8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported):	February 14, 2007
AURORA OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)

UTAH	0-25170	87-0306609
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)
4110 Copper Ridge Drive, Suite 100, Traverse City, MI		49684
(Address of principal executive offices)		(Zip Code)
Registrant’s telephone number, including area code:		(231) 941-0073
(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

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

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

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

Item 7.01Regulation FD Disclosure.

Today, Aurora Oil & Gas Corporation announced its year-end 2006 proved reserves and provided an operational update covering drilling and production results for the fourth quarter and year ended December 31, 2006. A copy of the press release is included as Exhibit 99.1 to this report.

The information in this Current Report appearing under the heading “Item 7.01 Regulation FD Disclosure,” including Exhibit 99.1 is being furnished pursuant to Item 7.01 of Form 8-K and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that Sections 11 and 12(a)(2) of the Securities Act of 1933, as amended.

Item 9.01 Financial Statements and Exhibits.

c. Exhibits

Exhibit No. Description

99.1 Aurora Oil & Gas Corporation press release dated February 14, 2007 entitled “Aurora Oil & Gas Corporation Provides Operational Update and Conference Call Information.”

SIGNATURES

According to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on February 14, 2007.

	Aurora Oil & Gas Corporation
Date: February 14, 2007		/s/ William W. Deneau
		By: William W. Deneau
		Its: President

EX-99.1

Aurora Oil & Gas Corporation Provides Operational Update and Conference Call Information

TRAVERSE CITY, MICHIGAN, February 14, 2007 - Aurora Oil & Gas Corporation (AMEX: AOG) today announced year-end proved reserves of 153 billion cubic feet of natural gas equivalent (Bcfe). This represents a 139% increase over year-end 2005.

William W. Deneau, President and CEO of Aurora Oil & Gas Corporation commented, “Our reserve growth demonstrates that this has been a wonderfully productive year for the Company. This is a direct result of executing our primary strategy of growth through the drill bit.”

Note: All financial and production information presented herein are unaudited and subject to change. The information will be presented in audited form in the filing of the Company’s 10-KSB with the Securities and Exchange Commission, to be filed during the latter half of March, 2007.

Drilling Results

In the second half of 2006, the Company announced its intention to participate in 73.04 net wells from July 1 through December 31, 2006. Actual results exceeded these expectations, as the Company participated in 76.34 net wells during the final six months of the year, bringing the total annual participation to 209 gross (112 net) wells. The success rate reported for the full-year 2006 drilling program is 94%.

Nearly 75% of the net wells were operated by Aurora, giving the Company greater ability to control costs and direct drilling activities. As expected, the majority of 2006 drilling activity was concentrated in the Antrim Shale properties where 173 gross (98 net) wells were drilled. The New Albany Shale added another 26 gross (7.5 net) wells, with 10 gross (5.6 net) wells added in non-core locations.

Proved Reserves

The year-end 2006 net proved reserves increased substantially from year-end 2005 by 89 Bcfe to 153 Bcfe. A summary of year-end 2006 results, with comparison to year-end 2005 is provided below:

Year-end Net Proved	Antrim Shale				New Albany Shale				Other				Total				2006
Reserves (Bcfe)	2006		2005		2006		2005		2006		2005		2006		2005		Change
PDP		81.2		28.9		0.5		0.0		0.3		1.2		82.1		30.1		52.0
PDNP		22.9		15.3		0.3		0.0		0.0		0.2		23.2		15.5		7.7
PUD		45.3		17.5		1.5		0.0		0.7		0.8		47.6		18.3		29.3
Total Net Proved Reserves		149.5		61.8		2.3		0.0		1.0		2.1		152.9		63.9		88.9

Changes to reserves, net of production, included a purchase of 22.3 Bcf of Antrim Shale properties completed in January of 2006, as well as the sale of 0.7 Bcfe of Louisiana properties in July of 2006. The Company will continue to manage its portfolio of properties to optimize the returns and operation of its properties. A net improvement to revisions of previous estimates and extensions also suggests that existing properties are showing improved reserve potential. The Company continues to review its drilling, completion and production methods to provide the best return on capital expended. A summary of the proved reserves reconciliation is provided below:

Reconciliation of Reserves	Proved Reserves (Bcfe)
Proved Reserves as of December 31, 2005		63.9
Revisions of previous estimates		4.2
Purchases of minerals in place		22.3
Extensions and discoveries		65.7
Production		-2.6
Sales of minerals in place		-0.7
Proved Reserves as of December 31, 2006		152.9

Excluding the benefit of financial hedges, pre-tax PV-10 decreased to $139 million at year-end 2006, versus $199.5 million at year-end 2005. This is a direct result of the decline in the natural gas price deck used for this calculation and is similar to the decline experienced by other operators with natural gas properties. The Aurora price deck has declined from $9.89 at year-end 2005 to $5.84 for year-end 2006. If the benefit of financial hedges is included, PV-10 is improved by $10.3 million.

In 2006, capital expenditures for drilling were approximately $56 million. The estimated cost of proved reserves found/added for 2006 is approximately $0.85 per mcfe. These are excellent results and are below the three year average for Aurora’s peer group.

In 2007, the Company expects capital expenditures of approximately $100 million to participate in over 400 gross (200 net) wells. This is approximately a two-fold increase in drilling activity from 2006. The majority of this budget will be allocated to the development of Antrim Shale properties. By the end of 2007, Aurora expects add over 100 Bcfe of proved reserves through the drillbit.

The proved reserves for year-end 2006 have been prepared by Schlumberger Data & Consulting Services and are consistent with calculations required by the Securities Exchange Commission.

Production Results

For the last quarter of 2006, the Company produced 671 thousand net mcfe, averaging 7.3 thousand net mcfe per day and exiting the year at 8.6 thousand net mcfe per day. The quarterly production is in-line with Company guidance and the exit rate shows a 250% improvement in production from year-end 2005. In 2007, the production growth has continued, climbing to an average of 8.7 thousand net mcfe per day for January, with an exit rate of 9.2 thousand net mcfe per day.

A summary of production for the fourth quarter and full-year 2006 is provided below: 

Estimated Production by	Q4 2006				2006
Formation (net mcfe)	Total		Daily Average		Total		Daily Average
Antrim Shale		619,872		6,738		2,353,691		6,449
New Albany Shale		11,994		130		28,517		78
Other		39,731		432		271,219		743
Total		671,597		7,300		2,653,427		7,270

Estimated Production by	Q4 2006				2006
Operator (net mcfe)	Total		Daily Average		Total		Daily Average
Operated		486,785		5,291		1,963,860		5,380
Non-operated		184,812		2,009		689,567		1,889
Total		671,597		7,300		2,653,427		7,270

The Company is disappointed, however, with the production growth during 2006. Production has been hampered by curtailments on a non-operated processing facility and delays on getting wells into production. Recently, Aurora completed and began selling Antrim Shale production via an alternative outlet which the Company built into the Great Lakes Pipeline. This will alleviate the impact of the curtailments experienced to date and allow the Antrim Shale properties to steadily dewater and increase production.

As seen in the summary table below, 42 gross (41.21 net) operated wells are waiting for hookup in the Company’s Antrim Shale properties as of December 31, 2006. The majority of these wells are waiting for pipeline easements and right-of-ways granted by state regulatory agencies. The Company is working closely with these agencies and legislators to minimize the delayed approvals which have notably increased over the past year.

Well Status as of	Antrim Operated				Antrim Non-Operated				New Albany Operated				New Albany Non-Operated				Other				Total
December 31, 2006	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Producing		164		155.00		249		43.86		0		0.00		14		0.70		28		13.70		455		213.26
Waiting on Hook-Up		42		41.21		40		9.96		12		6.21		8		0.65		3		1.34		105		59.38
		206		196.21		289		53.82		12		6.21		22		1.35		31		15.04		560		272.64

Mr. Deneau commented, “We are very pleased with the quantity and quality of our 2006 drilling campaign. Our proved reserves continue rapid growth through the drillbit and we continue to prove up undeveloped locations on our extensive leasehold. Our cost control has resulted in some of the lowest finding costs in the industry. Today we are focused on adding to our drilling successes and getting existing and future wells online and adding cash flow as quickly as possible.”

Please join us for our Conference Call and Webcast later today, February 14, 2007 at 11 a.m. EST.

Call-In Information

Aurora Oil & Gas invites interested persons to participate in the call by dialing 877-407-8035 (domestic) or 201-689-8035 (international) prior to 10:55 a.m. EST. A digital replay of the conference call will be available within 3 hours following the call and will remain available until 11:59 p.m. EST on February 21, 2007. The replay can be dialed at 877-660-6853 (domestic) or 201-612-7415 (international) and reference should be made to account number 286 and conference ID number 230645.

Webcast Information

The call will also be broadcast live via Internet webcast on the Company's website, www.auroraogc.com, through the "Investor Relations" page and the "Presentations & Webcasts" link. An archived webcast and podcast will be available for listening or download within 3 hours after the call and can be found under the link suggested above for up to 12 months following the event.

Company Description

Aurora Oil & Gas Corporation is an independent energy company focused on unconventional natural gas exploration, acquisition, development and production with its main operations in the Michigan Antrim Shale and New Albany Shale of Indiana and western Kentucky.

Forward-Looking Statements

Statements regarding the plans for the future growth, development plans and growth through drilling, estimated value of proved reserves and anticipated production volumes are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Although we believe that the forward-looking statements described are based on reasonable assumptions, we can give no assurance that they will prove accurate. Important factors that could cause our actual results to differ materially from those included in the forward-looking statements include the timing and extent of changes in commodity prices for oil and gas, drilling and operating risks, the availability of drilling rigs, changes in laws or government regulations, unforeseen engineering and mechanical or technological difficulties in drilling the wells, operating hazards, weather-related delays, the loss of existing credit facilities, availability of capital, and other risks more fully described in our filings with the Securities and Exchange Commission. All forward-looking statements contained in this release, including any forecasts and estimates, are based on management’s outlook only as of the date of this release and we undertake no obligation to update or revise these forward-looking statements, whether as a result of subsequent developments or otherwise.

Cost of Proved Reserves Found/Added

Cost of proved reserves found/added is calculated by dividing capital expenditures for oil and gas development for the period, by reserve extensions and discoveries for the period. Our calculation may be similar to an "all-in F&D cost" and includes costs and reserve additions related to the creation of proved reserves. The methods we use to calculate our cost may differ significantly from methods used by other companies to compute similar measures. As a result, our cost may not be comparable to similar measures provided by other companies. We believe that providing a measure of cost is useful in evaluating the cost, on a per thousand cubic feet of natural gas equivalent basis, to add proved reserves. However, this measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with generally accepted accounting principles. Due to various factors, including timing differences in the addition of proved reserves and the related costs to develop those reserves, these costs do not necessarily reflect precisely the costs associated with particular reserves. As a result of various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, we cannot assure you that our future cost of proved reserves will not differ materially from those presented.

Contact:

Aurora Oil & Gas Corporation

Jeffrey W. Deneau, Investor Relations

(231) 941-0073

www.auroraogc.com

Source: Aurora Oil & Gas Corporation