for personal injury, clean-up costs and other environmental and property damages as well as administrative, civil and criminal penalties. Accordingly, we could be liable or could be required to cease production on properties if environmental damage occurs. Although we maintain insurance coverage, the costs of complying with environmental laws and regulations in the future may harm our business. Furthermore, future changes in environmental laws and regulations could occur that result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, any of which could have a material adverse effect on our financial condition or results of operations. We maintain commercial property and general liability insurance coverage on the properties we operate. We also maintain operators extra expense insurance which provides coverage for well control incidents specifically relating to regaining control of a well, seepage, pollution, clean-up and containment. No coverage is maintained with respect to any fine or penalty required to be paid due to a violation of the regulations set out by the federal and provincial regulatory authorities. We are committed to meeting our responsibilities to protect the environment and anticipate making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment.

Alberta’s climate change regulation, effective July 1, 2007, requires Alberta facilities that emit more than 100,000 tons of greenhouse gases a year to reduce emissions intensity by 12%. Companies have four choices to meet their reductions: (i) they can make operating improvements to their operations that will result in greenhouse gas emission reductions; (ii) they can purchase Alberta based offset credits; (iii) they can contribute to the Climate Change and Emissions Management Fund; or (iv) they can purchase or use emission performance credits (“EPCs”). EPCs are generated by facilities that have gone beyond the 12% mandatory intensity reduction and can be banked for future use or sold to other facilities that need to meet the reduction target.

On June 18, 2009, the government of Canada passed an Environmental Enforcement Act (the “EEA”). The EEA was created to strengthen and amend nine existing statutes that relate to the environment and to enact provisions in respect of the enforcement of certain statutes that relate to the environment. The EEA amended various enforcement, offence, penalty and sentencing provisions to discourage offences under the EEA by setting minimum and maximum fines, in particular for serious offences. The EEA also provided enforcement officers new powers to investigate cases and grants courts new sentencing authorities that ensure penalties reflect the seriousness of the pollution and wildlife offences. The EEA also expands the authority to deal with environmental offenders by: (i) specifying aggravating factors such as causing damage to wildlife or wildlife habitat, or causing damage that is extensive, persistent or irreparable; (ii) providing fine ranges that are higher for corporate offenders than for individuals; (iii) doubling fine ranges for repeat offenders; (iv) authorizing the suspension and cancellation of licenses, permits or other authorizations upon conviction; (v) requiring corporate offenders to report convictions to shareholders; and (vi) mandating the reporting of corporate offences on a public registry.

Employees

Our Company currently has two prime subcontractors and three full-time employees. For further information on our subcontractors see “Compensation Arrangements for Executive Officers” under Item 11 “Executive Compensation” of this Annual Report. We expect that, from time to time, we will hire more employees, independent consultants and contractors during the stages of implementing our plans.

An investment in our common stock is speculative and involves a high degree of risk and uncertainty. You should carefully consider the risks described below, together with the other information contained in our reports filed with the SEC, including the consolidated financial statements and notes thereto of our Company before deciding to invest in our common stock. The risks described below are not the only ones facing our Company. Additional risks not presently known to us, or that we presently consider immaterial may also adversely affect our Company. If any of the following risks occur, our business, financial condition and results of operations and the value of our common stock could be materially and adversely affected.

Any Development Of Our Resources Will Be Subject To Crown Royalties. The royalty regime of Alberta is a significant factor in the profitability of oil and natural gas production in Alberta, Canada. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production with the royalty rate dependent in part upon prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced. Penalties and interest may be charged to us if we fail to remit royalties on our production to the Crown as prescribed in the regulation.

We Have A History Of Losses And May Not Achieve Or Sustain Profitability In The Future. Since our inception, we have suffered recurring losses from operations and have been dependent on new investment to sustain our operations. During the years ended September 30, 2014 and 2013 we reported net losses of $2,040,260 and $2,463,403 respectively. We may not achieve profitability in the foreseeable future, if at all. In addition, our operating expenses may be more than our future revenue growth. We expect our cost of revenue and operating expenses to continue to increase in the foreseeable future as we continue to expand on our thermal recovery operations at Sawn Lake, Alberta.

The Successful Implementation Of Our Business Plan Is Subject To Risks Inherent In The Oil Sands Business. Our oil sands operations are subject to the economic risks typically associated with exploration, development and production activities, including the necessity of significant expenditures to locate and acquire properties and to drill exploratory wells. In addition, the cost and timing of drilling, completing, operating and acquiring regulatory approval for thermal recovery operations on our wells is often uncertain. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause our exploration, development and production activities to be unsuccessful. This could result in a total loss of our investment in a particular property. If exploration efforts are unsuccessful in establishing economically proven reserves and exploration activities cease, the amounts accumulated as unproven costs will be charged against earnings as impairments. Our exploitation and development of oil sands reserves depends upon access to the areas where our operations are to be conducted. We conduct a portion of our operations in regions where we are only able to do so on a seasonal basis. Unless the surface is sufficiently frozen, we are unable to access our properties, drill or otherwise conduct our operations as planned. In addition, if the surface thaws earlier than expected, we must cease our operations for the season earlier than planned. Our operations are affected by road bans imposed from time to time during the break-up and thaw period in the spring. Road bans are also imposed due to spring-break up, heavy rain, mud, rock slides and periods of high water, which can restrict access to our well sites and potential production facility sites. Our inability to access our properties or to conduct our operations as planned would result in a shutdown or slowdown of our operations, which would adversely affect our business.

We Rely On Independent Experts And Technical Or Operational Service Providers Over Whom We May Have Limited Control. The success of our business is dependent upon the efforts of various third parties that we do not control. We rely upon various companies to assist us in identifying desirable oil prospects to acquire and to provide us with technical assistance and services. We also rely upon the services of geologists, geophysicists, chemists, engineers and other scientists to explore and analyze oil prospects to determine a method in which the oil prospects may be developed in a cost-effective manner. In addition, we rely upon the owners and operators of oil drilling equipment to drill and develop our prospects to production. Although we have developed relationships with a number of third-party service providers, we cannot assure that we will be able to continue to rely on such persons. If any of these relationships with third-party service providers are terminated or are unavailable on commercially acceptable terms, we may not be able to execute our business plan. Our limited control over the activities and business practices of these third parties, any inability on our part to maintain satisfactory commercial relationships with them or their failure to provide quality services could materially and adversely affect our business, results of operations and financial condition.

Our Interests Are Held In The Form Of Leases That We May Be Unable To Retain. Our Sawn Lake property is held under leases and working interests in leases. These leases to which we are a party are for a fixed term of 15 years, but contain a provision that allows us to extend the term of the lease so long as we meet the minimum level of evaluation as set out by the government of Alberta tenure guidelines. If we or the holder of a lease fails to meet the specific requirements of the lease regarding delay or non-payment of rental payments or we or the holder of the lease fail to meet the minimum level of evaluation, some or all of our leases may terminate or expire. There can be no assurance that any of the obligations required to maintain each lease will be met. The termination or expiration of our leases or the working interests relating to leases may reduce our opportunity to exploit a given prospect for oil production and thus could have a material adverse effect on our business, results of operations and financial condition.

We Expect Our Operating Expenses To Increase Substantially In The Future And We May Need To Raise Additional Funds. We have a history of net losses and expect that our operating expenses will increase substantially over the next 12 months as we continue to develop our oil sands leases. In addition, we may experience a material decrease in liquidity due to unforeseen capital calls or other events and uncertainties. As a result, we may need to raise additional funds, and such funds may not be available on favourable terms, if at all. If we cannot raise funds on acceptable terms, we may not be able to execute our business plan, take advantage of future opportunities or respond to competitive pressures or unanticipated requirements. This could have a material adverse effect on our business, results of operations and financial condition.

Our Ability To Produce Sufficient Quantities Of Oil From Our Properties May Be Adversely Affected By A Number Of Factors Outside Of Our Control. The business of exploring for and producing oil and gas involves a substantial risk of investment loss. Drilling oil wells involves the risk that the wells may be unproductive or that, although productive, the wells may not produce oil in economic quantities. Other hazards such as unusual or unexpected geological formations, pressures, fires, blowouts, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well. Adverse weather conditions can also hinder drilling operations. A productive well could become uneconomic due to, for example, pressure depletion, water encroachment or mechanical difficulties, which could impair or prevent the production of oil and/or gas from the well. There can be no assurance that oil will be produced from all of our properties in which we have interests. Marketability of any oil that we acquire or discover may be influenced by numerous factors beyond our control. The marketability of our production will depend on the proximity of our reserves to and the capacity of, third party facilities and services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities. The unavailability or insufficient capacity of these facilities and services could force us to shut-in producing wells, delay the commencement of production, or discontinue development plans for some of our properties, which would adversely affect our financial condition and performance. There may be periods of time when pipeline capacity is inadequate to meet our oil transportation needs. During periods when pipeline capacity is inadequate, we may be forced to reduce production or incur additional expense as existing production is compressed to fit into existing pipelines. Other risk factors include availability of drilling and related equipment, market fluctuations of prices, taxes, royalties, land tenure, allowable production and environmental protection. Our ability to manage these factors could have a material adverse effect on our business, results of operations and financial condition.

We Do Not Control All Of Our Operations. We do not operate all of our properties and we therefore have limited influence over the testing, drilling and production operations of those properties. Currently, we have a 90% working interest in 51 sections on six oil sands leases, a 100% working interest in five sections on one oil sands lease, where we are the operator of the 90% and 100% leases. We also have a 25% working interest in an additional 12 sections on two oil sands leases where one of our joint venture partners is the operator. These nine oil sands leases, which are all contiguous, cover 43,015 gross acres (17,408 gross hectares) where we currently have 34,096 net acres (13,798 net hectares). All nine oil sands leases are located in the Peace River oil sands area of Alberta, Canada. Our lack of operational control of the 12 sections currently not operated by us means we are exposed to the following possibilities:

Any of these events could materially reduce the value of those properties affected.

Aboriginal Peoples May Make Claims Regarding The Lands On Which Our Operations Are Conducted. Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of western Canada. Since aboriginal peoples have filed a claim claiming aboriginal title or rights to the lands on which some of our properties are located, and if such a claim is successful, it could have a material adverse effect on our operations.

The AER governs our operations in Alberta, Canada and they have implemented a new directive (“Directive 056”) through which the government of Alberta has issued its First Nations Consultation Policy on Land Management and Resource Development on May 16, 2005. The AER expects that all industry applicants must adhere to this policy and the consultation guidelines. These requirements and expectations apply to the licensing of all new energy developments and all modifications to existing energy developments, as covered in Directive 056. In the policy, the government of Alberta has developed consultation guidelines to address specific questions about how consultation for land management and resource development should occur in relation to specific activities. Prior to filing an application, the applicant must address all questions, objections, and concerns regarding the proposed development project and attempt to resolve them. This includes concerns and objections raised by members of the public, industry, government representatives, First Nations, Métis, and other interested parties. This process can cause significant delays in obtaining a drilling permit for exploration and/or a production well license for both oil and gas.

Our Operations Are Subject To A Wide Range of Environmental Legislation and Regulation From All Levels Of Government Of Which We Have No Control. Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. As well, environmental regulations are imposed on the qualities and compositions of the products sold and imported. Environmental legislation also requires that wells, facility sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments. Compliance with environmental legislation can require significant expenditures, and failure to comply with environmental legislation may result in the imposition of fines and penalties and liability for cleanup costs and damages. The costs of complying with environmental legislation in the future could have a material adverse effect on our business, results of operations and financial condition. We anticipate that changes in environmental legislation may require, among other things, reductions in emissions to the air from its operations and result in increased capital expenditures. Future changes in environmental legislation could occur and result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, which could have a material adverse effect on our business, results of operations and financial condition.

Market Fluctuations In The Prices Of Oil Could Adversely Affect Our Business. Prices for oil tend to fluctuate significantly in response to factors beyond our control. These factors include, but are not limited to, the ongoing wars in the Middle East and actions of the Organization of Petroleum Exporting Countries and its maintenance of production constraints, the U.S. economic environment, weather conditions, the availability of alternate fuel sources, transportation interruption, the impact of drilling levels on crude oil and natural gas supply, and the environmental and access issues that could limit future drilling activities for the industry.

Changes in commodity prices may significantly affect our capital resources, liquidity and expected operating results. Price changes directly affect revenues and can indirectly impact expected production by changing the amount of funds available to reinvest in exploration and development activities. Reductions in oil could not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable. Significant declines in oil prices could result in non-cash charges to earnings due to impairment.

Changes in commodity prices may also significantly affect our ability to estimate the value of producing properties for acquisition and divestiture and often cause disruption in the market for oil producing properties, as buyers and sellers have difficulty agreeing on the value of the properties. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation of projects. We expect that commodity prices will continue to fluctuate significantly in the future.

Our Stock Price Could Decline. Our common stock is traded on the OTCQB marketplace. There can be no assurance that an active public market will continue for our common stock or that the market price for our common stock will not decline below its current price. Such price may be influenced by many factors, including but not limited to, investor perception of us and our industry and general economic and market conditions. The trading price of our common stock could be subject to wide fluctuations in response to announcements of our business developments or our competitors, quarterly variations in operating results, and other events or factors. In addition, stock markets have experienced extreme price volatility in recent years. This volatility has had a substantial effect on the market prices of companies, at times for reasons unrelated to their operating performance. Such broad market fluctuations may adversely affect the price of our common stock. Our stock price may decline as a result of future sales of our shares or the perception that such sales may occur.

We Could Be Subject To SEC Penalties If We Do Not File All Of Our SEC Reports. Although we are presently up to date in our filings, in the past we have not timely filed all of our annual and quarterly reports required to be filed by us with the SEC, in a timely manner. It is possible that the SEC could take enforcement action against us, including potentially the de-registration of our securities, if we fail to file our annual and quarterly reports in a timely manner as required by the SEC. If the SEC were to take any such actions, it could adversely affect the liquidity of trading in our common stock and the amount of information about our Company that is publicly available.

Broker-Dealers Are Not Permitted To Solicit Trades In Our Common Stock. Our common stock is considered to be a “penny stock” because it meets one or more of the definitions of “penny stock” in Rule 3a51-1 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The principal result or effect of being designated a “penny stock” is that securities broker-dealers cannot recommend the stock and may only trade in it on an unsolicited basis. The continued inability of brokers to recommend our stock could have a material adverse effect on our business, results of operations and financial condition.

Risks Related To Broker-Dealer Requirements Involving Penny Stocks / Risks Affecting Trading and Liquidity. Section 15(g) of the Exchange Act and Rule 15g-2 promulgated thereunder by the SEC require broker-dealers dealing in penny stocks to provide potential investors with a document disclosing the risks of penny stocks and to obtain a manually signed and dated written receipt of the document before effecting any transaction in a penny stock for the investor’s account. These rules may have the effect of reducing the level of trading activity in the secondary market, if and when one develops.

Potential investors in our common stock are urged to obtain and read such disclosure carefully before purchasing any shares that are deemed to be “penny stock.” Moreover, SEC Rule 15g-9 requires broker-dealers in penny stocks to approve the account of any investor for transactions in such stocks before selling any penny stock to that investor. This procedure requires the broker-dealer to (i) obtain from the investor information concerning his or her financial situation, investment experience and investment objectives; (ii) reasonably determine, based on that information, that transactions in penny stocks are suitable for the investor and that the investor has sufficient knowledge and experience as to be reasonably capable of evaluating the risks of penny stock transactions; (iii) provide the investor with a written statement setting forth the basis on which the broker-dealer made the determination in (ii) above; and (iv) receive a signed and dated copy of such statement from the investor, confirming that it accurately reflects the investor’s financial situation, investment experience and investment objectives. Pursuant to the Penny Stock Reform Act of 1990, broker-dealers are further obligated to provide customers with monthly account statements. Compliance with the foregoing requirements may make it more difficult for investors in our stock to resell their shares to third parties or to alternatively dispose of them in the market or otherwise.

None.

Office Leases

We lease and maintain office space in Edmonton, Alberta for corporate and administrative operations. This lease will expire on June 30, 2015.

Oil and Gas Properties

Acreage

Currently, we have a 90% working interest in 51 sections on six oil sands leases, a 100% working interest in five sections on one oil sands lease, and a 25% working interest in an additional 12 sections on two oil sands leases in the Peace River oil sands area of Alberta, all of these sections are contiguous. These nine oil sands leases cover 43,015 gross acres (17,408 gross hectares). Of the 68 contiguous sections on nine oil sands leases, one of our joint venture partners is the operator of 12 sections on two oil sands leases where we have a 25% working interest since the execution of the Farmout Agreement, and we are the operator on 56 sections on seven oil sands leases where we have working interests of either 90% or 100%.

For further information, see Oil and Gas Properties on our Balance Sheet and Note 3 and Note 4 in the notes to our consolidated financial statements contained herein.

The following table summarizes, by geographic area, our gross and net developed and undeveloped Peace River oil sands rights under lease as of September 30, 2014:

A developed acre is considered to mean those acres spaced or assignable to productive wells, a gross acre is an acre in which a working interest is owned, and a net acre is the result that is obtained when the fractional ownership working interest of a lease is multiplied by gross acres of that lease. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether or not that acreage contains proven reserves, but does not include undrilled acreage held by production under the terms of a lease. As is customary in the oil and gas industry, we can generally retain our interest in undeveloped acreage by engaging in drilling activity that establishes commercial production sufficient to maintain the leases, or by paying delay rentals during the remaining primary term of such a lease. The oil sands leases in which we have an interest are for a primary term of 15 years, and if we meet the Minimum Level of Evaluation (“MLE”) as set out by the government of Alberta oil sands tenure guidelines we can continue these leases beyond their primary term for an indefinite period.

The government of Alberta owns the land and we have acquired the rights to perform oil and gas activities on these lands. If we meet the conditions of the 15-year leases we will be permitted to drill on and produce oil from the land into perpetuity. These conditions give us until the expiration of the leases to meet the following requirements on our primary oil sands leases:

(i)       drill 68 wells throughout the 68 sections; or

(ii)     drill 44 wells within the 68 sections and acquire and process two miles of seismic on each other undrilled section.

We plan to meet the second of these conditions. As at December 31, 2014, we have an interest in ten wells, which can be counted toward these requirements. We have acquired and processed 25 miles of seismic on the leases, some which can be counted toward the MLE requirements. Our joint venture partner and operator of the SAGD Project has also acquired additional seismic that can be used towards our MLE requirements.

We have also identified two other wells drilled on these leases, which may be included in the satisfaction of the MLE requirements.

Our developed and undeveloped oil sands acreage as of December 31, 2014, covers 43,015 gross acres (34,096 net acres) on 68 sections of land under nine oil sands leases. Until we extend the leases “into perpetuity” based on the government of Alberta regulations, the lease expiration dates of our nine oil sands leases are as follows:

Delivery Commitments

We are not subject to any obligations under existing delivery commitment contracts or agreements calling for the provision of fixed and determinable quantities of oil and gas.

Disclosure of Reserves

Our oil reserves are attributable solely to properties within Alberta, Canada. The following table discloses, in the aggregate, the Company’s estimated reserves on the Company’s Sawn Lake oil sands properties located in the Peace River oil sands area of Alberta, Canada, as of September 30, 2014, based on estimated constant prices and cost assumptions. We reported no proved, probable or possible reserves based on Petroleum Resources Management System (“PRMS”) standards as at September 30, 2013.

⁽¹⁾Gross Reserves – are defined as the Company’s working interest reserves (operating or non-operating) before deduction of royalties.

⁽²⁾Net Reserves – are defined as the Company’s working interest reserves (operating or non-operating) after deduction of royalties.

Note: The numbers in this table may not add exactly due to rounding.

Under current SEC standards, “Proved Reserves” are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Under current SEC standards, the term “Reasonable Certainty” if deterministic methods are used, implies a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (“EUR”) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.

Under current SEC standards, “Reliable Technology” is a grouping of one or more technologies (including computational methods) that have been field tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, we employ in-situ technologies that have been demonstrated to yield results in the oil sands with consistency and repeatability. The technical data used in the estimation of our proved reserves include, but are not limited to, electrical logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves attributable to our producing wells which have limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and technical data to assess the reservoir continuity.

The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves and future cash flows are based on various assumptions and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

There are numerous uncertainties inherent in estimating quantities of proved reserves and estimates of reserves quantities and values must be viewed as being subject to significant change as more data about our properties becomes available.

Estimates of probable and possible reserves are inherently imprecise. When producing an estimate of the amount of oil that is recoverable from a particular reservoir, probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are even less certain and generally require only a 10% or greater probability of being recovered. All categories of reserves are continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. Estimates of probable and possible reserves are by their nature much more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk.

Third Party Reports

Our estimates of proved, probable and possible reserves were based on an independent third party report prepared and evaluated by DeGolyer and MacNaughton Canada Limited (“DeGolyer”) an independent qualified reserves evaluator. DeGolyer is an Alberta Corporation with offices in Calgary, Alberta. DeGolyer is a subsidiary of DeGolyer and MacNaughton which has been providing petroleum consulting services throughout the world since 1936. DeGolyer was engaged by our Company to evaluate our Company’s Sawn Lake oil sands properties located in Northern Alberta and prepare an independent assessment and evaluation of our Company’s reserves as at September 30, 2014. Included herein, as Exhibit 23.1, is a consent report from DeGolyer.

Preparation of Reserves Estimates and Reserves Evaluation

Our reserves data and estimates were prepared and evaluated by DeGolyer in compliance with SEC definitions and guidance and in accordance with generally accepted petroleum engineering principles. The technical persons employed by DeGolyer met the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Our reserves estimates are prepared by independent examination and evaluation of our production data, reservoir pressure data, logs, geological data, and offset analogies. DeGolyer is provided full access to complete and accurate information pertaining to our properties, and to all applicable personnel of our Company. DeGolyer’s independent evaluation of our reserves was supervised by Mr. Douglas S. Christie, Vice President of DeGolyer. Mr. Christie is a registered professional geologist in Alberta, Canada and has over 33 years of oil and gas industry experience and 22 years of application evaluation experience. Our Board recently appointed a reserves and resources committee consisting of four Board members. The reserves and resources committee members are Mr. Said Arrata, Mr. David Roff, Mr. Colin Outtrim and Mr. Curtis James Sparrow. Our reserves estimates and process for developing such estimates are reviewed by our current reserves and resources committee and approved by our management. Our management on behalf of our Board ensures compliance with SEC disclosure and internal control requirements along with verifying the independence of all third-party consultants. Our management is ultimately responsible for reserve estimates and reserve disclosures and ensuring that they are in accordance with the applicable regulatory requirements and industry standards and practices.

Estimates of oil and natural gas reserves are projections based on a process involving an independent third party engineering firm’s collection of all required geologic, geophysical, engineering and economic data, and such firm’s complete external preparation of all required estimates are forward-looking in nature. These reports rely upon various assumptions, including assumptions required by the SEC, such as constant oil and natural gas prices, operating expenses and future capital costs. The process also requires assumptions relating to availability of funds and timing of capital expenditures for development of our proven undeveloped reserves. These reports should not be construed as the current market value of our reserves. Because of the uncertainties inherent in the interpretation of this data, we cannot be certain that the reserves will ultimately be realized. Our actual results could differ materially.

Proved Undeveloped Reserves

Our independent reserves report, prepared by DeGolyer, estimates that we have 290 thousand barrels proved undeveloped reserves, before deduction of royalties as at September 30, 2014, on our Sawn Lake oil sands properties located in the Peace River oil sands area of Alberta, Canada. We have no material changes in our proved undeveloped reserves that occurred during the year to be reported, for the reason that this is the first time we have reported proved undeveloped reserves in any of our SEC filings.

The operator of the SAGD Project has indicated spending plans related to development of some of our proved undeveloped reserves over the next year, which includes the drilling of an additional SAGD well pair and potentially the expansion of our joint SAGD plant facility.

Reserves Reported to Other Agencies

The Company has filed a Statement of Reserves Data and Other Oil and Gas Information on Form 51-101F1 with the Alberta Securities Commission pursuant to National Instrument 51-101 – Standard of Disclosure for Oil and Gas Activities, which included estimates of total proved, probable and possible (developed and or undeveloped) net oil reserves prepared in accordance with the Canadian Oil and Gas Evaluation Handbook (“COGEH”).

Oil and Gas Production, Production Prices and Production Costs

On September 16, 2014, the first SAGD well pair started producing oil from our joint Sawn Lake oil sands properties. We received our first revenue late in September of 2014 from the sales of our produced oil. The following table discloses our Company’s share of production and average sales price for the last three fiscal years:

⁽¹⁾ First production began September 16, 2014.

⁽²⁾ Our Company’s working interest share before royalties.

⁽³⁾ Currently all of our operating costs from the SAGD Project are being paid by the Farmee under the terms of the Farmout Agreement

Productive Wells

The following table sets forth our gross and net productive oil wells as of September 30, 2014:

⁽¹⁾ SAGD producer well

Drilling and Other Exploratory and Development Activities

The following table summarizes the results of our drilling activities in the Peace River oil sands area of Alberta during the fiscal years ended September 30, 2014, 2013 and 2012.

⁽¹⁾ Our 25% working interest in one SAGD producer well.

⁽²⁾ Our 25% working interest in one SAGD steam injection well, one water source well and one disposal well.

Present Activities – Peace River Oil Sands, Alberta Canada (Sawn Lake Properties)

Currently we have no wells in the process of being drilled. However, we have nine wells on our Sawn Lake oil sands properties that we previously drilled and completed which are currently suspended.

On July 30, 2013, we entered into the SAGD Project Agreement. Our Company’s participation in the SAGD Project is well underway. For Phase 1 of the SAGD Project, one SAGD well pair was drilled in the fourth quarter of 2013 to a depth of 650 meters and a horizontal length of 780 meters. After the construction of the SAGD facility for steam generation, water handling and oil treating was completed in 2014, and steam injection commenced on May 21, 2014. The first oil production commenced on September 16, 2014. Results to date indicate that the SAGD production process is effective in this Bluesky formation reservoir. Oil sales averaged 221 barrels of oil per day, half way through the 3rd thirty day period since the start-up of production. Over the next several months the SAGD well pair is expected to have increased steam injection and oil production as the steam chamber develops. The objective of this initial SAGD well pair was to establish that SAGD technology is effective in producing oil from the Bluesky reservoir, and results to date support this. Production is anticipated to peak around September 2015 corresponding to the end of the first year of production.

On July 31, 2013, we entered into the Farmout Agreement. In accordance with the Farmout Agreement, the Farmee has agreed to provide up to $40,000,000 in funding for our portion of the costs for the SAGD Project, in return for a net 25% working interest in 12 sections where we had a working interest of 50% before the execution of the Farmout Agreement. The Farmee will also provide funding to cover monthly operating expenses of our Company, not to exceed $30,000 per month. In addition, and as recently amended, the Farmee has the option to elect, prior to December 31, 2015,by committing an additional $110,000,000 of financing to the development of our Company’s Sawn Lake oil sands properties, to obtain an additional working interest of 45% to 50% in the remaining 56 sections of land where we have working interests ranging from 90% to 100%. As required by the Farmout Agreement, as of December 15, 2014, the Farmee has currently paid Cdn$19,355,129 to the operator of the SAGD Project for the Farmee’s share and our share of the costs of the SAGD Project.

Currently, we have in place joint operating agreements (our “Joint Operating Agreements”) with our joint venture partners to manage the operations of our joint oil sands leases. Under these agreements our joint oil sands leases were evaluated seismically, geologically and by drilling to establish the continuity and the distribution of the crude bituminous-bearing Bluesky reservoir zone across our joint lands. The development progress of our properties is governed by several factors such as federal and provincial governmental regulations. Long lead times in getting regulatory approval for thermal recovery projects are commonplace in our industry. Road bans, winter access only roads and environmental regulations can and often do delay development of similar projects. Because of these and other factors, our oil sands project can take significantly longer to complete than regular conventional drilling programs for lighter oil. To date, our geological, engineering and economic studies lead us to believe that our working interest can support full profitable commercial production.

In August 2013, we received approval from the AER for our HCSS Project application. It is anticipated that we will develop a thermal demonstration project on our properties followed by a commercial expansion project on one half section of land located on section 10-92-13W5 of our Sawn Lake oil sands properties where we currently have a 90% working interest. This application, submitted in early 2012, was an application to modify our previously approved in-situ demonstration project for a well to test thermal production on our Sawn Lake oil sands leases. This modification changed the vertical CSS well earlier approved, into a thermal recovery project to test two wells that use a horizontal application of CSS. We are currently waiting on the production facility performance results from the SAGD Project in order to fine-tune our HCSS Project facility design before we initiate start-up operations on the ½ section of land where we plan to drill two horizontal wells to test the use of HCSS technology.

DISMISSED - I.G.M. Resources Corp. vs. Deep Well Oil & Gas, Inc., et al

On February 11, 2014, the Court dismissed, without any costs to the Company, the Plaintiff’s claims against Deep Well Oil & Gas, Inc. and its subsidiary Northern Alberta Oil Ltd.

Previously on March 10, 2005, I.G.M. Resources Corp. (the“Plaintiff”) filed against Classic, 979708 Alberta Ltd. (“979708”), Deep Well Oil & Gas, Inc., Nearshore, Steven P. Gawne, Rebekah Gawne, Gawne Family Trust, 1089144 Alberta Ltd., John F. Brown, Diane Lynn McClaflin, Cassandra Doreen Brown, Elissa Alexandra Brown, Brown Family Trust, Priority Exploration Ltd., Northern and Gordon Skulmoski (the “IGM Defendants”), a Statement of Claim in the Court of Queen’s Bench of Alberta Judicial District of Calgary. This suit was part of a series of lawsuits or actions undertaken by the Plaintiff against some of the other above-named IGM Defendants. The Plaintiff claimed the value of the assets sold was far in excess of the value paid for those assets. On April 23, 2004, Northern purchased some of Classic’s assets, including some of which are under dispute by the Plaintiff. On June 7, 2005, Deep Well acquired all of the common shares of Northern thereby giving Deep Well an indirect beneficial interest in the assets in which the Plaintiff had claimed an interest. The Plaintiff had sought an order setting aside the transaction between 979708, compensation in the amount of Cdn $15,000,000 and a declaration of trust declaring that Northern and Deep Well hold all of the assets acquired from 979708 and any property acquired by use of such assets or confidential information of 979708, in trust for the Plaintiff.

Not applicable.

PART II

Market Information

Deep Well’s stock is currently quoted on the OTCQB marketplace under the trading symbol DWOG. The following table sets forth the high and low sales prices for Deep Well common stock as reported on the OTCQB marketplace for the two most recent fiscal years indicated below. These over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, markdown or commission and may not necessarily represent actual transactions:

Holders of Record

As of October 31, 2014, we had approximately 164 holders of record of our shares of common stock. Our Company estimates that investment dealers and other nominees are the record holders for approximately 2,200 beneficial holders.

Dividends

We have not paid cash dividends since inception. We intend to retain all of our earnings, if any, for use in our business and do not anticipate paying any cash dividends in the foreseeable future. The payment of any future dividends will be at the discretion of the Board of Directors (our “Board”) and will depend upon a number of factors, including future earnings, the success of our business activities, capital requirements, the general financial condition and our future prospects, general business conditions and such other factors as our Board may deem relevant.

Return of Capital Distribution

On August 9, 2013, our Company approved a distribution to our shareholders in the amount of $0.07 per share of common stock to be payable on September 20, 2013 (the “Payment Date”) to the holders of record of all the issued and outstanding shares of common stock of the Company as of the close of business on August 16, 2013, (the “Record Date”). This cash distribution to our Company’s shareholders was not a dividend paid out of the earnings and profits, but was a non-dividend distribution characterized as a “return of capital”.

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information as of September 30, 2014 with respect to shares of Deep Well’s common stock that may be issued under our existing equity compensation plans.

⁽¹⁾ On March 23, 2011, our Board granted our directors, Dr. Horst A. Schmid, Mr. Said Arrata, Mr. Satya Das, Mr. David Roff, Mr. Curtis James Sparrow and Mr. Malik Youyou, options to purchase 450,000 shares each of common stock at an exercise price of $0.14 per share of common stock, with one-third vesting immediately, one-third vesting on March 23, 2012, and one-third vesting on March 23, 2013, each with a five-year life from the original grant date. On June 20, 2013, our Board granted our directors Dr. Horst A. Schmid, Mr. Said Arrata, Mr. Satya Das, Mr. David Roff, Mr. Curtis James Sparrow and Mr. Malik Youyou, options to purchase 450,000 shares each of common stock at an exercise price of $0.05 per share of common stock, with one-third vesting immediately, one-third vesting on June 20, 2014, and one-third vesting on June 20, 2015, each with a five-year life from the original grant date. And on June 20, 2013, our Board also granted two consultants, Portwest Investments Ltd. and Concorde Consulting, options to purchase 1,000,000 shares each of common stock at an exercise price of $0.05 per share of common stock, with one-half vesting immediately and one-half vesting on June 20, 2014, each with a five-year life from the original grant date. And on June 20, 2013, our Board also granted one employee of our Company, options to purchase 150,000 shares of common stock at an exercise price of $0.05 per share of common stock, with one-third vesting immediately, one-third vesting on June 20, 2014, and one-third vesting on June 20, 2015, with a five-year life from the original grant date. From August 12 to 15, 2013, six of our directors and one consultant exercised a total of 3,200,000 stock options. On October 28, 2013, the our Board granted a contractor an option to purchase 250,000 shares of common stock at an exercise price of $0.30 per share of common stock, all vesting immediately, with a five-year life, for his services in connection with the Farmout Agreement. On December 4, 2013, the Board appointed Mr. Pascal Nodé-Langlois to its Board and in connection with this appointment the Board granted Mr. Nodé-Langlois an option to purchase 450,000 shares each of common stock at an exercise price of $0.34 per share of common stock, 150,000 vesting immediately and the remaining vesting one-third on December 4, 2014, and one-third on December 4, 2015, with a five-year life. On September 19, 2014, the Board granted Dr. Horst A. Schmid, Mr. Said Arrata, Mr. Satya Das, Mr. Pascal Node-Langlois, Mr. David Roff, Mr. Curtis James Sparrow and Mr. Malik Youyou options to purchase 600,000 shares each of common stock at an exercise price of $0.38 per share of common stock, 200,000 vesting immediately and the remaining vesting one-third on September 19, 2015, and one-third on September 19, 2016, with a five-year life. On September 19, 2014, the Board granted two consultants, Portwest Investments Ltd. and Concorde Consulting, an option to purchase each 1,200,000 shares each of common stock at an exercise price of $0.38 per share of common stock, 600,000 vesting immediately and remaining vesting on September 19, 2015. On September 19, 2014, the Board granted one employee an option to purchase 180,000 shares each of common stock at an exercise price of $0.38 per share of common stock, 60,000 vesting immediately and the remaining vesting one-third on September 19, 2015, and one-third on September 19, 2016, with a five-year life.

⁽²⁾ Based on 229,326,987 issued and outstanding shares as at September 30, 2014. The maximum number of common shares that may be reserved for issuance under the Stock Option Plan (as defined below), as amended, may not exceed 10% of our Company’s issued and outstanding common shares.

Stock Option Plan

On November 28, 2005 and as amended on December 4, 2013, our Board adopted the Deep Well Oil & Gas, Inc. stock option plan (the “Stock Option Plan”). The Stock Option Plan was approved by a majority of our shareholders at the February 24, 2010 general meeting of shareholders. The Stock Option Plan, which is administered by our Board, permits options to acquire shares of Deep Well’s common stock to be granted to our directors, senior officers and employees of the Company and its subsidiaries, as well as certain consultants and other persons providing services to our Company. This Stock Option Plan was adopted to provide an incentive to the retention of our directors, officers and employees as well as consultants that we may wish to retain in the future. The maximum number of shares of common stock, which may be reserved for issuance under the Stock Option Plan may not exceed 10% of our issued and outstanding common stock, subject to adjustment as contemplated by the Stock Option Plan. For further information see Note 12 in the notes to our consolidated financial statements contained herein.

On November 17, 2014, our Board appointed Mr. Colin P. Outtrim to serve on our Board and in connection with Mr. Outtrim’s appointment our Board granted Mr. Outtrim an option to purchase 600,000 shares each of common stock at an exercise price of $0.23 per common share, 200,000 vesting immediately and the remaining vesting one-third on November 17, 2015, and one-third on November 17, 2016, with a five-year life.

Performance Graph

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and therefore are not required to provide the information required under this item.

Recent Sales of Unregistered Securities

Effective November 23, 2012, pursuant to a subscription agreement, our Company completed a private placement with Mr. Malik Youyou of an aggregate of 42,857,142 units at a price of $0.07 per unit, for total gross proceeds of $3,000,000. Each unit is comprised of one share of common stock and one common share purchase warrant. Each warrant entitles the holder to purchase one share of common stock at a price of $0.105 for a period of three years from the date of closing, provided that if the closing price of the common shares of our Company on the principal market on which our common shares trade is equal to or exceeds $1.00 for thirty consecutive trading days, the warrant term will automatically accelerate to the date that is thirty calendar days following the date that written notice has been given to the warrant holder. No commission or finder’s fees were payable in connection with this private placement. The units were issued pursuant to Regulation S (“Regulation S”) under the Securities Act of 1933, as amended (the “Securities Act”). The warrants will expire on November 23, 2015 unless expiration is automatically accelerated.

On July 10, 2013, pursuant to a subscription agreement, our Company closed a private placement with Portwest Investments Ltd. (“Portwest”) a company 100% owned by Dr. Horst A. Schmid, of an aggregate of 850,000 units at a price of $0.05 per unit, for total gross proceeds of $42,500. Each unit is comprised of one share of common stock and one common share purchase warrant. Each warrant entitles the holder to purchase one share of common stock at a price of $0.075 for a period of three years from the closing date, provided that if the closing price of the common stock of our Company on the principal market on which our shares trade is equal to or exceeds $1.00 for thirty consecutive trading days, the warrant term shall automatically accelerate to the date which is thirty calendar days following the date that written notice has been given to the warrant holder. No commission or finder’s fees were payable in connection with this private placement. The units were issued pursuant to Regulation S. The warrants will expire on July 10, 2018 unless expiration is automatically accelerated.

On July 31, 2013, pursuant to a subscription agreement, our Company closed a private placement to one investor, our current Farmee, of an aggregate of 45,111,778 shares of common stock for total gross proceeds of $22,000,000. As per the private placement documents, the common stock were to be issued to the investor after September 20, 2013 but before November 30, 2013. And on October 16, 2014, we issued out of treasury 45,111,778 shares of our common stock to the Farmee. No commission or finder’s fees were payable in connection with this private placement. The shares of common stock were issued pursuant to Regulation S.

Between August 12 and August 15, 2013, six directors and two consultants of our Company acquired a combined total of 3,768,096 common shares of our common stock, upon exercising stock options and warrants, at exercise prices ranging from $0.05 to $0.14 per common share for total combined gross proceeds to our Company of $372,000. The shares of common stock were issued pursuant to Section 4(2) of the Securities Act.

On October 3, 2014, a warrant holder of our Company acquired 47,618 common shares of our Company, upon exercising warrants, at an exercise price of $0.105 per share of common stock for gross proceeds to our Company of $4,999.90.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

There were no repurchases of equity securities by our Company or affiliated purchasers during the fourth quarter of the fiscal year ended September 30, 2014.

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and therefore are not required to provide the information required under this item.

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes. This discussion includes forward-looking statements that reflect our current views with respect to future events and financial performance that involve risks and uncertainties. Our actual results, performance or achievements could differ materially from those anticipated in the forward-looking statements as a result of certain factors including risks discussed in “Cautionary Note Regarding – Forward-Looking Statements” below and elsewhere in this report, and under the heading “Risk Factors” and “Environmental Laws and Regulations” disclosed in this Annual Report.

Our consolidated financial statements and information are reported in US dollars and are prepared based upon US generally accepted accounting principles (“US GAAP”). On January 6, 2015, the noon rate of exchange for Canadian dollars expressed in US$ was Cdn$1.00 = US$0.8472 as reported by the Bank of Canada.

General Overview

Deep Well Oil & Gas, Inc., along with its subsidiaries through which it conducts business, is an emerging independent junior oil and gas exploration and development company headquartered in Edmonton, Alberta, Canada. Our immediate corporate focus is to develop the existing land base that we presently control in the Peace River oil sands area in Alberta, Canada. Our principal office is located at Suite 700, 10150 - 100 Street NW, Edmonton, Alberta, Canada T5J 0P6, our telephone number is (780) 409-8144, and our fax number is (780) 409-8146. Deep Well Oil & Gas, Inc. is a Nevada corporation and trades on the OTCQB marketplace under the symbol DWOG. We maintain a web site at www.deepwelloil.com. The OTCQB marketplace requires companies to be fully compliant in their filing requirements under the Exchange Act.

Results of Operations

Since the inception of our current business plan, our operations have consisted of various exploration and start-up activities relating to our properties, which included acquiring lease holdings by acquisitions and public offerings, seeking investors, locating joint venture partners, acquiring and analyzing seismic data, environmental regulations, as well as providing project management, drilling, testing and analysis of wells to define our oil sands reservoir, and development planning of our AER approved thermal recovery projects, including the recent start-up of the SAGD Project which began producing oil on September 16, 2014. The following table sets forth certain financial information along with our first revenue with respect to our operations:

Our Company reported its first oil revenue in the amount of $47,116 after deduction of royalties. Given that our first oil production began close to our year end on September 16, 2014, we produced oil for only 14 days during the year ending September 30, 2014, therefore the volumes of oil delivered were only 818.6 barrels net to us, before royalties, for an average oil price of $61.77 per barrel. Transportation costs are included in operating expenses which are covered by our Farmout Agreement. Our total share of the material costs and operating expenses of the SAGD Project, as disclosed below, has been funded in accordance with the Farmout Agreement, at a net cost to us of $Nil. As required by the Farmout Agreement, as disclosed below, the Farmee during our September 20, 2014 fiscal year paid Cdn$16,677,530 to the operator of the SAGD Project for the Farmee’s share and our share of the costs of the SAGD Project up to September 30, 2014. These costs included the drilling of the SAGD well pair; the purchase and transportation of equipment; installation and construction of the steam plant facility; testing and commissioning; the purchase of the water source and disposal wells and expenditures to connect these water wells to the steam plant facility along with a fuel source tie-in; and the monthly operating expenses associated with the steaming and production of the SAGD well pair up to September 30, 2014. The total SAGD Project capital costs for Phase 1 plus additions have been estimated by the operator to be Cdn$32.6 million.

For the year ended September 30, 2014, our general and administrative expenses increased by $1,116,466 compared to the year ended September 30, 2013, which was a 130.7% increase from the prior year primarily due to (i) an increase of $962,257 in non-cash share-based compensation charged to expenses, which was due to vested stock options we granted on October 28, 2013, December 4, 2013 and September 19, 2014 to contractors and directors; (ii) an increase of foreign exchange loss of $274,624, due to the currency depreciation of the Canadian dollar conversion to U.S. dollars; and (iii) an increase in engineering fees for the preparation of a mandatory independent reserves evaluation of our Sawn Lake properties.

We also received $360,000 during the current fiscal year from the Farmee in accordance with a Farmout Agreement to offset some of our monthly operational expenses. After adjusting for the non-cash items and operational expenses reimbursed in accordance with the Farmout Agreement, our general and administrative expenses were $675,498 for the year ended September 30, 2014 compared to $795,913 for the year ended September 30, 2013.

For the year ended September 30, 2013, we charged to expense $1,790,684 for costs relating to the Farmout Agreement, which included a one-time agency fee of $1,500,000.

For the year ended September 30, 2014, our depreciation and accretion expense decreased by $11,582 compared to the year ended September 30, 2013, which was primarily due to the depreciating value of our assets. Depreciation expense is computed using the declining balance method over the estimated useful life of the asset. Effective December 3, 2012, we entered into and closed upon a Purchase and Sale agreement with 1132559 Alberta Ltd. (“113”), one of our former joint venture partners, pursuant to which we acquired 113’s 10% working interest in most of the Sawn Lake oil sands properties where we already own working interests, in exchange for cash and the discontinuance of claims. In compliance with our accounting policy, only half of the depreciation is taken in the year of acquisition.

For the year ended September 30, 2014, our rental and other income was $19,675 compared to $272,339 for the year ended September 30, 2013, this decreased by $252,664 compared to the year ended September 30, 2013, was primarily due to the recovery of expenses in fiscal 2013, arising from the reversal of part of the receivables and bad debts previously written-off in the amount of $239,459 which was paid to us in connection with a Purchase and Sale agreement, whereby our Company acquired an additional 10% working interest in most of the Sawn Lake oil sands properties where our Company already owns working interests.

As a result of the above transactions, our net loss and comprehensive loss from operations for the year ended September 30, 2014 decreased by $423,143 compared to the year ended September 30, 2012. As discussed above this increase was primarily due to $1,790,684 charged to expense for costs in connection with the Farmout Agreement and offset by the reversal of part of the receivables and bad debts previously written-off.

Operations

As previously disclosed by us, on July 31, 2013 we entered into the Farmout Agreement with our new joint venture partner (the “Farmee”), to fund our share of the SAGD Project. The SAGD Project is located on our Sawn Lake properties in the Peace River oil sands region of Alberta. In accordance with the Farmout Agreement, the Farmee has agreed to provide up to $40,000,000 in funding for our portion of the costs for the SAGD Project, in return for a net 25% working interest in 12 sections where we had a working interest of 50% before the execution of the Farmout Agreement. Also, the Farmee is required to provide funding to cover our monthly operating expenses not to exceed $30,000 per month. In addition, as amended on November 17, 2014, the Farmee has the option to elect to obtain additional working interests ranging from 45% to 50% in the remaining 56 sections of land where we have working interests ranging from 90% to 100%, by committing an additional $110,000,000 of financing for the development of our Sawn Lake oil sands properties.

SAGD Steam Plant Facility May 2014 – Startup of first steam.

Installation of the water treatment plant at our joint SAGD Project.

Since entering into the Farmout Agreement and the SAGD Project Agreement with our joint venture partners we can report that the first oil production commenced on September 16, 2014 from the first SAGD well pair. The SAGD well pair was drilled to a vertical depth of approximately 650 meters with a horizontal length of 780 meters each. Steam injection began in May of 2014 and circulated for up to four months with production commencing in mid-September 2014 from the Bluesky oil sands reservoir. The operator along with its joint venture partners will evaluate the production levels and steam to oil ratios over the next few months to determine and verify the use of SAGD technology in the Bluesky reservoir. After the production facility performance evaluation period, the operator of the SAGD Project is expecting to proceed with Phase 2, which includes work on preliminary engineering design, regulatory approval, environmental approval work, determining regulatory requirements sufficient to define the work program, and the drilling of an additional SAGD well pair and the associated expansion of the current SAGD plant facility.

Results to date indicate that the use of SAGD technology is successful in producing oil in the bitumen form from the Bluesky formation reservoir. Oil sales averaged 221 barrels of oil per day, half way through the 3rd thirty day period since the start-up of production. Over the next several months the SAGD well pair is expected to have increased steam injection and oil production as the steam chamber develops. The objective of this initial SAGD well pair was to establish that SAGD technology works in the Bluesky formation reservoir, and results to date support this. We are now focused on achieving commercial rates. We expect to achieve these results about March 2015 when reservoir modelling indicates that the steam chamber will have reached the top of the Bluesky formation sandstone reservoir. Peak production is anticipated to occur in the fourth quarter corresponding to the end of our first fiscal year of production.

On March 18, 2014 and June 27, 2014, through our subsidiary company, Northern, we entered into and subsequently closed two Acquisition of Royalty Interest Agreements and General Indenture of Conveyance, Assignment and Transfer Agreements (collectively “the Agreements”), with one of our joint venture partners (“JV Partner”) and one related party (Mr. Malik Youyou), whereby we acquired and cancelled 5.5% of the disputed 6.5% overriding royalty claim (the “Purported 6.5% Royalty”) on certain lands owned by us. Our counsel and the vendor’s counsel negotiated the terms and conditions of Agreements. Pursuant to the terms and conditions of the Agreements to acquire the purported overriding royalty interest claims, we paid the following consideration:

Although we continue to deny the validity of the Purported 6.5% Royalty, we determined that it was in the best interests of our shareholders to come to an arrangement to acquire and cancel most of the Purported 6.5% Royalty to prevent a potential encumbrance over our land or the possibility of future litigation resulting from these alleged royalty claims.

In August 2013, we received approval from the AER for our HCSS Project application. It is anticipated that we will develop a thermal demonstration project on our properties followed by a commercial expansion project on one half section of land located on section 10-92-13W5 of our Sawn Lake oil sands properties where we currently have a 90% working interest. This application, submitted in early 2012, was an application to modify our previously approved in-situ demonstration project for a well to test thermal production on our Sawn Lake oil sands leases. This modification changed the vertical CSS well earlier approved, into a thermal recovery project to test two wells that use a horizontal application of CSS. We are currently waiting on the production facility performance results from the SAGD Project in order to fine-tune our HCSS project facility design, before we initiate start-up operations on the ½ section of land where we plan to drill two horizontal wells to test the use of HCSS technology.

Currently we have a 90% working interest in 51 sections on six oil sands leases and a 100% working interest in five sections on one oil sands lease in the Peace River oil sands area of Alberta, where we are the operator. In addition, we have a 25% working interest in another 12 sections on two oil sands leases in the Peace River oil sands area of Alberta. These nine oil sands leases are contiguous and cover 43,015 gross acres (17,408 gross hectares). The development progress of our properties is governed by several factors such as federal and provincial governmental regulations. Long lead times in getting regulatory approval for thermal recovery projects are commonplace in our industry. Road bans, winter access only roads and environmental regulations can and often do delay development of similar projects. Because of these and other factors, our oil sands project can take significantly longer to complete than regular conventional drilling programs for lighter oil. To date; our geological, engineering and economic studies affirm that our working interest can support full profitable commercial production.

Liquidity and Capital Resources

As of September 30, 2014, our total assets were $23,691,595 compared to $24,366,368 as of September 30, 2013. In comparison to the prior year, we had a decrease of $674,773 in our total assets, which was primarily due to (i) an increase in general and administrative expenses due to an increase in engineering fees; (ii) $250,000 paid for legal costs related to the Farmout Agreement; and (iii) $189,500 paid to one of our directors for an outstanding loan payable.

As of September 30, 2014, our total liabilities were $1,200,188 compared to $922,057 as of September 30, 2013. In comparison to the prior year, we had an increase of $278,131 in our total liabilities. This increase was the result of $692,124 ($772,288 Cdn) owed to the operator of the SAGD Project for our share of the cost overruns, operating expenses, including the Phase 2 front end costs for the SAGD Project, of which costs were subsequently paid by the Farmee after September 30, 2014, in accordance with the Farmout Agreement, and offset by (i) the payout of a $189,500 loan payable owed to one of our directors; and (ii) $250,000 paid for legal costs related to the Farmout Agreement.

Our working capital (current liabilities subtracted from current assets) is as follows.

As of September 30, 2014, our Company had working capital of $2,687,554 compared to our working capital of $7,295,023 as of September 30, 2013. This decrease was primarily the result of the purchase and cancellation of 5.5% of the disputeda Purported 6.5% Royalty on certain lands owned by us, as further described below in our “Investing Activities”. Currently we have no long-term debt other than our estimated asset retirement obligations on oil and gas properties. Effective November 23, 2012, we completed a private placement financing with one investor for aggregate gross cash proceeds of $3,000,000. Also, on July 31, 2013, we completed another private placement financing with one investor for aggregate gross cash proceeds of $22,000,000. Also as disclosed above, on July 30, 2013 our Company entered into the Farmout Agreement to fund our Company’s share of the SAGD Project.

As reported on our Consolidated Statement of Cash Flows under “Operating Activities”, for the year ending September 30, 2014, we had a decrease of $1,007,570 compared to September 30, 2013 year end, which was primarily due to a decrease of a one-time agency fee in the amount of $1,500,000 that was paid out in our 2013 fiscal year end, that was related to the Farmout Agreement and offset by an increase of $381,280 in non-cash working capital. As of December 31, 2012, we reversed part of the receivables and bad debts for one former joint venture partner in the amount of $267,962, which was related to a purchase agreement whereby we acquired an additional 10% working interest in most of the Sawn Lake oil sands properties where we already own working interests.

As reported on our Consolidated Statement of Cash Flows under “Investing Activities”, we had an increase of $1,148,707 in cash flows from investing activities for the year ended September 30, 2014 compared to the year ended September 30, 2013. As previously described under “Operations” above, we acquired and cancelled 5.5% of the Purported 6.5% Royalty from two separate parties for a total cost of $3,442,124. We also had an increase in our Company’s security deposits held in trust with the AER for our asset retirement obligations for future abandonment and reclamation of our Company’s well sites. In December 2012 we closed a purchase and sale agreement with a former joint venture partner, whereby we acquired an additional 10% working interest in our joint properties along with a 10% working interest increase in the equipment purchased for the wells drilled within those joint properties, in exchange for $2,412,960 cash and the discontinuance of legal actions against our former joint venture partner to collect amounts owed to us for past operations conducted on our joint properties.

As reported on our Consolidated Statement of Cash Flows under “Financing Activities”, for the year ended September 30, 2014, we had a decrease of $12,555,936 in net cash provided in financing activities. This decrease of net cash used in Financing Activities was primarily due to us completing (i) a private placement with one investor in November 2012 for total gross proceeds of $3,000,000; (ii) a private placement with one investor in July 2013 for total gross proceeds of $22,000,000; and (iii) a return of capital paid out to our shareholders in September of 2013 in the amount of $12,895,065. In October 2013, we paid $189,500 for the remaining outstanding loan payable owed to one of our directors.

Our cash and cash equivalents for the year ending September 30, 2014 were $2,324,755 compared to $7,633,009 for the prior year ended September 30, 2013, this decrease in cash and cash equivalents was primarily due to the acquisition of 5.5% of the Purported 6.5% Royalty from two separate parties at a total cost of $3,442,124; and (ii) a Cdn$1,200,000 cash call that we paid to the Operator of the SAGD Project for the winterization program in September 2014, which we subsequently collected from our Farmout partner in October 2014.

For our long-term operations, we anticipate that, among other alternatives, we may raise funds during the next twenty-four months through sales of our equity securities. We also note that if we issue more shares of our common stock, our stockholders will experience dilution in the percentage of their ownership of common stock. We may not be able to raise sufficient funding from stock sales for long-term operations and if so, we may be forced to delay our business plans until adequate funding is obtained.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Cautionary Note Regarding Forward-Looking Statements

This Annual Report, including all referenced Exhibits, contains “forward-looking statements” within the meaning of the US federal securities laws. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, projected costs and plans and objectives of management for future operations, are forward-looking statements. The words “may,” “believe,” “intend,” “will,” “anticipate,” “expect,” “estimate,” “project,” “future,” “plan,” “strategy,” “probable,” “possible,” or “continue,” and other expressions that are predictions of or indicate future events and trends and that do not relate to historical matters, often identify forward-looking statements. For these statements, Deep Well claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. The forward-looking statements in this Annual Report include, among others, statements with respect to:

These forward-looking statements are based on the beliefs and expectations of our management and are subject to significant risks and uncertainties. If underlying assumptions prove inaccurate or unknown risks or uncertainties materialize, actual results may differ materially from current expectations and projections. Factors that could cause actual results to differ materially from those set forward in the forward-looking statements include, but are not limited to:

The preceding bullets outline some of the risks and uncertainties that may affect our forward-looking statements. For a full description of risks and uncertainties, see the sections elsewhere in this Annual entitled “Risk Factors” and “Environmental Laws and Regulations”. 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. Any forward-looking statement speaks only as of the date on which it was made and, except as required by law, we disclaim any obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise. However, any further disclosures made on related subjects in subsequent reports on Forms 10-K, 10-Q, 8-K and any other SEC filing or amendments thereto should be consulted.

We are a smaller reporting company as defined by Rule 12b-2 under the Exchange Act and therefore are not required to provide the information required under this item.

SADLER, GIBB & ASSOCIATES, LLC

Certified Public Accountants

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Deep Well Oil and Gas, Inc.

We have audited the accompanying consolidated balance sheets of Deep Well Oil & Gas, Inc. (“the Company”) as of September 30, 2014 and 2013, and the related consolidated statements of operations, shareholders’ equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.  

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 audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits 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 Company’s 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 audits provide a reasonable basis for our opinion.

In our opinion the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Deep Well Oil & Gas, Inc. as of September 30, 2014 and 2013, and the results of its operations and cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

/s/ Sadler, Gibb & Associates, LLC

Sadler, Gibb & Associates, LLC

Salt Lake City, UT

January 13, 2015

www.sadlergibb.com 2455 E. Parleys Way Suite 320, Salt Lake City, UT 84109

DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)

Consolidated Balance Sheets

September 30, 2014 and September 30, 2013

See accompanying notes to the consolidated financial statements

DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)

Consolidated Statements of Operations and Comprehensive Income (Loss)

For the Years Ended September 30, 2014 and 2013

See accompanying notes to the consolidated financial statements

DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)

Consolidated Statements of Shareholders’ Equity

For the Period from September 30, 2012 to September 30, 2014

See accompanying notes to the consolidated financial statements

DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)

Consolidated Statements of Cash Flows

For the Years Ended September 30, 2014 and 2013

See accompanying notes to the consolidated financial statements

DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)

Notes to the Consolidated Financial Statements

September 30, 2014 and 2013

Nature of Business

Deep Well Oil & Gas, Inc. was originally incorporated on July 18, 1988 under the laws of the state of Nevada as Worldwide Stock Transfer, Inc. (Worldwide Stock Transfer, Inc. later changed its name to Allied Devices Corporation) and in connection with a plan of reorganization, effective on September 10, 2003, the company was reorganized and changed its name to Deep Well Oil & Gas, Inc. (“Deep Well”).

Deep Well together with its subsidiaries, Northern Alberta Oil Ltd. and Deep Well Oil & Gas (Alberta) Ltd, (collectively referred to as the “Company”) is an independent junior oil sands exploration and development company with an existing oil sands land base in the Peace River oil sands area in Alberta, Canada.

These consolidated financial statements have been prepared showing the name “Deep Well Oil & Gas, Inc. (and Subsidiaries)” (“the Company”) and the post-split common stock, with $0.001 par value.

Basis of Presentation

These consolidated financial statements are expressed in U.S. dollars and are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”).

These statements reflect all adjustments, consisting solely of normal recurring adjustments (unless otherwise disclosed) which, in the opinion of management, are necessary for a fair presentation of the information contained herein.

Basis of Consolidation

These consolidated financial statements include the accounts of two wholly owned subsidiaries: (1) Northern Alberta Oil Ltd. ("Northern") from the date of acquisition, being June 7, 2005, incorporated under the Business Corporations Act (Alberta), Canada; and (2) Deep Well Oil & Gas (Alberta) Ltd., incorporated under the Business Corporations Act (Alberta), Canada on September 15, 2005. All inter-company balances and transactions have been eliminated.

Cash and Cash Equivalents

The Company considers all highly liquid instruments with a maturity of three months or less at the time of issuance to be cash equivalents.

Accounts Receivable, Net

As of September 30, 2014, accounts receivable included a prepayment of $1,200,000 Cdn that the Company subsequently collected from Farmout partner on October 21, 2014.

Allowance for Doubtful Accounts

The Company determines allowances for doubtful accounts based on aging of specific accounts. Accounts receivable are stated at the historical carrying amounts net of allowances for doubtful accounts and include only the amounts the Company deems to be collectable. The allowance for bad debts was $nil and $17,048 at September 30, 2014 and September 30, 2013 respectively.

Crude oil and natural gas properties

The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance, repairs and costs of injection are expensed as incurred, except that the costs of replacements or renewals that expand capacity or improve production are capitalized.

Under the successful efforts method of accounting, the Company capitalizes exploratory drilling, equipping and facility costs on the balance sheet pending determination of whether the project has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are assigned to a project, the associated capitalized costs become part of well equipment and facilities. However, if proved reserves are not found in a project, the capitalized costs associated with the project are expensed, net of any salvage value. Total capitalized costs pending the determination of proved reserves were $19.6 million and $15.9 million as of September 30, 2014 and 2013, respectively.

Property and Equipment

Property and equipment are stated at cost less accumulated depreciation. Depreciation expense is computed using the declining balance method over the estimated useful life of the asset. Only half of the depreciation rate is taken in the year of acquisition. The following is a summary of the depreciation rates used in computing depreciation expense:

Expenditures for major repairs and renewals that extend the useful life of the asset are capitalized. Minor repair expenditures are charged to expense as incurred. Leasehold improvements are amortized over the greater of five years or the remaining life of the lease agreement.

Long-Lived Assets

Oil and Gas Properties - Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter, or when events and circumstances indicate a possible decline in the recoverability of the carrying value of such field. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. The discounted cash flow method estimates future cash flows based on management’s estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips, operating and development costs, and a risk-adjusted discount rate.

Non-producing crude oil and natural gas properties primarily consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Individually significant non-producing properties, if any, are assessed for impairment on a property-by-property basis and, if the assessment indicates an impairment, a loss is recognized by providing a valuation allowance consistent with the level at which impairment was assessed. For individually insignificant non-producing properties, impairment losses are recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on experience of successful drilling and the average holding period. The Company’s impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management.

Non Oil and Gas Assets - The Company reviews for the impairment of long-lived assets annually and whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss would be recognized when estimated undiscounted future cash flows expected to result from the use of the asset and its eventual disposition is less than its carrying amount. Impairment is measured as the amount by which the assets’ carrying value exceeds its fair value. No impairments to the Company’s long-lived assets were identified or recorded in the fiscal years ended September 30, 2014 and 2013.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed crude oil and natural gas reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least in conjunction with annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.

Asset Retirement Obligations

The Company accounts for asset retirement obligations by recording the fair value of the estimated future cost of the Company’s plugging and abandonment obligations. The asset retirement obligation is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the fair value of the liability can be reasonably estimated. Upon initial recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value through charges to oil and gas production and well operations costs. The initial capitalized costs are depleted over the useful lives of the related assets through charges to depreciation, depletion, and amortization. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost.

Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs, and changes in the estimated timing of settling asset retirement obligations. As at September 30, 2014 and 2013, asset retirement obligations amount to $469,013 and $446,155, respectively. The Company has posted bonds, where required, with the Government of Alberta based on the amount the government estimates the costs of abandonment and reclamation to be.

Foreign Currency Translation

The functional currency of the Canadian subsidiaries is the United States dollar. However, the Canadian subsidiaries transact in Canadian dollars. Consequently, monetary assets and liabilities are remeasured into United States dollars at the exchange rate on the balance sheet date and non-monetary items are remeasured at the rate of exchange in effect when the assets are acquired or obligations incurred. Revenues and expenses are remeasured at the average exchange rate prevailing during the year. Foreign currency transaction gains and losses are included in results of operations.

Accounting Methods

The Company recognizes income and expenses based on the accrual method of accounting.

Dividend Policy

The Company has not yet adopted a policy regarding payment of dividends.

Financial, Concentration and Credit Risk

The Company does not have any concentration or related financial credit risk related to cash as most of the Company’s funds are maintained in a financial institution which has its deposits fully guaranteed by the Government of Alberta.

The Company is not directly subject to credit risk resulting from the concentration of its crude oil sales. For the year ended September 30, 2014, the Company has recorded oil sales received from the operator of the Company’s producing properties. The Company’s joint venture partner is the operator of the Company’s producing properties and it is the Company’s joint venture partner who sells 100% of the Company’s oil production to two or more purchasers in the oil and gas industry. The Company does not require collateral and management periodically evaluates the operator’s financial statements and the collectability of oil sales receivables from the operator and believes that the Company’s oil sales receivables are fully collectable and that the risk of loss is minimal.

Income Taxes

The Company utilizes the liability method of accounting for income taxes. Under the liability method, deferred tax assets and liabilities are determined based on the differences between financial reporting and the tax bases of the assets and liabilities, and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. An allowance against deferred tax assets is recorded when it is more likely than not that such tax benefits will not be realized.

Due to the uncertainty regarding the Company’s profitability, a valuation allowance has been recorded against the future tax benefits of its losses and no net benefit has been recorded in the consolidated financial statements.

Revenue Recognition

The Company is in the business of exploring for, developing, producing, and selling crude oil and natural gas. Crude oil revenue is recognized when the product is taken from the storage tanks on the lease and delivered to the purchaser and title transfers to the purchaser. Payment is generally received one to three months after the sale has occurred.

Occasionally the Company may sell specific leases, and the gain or loss associated with these transactions will be shown separately from the profit or loss from the operations or sales of oil and gas products. Such gain or losses will be measured and recognized when all of the following have occurred: (1) there is persuasive evidence of an arrangement to sell; (2) the price of the sale is fixed or determinable; (3) the title to the lease has transferred; and (4) collection is reasonably assured.

Advertising and Market Development

The Company expenses advertising and market development costs as incurred.

Basic and Diluted Net Income (Loss) Per Share

Basic net income (loss) per share amounts are computed based on the weighted average number of shares actually outstanding. Diluted net income (loss) per share amounts are computed using the weighted average number of common shares and common equivalent shares outstanding as if shares had been issued on the exercise of the common share rights, unless the exercise becomes anti-dilutive and then the basic and diluted per share amounts are the same. There were 51,340,385 common stock equivalents excluded from the calculation because their effect would be antidilutive.

Financial Instruments

Financial instruments include cash and cash equivalents, accounts receivable, long term investments, investment in equity securities, accounts payable and accounts payable – related parties. The fair value of these financial instruments approximates their carrying value because of the short-term maturity of these items unless otherwise noted. The fair value of the investment in equity securities cannot be determined as the market value is not readily obtainable. The equity securities are reported using the cost method.

Environmental Requirements

At the report date, environmental requirements related to the oil and gas properties acquired are unknown and therefore an estimate of any future cost cannot be made.

Share-Based Compensation

The Company accounts for stock options granted to directors, officers, employees and non-employees using the fair value method of accounting. The fair value of stock options for directors, officers and employees are calculated at the date of grant and is expensed over the vesting period of the options on a straight-line basis. For non-employees, the fair value of the options is measured on the earlier of the date at which the counterparty performance is complete or the date at which the performance commitment is reached. The Company uses the Black-Scholes model to calculate the fair value of stock options issued, which requires certain assumptions to be made at the time the options are awarded, including the expected life of the option, the expected number of granted options that will vest and the expected future volatility of the stock. The Company reflects estimates of award forfeitures at the time of grant and revises in subsequent periods, if necessary, when forfeiture rates are expected to change.

Recently Adopted Accounting Standards

In June 2014, the FASB issued ASU 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”. The guidance eliminates the definition of a development stage entity thereby removing the incremental financial reporting requirements from U.S. GAAP for development or exploration stage entities, primarily presentation of inception to date financial information. The provisions of the amendments are effective for annual reporting periods beginning after December 15, 2014, and the interim periods therein. However, early adoption is permitted. Accordingly, the Company has adopted this standard as of September 30, 2014.

The Company does not expect the adoption of any other recent accounting pronouncements to have a material impact on its financial statements.

Estimates and Assumptions

Management uses estimates and assumptions in preparing financial statements in accordance with generally accepted accounting principles. Those estimates and assumptions affect the reported amounts of the assets and liabilities, the disclosure of contingent assets and liabilities, and the reported revenues and expenses. Actual results could vary from the estimates that were used in preparing these consolidated financial statements.

Significant estimates by management include valuations of oil and gas properties, valuation of accounts receivable, useful lives of long-lived assets, asset retirement obligations, valuation of share-based compensation, and the realizability of future income taxes.

The Company’s undeveloped oil sands acreage as of September 30, 2014, covers 43,015 gross acres (34,096 net acres) on 68 sections of land under nine oil sands leases. However, the Company announced in late September of 2014 that the operator confirmed production from the joint SAGD Project on some of the Company’s acreage. Until such time that the SAGD Project lands are classified as developed the Company will classify all of its oil sands acreage as undeveloped as of September 30, 2014. Until the Company extends the leases “into perpetuity” based on the Alberta governmental regulations, the lease expiration dates of the Company’s nine oil sands leases are as follows:

Effective September 25, 2014, the Company, through its subsidiary Deep Well Alberta, entered into a Purchase and Sale agreement with Classic Energy Inc. (“Classic”), pursuant to which the Company acquired Classic’s 20% working interest in five sections in one Sawn Lake oil sands lease where the Company already owned working interests. As of September 25, 2014, the Company increased its net acres in the Sawn Lake oil sands properties from 33,463 to 34,096 net acres.

Lease Rental Commitments

The Company has acquired interests in certain oil sands properties located in North Central Alberta, Canada. The terms include certain commitments related to oil sands properties that require the payments of rents as long as the leases are non-producing. As of September 30, 2014, the Company’s net payments due under this commitment are as follows:

The Government of Alberta owns this land and the Company has acquired the rights to perform oil and gas activities on these lands. If the Company meets the conditions of the 15-year leases the Company will then be permitted to drill on and produce oil from the land into perpetuity. These conditions give the Company until the expiration of the leases to meet the following requirements on its primary oil sands leases:

The Company plans to meet the second of these conditions. As at September 30, 2014 and 2013, the Company has an interest in ten wells, which can be counted towards these requirements.

The Company has identified two other wells drilled on these leases, which may be included in the satisfaction of this requirement. The Company has also acquired and processed 25 miles of seismic on the leases, which can be counted towards these requirements.

The Company follows the successful efforts method of accounting for costs of oil and gas properties. Under this method, only those exploration and development costs that relate directly to specific oil and gas reserves are capitalized; costs that do not relate directly to specific reserves are charged to expense. Producing, non-producing and unproven properties are assessed annually, or more frequently as economic events indicate, for potential impairment.

This consists of comparing the carrying value of the asset with the asset's expected future undiscounted cash flows without interest costs. Estimates of expected future cash flows represent management's best estimate based on reasonable and supportable assumptions. Proven oil and gas properties are reviewed for impairment on a field-by-field basis. No impairment losses were recognized for the year ended September 30, 2014 (September 30, 2013 - $nil).

Capitalized costs of proven oil and gas properties will be depleted using the unit-of-production method when the property is placed in production.

Substantially all of the Company's oil and gas activities are conducted jointly with others. The accounts reflect only the Company's proportionate interest in such activities.

Steam Assisted Gravity Drainage Demonstration Project

On July 30, 2013, the Company entered into a Steam Assisted Gravity Drainage demonstration project (“SAGD Project”) Agreement with the Company’s joint venture partner to participate in a recently, Alberta Energy Regulator (“AER”), approved SAGD Project on the Company’s 50% (before Farmout Agreement) owned oil sands properties located in North Central Alberta, Canada (also known as the Sawn Lake heavy oil reservoir). On August 15, 2013, and in accordance with the SAGD Project Agreement and the Amendment, the Company served notice (“Notice of Election”) to the operator of the Company’s election to participate in the SAGD Project. Upon signing the Notice of Election the Company was required to pay in full the cash calls for the Company’s initial share of the costs of the SAGD Project and in accordance with a Farmout Agreement dated July 31, 2013, the Company has since paid all cash calls in full to the operator of the SAGD Project.

Farmout Agreement

On July 31, 2013, the Company entered into Farmout agreement (the “Farmout Agreement”) with an additional joint venture partner (the “Farmee”) to fund the Company’s share of the AER approved SAGD Project at the Company’s Sawn Lake heavy oil reservoir in North Central Alberta, Canada. In accordance with the Farmout Agreement the Farmee has agreed to provide up to $40,000,000 in funding for the Company’s portion of the costs for the SAGD Project, in return for a net 25% working interest in 12 sections where the Company has a working interest of 50%. The Farmee will also provide funding to cover monthly operating expenses of the Company, of which the first such payment shall be in respect of the month of August 2013 and not to exceed $30,000 per month. In addition, until December 31, 2014, the Farmee has the option to elect to obtain a working interest of 40% to 45% working interest in the remaining 56 sections of land where the Company has working interests ranging from 80% to 90% (amended November 17, 2014, see Note 17 herein), by committing an additional $110,000,000 of financing to the development of the Company’s Sawn Lake oil sands properties. An agent fee of $1,500,000 was paid in connection with the Farmout Agreement.

SAGD Project – Phase 1

The SAGD Project started with the first phase (“Phase 1”) consisting of the drilling and completion of one SAGD well pair, the construction of a facility for steam generation, water handling and oil treating, plus water source and disposal facilities. As required by the Farmout Agreement, the Farmee has since paid Cdn $16,677,530 to the operator of the SAGD Project for the Farmee’s share and the Company’s share of the costs of the SAGD Project up to September 30, 2014. The total SAGD Project capital costs for Phase 1 plus additions have been estimated by the operator to be Cdn $32.6 million. In late September of 2014, the Company paid a cash call to the operator in the amount of Cdn $1,200,000 for the winterization program of the SAGD Project. Pursuant to the Farmout Agreement dated July 31, 2013, the Farmee reimbursed the Company in the amount of Cdn $1,200,000 for the cash call in October 2014.

SAGD Project – Phase 2

On June 27, 2014, the Company paid a Cdn $300,000 cash call to the operator for the proposed Phase 2 front end costs for the SAGD Project. The Phase 2 front end costs include work on preliminary engineering design, regulatory approval, environmental approval work and determining regulatory requirements sufficient to define the work program, schedule and estimated cost of this second phase which is anticipated to include the drilling of two additional SAGD well pairs and the associated expansion of the current SAGD steam plant. The Farmee has reimbursed the Company in the amount of Cdn $300,000 as per the Farmout Agreement dated July 31, 2013.

Water Rights Conveyance Agreement