[Aurora Oil & Gas Corporation Letterhead]

January 17, 2008

VIA EDGAR CORRESPONDENCE

Brad Skinner, Senior Assistant Chief Accountant

Division of Corporation Finance

Mail Stop 7010

United States Securities and Exchange Commission

100 F Street, N.E.

Washington, DC 20549-1090

Re: Aurora Oil & Gas Corporation Form 10-KSB for the Fiscal Year Ended December 31, 2006 Filed March 15, 2007 File No. 1-32888   Form 10-Q for the Period Ended September 30, 2007 Filed November 14, 2007

Dear Mr. Skinner:

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 December 18, 2007 (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 have set forth the nature of the disclosure that we would propose to add to our amended Form 10-KSB and Form 10-Q filings. In this regard, we would request that the Staff review the Company’s suggested disclosures prior to amending the Form 10-KSB and Form 10-Q, thus ensuring only one additional amendment to each of these filings.

Mr. Brad Skinner

U.S. Securities and Exchange Commission

January 17, 2008

Page 2

Form 10-KSB for year ended December 31, 2006

Consolidated Statements of Operations, page 44

1. Revise your line item presentation to comply with SAB 11:B.

RESPONSE: We believe the present line presentation of our Consolidated Statement of Operations is standard practice for the oil and gas industry. Our investors and analysts recognize that depletion, depreciation, and amortization (“DD&A”) will be shown separately. We reviewed numerous oil and gas exploration and production companies’ filings and did not find language in any of them identifying the exclusion of DD&A. We believe that the additional disclosure would not be consistent with our oil and gas peers and would be more confusing than helpful to an informed reader of our financial statements. Therefore, we respectfully request that the Staff reconsider this comment.

Note 3. Basis of Presentation and Summary of Significant Accounting Policies

Asset Retirement Obligation, page 50

2. Tell us and disclose the factors that resulted in your revisions of estimated liabilities for your asset retirement obligation.

RESPONSE: We will clarify our disclosure to identify the factors that were attributable to our revision of estimated liabilities for our asset retirement obligation. The following sentence will be added to the end of the second paragraph under Asset Retirement Obligation disclosure: “Revisions of estimated liabilities included reductions in well working interest totaling $55,358 and increases in the salvage value of equipment totaling $94,900.”

Income (Loss) per Share, page 53

3. We note that stock options, warrants, and redeemable convertible preferred shares were excluded from the computation of diluted loss per share because the effect of assumed exercises or conversions was anti-dilutive. Expand your disclosure to quantify the number of shares excluded from your computation. Refer to SFAS No. 128, paragraph 40(c) and Illustration 2 at paragraph 151.

RESPONSE: We will revise our Income (Loss) Per Share disclosure in the following manner:

Mr. Brad Skinner

U.S. Securities and Exchange Commission

January 17, 2008

Page 3

Basic net income (loss) per common share is computed based on the weighted average number of common shares outstanding during each period. Diluted net income (loss) per common share is computed based on the weighted average number of common shares outstanding plus other dilutive securities, such as stock options, warrants, and redeemable convertible preferred stock. [The last sentence of the paragraph will be deleted.] During the years ended December 31, 2006, and 2005, outstanding stock options, warrants, and redeemable convertible preferred stock that totaled 766,500 and none, respectively were excluded in the computation of diluted loss per share because their effect of assumed exercises or conversions was anti-dilutive. [The following language will be added] The following securities were not included in the computation of diluted net income (loss) per share as their effect would have been anti-dilutive:

	2006		2005
Options to purchase common stock		766,500		1,120,640
Warrants to purchase common stock		-		15,560,000
Convertible preferred stock		-		34,950
		766,500		16,715,590

Note 8. Shareholders’ Equity

Common Stock—2006, page 61

4. We note in December 2005 through early February 2006, the Company reduced the exercise price of certain outstanding stock options and warrants in order to encourage early exercise of these securities. Citing the authoritative literature you used, tell us and disclose how you accounted for this reduction in the exercise price and quantify the amount of stock-based compensation expense recognized from the reduction.

RESPONSE: The Company’s offer to reduce the exercise price of certain outstanding stock options and warrants was extended primarily to those who had acquired such options and warrants in connection with private equity offerings in January 2005 and prior. The Company did not extend the offer to reduce the exercise price to holders of options issued under the 2004 Equity Incentive Plan and the 1997 Stock Option Plan. Of the approximately 16.8 million discounted options and warrants that were exercised, only three option grants for a total of 199,998 shares were considered compensatory under our 2001 Equity Compensation Plan, with vesting between 2002 and 2004. Accordingly, substantially all of these options and warrants were noncompensatory in nature and were accounted for as equity transactions.

Mr. Brad Skinner

U.S. Securities and Exchange Commission

January 17, 2008

Page 4

On January 1, 2006, the Company adopted SFAS 123(R). The Company elected to use the modified prospective method for adoption, which requires compensation expense to be recorded for all unvested stock options beginning in the first quarter of adoption. Because the vested options noted above were modified, the Company performed an evaluation to determine if there was an incremental fair value of the modified share options immediately before and after the date of the modification. It was determined that there was only an immaterial amount of additional compensation. This modification was not given accounting recognition in the Company's financial statements due to the immaterial amount ($6,800) involved, and therefore, the Company does not believe that it would be necessary to amend its financial statements to account for the modification.

Note 15. Fourth Quarter Adjustments, page 68

5. Tell us and disclose why you consider your adjustments for depreciation, depletion and amortization to be the result of a change in estimates and not the correction of an error as defined in SFAS No. 154—Accounting Changes and Error Corrections. Rule 4-10(c)(3) of Regulation S-X states that amortization of costs shall be based on the unit-of-production basis using proved oil and gas reserves. Your change from using proved developed reserves to all proved reserves would appear to be an error in application of GAAP, not a change in estimate.

RESPONSE: In 2005, the Company recognized that its position in the Michigan Antrim shale play was located in the outer rim of the shale play which was believed to pose a higher risk in the finding and development of natural gas. In addition, significant gathering and processing facilities would be required to bring the natural gas to market. Therefore, the Company applied Reg. S-X Rule 4-10(c)(3)(ii)(B) which states, “certain costs may be excluded from amortization when incurred in connection with major development projects expected to entail significant costs to ascertain the quantities of proved reserves attributable to properties under development.” Therefore, we recognized only the cost associated with proven developed reserves and utilized proven developed reserves totaling 33.3 bcfe in the depletion calculation due to the unknown timing and significant costs to bring the proven non-producing and proven undeveloped natural gas reserves to market. As our understanding and development of the Michigan Antrim shale expanded in 2006, we recognized that we had a vital shale play and determined that all proven reserves should be amortized. In addition, our independent engineering firm advised us that the life of wells should be extended from 40 years to 50 years. We viewed the changes in these two factors—(a) the change in well life from 40 to 50 years (i.e., revising estimates that were previously made); and (b) the process of reviewing new information (i.e., significant drilling information attributable to 98 net wells being drilled in 2006)—as part of the process of obtaining additional information and revising estimates. Therefore, we considered these to be changes in accounting estimates, in accordance with the guidance set forth in paragraph 20 of SFAS No. 154.

Mr. Brad Skinner

U.S. Securities and Exchange Commission

January 17, 2008

Page 5

Supplementally, we would point out that, in response to the Staff’s comment, we evaluated the impact of the change in our methodology to determine if the change would have been considered material to our 2005 financial statements, had it been applied retrospectively. It was determined that there would have been a decrease of approximately $94,000 in depletion expense which we consider to be immaterial.

6. Revise your disclosure to clarify your original and new methodologies for capitalizing interest. Your current disclosure is not clear. Tell us and disclose how your methodology complies with paragraphs 12-16 of SFAS No. 34. Tell us why your change in accounting treatment is considered a change in estimate instead of a change in the method of applying an accounting principle. We may have further comments.

RESPONSE:In August 2004, the Company entered into a mezzanine credit facility to enable the Company to fund its share of the Michigan Antrim drilling program. The mezzanine credit facility required a separate financing entity be established and the use of proceeds were to be limited to fund drilling, completion, gathering lines, and gas processing facility for certain Michigan Antrim wells. Thus, during 2004 and 2005, the Company’s approach to capitalization of interest cost was to identify the specific exploration and development activities in progress that were allowed under the mezzanine credit facility and to tie such activities to specific mezzanine credit facility borrowing. If the mezzanine credit facility did not have a borrowing in a month that matched the drilling activities, then no interest was capitalized. SFAS No. 34, paragraph 13, does state, “If the enterprise associates a specific new borrowing with the asset, it may apply the rate on that borrowing to the appropriate portion of the expenditures for the asset.” Since the mezzanine debt provision was restrictive, the Company only capitalized interest related to developing those assets.

On January 31, 2006, the Company entered into a new senior secured revolving credit facility for drilling, development, and acquisitions, as well as other general corporate purposes. In this connection, the mezzanine credit facility was subordinate to the new senior credit facility and no further borrowings occurred under the mezzanine credit facility. Since the new senior revolving credit facility was not limited to certain exploration and development activities, the Company reviewed its approach to capitalized interest. The Company recognized all oil and gas properties that were not being depreciated, depleted, or amortized, as well as any exploration and development activities that were in progress of being developed. SFAS No. 34, paragraph 14, states that, “the use of judgment in determining capitalization rates shall not circumvent the requirement that a capitalization rate be applied to all capitalized expenditures for a qualifying asset to the extent that interest cost has been incurred during an accounting period.” Therefore, the Company identified all its long-term debt borrowings to be included in the weighted average rate calculation for capitalized interest.

Mr. Brad Skinner

U.S. Securities and Exchange Commission

January 17, 2008

Page 6

We will delete our original disclosure relating to the fourth quarter adjustment for capitalized interest and replace it with the following:

During the fourth quarter of 2006, the Company modified its approach to estimating capitalized interest. The Company’s original approach to capitalization of interest cost was to relate the specific exploration and development activities in progress that were allowed under the mezzanine credit facility to specific mezzanine credit facility borrowings. If there were no such borrowings in a month that matched the drilling activities, then no interest was capitalized. On January 31, 2006, the Company entered into a new senior secured revolving credit facility for drilling, development, and acquisitions, which was not limited to certain exploration and development activities. In this connection, the mezzanine credit facility was subordinated to the new senior credit facility, and no further borrowings occurred under the mezzanine facility. The Company reviewed its approach to capitalized interest and began treating all oil and gas properties that were not being depreciated, depleted, or amortized, as well as any exploration and development activities that were in progress of being developed as qualifying assets under SFAS No. 34. The Company identified all its long-term debt borrowings to be included in the weighted average rate calculation for capitalized interest. This change resulted in additional $3.2 million of capitalized interest for the entire fiscal year of 2006 which was recorded in the fourth quarter; of this amount, $1.9 million related to prior quarters.

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

7. Please remove the subtotal “Future net cash flows before income taxes” from your table. The provisions of SFAS 69 do not provide for such disclosure. See paragraph 30 and Appendix A, Illustration 5 of SFAS 69.

RESPONSE: We will remove the subtotal “Future net cash flows before income taxes” from our table that sets forth the Standardized Measure of Discounted Future Cash Flows.

Mr. Brad Skinner

U.S. Securities and Exchange Commission

January 17, 2008

Page 7

Changes in Standardized Measure of Discounted Future Cash Flows, page 71

8. We note the significant changes within your detailed line items for revision to reserves provided in prior years. Tell us and disclose the factors behind some of these changes—specifically the net change in prices and production costs, revisions in quantity estimates, accretion of discount, and other.

RESPONSE: The changes noted in the various line items under “Revision to reserves proved in prior years” are primarily due to differences in circumstances surrounding the preparation of the FAS 69 disclosure and resulting methodology applied. The 2005 SFAS 69 disclosure was prepared with the assistance of an accounting consultant as we did not have an in-house engineer in place to complete this task. In 2006, we had an in-house engineer and specialized engineering software available that resulted in a more streamlined approach to the disclosure.

The factors behind the specific changes by line item are summarized as follows:

(a) “Net changes in prices and production costs” - Our reserves consist primarily of natural gas. A significant change in natural gas price between reporting periods resulted in a large difference between 2005 and 2006. For 2006, the difference between the 12/31/05 year-end price versus the 12/31/06 year-end price applied to reserves was a reduction of $4.05/mmbtu ($5.84/mmbtu in 2006 versus $9.89/mmbtu in 2005). An opposite fluctuation between 12/31/04 and 12/31/05 resulted in an increase of $3.69 applied to prior year-end reserves ($9.89/mmbtu in 2005 versus $6.20/mmbtu in 2004). These price fluctuations were offset by changes in production costs. For 2006, this difference was a net reduction in estimated production costs of $0.39 ($2.47/mmbtu in 2006 versus $2.86/mmbtu in 2005). In 2005, the offset went the other way due to a net increase in estimated production costs of $0.74/mmbtu ($2.86/mmbtu in 2005 versus $2.12/mmbtu in 2004).

(b) “Revisions in quantity estimates” - The quantity estimates varied more significantly between 2005 and 2006 due to the classification of additional wells being added to the proved undeveloped category from the 12/31/05 report versus the 12/31/06 report. The additional wells were treated as “revisions” in the 2005 report but as new discoveries or extensions in the 2006 report which impacts the comparability between the 2 years. In addition, an upward revision was made in 2005. This was due to positive initial production rates from one particular project area which outperformed prior year expectations resulting in an upward adjustment to the projected production profile.

Mr. Brad Skinner

U.S. Securities and Exchange Commission

January 17, 2008

Page 8

(c) “Accretion to the discount” - In 2005, this line item was computed as the change in the overall discount between the 2004 report and the 2005 report. In 2006, it was computed using the more simplified and industry-recognized method as a computation of the 10% of the pre-tax present value of the prior year reserve report.

(d) “Other” - This line item reflects reconciling amounts which is made available to capture those timing and other differences, including modifications to the methodology applied from 2005 to 2006.

We recognize that the application of different methodologies resulted in some variation in amounts reported. We plan to apply the methods reflected in current industry resources to insure consistent application and plan to incorporate additional explanations similar to that reflected above, in the upcoming filing of our Annual Report on Form 10-K for the period ended 12/31/07.

Form 10-Q for the period ended March 31, 2007

Note 2. Basis of Presentation and Summary of Significant Accounting Policies

Asset Retirement Obligation, page 9

9. We note effective January 1, 2007, based on reserve study by an independent reserve engineering firm, the estimated life of your wells was increased by 10 years for an estimated life of 50 years per well. Please identify the expert in your disclosure. Additionally, tell us why you have not filed a related consent as an exhibit in accordance with Item 601 of Regulation S-K.

RESPONSE: Our independent reserve engineering firm is Data & Consulting Services, Division of Schlumberger Technology Corporation. We did not file a related consent as an exhibit since we were not specific in our footnote reference. In the future, we will identify our experts in our disclosure and file related consents as exhibits.

Engineering comments:

General

10. Please provide us with a copy of your reserve reports as of December 31, 2006. Please provide these on electronic media, such as CD-ROM, if possible. If you would like this information returned to you, please follow the guidelines in Rule 418(b) of Regulation C. Please send the CD-ROM to James Murphy at mail stop 7010.

Mr. Brad Skinner

U.S. Securities and Exchange Commission

January 17, 2008

Page 9

RESPONSE: We will overnight a copy of our reserve reports as of December 31, 2006, to Mr. James Murphy for receipt on January 17, 2008.

Supplemental Reserve Information, page 69

11. Please revise your document to include appropriate explanations for all significant reserve changes in the year to year reserves table. We note revisions that appear to be large in 2005, large volumes of extensions and discoveries in both 2005 and 2006, and large purchases of reserves in 2006. See paragraph 11 of SFAS 69 for guidance.

RESPONSE: We will clarify our disclosure in the following manner:

During 2006, we recorded upward revisions of 4.9 bcfe to the December 31, 2005, estimates of our reserves. This was due primarily to the increase in the lives of the wells from 40 years to 50 years. This increase was net of the downward adjustments caused by lower natural gas prices at December 31, 2006. A decrease in pricing reduces the economic lives of the properties which subsequently reduces the reserves.

We recorded an increase in extensions and discoveries of 65 bcfe which was due to positive results from our 2006 drilling activity. Certain positive drilling results coupled with increased drilling opportunities from significant leasing activity resulted in an increase in the number of identifiable offsets which moved certain probable reserves to proved reserves.

Also in 2006, the Company acquired approximately 23 bcfe of proved reserves through purchases of natural gas properties for approximately $24.0 million. We sold 0.7 bcfe of proved reserves for approximately $4.75 million.

During 2005, we recorded upward revisions of 5.4 bcfe to the December 31, 2004, estimates of our reserves. This upward revision was primarily due to positive initial production rates from one particular project area which outperformed prior year expectations which resulted in an upward adjustment to the projected production profile. This new profile became the analog for the entire project area increasing the reserves accordingly.

Also in 2005, we recorded an increase in extensions and discoveries of 22 bcfe which was due to positive results from our 2005 drilling and leasing activity. Certain positive drilling results coupled with increased drilling opportunities from leasing activity resulted in an increase in the number of identifiable offsets which moved certain probable reserves to proved reserves.

Mr. Brad Skinner

U.S. Securities and Exchange Commission

January 17, 2008

Page 10

Also in 2005, we acquired approximately 1.7 bcfe of proved reserves of oil and natural gas properties through our reverse merger.

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

12. We note your 2006 estimate of future development costs of $37.3 million dollars to develop proved undeveloped reserves of 70.5 BCFe and your 2005 estimate of $15.1 million to develop 18.7 BCFe. Please reconcile the fact that your 2005 estimate of future development costs are approximately $0.81 per Mcfe as compared to your 2006 estimate of $0.53 per Mcfe.

RESPONSE: The proved undeveloped reserves for 2006 were 47.9 bcfe, rather than 70.5 bcfe, and the future development costs to develop those reserves totaled $33.7 million, rather than $37.3 million. The higher numbers stated in your Comment Letter include proved developed non-producing reserves associated with wells that had not yet been hooked up to sales. Comparable values for 2005 include proved undeveloped reserves of 18.3 bcfe and future development costs of $15.1 million. A recalculation of future development costs using these metrics yields a ratio of $0.82 per mcfe for 2005 compared to $0.70 per mcfe for 2006.

The improved development cost ratio for 2006 is a result of the following:

a) Most of the well additions made to the proved undeveloped category are in areas where our independent reserve engineering firm has assigned higher reserve quantities on a per well basis; and

b) The 10-year increase in estimated life (from the 2005 report to the 2006 report) for our Antrim Shale and New Albany Shale wells has resulted in an increase in our reserves on a per well basis.

Finally, we would propose to include disclosures similar to the foregoing in items 1-12 in our next Form 10-K filing which will be filed on or around March 14, 2007.

Mr. Brad Skinner

U.S. Securities and Exchange Commission

January 17, 2008

Page 11

We acknowledge that:

· we are responsible for the adequacy and accuracy of the disclosure in our filing;

· Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to our filing; and

· we may not assert Staff comments as a defense in any proceedings initiated by the Commission or any person under the federal securities laws of the United States.

If you have any further questions or comments, please feel free to contact me at 330-353-0649.

Very truly yours,

/s/ Ronald E. Huff

Ronald E. Huff

President and Chief Financial Officer