Deep Well Oil & Gas, Inc.

Suite 700, 10150 - 100 Street, Edmonton, AB  T5J 0P6, Telephone: 780-409-8144, Fax: 780-409-8146

October 21, 2011 SENT VIA EMAIL: GallagherJ@SEC.GOV

Division of Corporation Finance

U.S. Securities & Exchange Commission

100 F Street, NE

Washington, D.C. 20549

U.S.A.

Attention:  Mr. Brad Skinner, Senior Assistant Chief Accountant

RE: Deep Well Oil & Gas, Inc. – File No. 000-24012

In response to the U.S. Securities & Exchange Commission (“SEC”) letter, dated September 12, 2011, the following are our responses to your questions.

We are incorporating all of the amendments suggested by the SEC in our future Annual Report on Form 10-K for the year ending September 30, 2011, to be filed with the SEC on or before December 29, 2011.

Response to SEC Comment #1.

In response to Point 1 of your letter, we will be providing in all of our future annual financial statements the following disclosure:

· Capitalized costs related to oil and gas producing activities as outlined in FASB ASC 932-235-50-12 through 50-15;

· Continued capitalization of exploratory well costs as outlined in FASB ASC 932-235-50-16; and

· Costs incurred for property acquisition, exploration and development activities as outlined in FASB ASC 932-235-50-17 through 50-20.

Response to SEC Comment #2.

In response to Point 2 of your letter, we confirm that we have not expensed any previously capitalized exploratory well costs. Furthermore, we have incurred some exploratory well costs that were immediately charged to expense under the successful efforts method. Specifically, those were costs related to salaries and expenses of our Company’s geologist and geophysicist and they have already been included in our table of costs incurred for property acquisition, exploration and development activities.

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Response to SEC Comment #3.

In response to Point 3 of your letter, it is correct that we have capitalized some exploratory well costs during years 2008 and 2010 even though we did not drill any exploratory wells in those fiscal years. Also, we confirm that our capitalized costs include only the costs of drilling exploratory wells, excluding the costs related to other exploration activities outlined in ASC paragraph 932-360-25-9.

As indicated in the table of changes to our Company’s suspended exploratory well costs provided in our July 29, 2011 letter, the amount of capitalized exploratory well costs recorded in 2008 was $1,587,262. Over $1 million was the cost incurred for the completion and production test phases of a well previously drilled by a company that entered into a farmout agreement with us. This information was disclosed and can be viewed in our Forms 10-K for the years ended September 30, 2005 and 2006. The remaining capitalized costs recorded in 2008 were costs related to the preparatory work for our 2009 drilling winter program.

In regards to the amount and nature of our exploratory well costs capitalized in 2010, roughly $200,000 of the $513,437 recorded was the remaining cost associated with our 2009 winter drilling program, $100,000 were the costs related to engineering fees, $50,000 was incurred for the production test phase of five wells previously drilled in fiscal 2009. The remaining $150,000 was the cost incurred for our annual lease rental payments and the preparation of an application for a cyclical steam stimulation (CSS) test on one of our wells.

From October 1, 2010 to June 30, 2011, our Company has capitalized an additional $482,700 of exploratory well costs. The majority of this cost related to the first phase of the single well cyclical steam stimulation test mentioned above.

Response to SEC Comment #4.

In response to Point 4 of your letter regarding our Form 10-K for the fiscal year ended September 30, 2010, “Note 3 Oil and Gas Properties”, the following discusses our progress of our oil sands project to date.

Currently we have in place a few joint operating agreements, which are based on the 1990 Canadian Association of Petroleum Landmen (“CAPL”) Operating Procedure, with two other joint interest partners to manage our joint oil sands leases. We are currently working with our joint venture partner toward developing a new more comprehensive joint operating agreement. 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 following paragraphs summarize the progress of our Sawn lake oil sands project.

In late 2006, we acquired with our joint venture partners over 200 km of reprocessed seismic and aeromagnetic studies, which cover all of our joint properties. In October of 2008 we enter into a service agreement with Exergy Engineers and Constructors Inc. to provide project management services to us for our 2008/2009 winter drilling program. During our winter drilling season of 2008/2009 we successfully drilled six vertical wells on our oil sands leases to a depth of approximately 700 meters each and we acquired a well that was previously drilled and cased by an unrelated party for heavy oil production. We also have an interest in three horizontal wells, which were previously drilled by one of our joint interest partners under a farm-in agreement at no cost to us. All of our exploratory wells were logged, cored and analyzed by independent service providers and are currently being evaluated for in-situ recovery methods.

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Weather and road use bans on roads we do not own can and often prevent us from continuing our operations on our oil sands leases. All of the roads we own are winter access only. All-weather roads owned by others are monitored by their owners and during spring break-up these owners impose road access restrictions for a few months during the year. In late 2008 and early 2009 we acquired approximately 30 km of existing road infrastructure accessing our Northern oil sands properties, this is in addition to the road infrastructure we already acquired from the province and constructed as winter access roads to our wellsites. Approximately 25% of these newly acquired access roads are scheduled to be upgraded to all-weather access roads by the end of 2011. This will improve the year round access to some of our Northern properties and more importantly year round access to our proposed in-situ pilot project location.

In September of 2009, we submitted an application to the Alberta Energy Resources Conservation Board (“ERCB”) for a commercial bitumen recovery scheme to evaluate one of our wells for potential development using Cyclic Steam Stimulation (“CSS”) and over a year later in October of 2010, this application was approved by the ERCB. Since October of last year we have put together a team to assist us with the development of our properties and to embark on a production test using in-situ recovery technology. The team consists of Asher Engineering Ltd. for engineering, project management and submission of additional ERCB directives/applications for our in-situ project, Fire Creek Resources Ltd. for completions engineering, Geomechanics International and Baker Hughes for cap rock integrity analysis studies, Pioneer Land and Environmental for permits along with construction of road access and environmental regulatory compliance, Kade Technologies Inc. for reservoir stimulation modeling and DeGolyer and MacNaughton Canada Limited for reservoir engineering. We continue to capitalize exploratory well costs for the first phase of our project.

In July 2010 and June 2011, it was determined through two separate independent reservoir engineering firms that our exploratory wells have found sufficient quantities of heavy oil in place to justify the completion of our wells for future production. Also in July of 2010, it was confirmed that our properties are suitable for thermal recovery methods. In addition, another hydrocarbon bearing zone was identified up-hole from the Bluesky zone presently being concentrated on by our Company. This secondary heavy oil zone is in the Peace River formation. We intend to continue the development of the Bluesky reservoir and at the same time we intend to evaluate this newly discovered reservoir by coring future wells within this zone. In January of 2011, Sproule Associates Ltd. prepared a National Instrument 51-101 (a Canadian evaluation engineering standard) compliant resource appraisal report for one of our joint venture partners. This report evaluated the resource of some of our Sawn Lake joint properties and included a complete geological and economic evaluation of the oil sands leases in the Sawn Lake area based on using thermal recovery to exploit the resource.

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In 2011, we engaged environmental consultants to proceed with the environmental studies mandated by Alberta Environment regulations before we can embark on our proposed thermal pilot project. We are currently working with an independent reservoir engineering company to prepare a reservoir modeling stimulation study to determine the optimum method for us to develop our reservoir. Following this reservoir model evaluation it is anticipated that we will develop a thermal pilot project on our properties followed by a commercial expansion project. We are currently negotiating a downhole contribution agreement with another company to obtain a Bluesky core and possible Peace River core for conducting a hot water and/or steam flood test and to also contribute toward meeting our requirements with the Alberta Department of Energy to continue our oil sands leases beyond their initial 15 year primary lease term.

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 delay development of our 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 studies lead us to conclude that our working interest can support full commercial production.

Response to SEC Comment #5.

In response to your Point 5 of your letter, the oil and gas properties line item on our balance sheet does include the capitalized asset retirement cost. Also, we confirm that we have recorded the asset retirement cost when recognizing our asset retirement obligation in our fiscal year 2009.

If you have any questions regarding the foregoing, please do not hesitate to call the undersigned at 780-409-8144.

Sincerely,

DEEP WELL OIL & GAS, INC.

/s/ Curtis Sparrow

Mr. Curtis Sparrow, P.Eng., MBA

Chief Financial Officer

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