February 28, 2008

VIA OVERNIGHT MAIL

Christopher J. White, Accounting Branch Chief

Division of Corporation Finance

United States Securities and Exchange Commission

Mail Stop 7010

Washington, DC 20549-7010

Re: Aurora Oil & Gas Corporation Form 10-KSB for the Fiscal Year Ended December 31, 2006 Filed March 15, 2007 File No. 1-32888

Dear Mr. White:

This letter sets forth the responses of Aurora Oil & Gas Corporation (the “Company”) to the comments provided by the staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”) in its comment letter dated February 13, 2008 (the “Comment Letter”). For your convenience, we have repeated each comment of the Staff in bold type face exactly as given in the Comment Letter and set forth below such comment is our response.

With respect to those comments which suggested that additional disclosure be made, we respectfully request that the Staff allow the Company to comply with the comments in a prospective manner in future filings as outlined in our responses below. The Company is preparing to file its Annual Report on Form 10-K for the year ended December 31, 2007, and will include disclosures that are responsive to the applicable Staff comments.

Engineering Comments

Supplemental Reserve Information, page 69

1.We have reviewed your response to prior comment 11 of our letter dated December 18, 2007. We note you have clarified that significant changes to reserves are due to extensions and discoveries from positive results from drilling activity. Please further expand your revised disclosure on extensions and discoveries to include the location of the reserves added, the number of wells associated with each location, whether the reserves were extensions of an existing field or a new discovery, the percentage of the reserves that are undeveloped and the expected timing of the development of these reserves.

Mr. Christopher J. White

U.S. Securities and Exchange Commission

February 28, 2008

Page 2

RESPONSE: During 2006, the Company experienced significant changes in reserves due to extensions and discoveries associated with drilling activities conducted by both the Company and by third parties. Approximately 99.6% of the 65.4 bcfe of reserves attributable to extensions and discoveries are associated with the following:

The drilling of 16 gross (0.9 net) New Albany Shale wells in Daviess and Greene Counties, Indiana resulted in two field discoveries and reserves of 2.3 bcfe associated with 40 gross (2.4 net) wells. Approximately 67% of the reserves are undeveloped and are expected to be developed in 2007 and 2008.

The drilling of 196 gross (90.1 net) Antrim Shale wells in Alcona, Alpena, Antrim, Charlevoix, Cheboygan, Montmorency and Otsego Counties, Michigan resulted in reserve extensions of 62.8 bcfe associated with 257 gross (138.1 net) wells. Approximately 59% of the reserve extensions are undeveloped and are expected to be developed in 2007 and 2008.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves, page 70

2. We have reviewed your response to prior comment 12. Please tell us the reasons your Antrim Shale and New Albany Shale wells increased in estimated well life by 10 years in 2006 compared to 2005 when your reported end of year gas price decreased from $9.89 per mmbtu in 2005 to $5.84 per mmbtu in 2006.

RESPONSE: The Company’s reserve report for 2005 recognized a maximum well life of 40 years for Antrim Shale wells. Schlumberger Data & Consulting Services (“DCS”), the preparer of the Company’s reserve reports, extended the maximum well life for the Antrim Shale by an additional 10 years in the 2006 reserve report, and they also recognized a 50-year maximum life for the New Albany Shale, for the following reasons:

(a) A number of Antrim Shale properties operated by third parties have exhibited extended lives that suggest that a 50-year life is a reasonable expectation. An example of such a property is the SCV Unit, located in T29N-R2W in Otsego County, Michigan. Production from the unit commenced in December 1968, and the current production rate averages 29 mcf/day/well suggesting that the wells should remain economic for at least 10 more years.

Mr. Christopher J. White

U.S. Securities and Exchange Commission

February 28, 2008

Page 3

(b) In most cases, the Company’s Antrim Shale and New Albany Shale properties are projected to still be economic to produce after 50 years of production.

(c) The casing in the Company’s Antrim Shale and New Albany Shale wells is expected to maintain its integrity for 50+ years.

(d) Quicksilver Resources Corporation (“Quicksilver”), another client of DCS, is one of the leading Antrim Shale and New Albany Shale producing companies. DCS projects Quicksilver’s Antrim Shale reserves and New Albany Shale reserves using a 50-year maximum well life.

The New Albany Shale properties were included for the first time in the Company’s 2006 reserve report. The New Albany Shale reservoir is comparable to the Antrim Shale in its age, depth, pay thickness, gas content, gas origin and production characteristics, so it is the Company’s belief and the belief of DCS that the maximum well life will be comparable.

Reserve Report

3. We note a number of proved undeveloped wells in the Plainville field in which you do not include any investment or capital expenditures. Please explain this to us.

RESPONSE: El Paso Production Company (“El Paso”) is operator of the Plainville Field. Paragraph 11 of the Assignment Agreement entered into between El Paso and Aurora, effective November 4, 2003, states that “Aurora shall own a 5% of 8/8ths carried working interest (“CWI”) in any wells, whether horizontal pilot, salt water disposal or any other type of well, drilled by El Paso on the Leased Premises or acreage pooled or unitized therewith up to the first fifty (50) of such wells…Once any such CWI Well has been connected to the lease meter, Aurora shall be fully responsible for and shall pay its 5% of 8/8ths of any further costs and expenses associated with any such well.” In short, Aurora is not responsible for paying drilling and completion costs on the first 50 wells drilled by El Paso.

Mr. Christopher J. White

U.S. Securities and Exchange Commission

February 28, 2008

Page 4

4. We note a number of proved undeveloped wells in the Plainville field in which there are no proved producing wells on the same leases. Please tell us if all of your proved undeveloped locations are within one offset location away from a producing well in the same formation.

RESPONSE: Drilling units in the Plainville Field are generally 320 acres or 640 acres in size since all of the wells are drilled with one or more horizontal laterals. Most leases in the field are tracts that are smaller in size than the drilling units, so it is not uncommon for the closest offset location to be on a different lease. All of the proved undeveloped locations reflected in the Company’s reserve report are within one offset location away from a producing well in the same formation.

5. It appears that with low cumulative production volumes most of the New Albany Shale wells have been on production for just a short time. Please confirm if this is true and if so, tell us how you estimated the reserves for these wells, the proved developed not producing wells and the proved undeveloped wells. Provide us with a production graph over time for all the New Albany Shale wells you have an interest in. Include the production to date, your forecasted rate of production as of December 31, 2006 with the reserves as of that date and your forecasted rate of production as of December 31, 2007 on the graphs.

RESPONSE: The first four New Albany Shale wells in the Plainville Field commenced production on December 30, 2005. After these wells had been producing for approximately six months, Schlumberger Data & Consulting Services (“DCS”) generated a forecast of production and reserves utilizing their SHALEGAS multi-phase reservoir simulator which was designed specifically for evaluating fractured shale formations. General reservoir information, rock matrix data and bulk fracture system parameters were input into the simulator; then the available production data was used to calibrate the simulator through history matching. The result was a composite New Albany Shale type curve that has thus far proven to accurately model performance of an average Plainville Field producing well. Please see the attached plot (Attachment 1) that depicts composite performance of the 25 producing wells drilled to date in the Plainville Field. This is a “zero-time” plot that graphs average production from all wells using the same starting point. After more than two years of production history, the composite gas production plot agrees closely with the DCS type curve (green triangles).

Mr. Christopher J. White

U.S. Securities and Exchange Commission

February 28, 2008

Page 5

The type curve developed by DCS was adjusted upward or downward as appropriate to match actual performance of the proved developed producing wells. The same type curve was applied, without adjustment, to provide a representation of production and reserves for each proved developed non-producing well and for each proved undeveloped well. It is the Company’s belief that the DCS type curve is a reasonable projection of average New Albany Shale well performance in the Plainville Field.

As requested, we have provided a graph (Attachment 2) for the Plainville Field which depicts the daily combined production for the 14 New Albany Shale wells that were producing at the end of 2006 and the corresponding projection of proved developed producing reserves recognized in the Company’s 2006 reserve report.

If you have any further questions or comments, please feel free to contact me at 231-941-0073.

Very truly yours,

/s/ Barbara E. Lawson

Barbara E. Lawson

Chief Financial Officer