UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-KSB

x ANNUAL REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2005

o TRANSITION REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____________ to ____________

Commission File Number 000-25170

CADENCE RESOURCES CORPORATION

(Name of Small Business Issuer in Its Charter)

Utah	87-0306609
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

4110 Copper Ridge Drive, Suite 100, Traverse City, Michigan	49684
(Address of Principal Executive Offices)	(Zip code)

(231) 941-0073

(Issuer’s Telephone Number, Including Area Code.)

Securities registered under Section 12(b) of the Exchange Act:

Title of Each Class	Name of Each Exchange on Which Registered
None	N/A

Securities registered under Section 12(g) of the Exchange Act:  Common Stock, par value, $0.01

 (Title of class)

Check whether the issuer: (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for past 90 days. Yes x    No o

Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B is not contained in this form, and no disclosure will be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-KSB or any amendment to this Form 10-KSB.

State issuer’s revenues for its most recent fiscal year: $2,513,046.

The aggregate market value of the voting and non-voting stock held by non-affiliates of the registrant as of December 15, 2005, was approximately $188,159,725. For purposes of this computation, all executive officers, directors and 10% stockholders were deemed affiliates. Such a determination should not be construed as an admission that such 10% stockholders are affiliates.

As of December 15, 2005 there were 59,041,685 shares of the common stock, par value $0.01 per share, of the registrant issued and outstanding.

Documents Incorporated by Reference: None

Transitional Small Business Disclosure Format: Yes o No x

TABLE OF CONTENTS

Item		Page
PART I
Item 1.	Description of Business	1
Item 2.	Description of Properties	44
Item 3.	Legal Proceedings	45
Item 4.	Submission of Matters to a Vote of Security Holders	45
PART II
Item 5.	Market for Common Equity and Related Stockholder Matters	45
Item 6.	Management’s Discussion and Analysis or Plan of Operations	49
Item 7.	Financial Statements	56
Item 8.	Changes in and Disagreements with Accountants	56
Item 8A.	Controls and Procedures	56
PART III
Item 9.	Directors, Executive Officers, Promoters and Control Persons	57
Item 10.	Executive Compensation	61
Item 11.	Security Ownership of Certain Beneficial Owners and Management	64
Item 12.	Certain Relationships and Related Transactions	66
Item 13.	Exhibits and Reports on Form 8-K	67
Item 14.	Principal Accountant Fees And Services	68
Financial Statements
	Independent Auditor’s Report	F-1
	Balance Sheets as of September 30, 2005, 2004 and 2003	F-2
	Statements of Operations and Comprehensive Loss for the years ended September 30, 2005, 2004 and 2003	F-4
	Statement of Stockholder’s Equity	F-5
	Statements of Cash Flows for the years ended September 30, 2005, 2004 and 2003	F-7
	Notes to the Financial Statements	F-9

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PART I

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (“Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). You can find many of these statements by looking for words such as "believes," "expects," "anticipates," "estimates" or similar expressions used in this report.

These forward-looking statements are subject to numerous assumptions, risks and uncertainties. Factors which may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by us in those statements include, among others, the following:

·    the quality of our properties with regard to, among other things, the existence of reserves in economic quantities;

·    our ability to increase our production and oil and gas income through exploration and development;

·    the number of locations to be drilled and the time frame within which they will be drilled;

·    future prices of natural gas and crude oil;

·    anticipated domestic demand for oil and natural gas; and

·    the adequacy of our capital resources and liquidity.

Because such statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. You are cautioned not to place undue reliance on such statements, which speak only as of the date of this report.

Item 1. Description of Business

The Company

Cadence Resources Corporation is a Utah corporation incorporated on April 7, 1969 to explore and mine natural resources under the name Royal Resources, Inc. In January 1983, we changed our name to Royal Minerals, Inc. In March 1994, we changed our name to Consolidated Royal Mines, Inc. In September 1995, we changed our name to Royal Silver Mines, Inc. On May 2, 2001 we changed our name to Cadence Resources Corporation in connection with a corporate reorganization to focus our operations on oil and gas exploration.

We acquired Aurora Energy, Ltd. ("Aurora") on October 31, 2005 through the merger of our wholly-owned subsidiary with and into Aurora. As a result of that merger, Aurora became our wholly-owned subsidiary. The acquisition of Aurora will be accounted for as a reverse merger, with Aurora being the acquiring party for accounting purposes. The acquisition of Aurora was pursuant to the Agreement and Plan of Merger dated as of January 31, 2005 (the "Merger Agreement"). In connection with the acquisition of Aurora, we issued an aggregate of 37,512,366 shares of our common stock to the former shareholders of Aurora, and have reserved an additional 10,497,328 shares of our common stock for issuance upon exercise of option or warrants that had been issued by Aurora prior to the acquisition and that were previously exercisable for shares of the common stock of Aurora. Pursuant to the terms of the Merger Agreement our board of directors is composed of seven individuals, three of whom were directors of Aurora prior to the acquisition and two of whom were directors of Cadence prior to the acquisition. Our Board of Directors consists of William W. Deneau, the former Chairman and President of Aurora, Howard M. Crosby, Kevin D. Stulp, Ronald E. Huff, Richard Deneau, Gary J. Myles and Earl V. Young. Messrs. Crosby and Stulp, were directors of the Company immediately prior to the acquisition of Aurora and Messrs. Deneau, Myles and Young were directors of Aurora immediately prior to the acquisition of Aurora.

Although the acquisition of Aurora occurred after the period to which this report on Form 10-KSB relates, the description of our business contained herein includes descriptions of the material aspects of the business of Aurora. Because the business of Aurora is now included as our Aurora division, we believe that a full understanding of our business as it will be conducted in the future requires an understanding of the business operations of both Cadence and Aurora. In addition, as a result of the acquisition, we will revise certain of our accounting principles applicable to our oil and gas properties, and have changed our accounting fiscal year to end on December 31, commencing December 31, 2005. See "Management's Discussion and Analysis of Financial Condition and Results of Operation."

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We are engaged in acquiring, exploring, developing, and producing oil and gas properties. We have operations in Wilbarger County, Texas, DeSoto Parish, Louisiana, Eddy County, New Mexico and Alpena County, Michigan. We also have leased interests in western Kansas and southern Texas. Through our subsidiary Aurora, we have an interest in the following productive properties: the Beyer, Black Bean, Blue Spruce, Devil River, Dover, Gehrke, Hudson, Mackinaw, Nicholson Hill, Paxton Quarry, Sequin, Timm and Treasure Island Antrim Shale gas projects in Michigan; and the Bergsasi oil well and Church Lake oil field in Michigan. We also own a number of non-producing properties described below that are in various stages of development.

One of our primary goals is to produce gas from lower risk unconventional gas reservoirs such as black shales, coal seams and tight sands, targeting projects where large acreage blocks can be easily evaluated with a series of low cost test wells prior to development investments. To achieve this goal, we have a particular, but not exclusive, focus on the black shales of Michigan and Indiana.

Historically, we have acquired and then resold (for cash) mineral leases, often with a retained interest. Those mineral leasehold interests in which we or our affiliates currently have an interest are described below. In 2004, we sold 80% of a substantial block of our Michigan Antrim leaseholds and working interests to Samson Resources Company. This transaction with Samson Resources Company is described below in more detail under the caption "Samson Transaction" (the "Samson Transaction"). In 2003, 2004 and 2005, we sold substantial blocks of our Indiana New Albany Shale assets as described below. These sales, and others, were undertaken to generate cash that we could use to continue work on our development plan. Greater detail about the terms of these sales is provided below. A subsidiary of our Aurora division also has a $50 million credit facility with Trust Company of the West. In addition, during December 2004 and January 2005, we raised an aggregate of $22,312,500 million through the sale of equity and warrants in two private placements, one through our Cadence division and the second through our Aurora division.

Our longer term goal is to generate revenues from the sale of oil and gas production sufficient to support ongoing development. Once wells are drilled and in production, the underlying gas reserves will be characterized as proved developed producing reserves, which have greater value than unproven probable reserves. As a general rule, once the underlying reserves are characterized as proved developed producing reserves, the underlying assets can be pledged to support debt financing. We currently have one such financing facility in place. Proved developed producing reserves are also generally more attractive to prospective asset purchasers such as larger oil and gas companies.

During the year ended September 30, 2005, substantially all of our revenues were derived from our Cadence division's interests in nine producing oil wells in Wilbarger County, Texas and eleven producing natural gas wells in DeSoto Parish, Louisiana. We received small revenues from our Cadence division's interest in nine producing gas wells in Alpena County, Michigan and a minority interest in a producing well in Eddy County, New Mexico. As of December 31, 2004 our Aurora division had 200 gross (42.35 net) oil and gas wells, 7,956 gross (2,739 net) acres of developed wells and 408,379 gross (276,459 net) acres of undeveloped wells. With the acquisition of Aurora and with the proceeds that we received from the private placements in January 2005, we have greatly expanded our drilling program, as described below.

At the completion of our 2005 fiscal year in September, we were continuing to evaluate the performance of our Cadence division's natural gas wells in DeSoto Parish. Along with our partner, Bridas Energy, we have not made plans to drill additional wells at that location. In the fiscal year 2005, we drilled four new wells on our West Electra Lake Unit and a new well on our E lease, all in Wilbarger County, Texas, completed the seismic evaluation process on the north block of our Kansas acreage, and drilled two exploratory wells on the property, participated for a working interest in development wells being drilled in Eddy County, New Mexico, and acquired an interest in a company that is participating for a working interest in an exploratory well in Tennessee.

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We plan to participate in the drilling of approximately 200 gross wells in the Michigan Antrim Shale and the New Albany Shale during 2006. Through September 30, 2005, we have drilled 298 gross (194 net) wells in the Michigan Antrim Shale. We have a development plan for the Michigan Antrim Shale for the next three years. We are also formulating a development plan for the New Albany Shale in Indiana and Kentucky. We continue to explore different sources of possible equity financing and credit facilities to be sure that we have sufficient resources to achieve our 2006 goals.

Oil and Natural Gas Operations

DeSoto Parish, Louisiana

We leased over 4,800 acres (2,160 net acres) in DeSoto Parish (approximately 40 miles south of Shreveport, Louisiana) in the summer of 2001 and throughout 2002. Our acreage is southwest of the Holly Field and southeast of the Bethany Longstreet Field, both extensively drilled and developed since 1996 by Sonat (now El Paso Corporation). In April 2003, we contributed these leases to a joint exploration and development program with Bridas Energy, which has operations in the Texas-Louisiana Gulf Coast area. Under this program, Bridas Energy is the operator of the DeSoto Parish properties. Bridas Energy is a wholly-owned subsidiary of Bridas Corporation, an Argentinean-based private, independent energy company with headquarters in Buenos Aires.

Under the terms of our joint exploration agreement with Bridas Energy, we assigned Bridas Energy a 55% working interest in all of the acreage constituting the area of mutual interest of our DeSoto Parish leases in return for a cash payment of $50,000. Bridas Energy agreed to fund all costs of drilling, completing and bringing to production the initial test well, the Ardis-Martin Timber #27-1, drilled during June 2003, in Section 27 of this prospect. Upon successful completion of this test well, we conveyed an additional 20% working interest to Bridas Energy in that well and all other leases covering acreage in Section 27, leaving us a 25% working interest in Section 27. We retain a 45% working interest in all other wells on the leased acreage in this prospect and a lesser working interest in any wells drilled in the area of mutual interest around the leased acreage, depending upon the amount of acreage leased by each respective party in that particular section.

As of September 30, 2005 we had nine producing wells in this field. During the month of September 2005, these wells produced an aggregate of 25,959 MCF of natural gas on a net basis to us. At September 30, 2005, twelve wells had produced an aggregate of 192,663 MCF of natural gas on a net basis to us. In May, 2005 one well was removed from production due to low output.

As of September 30, 2005, all but two of our producing wells in DeSoto Parish were from the Cotton Valley formation. The Cotton Valley formation lies immediately below the Hosston, with the best sands typically extending to about 10,300 feet. Of the eleven producing wells as of September 30, 2005, we have a 25% working interest and an approximate 20% net revenue interest in four of them, a 45% working interest and an approximate 36% net revenue interest in six of them, and a 25% working interest and an approximate 18% net revenue interest in one of them.

The DeSoto Parish properties are located on a major anti-clinorium on the southeast side of the Sabine Uplift. The Sabine Uplift is a large structure that is related to the cretaceous and younger rocks in the established oil and gas fields of northeast Texas and northern Louisiana. In this area, wells from these formations produce approximately 35% to 50% of the well's total anticipated output in the first 24 months of production, with the remainder produced over 12 to 15 years.

Our drilling and completion costs for these DeSoto Parish wells drilled to the Cotton Valley formation, to the 8/8ths interest, were approximately $1.25 million to $1.3 million per well. However, costs to drill and complete wells to this depth in this area have increased significantly due to rapidly accelerating materials and labor costs. These increases will greatly affect our future decisions about drilling further wells in this field.

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Wilbarger County, Texas

Our property in Texas is located on the Waggoner Ranch, a privately-held ranch in Wilbarger County, approximately 50 miles northwest of Wichita Falls, Texas, and 15 miles south of the Oklahoma border. Since October 2001, we have conducted exploration activities on the Waggoner Ranch. The W.T. Waggoner Estate is the operator of all of our wells on the Waggoner Ranch and the sole purchaser of all production from these properties. We logged our first productive well in this field in January 2002. As of September 30, 2005, we owned interests in nine wells on these properties, producing an aggregate of approximately 54 net working interest barrels per day, to the 8/8ths interest, of 35 (degree) API sweet crude oil.

The major geologic feature in this part of north Texas is the Red River Arch, which consists of Permian and Leonardon shales and sands. This structure has historically produced more than 150 million barrels of oil from several geologic features, including the Canyon limestone formation. Our primary targets on this prospect are oil-bearing pinnacle reefs in the Canyon limestone formation, typically located between 3,000 and 3,600 feet. We are producing oil from three areas of the Ranch: the east side of Electra Lake, referred to as the Virgin Reef Prospect, and the west side of Electra Lake, referred to as the West Electra Lake Prospect, and from an area north of Electra Lake referred to as North Electra.

The Virgin Reef Leasehold consists of approximately 400 acres. In August 2002, we signed an exploration agreement with the Waggoner Ranch on 650 acres in the West Electra Lake Prospect, with a surrounding 1/2 mile area of mutual interest, from which our current production comes. The West Electra Lake Leasehold currently consists of an aggregate of 532 acres under lease and a 1/2 mile area of mutual interest surrounding such acreage. In March, 2005 we signed an additional lease agreement with the Waggoner Ranch on acreage north and west of Electra Lake which currently consists of an aggregate of 700 acres under lease and which also has mutual interest surrounding such acreage.

We have two producing wells on the Virgin Reef Prospect, the #1A in which we have a 60% working interest and a 45.6% net revenue interest and the #1B well, in which we have 100% working interest and a 76% net revenue interest. The #1A well was logged in January 2002 and showed four pay zones between 2,400 feet and 3,002 feet. This well is currently producing from the Lower Milham Sand at a depth of approximately 2,500 feet. We have already produced this well from the deeper Canyon formation zones and re-completed the well in the Lower Milham zone. One more zone in this well remains to be completed. This well produced an average of approximately 12.5 net working interest barrels per day during September 2005. The other producing well, the #1B, well is producing at only a nominal rate.

In August 2002, we began developing the West Electra Lake Prospect. We logged our first well in the first quarter of calendar 2003. We have three producing wells in this prospect, all of which are producing from the upper Milham Sand at a depth of approximately 2,600 feet. The first well, the West Electra Lake #1, in which we have a 45% working interest and a 34.2% net revenue interest, has 10 feet of net pay. The West Electra Lake #2 and #3 wells, in which we have a 50% working interest and a 38% net revenue interest, were both drilled in June 2003 and encountered 10 feet and 11 feet of net pay, respectively, in the same zone. These three wells are subject to Texas Railroad Commission production limits and during September 2005, produced at the rate of an aggregate of approximately 25 barrels of oil per day, which is below the maximum allowable rate of an aggregate of 120 barrels of oil per day, with the pumps operating for only eight hours per day. At this time we expect that rate of production to continue for at least the next ten years, subject to normal decline. Drilling and completion costs for the wells on the West Electra Lake Prospect have ranged from approximately $160,000 to $220,000 per well, on an 8/8th basis.

In December 2004 we commenced a program to drill three more wells on the West Electra Lake unit. The first well was logged on December 7, 2004, and indicated the expected Milham pay interval, as well as an unexpected 12 feet of pay in the Saddle Creek formation at about 1700 feet. The second new well was logged on December 18, 2004 and encountered some ten feet of net pay in the Upper Milham formation. Both of these wells were completed as of January 31, 2005 and commenced producing commercial quantities of oil in March 2005. Four new wells were drilled in March and April, 2005 in the West Electra Lake area. As of September 30, 2005, three of these new wells are producing commercial quantities of oil. The forth well encountered shows of natural gas, but as there is no gas pipeline in the area, this well has been capped. We drilled four more development wells in the West Electra Lake area during September and October of 2005.

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We have drilled four non-commercial wells on the Virgin Reef and West Electra Leases. In May, 2002 we drilled the #2A well which targeted the lower Milham Sand formation. This well was only marginally productive, so we converted it to a saltwater disposal well. In December, 2002 we drilled the #2B well which targeted a reef prospect in the Canyon limestone formation. The #2B well was a dry hole. In July, 2004 we drilled the 1D and encountered only a sub economic pay in the Dyson sand. The well was therefore plugged and abandoned.

Matagorda County, Texas

We completed the leasing of 58 acres in Matagorda County, Texas in September 2005 on a salt dome prospect. In October 2005 we drilled our first well on this prospect and it was determined to be a commercially viable gas well. The drilling and completion costs on this well were approximately $317,591. We sold a 20% working interest in this well for $100,000 and retained 80% of the working interest. We are currently awaiting hook-up of this well to a nearby gas pipeline. The Operator of the well will be G.L. McLeod, Inc.

Michigan

In December 2002, through our Cadence division, we began participating in a natural gas drilling program in Alpena County, Michigan. As of September 30, 2005, we had a 22.5% working interest before payout, 22.5% after payout, 20% net revenue interest before payout, 18% after payout), in ten producing wells in Alpena County. Production commenced from this field in June 2003. See `Antrim Shale' subsection below".

New Mexico

In June 2004, we participated for a 20% working interest, 15% net revenue interest, in the Santa Nina Prospect in Eddy County, NM. This prospect was developed by and is operated by SDX Resources of Midland, TX, an experienced operator with over 20 years of operational experience in the Permian Basin. The well was completed in July 2004, with an initial flow rate in excess of 50 barrels of oil per day, plus natural gas. The well was produced for some 40 days, and then shut in to allow a gas pipeline to be attached. This work is in process. We received our first production check for this well in October 2004.

Early in 2004, we announced that we had signed an agreement with SDX Resources for an option to participate for up to a 25% working interest, 20% net revenue interest, in up to 17 development wells in a project called the Sparkplug Unit. These wells will be offsetting existing production in the San Andreas and Yeso formations to a maximum depth of about 5,000 feet. Drilling on the initial development well, in which we elected to take a 20% working interest, commenced on December 16, 2004. Initial results indicate multiple pay horizons in the San Andreas formation and the well was completed in February 2005. As a result of subsequent low production rates, the operator, SDX, has determined to dispose of this well; the sale of the well is in process.

Tennessee

In August 2004 we acquired an equity interest in TN Oil Company, which owns leases covering some 1500 acres prospective for oil in central and north central Tennessee. Subsequent to the end of the fiscal year, we elected to participate for 100% of the working interest in a well being drilled by TN Oil, as operator, to a depth of some 1700 feet. This well targeted oil production from the Murfreesboro and Knox formations. The well was spudded in December 2004. Based upon the well logs, our geologists determined that this well was non-commercial and elected to plug the well. A second non-commercial drill test was conducted by TN Oil in November 2005. The equity stake of the Company in TN Oil Co. is approximately 14% as of September 30, 2005.

Western Kansas

Our Kansas oil exploration project is in the Anadarko Basin in Lane and Ness Counties, Kansas. In June 2004, we completed our first leasing program in the area, consisting of approximately 28,000 acres. We have a 100% working interest and an approximate 82.5% net revenue interest in these leases. During September and October 2004, we completed a three dimensional seismic shooting program on the 13,000 acres which constitute the Cadence North Block. During the third quarter of 2005, we drilled our first two exploratory wells on the north block of its Kansas acreage. The first test well did not encounter commercial quantities of oil, and was plugged as a dry hole. The second well has been in production for the last 60 days and has produced commercially viable quantities of oil. The Operator of the project is SEDONA Oil & Gas Corporation.

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Antrim Shale Operations

Antrim Shale is a black shale that underlies the entire Michigan Basin. The shale is very thick (140 to over 200 feet) and has a high percentage organic content (15% to over 20%). Due to the nature of the natural fractures in the Antrim Shale, production will vary from well to well.

The productive, fractured trend for the Antrim Shale runs across the northern portion of the Michigan Basin from Lake Huron to Lake Michigan (160 miles). Gas wells have been drilled and produced in the Antrim Shale from depths of 250 feet down to 1,500 feet. A high percentage of the wells drilled in the Antrim Shale have been put into production, although as noted above, levels of production vary from well to well. Over 8,000 wells are currently producing in the Antrim Shale. In recent years, 200 to 300 wells have been drilled annually. It is expected that a similar number of wells will be drilled in 2006.

The gas produced from the Antrim Shale is a combination of thermogenic and biogenic gas. At shallower depths the gas is primarily biogenic due to the presence of microbes in the low to medium saline waters. The low-density pay zones in the Antrim Shale are over 100 feet thick. Methane gas is continuously being generated by anaerobic bacteria that feed on CO2, organic material, and the heavier thermogenic gases stored in the shale.

The Antrim Shale gas adsorbs to organic material in a similar manner to coal seams. Water in the natural fractures of the shale provides a trapping mechanism to hold the gas in place. As the water is produced to the surface, lowering the fluid and pressure in the reservoir, gases are released from the organic material and are produced to the surface. At depths of less than 1,500 feet, the gas-in-place is typically 90% methane or greater, with the balance being CO2 and some heavier thermogenic gases.

The oldest Antrim Shale gas field was drilled in the 1940s. It is still in production today. The production curve for the shale typically contains a peak rate of gas occurring after the first two years of production when the shale reservoir has been thoroughly de-watered. Peak rate production usually continues for some time. Cash values of production may be better five years or more into the life of a well than in the first six months of production, since dewatering takes up to two years to complete. After the water is off the formation and the gas is able to fully release from the shale into the well bore, the rate of production will typically begin to decline hyperbolically to a slow 2% to 3% exponential decline per year.

We have identified the Michigan Antrim Shale as an area with natural fractures using a variety of diagnostic tests, including a review of production trends, fracture imaging logs and geological mapping. In management's opinion, based upon performance information from almost 8,000 wells in similar circumstances, areas with natural fractures in shale have good production potential.

We currently plan to focus significant development activity over the next few years in the Michigan Antrim Shale. If sufficient capital is procured, we plan to drill up to 500 gross wells in the Michigan Antrim Shale over the next three years. Management believes that so long as our existing credit facility remains available and we are able to increase it as production increases, we will have sufficient financing to achieve this goal. We are, however, exploring possible avenues of additional equity financing. Changes in circumstances could necessitate more financing than currently contemplated, such as greater than budgeted costs or lower than expected production or gas prices. Other variables that will affect our ability to achieve our goals include unexpected drilling results, a shortage of available drilling rigs, delays in testing and drilling, difficulties in acquiring leases, a shortage of transportation pipelines, and new opportunities that cause management to change focus. Any one of these variables could cause actual results to differ materially from our current business plan.

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Samson Transaction

On May 14, 2004, we entered into a Purchase and Sale Agreement ("PSA") and Exploration Agreement with Samson Resources Company ("Samson") with respect to a substantial portion of our Michigan Antrim Shale properties. Pursuant to the PSA, we assigned to Samson 80% of our interest in the following assets:

·    Our working interests in all of our producing wells and related leaseholds in the Michigan Antrim comprising a total of 116 permitted wells, 66 of which had been drilled, and approximately 6,521 proved developed producing net leasehold acres.

·    Our interest in approximately 15,000 acres of undeveloped leaseholds in the Michigan Antrim. We did not include all of our Michigan Antrim leaseholds in this transaction, but limited this assignment to leases within an Area of Mutual Interest ("AMI") located generally in Alcona and Alpena Counties and the eastern 3/4ths of Montmorency County.

·    Our interest in an approximately 3.5 mile long pipeline that services the producing wells assigned, including equipment, leases, easements and permits.

·    Our interest in material contracts, such as marketing, transportation and gas treatment contracts, development agreements, unitization agreements, and equipment leases that relate to the assigned acreage.

Samson paid us $6,433,890 for these assets. With respect to the wells and leaseholds for which we served as operator, Samson was appointed as a replacement operator. The assignment was given a March 1, 2004 effective date.

The Exploration Agreement addresses development within the AMI with respect to leases that are jointly owned or jointly acquired by both us and Samson. The Exploration Agreement generally provides as follows:

·    Lease maintenance and acquisition expenses will be paid 80% by Samson and 20% by us.

·    Samson will be designated as the operator, but will hire us to conduct or oversee pre-drilling activities and operations for wells drilled in the AMI. We will specifically be responsible for lease acquisition; staking and surveying of wells to be drilled; regulatory and administrative matters such as well permitting, pipeline permitting and compliance with bonding requirements; title review and title curative; surface/access negotiations and settlements; and location preparation. Samson will pay us $750 per well drilled for these activities, an expense to which we are not required to contribute.

·    Samson is responsible for the receipt and distribution of all revenues.

·    For the first 150 wells drilled pursuant to the Exploration Agreement, Samson will pay 88% of the actual cost to drill and complete, and we will pay 12%. This includes costs for gathering and surface equipment that are included in the Authority for Expenditure ("AFE") prepared by Samson. This is called a "promoted" share. Samson's obligation is, however, capped at 110% of the estimated drilling and completion costs for the well as reflected in the AFE.

·    From the 151st well forward, Samson will pay 80% of the development costs and we will pay 20%.

·    The working interest for each well will be owned 80% by Samson and 20% by us. All operating costs, costs associated with compression, treatment (such as CO2 removal), processing or road use/access, and expenses associated with pipeline, gathering or surface facilities not included in the AFE for the well, will track the working interest percentages. Revenue participation will also track the working interest percentages.

·    Each party has a preferential right to purchase (right of first refusal) that applies if the other party seeks to assign its interest in a lease or well within the AMI.

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As of September 30, 2005, approximately 83 wells have been drilled under the Exploration Agreement. Of these, 56 are producing, 19 are not yet in production, four are salt water disposal wells, and four were plugged and abandoned.

CDX Transaction

In January 2002, we sold the leases for several Antrim prospects to CDX Gas, LLC ("CDX"). In 2004, we entered into a Farmout Agreement with CDX with respect to an area of mutual interest that included much of the acreage we had sold to CDX. On December 1, 2005, we entered into an Exchange Agreement with CDX rescinding all prior agreements and agreeing to effectuate an exchange, pursuant to which CDX will assign to us all of CDX's interest (including reversionary interests) in Michigan Antrim Shale properties, including the Black Bear and Almira-Long Lake properties. In return, we will assign to CDX all of our interest (including reversionary interests) in the CDX Indiana and Kentucky New Albany Shale properties (with non-material exceptions), including the Corydon, Dumada-Loogootee, Maria Creek, Orleans, Jordan and Hogback properties.

Samson Antrim Projects

As of September 30, 2005, we owned the following properties in the Michigan Antrim Shale, which are part of the Samson joint venture.

·    The Treasure Island Antrim Project is located in Alpena County, Michigan, and consists of approximately 2,373 acres. This project currently has 26 wells. Twenty-three of these wells are producing commercial rates of gas. Two of these wells have been plugged and abandoned. One Salt Water Disposal Well has also been drilled. Production from the initial wells in the project began in October 2003. Gas is transported on the DTE Alpena LP Pipeline and sold into the Alpena Gaylord line. The project is expected to have a production life of approximately 30 to 40 years. We currently own an 18% working interest.

·    The Black Bean Antrim Project is located in Alpena County, Michigan, and consists of approximately 4,385 acres. This project is currently divided into four separate projects, as described below. Gas from this project is sold through the Paxton Quarry facility into the Thunder Bay Pipeline. The project is expected to have a producing life of approximately 30 to 40 years.

·    Black Bean #1 currently has 16 drilled wells. Thirteen of these wells have been completed and are producing commercial rates of gas. Two wells have been plugged and abandoned, and one Salt Water Disposal Well has been drilled. Our business plan contemplates that five additional wells, in addition to those currently permitted, will be drilled as part of Black Bean #1. We and our affiliates currently own approximately a 15.5% working interest in the Black Bean #1 project.

·    Black Bean #2 currently has two drilled wells which have been completed and are producing commercial rates of gas. Two more wells have been permitted, but have not yet been drilled. Our business plan contemplates that five additional wells in addition to those currently permitted, will be drilled as part of Black Bean #2. We currently hold approximately a 28.72% working interest in Black Bean #2.

·    Black Bean #3 currently has four drilled wells which have been completed and are producing commercial rates of gas. One more well has been permitted, but has not yet been drilled. We currently hold approximately a 29.22% working interest in Black Bean #3.

·    Black Bean #4 does not yet have any wells that have been drilled. No specific drilling plans have yet been proposed. We will hold approximately a 20.00% working interest in Black Bean #4.

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·    The Beyer Antrim Natural Gas Field Project is located in Alpena, Michigan. It consists of approximately 2,575 acres. This project currently has 18 drilled wells. Sixteen are producing commercial rates of gas. One well has been plugged and abandoned. One Salt Water Disposal Well has also been drilled. Two additional wells have been permitted but not yet been drilled. Our business plan contemplates that, in addition to those wells currently permitted, one more well will be permitted and drilled. Production began in this field in February 2002. Gas is sold through the Paxton Quarry Facility into the Thunder Bay Pipeline. The project should have a production life of approximately 30 years. We and our affiliates currently own a 7.639% working interest in this project.

·    The Paxton Quarry Antrim Project is located in Alpena County, Michigan, and consists of approximately 2,485 acres. Currently, 18 wells have been drilled. Fifteen wells have been completed and are producing commercial rates of gas. Two of the wells have been plugged and abandoned. One of the wells is a Salt Water Disposal Well. Production from this field began in November 1998. Gas is sold into the Thunder Bay Pipeline. The project should have a production life of approximately 30 years. We own a 19.8% working interest in this project.

·    The Clear Lake Project is located in Alpena County, Michigan, and consists of approximately 4,148 acres. Two wells have been drilled in this project. They are not yet in production. Gas will be sold into the Thunder Bay Pipeline. We currently hold a 20% working interest in this project.

·    The Discard Project is located in Alpena County, Michigan, and consists of approximately 1,512 acres. One well has been drilled in this project. It is not yet in production. Four more wells have been permitted, but have not yet been drilled. Gas will be sold into the Thunder Bay Pipeline. We currently hold a 20% working interest in this project.

·    The Gehrke Project is located in Alpena County, Michigan, and consists of approximately 2,698 acres. Twenty-one wells have been drilled in this project. Seventeen are producing commercial rates of gas. Four more wells have been permitted, but have not yet been drilled. Our business plan contemplates that one more well in addition to the wells currently permitted will be drilled as a part of this project. Gas is sold into the Thunder Bay Pipeline. We currently hold a 20% working interest in this project.

·    The Green Bean #1 Project is located in Alpena County, Michigan, and consists of approximately1,696 acres. One well has been drilled in this project, but is not yet in production. Six wells have been permitted, but not yet drilled. Our current business plan contemplates that a total of 13 wells will be drilled in this project. Gas will be sold into the Paxton Quarry Facility and then into the Thunder Bay Pipeline. We currently hold a 20% working interest in this project.

·    The Green Bean #2 Project is located in Alpena County, Michigan, and consists of approximately 940 acres. Three wells have been drilled in this project. They are not yet in production. Five more wells have been permitted, but have not yet been drilled. Our current business plan contemplates that a total of 12 wells will ultimately be drilled in this project. Gas will be sold into the Paxton Quarry Facility and then into the Thunder Bay Pipeline. We currently hold a 39.22% working interest in this project.

·    The Leeseberg #1 Project is located in Alpena County, Michigan, and consists of approximately 429 acres. No wells have yet been drilled in this project, but three wells have been permitted. Our current business plan contemplates that a total of seven wells will be drilled in this project. Gas will be sold into the Thunder Bay Pipeline. We currently hold a 20% working interest in this project.

·    The Leeseberg #2 Project is located in Alpena County, Michigan, and consists of approximately 1,094 acres. No wells have yet been drilled in this project, but two wells have been permitted. Our current business plan contemplates that a total of five wells will be drilled in this project. Gas will be sold into the Thunder Bay Pipeline. We currently hold a 20% working interest in this project.

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·    The Mackinaw #1 Project is located in Alpena County, Michigan, and consists of approximately 1,670 acres. No wells have yet been drilled in this project, but 10 wells have been permitted. Our current business plan contemplates that a total of 12 wells will be drilled in this project. Gas will be sold into the Thunder Bay Pipeline. We currently hold a 20% working interest in this project.

·    The Mackinaw #2 Project is located in Alpena County, Michigan, and consists of approximately2,520 acres. Nine wells have been drilled in this project. Five of these are in production. Five more wells have been permitted, but have not yet been drilled. Our current business plan contemplates that a total of 18 wells will be drilled in this project. Gas will be sold into the Thunder Bay Pipeline. We currently hold a 20% working interest in this project.

·    The Mt. Mohican Project is located in Alcona County, Michigan, and consists of approximately 15,447 acres. Three wells have been drilled in this project. They are not yet in production. Ten more wells have been permitted, but have not yet been drilled. Our current business plan contemplates that a total of 61 wells will be drilled in this project. The pipeline to be used has not yet been determined. We currently hold a 20% working interest in this project.

·    The Nicholson Hill #1 Project is located in Alpena County, Michigan, and consists of approximately 569 acres. Two wells have been drilled in this project. They have been completed and are producing. Two more wells have been permitted, but have not yet been drilled. Our current business plan contemplates that a total of five wells will be drilled in this project. Gas will be sold into the Thunder Bay Pipeline. We currently hold a 20% working interest in this project.

·    The Nicholson Hill #2 Project is located in Alpena County, Michigan, and consists of approximately 2,967 acres. One well has been drilled. It is not yet in production. Our current business plan contemplates that a total of 11 wells will be drilled in this project. Gas will be sold into the Thunder Bay Pipeline. We currently hold a 20% working interest in this project.

·    The Nicholson Hill #3 Project is located in Alpena County, Michigan, and consists of approximately 1,459 acres. One well has been drilled. It is not yet in production. Our current business plan contemplates that a total of 11 wells will be drilled in this project. Gas will be sold into the Thunder Bay Pipeline. We currently hold a 20% working interest in this project.

·    The Northwest Michigan Project is located in Benzie County, Michigan, and consists of approximately 20,478 acres. Two wells have been drilled, one of which has been plugged and abandoned. The other well is not in production. No further wells are currently scheduled to be drilled in this project, but the plans could change in the future.

·    The Sequin Project is located in Alpena County, Michigan, and consists of approximately 1,776 acres. Eighteen wells have been drilled. Sixteen of these wells are producing commercial quantities of gas, one well has been plugged and abandoned, and one well is a salt water disposal well. We currently hold a 20% working interest in this project.

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Hudson Antrim Project

The Hudson Antrim Project is located in Charlevoix County, Michigan. It is being developed in a joint venture with Oilfield Investments, Ltd. ("Oilfield"), an affiliate of O.I.L. Energy Corp. This project is currently divided into eight separate units, as described below. Gas produced from this project will initially flow to the central production and processing facility owned by Hudson Pipeline & Processing Co., LLC. Information as of September 30, 2005 follows:

·    The Hudson 34 unit is comprised of approximately 1,438 acres, and to date has two salt water disposal wells, 21 wells producing commercial quantities of gas, and one well that has been plugged and abandoned. An additional three wells have been permitted but are not yet drilled. We hold a 46.58% working interest before payout and a 45.33% working interest after payout. Oilfield is the operator.

·    The Hudson SW unit is comprised of approximately 1,122 acres, and to date has two saltwater disposal wells, 21 wells producing commercial quantities of gas, and three wells not yet in production. We hold a 37.54% working interest before payout and a 36.54% working interest after payout. Oilfield is the operator.

·    The Hudson NE unit is comprised of approximately 1,312 acres, and to date has one salt water disposal well, 21 wells that are producing commercial quantities of gas, one well that has been plugged and abandoned, and four gas wells that are not yet in production. Three additional wells have been permitted, but are not yet drilled. We hold a 48.54% working interest before payout and a 47.29% working interest after payout. We are the operator.

·    The Hudson NW unit is comprised of approximately 2,096 acres. Nineteen wells have been drilled in this unit, none of which are yet in production. Two are salt water disposal wells. An additional five wells have been permitted, but are not yet drilled. Our current business plan contemplates that a total of 25 wells will be drilled in this unit. We hold a 76.08% working interest before payout. We are the operator.

·    The Hudson #13 unit is comprised of approximately 379 acres. To date, one well has been drilled, It is not yet in production. An additional seven wells have been permitted but are not yet drilled. Our current business plan contemplates that a total of eight wells will be drilled in this unit. We hold a 31% working interest before payout and a 30% working interest after payout. We are the operator.

·    The Hudson #19 unit is comprised of approximately 249 acres. To date, three wells have been drilled, but are not yet in production. We do not currently plan to drill additional wells in this Unit. We hold a 78% working interest before payout and a 76.75% working interest after payout. We are the operator.

·    The Hudson West unit is comprised of approximately 616 acres. To date, three wells have been drilled. Two of these are awaiting hook-up and are not yet in production. One has been plugged and abandoned. Our current business plan contemplates that a total of 14 wells will be drilled in this unit. We hold a 44% working interest. We are the operator.

·    The Hudson Joint unit is comprised of approximately 1,867 acres for which we do not yet have a business plan. We hold a 50% working interest before payout.

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The table below demonstrates the results of operations of the foregoing Hudson projects from January 1, 2005 through September 30, 2005:

GROSS PROJECT PRODUCTION
Production Month	Hudson 34		# of Wells		Hudson SW		# of Wells		Hudson NE		# of Wells		Total MCF’s		Total Wells
January-05		25,475		17		–		–		–		–		25,475		17
February-05		24,875		17		5,981		2		–		–		30,856		19
March-05		25,343		17		10,345		10		–		–		35,688		27
April-05		24,081		17		16,540		13		6,794		8		47,415		38
May-05		22,265		18		23,854		13		29,796		11		75,915		42
June-05		24,965		21		26,222		13		36,336		11		87,523		45
July-05		27,738		21		34,810		14		41,526		17		104,074		52
August-05		29,549		21		34,119		14		58,591		21		122,259		56
September-05		31,429		21		38,903		14		70,722		21		141,054		56
TOTALS		235,720				190,774				243,765				670,259

NET PROJECT PRODUCTION
Production Month	Hudson 34		# of Net Wells		Hudson SW		# of Net Wells		Hudson NE		# of Net Wells		Total MCF’s		Total Net Wells
January-05		10,164		7		–		–		–		–		10,164		7
February-05		9,396		7		1,826		1		–		–		11,222		8
March-05		9,706		7		3,181		3		–		–		12,887		10
April-05		9,223		7		5,085		4		2,671		3		16,979		14
May-05		8,528		7		9,004		4		11,801		4		29,333		15
June-05		9,562		8		8,062		4		14,391		4		32,014		16
July-05		10,624		8		10,703		4		16,446		7		37,773		19
August-05		11,317		8		10,490		4		23,205		8		45,012		21
September-05		12,037		8		11,961		4		28,009		8		52,008		21
TOTALS		90,557				60,312				96,523				247,392

Other Antrim Projects

Information on other Michigan Antrim drilling projects as of September 30, 2005 follows:

·    The 1500 Antrim Mio Project is located in Oscoda County, and consists of approximately 17,365 acres. One well has been drilled in the project. It is not yet in production. A salt water disposal well has also been drilled. Two more wells have been permitted, but have not yet been drilled. Our current business plan contemplates that a total of 18 wells will be drilled in this project. The pipeline to be used has not yet been determined. We hold a 48.33% working interest in this project. We are the operator.

·    The Blue Chip Project is located in Montmorency County, Michigan, and consists of approximately 1,800 acres. One well has been drilled in this project but is not yet in production. Another four wells have been permitted. Our current business plan contemplates that a total of eight wells will be drilled in this project. Gas will be sold into the MichCon Wet Header Pipeline. We hold a 100% working interest in this project, and we are the operator.

·    The Arrowhead Project is located in Montmorency County, Michigan, and consists of approximately 3,683 acres. Ten wells have been drilled in this project, but are not yet in production. Another five wells have been permitted but are not yet drilled. Our current business plan contemplates that a total of 24 wells will be drilled in this project. Gas will be sold into the MichCon Wet Header Pipeline. We currently hold a 100% working interest in this project before payout and an 80% working interest after payout. We are the operator.

·    The 400 Antrim Project is located in Cheboygan County, Michigan, and consists of approximately 5,433 acres. No wells have yet been drilled. Four wells have been permitted. We hold a 100% working interest in this project, and we are the operator.

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·    The Black Bear Central unit consists of approximately 2,178 acres. Five wells have been drilled, but are not yet in production. One salt water disposal well has also been drilled. Thirteen more wells have been permitted, but have not yet been drilled. Our current business plan contemplates that a total of 27 wells will be drilled in this unit. Production will be sold through the Hudson and Dogwood Pipelines. We hold a 100% working interest in this unit before payout, and a 60% working interest after payout. We are the operator.

·    The Dover project consists of approximately 505 acres. To date, it has two wells producing commercial quantities of gas and one salt water disposal well. Production is sold through the North Charlton 7 Pipeline. No additional wells are planned for this project. We hold a 20% working interest in this project. Savoy Energy is the operator.

·    Undeveloped acreage - We have acquired mineral rights for prospects that are being held for development in future years. As of September 30, 2005, this involved approximately 31,831 gross acres in 21 prospects at varying working interest percentages.

New Albany Shale Operations

The New Albany Shale is found in the Illinois Basin, much of which is located in the state of Indiana. The New Albany Shale is at least 100 feet thick throughout Indiana, with proven producing pay zones throughout. The shale is capped by a very thick, dense, gray-green shale (Borden Shale). The play covers 6,000,000 acres.

In the New Albany Shale, a well commonly produces water along with the gas. It was learned in the early 1900's that a simple open-hole completion in the very top of the shale would yield commercial gas wells that would last for many years, even while producing some water. Vertical fractures in the shale feed the gas flow at the top of the shale. The potential of these wells was seldom realized in the early to mid twentieth century, as the production systems for handling the water were limited. However, with current technology, the water can be dealt with cost effectively. As a result, the water produced can be kept off of the shale, allowing better rates of gas production. Utilizing the success of simple completions and modern water production systems, long-term production of natural gas is achieved.

Current recoverability of gas from vertical wells to the black shale is estimated typically at 15% to 20% of gas-in-place. On a well-to-well basis, this recoverability varies depending on the natural fracture intensity associated with each well bore. Production volumes from the black shale are related mostly to the ability to desorb gas from the shale. Removing the hydrodynamic trap on the shale is the key to producing shale gas. This is accomplished with a large sump drilled downward from the lowest point in the well bore. Water is produced to the surface for disposal in approved salt water disposal wells with electric submersible pumps. As the water pressure in the fractures is removed from the shale, the gas begins to release through open natural fractures. The lower the producing pressure of the well bore, the greater its capacity to produce gas. We utilize production systems that keep the pressure low from the reservoir to the sales line. Included in development plans are drilling under balanced whenever possible, producing gas from wells at low pressures and designing pipeline and facility systems to operate at less than 250 pounds of pressure. This will also be the maximum pressure maintained through our CO2 reduction units.

Significant research and study has been conducted to evaluate the producibility of the New Albany Shale. In cooperation with the Gas Research Institute, we combined resources and data with 11 other industry partners in a shale gas producibility consortium lasting almost two years (concluded in 1999). The consortium identified critical differences and similarities of the New Albany Shale play to other shale plays. Reserve studies were conducted on behalf of the consortium by Schlumberger Holditch & Associates ("Schlumberger"), a third party engineering firm, for both vertical producing wells and horizontal wells. Since then, we have participated in 15 pilot horizontal well drilling programs across multiple counties which support the conclusions of the consortium. With the data from these pilot wells, we have established a development concept for the New Albany Shale, which we hope to begin implementing in 2006. Numerous interstate pipelines intersect the New Albany Shale acreage in which we hold working interests and residual overriding royalty interests.

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We continue to actively explore opportunities in the New Albany Shale. Although we have sold off large portions of the leases we have acquired to joint venture partners, we continue to aggressively lease new projects, which we plan to develop once management has an opportunity to learn from our joint venture partners what geological work and drilling methods are most efficient in this area. In many cases, when we have sold leases in the New Albany Shale, we have retained a carried working interest or overriding royalty interests as described in more detail below.

Wiser Oil Transaction

In a joint venture with the Wiser Oil Company ("Wiser"), we acquired approximately 10,143 acres of leasehold in Pike County, Indiana, in the New Albany Shale play. In 2003, we drilled three horizontal wells in the Pike project. We have now transferred operations to Wiser, but have retained working interests and carried working interests, as follows:

Test Wells: 21.25% working interest First 50 Subsequent Wells:

Before Payout - NRI 87.5% or greater: 29.125% working interest (of which 7.875% is carried by Wiser to the point of the sales meter) Before Payout - NRI below 87.5%: 26.125% working interest (of which 4.875% is carried by Wiser to the point of the sales meter) After Payout: 31% working interest

After First 50 Subsequent Wells: carried working interest is reduced from a proportionate 10% to a proportionate 7.5%

"Payout" means the first day of the month following the point that 100% of costs associated with the well or group of wells flowing through one sales meter has been recouped out of net revenues.

Since entering into this joint venture arrangement no significant new development activity has occurred. The number of acres of leaseholds in the project is now approximately 8,536. Wiser has recently been sold to Forest Corporation.

Quicksilver Transactions

In February 2003, we sold two major blocks of mineral leases and related assets to Quicksilver Resources, Inc. of Fort Worth, Texas ("Quicksilver"). We sold our interests in the Georgetown Fault, Corydon, Organ Creek, Graben, M-J, J-L and Orleans Projects to Quicksilver. We delivered an 80% net revenue interest for these leases. To the extent we owned more than an 80% net revenue interest before the assignment, we retained the balance as an overriding royalty interest.

Indiana Joint Venture

We entered into a Development Agreement (the “Development Agreement”) dated December 6, 2003, for a joint venture with Wabash Energy Partners, L.P. (“Wabash”), to acquire and develop mineral leases for the New Albany Shale gas play in Indiana. As described below, Wabash also owns a 20% membership interest in Aurora Operating, L.L.C.

On October 13, 2005, we entered into a Purchase and Sale Agreement (the “Wabash Purchase Agreement”) with Wabash. Under the Wabash Purchase Agreement, we agreed to purchase all of Wabash’s interest in the leases that were acquired under the Development Agreement, Wabash’s 20% interest in Aurora Operating, L.L.C., and the interest that Wabash has in a farmout agreement it had previously entered into jointly with Aurora relating to certain additional Indiana leaseholds. Upon closing of the transaction, the Development Agreement will be terminated. The closing is scheduled to occur by February 1, 2006. There are certain conditions to closing that must be satisfied before a closing will occur.

On November 15, 2005, we entered into a Purchase and Sale Agreement (the “New Albany Agreement”) with New Albany-Indiana, LLC (“New Albany”), pursuant to which New Albany has agreed to purchase from us an undivided 48.75% working interest (40.7% net revenue interest) in the leaseholds that are the subject to the Wabash Purchase Agreement. In addition, at the closing of the New Albany purchase, we will grant New Albany an option, exercisable for a period of 18 months at a fixed price per acre, to acquire a 50% working interest in additional acreage leased or acquired by us within certain other specified counties located in Indiana. The closing is scheduled to occur by February 1, 2006. There are certain conditions to closing that must be satisfied before a closing occurs. New Albany is owned 50% by College Oak Investments, Inc. and 50 % by Rex Energy Operating Corp. We will serve as operator for all of the wells drilled that we participate in under the New Albany Agreement.

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The effect of the Wabash Purchase Agreement and the New Albany Agreement is to substitute New Albany as our joint venture partner for the Indiana acreage in question, increase our ownership position from a 17.5% working interest to a 48.75% working interest (40.7063% net revenue interest), and provide that we will be the operator for these Indiana wells.

El Paso Transactions

On November 4, 2003, we entered into an Assignment Agreement with El Paso Production Company ("El Paso") on behalf of the Company and Aurora Operating, L.L.C., under which we agreed to assign to El Paso the mineral leases for approximately 90,000 acres located in Dubois, Knox, Martin and Daviess Counties in Indiana (the "Dumada AMI"). These acres fall within the potential New Albany Shale gas development region. The Assignment Agreement also reserves to El Paso the right to require us to exercise an option that we have with respect to the mineral leases owned by Highway Resources, Inc., and resell them to El Paso at our acquisition price.

With respect to all mineral leases acquired by El Paso under the Assignment Agreement, we have retained a 5% carried working interest in the first 50 wells drilled, including salt water disposal wells, horizontal pilot wells, and wells drilled for the purpose of taking core samples, in addition to wells drilled for the purpose of taking gas production. With respect to wells drilled for the purpose of gas production, El Paso must bear the expenses for our 5% working interest associated with drilling, testing, completing and connecting the well to the lease sales meter, but we must bear our expenses associated with costs and expenses incurred after connection to the lease meter, plus all costs associated with catastrophic events. With respect to salt water disposal wells, El Paso must bear the expenses for our 5% working interest associated with drilling, casing, stimulating, testing, equipping of and first successful injection of water into the well, and we must bear our associated costs and expenses after the first successful injection of salt water into the well. With respect to wells drilled for the purpose of taking core samples, El Paso must bear all of the expenses for our 5% working interest. Starting with the 51st well, we must bear 5% of all costs and expenses.

El Paso will own 100% of all gathering systems, flow lines, facilities, appurtenance and equipment it installs down stream of the lease meter. We must bear our 5% of costs associated with compression treatment, gathering and transportation charges related to gas and water produced.

El Paso agreed to drill three horizontal pilot wells and three salt water disposal wells in the Dumada AMI subject to a $2,225,000 expense cap. It has agreed to make a good faith effort to lease a minimum of 50,000 net acres within the Dumada AMI to support this drilling commitment, subject to a $1,000,000 expense cap. In late 2004 El Paso notified us that it has now satisfied this commitment.

Through September 30, 2005, El Paso had drilled seven gas wells in the Dumada AMI. These wells are waiting on pipeline installation and are not yet in production. The total acres leased in the El Paso Dumada AMI as of September 30, 2005 is approximately 162,328.

The Assignment Agreement provided that after drilling the pilot wells, El Paso had until January 3, 2005 to decide whether to retain some or all of the mineral leases in the Dumada AMI we had previously assigned to it. On December 30, 2004, El Paso notified us of its election to retain all of the leases. The retention election was closed on January 6, 2005, at which time, El Paso paid us $7,321,000.

On July 9, 2004, we entered into a separate Purchase and Sale Agreement with El Paso concerning 8,843.38 gross and net leasehold acres located in Daviess County, Indiana. These are the leases originally owned by Highway Resources, Inc. addressed in the original Assignment Agreement. El Paso acquired an undivided 95% working interest in these leases, and we retained a 5% working interest. El Paso paid us $349,829, which is the same price that we paid Highway Resources, Inc. for the leases.

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CDX Transaction

In 2001 and 2002, we sold leasehold acreage to CDX from the New Albany Shale formation. That includes: approximately 33,217 acres in Breckinridge and Meade Counties, Kentucky; approximately 13,967 acres in the Maria Creek project located in Knox and Sullivan Counties, Indiana; approximately 1,723 acres in Harrison County, Indiana; approximately 11,918 acres in the Loogootee project located in Daviess, Dubois and Martin Counties, Indiana; and approximately 39,800 acres in Washington and Floyd Counties, Indiana. In each case, we retained a 5% carried working interest before payout and an additional 15% carried working interest after payout. As noted above, on December 1, 2005, we entered into an Exchange Agreement with CDX in which we agreed to give up our entire interest in these projects in return for receiving an assignment of all of CDX's interest in certain Michigan Antrim Shale properties.

Knox Gas Development Project

In February 2005, we entered into a Development Agreement with Horizontal Systems, Inc. of Casey, Illinois ("HSI"). This agreement has since been amended twice to expand the area of mutual interest to which it applies. It now applies to most of Knox County, Indiana, with limited specified exceptions, and is called the Knox Gas Development Project. Under this Development Agreement, we will own 75% of the working interest in the project and HSI will own 25%. Neither party will retain overriding royalties. We are responsible for acquiring all of the leases in the project area, but will acquire them in HSI's name. HSI will initially be the operator, though we have retained the right to assume operations, in our discretion. For the first 25 wells drilled, we will pay 75% of costs plus 10%. Thereafter, we will be responsible for only 75% of costs. The Development Agreement provides that at least two horizontal wells will be drilled in the project in 2005. As of September 30, 2005, one of these wells had been drilled, but is not yet in production, and 19,155 acres of leasehold had been acquired.

Other New Albany Shale Projects

We have acquired other mineral rights in New Albany Shale projects that are being held for development in future years. As of September 30, 2005, we have acquired 111,818 acres of leasehold in 11 different fields in the New Albany Shale in Indiana, and 44,277 acres of leaseholds in two fields in Kentucky, all at a 100% working interest.

Crossroads Project

Henry County, Ohio was the site of oil and gas exploration in 1885, 1975 and 1985. Each time gas was found with some oil. Because there was no pipeline to transport gas to market from this area, the 1985 effort was abandoned by the operator. In 1995, Crossroads Pipeline Company converted a 20-inch oil transport line that runs through Henry County into a natural gas transport line. This opened the area to natural gas exploration and production.

In 1998, we began leasing land in Henry County for what is known as the Crossroads Project. In July 1998, three exploratory wells that had previously been drilled were drilled out again and tested. In January 1999, we initiated development by drilling out an additional four pre-existing wells and acquiring four producing wells. As of September 30, 2005, there are 10 producing wells. We have an additional leasehold targeting an area with potential of more than 200 wells. We originally owned 76% of the leasehold and working interests in this acreage.

On March 31, 2004, we entered into a Development Agreement with Oil & Gas Engineering GmbH, an Austrian Company ("OGE") with respect to the Crossroads project. OGE purchased all of our interest in this project. OGE agreed to expend $2,600,000 developing the project, subject to certain limitations. OGE immediately advanced us $94,000 to be used for getting the existing wells back in production. The remainder of the $2,600,000 will be spent only as supported by seismic analysis to develop another seven wells. OGE's obligation to expend funds will cease at the time the Crossroads project is producing at least 2,000 MCF per day, even if the full $2,600,000 has not yet been expended. If either this minimum production level has not been achieved or the full $2,600,000 has not been expended by March 1, 2006, all of the assets will be reassigned to us.

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Although OGE will be in control of all decision making with respect to the exploration and development of the wells in the Crossroads project, OGE is required to subcontract to us the actual field operations, unless we decide we do not want to continue in this role. Until OGE receives net revenue from production from the Crossroads Project in the amount of the committed funds actually expended by OGE, OGE will receive 90% of net revenues and we will receive 10%. Thereafter, OGE will receive 75% of net revenues and we will receive 25%. If the project is abandoned and shut in, OGE will pay up to $500,000 of the associated costs, and we will pay for anything over $500,000, if any. Since this agreement was entered into on March 31, 2004 until recently, only minimal development activity had occurred. We have now drilled a salt water disposal well. In June 2005, gas plant operations were started, with nominal production to date as the 10 shut-in wells are being brought back into production.

The Eastern Group

In December 1997 we acquired from Jet Exploration, Inc. ("Jet") small interests in Antrim shale wells in three projects located in Alcona County, Michigan. We have a 2.3% working interest before payout and 3.68% after payout in the Devil River Project where 10 wells began producing in November of 1998. We have a 1.5% working interest in the Blue Spruce Project, which began producing in September 1997 and has 16 producing gas wells and one salt water disposal well. We own a 1.8% working interest before payout and 3.18% after payout in the Timm Project that started producing in August of 1998 and has 21 wells producing. The majority interest owner and Operator of these projects is Petroleum Development Corporation of West Virginia. These wells are producing a positive cash flow to us.

Beregsasi Reef Field

The Beregsasi is a one-well field located in Sterling Heights, Michigan. West Bay Exploration is the operator. The well is producing oil and gas from the Niagaran formation. Production began in August 1999. We own a 9% working interest.

Church Lake Field

The Church Lake Field is a six-well oil field in the Richfield formation in northern Michigan which produces an average of 32 barrels of oil per day. Petroleum Development Corporation is the operator of this field and major interest holder. We have a 17.5% working interest in the third through the sixteenth wells and a 22.5% working interest in an additional five wells.

Miscellaneous Well Interests

We acquired small interests in numerous fields in 2000. We do not serve as operator for any of these interests. They generate an overall positive cash flow to us.

Drilling Funds

We have acted as promoter and manager for three drilling funds, as follows:

·    Aurora Investments, LLC was formed in 2001. Membership interests totaling $954,000 were sold to 15 investors. Aurora Investments, LLC purchased a 41.63% working interest in 14 natural gas wells drilled in the Beyer Antrim project in Alpena County, Michigan. As a result of the Samson Transaction, the working interest was reduced to 1.98%. We have accepted a distribution of our prorated share of the working interests in the leases owned by Aurora Investments, LLC. As a result, we no longer have an equity interest in Aurora Investments, LLC. However, we continue to serve as manager of Aurora Investments, LLC, and are entitled to receive a fee equal to $300 per net well per month as compensation for overseeing operations and production.

-17-

·    Beyer Antrim Company, L.L.C. was formed in 2002. A membership interest totaling $650,000 was sold to one outside investor. Beyer Antrim Company, L.L.C. purchased a 16.14% working interest in 14 natural gas wells drilled in the Beyer Antrim project in Alpena County, Michigan. As a result of the Samson Transaction, the working interest was reduced to .71%. We have accepted a distribution of our prorated share of the working interests in the leases owned by Beyer Antrim Company, L.L.C. As a result, we no longer have an equity interest in Beyer Antrim Company, L.L.C. However, we continue to serve as a manager of Beyer Antrim Company, L.L.C., and are entitled to receive a fee equal to $300 per net well per month as compensation for overseeing operations and production.

·    Aurora Natural Gas Production, LLC was formed in 2002. Membership interests totaling $455,000 were sold to 13 investors. Aurora Natural Gas Production, LLC purchased a 17% working interest in 10 natural gas wells in the Black Bean #1 Antrim project located in Alpena County, Michigan. As a result of the Samson Transaction, the working interest was reduced to 0.60%. We have accepted a distribution of our prorated share of the working interests in the leases owned by Aurora Natural Gas Production, LLC. As a result, we no longer have an equity interest in Aurora Natural Gas Production, LLC. However, we continue to serve as manager of Aurora Natural Gas Production, LLC, and are entitled to receive a fee equal to $300 per net well per month as compensation for overseeing operations and production.

Financing Subsidiary

Aurora Antrim North, L.L.C. ("AAN") is a wholly-owned subsidiary of our Aurora subsidiary. It is the borrower under the TCW Energy, et al. credit facility, and holds those assets pledged as collateral under the credit facility. These assets include all of our Michigan Antrim Shale properties located in Alcona, Alpena, Charlevoix, Cheboygan, Montmorency, and Otsego Counties, and an interest in the Hudson Pipeline & Processing Co., LLC, as described below.

Other Subsidiaries and Affiliates

Aurora Operating, L.L.C. ("AOC"), owns an interest in approximately 56,000 acres of New Albany Shale leasehold interests in Martin, Daviess and Dubois Counties, Indiana. Our Aurora subsidiary originally owned a 71% membership interest, with the balance owned by 11 unrelated limited liability company members. On November 21, 2003, we sold a portion of our membership interest to Wabash Energy Partners, L.P. ("Wabash"), resulting in Wabash holding a 20% membership interest while we continue to own a 51% membership interest. As described above, on October 13, 2005 we entered into the Wabash Purchase Agreement. At the closing, which is scheduled to occur by February 1, 2006, we will repurchase this membership interest from Wabash and again own a 71% membership interest.

Aurora Production, L.L.C. is the nominal owner of a number of override interests in the New Albany Shale projects. These assets have been assigned to Indiana Royalty Trustory, L.L.C. by letter agreement, but lease assignments have not yet been recorded. Our Aurora subsidiary owns a 51% membership interest in Aurora Production, L.L.C. for purposes of voting, but receive only 50% of net revenue distributions. The balance is owned by LaVanway Capital & Trade Corporation. All operations of Aurora Production, L.L.C. ceased as of December 31, 2003. As we acquire new interests in New Albany Shale projects, we are acquiring them in the name of our Aurora subsidiary, and not through Aurora Production, L.L.C.

Indiana Royalty Trustory, L.L.C. ("IRT") owns an overriding royalty in the amount of 2.5% on approximately 60,000 acres in the New Albany Shale in Indiana. Certain assets are also in the process of being assigned from Aurora Production, L.L.C., as described above. Our Aurora subsidiary owns a 50% membership interest in IRT. The balance is owned by LaVanway Capital & Trade Corporation.

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Hudson Pipeline & Processing Co., LLC ("Hudson") owns a facility plant, pipeline, rights-of-way and meter used by nearby Antrim wells, and processes the gas produced from those wells. AAN owns a 48.75% membership interest in this limited liability company. The balance is owned by O.I.L. Energy Corp. ("OIL"), and Major Pipeline, LLC. After Hudson receives revenues equal to 125% of the amount spent on construction of the pipeline by AAN and OIL, Major Pipeline, LLC will receive an increased ownership percentage, and AAN's interest will drop to 47.50%.

Geopetra Partners. LLC ("Geopetra") is a limited liability company engaged primarily in the identification and evaluation for acquisition of oil and gas properties and interests in entities which hold such properties and interests, identification and evaluation of areas to be explored and developed for the production of oil and gas, and providing consulting services to its members in connection with other oil and gas properties and interests, operations and activities. Geopetra was formed on April 1, 2005. Our Aurora subsidiary owns a 30% interest in Geopetra for which we paid $14,000. To date, Geopetra's operations have not been significant.

Oil and Gas Reserves

The following table presents information regarding proved reserves of oil attributable to our Cadence division's interests in producing properties in Wilbarger County, Texas, and De Soto Parish, LA as of September 30, 2005. The information regarding reserves is based on proved reserves reports prepared by Ralph E. Davis Associates, Inc., Houston, Texas, independent petroleum engineers. The following report (and table) do not include information on our interests in gas wells located in Alpena County, MI as no engineering study has been undertaken of these wells as of the date of this report. Ralph E. Davis's audit was based upon review of production histories and other geological, economic, ownership and engineering data we provided. All of the reserves presented in the following table are proved, developed reserves.

Estimates of our future net revenues from proved reserves are discounted to present value using an annual discount rate of 10% (the PV-10 Value), using oil and gas prices in effect as of the dates of such estimates, held constant throughout of the life of the properties. Proved reserves as of September 30, 2005 were estimated based upon the price for oil and gas actually received by Cadence on September 30, 2005 which was $63.09 per barrel of oil and $11.23 per MMBTU of gas.

The following table contains estimates of future net revenues presented on the basis of unescalated prices and costs and their PV-10 Value. We deducted operating costs which were calculated as the average operating cost from April, 2005 to September, 2005. For newer wells having produced less than six months the costs for the available months were averaged. The future net revenues are estimated based upon reserve volumes which are estimated by performance methods, volumetrically, or by analogy to surrounding wells. Many of these wells have produced long enough that a definitive performance trend can be determined and extrapolated into the future. We made no provision for income taxes. The estimates of future net revenues and their present value differ in this respect from the standardized measure of discounted future net cash flows contained in the supplemental information to this report which is calculated after provision for future income taxes.

Cadence Division Revenues

	ESTIMATED NET
	RESERVES		ASSUMED		FUTURE NET INCOME
PROVED RESERVES	(MBBLS/MMCF)		PRICE ($BBL/MCF)		UNDISCOUNTED		PV-10
Producing Oil		59.4	$	63.09	$	2,774,400	$	2,188,500
Producing Gas		505.3	$	11.23	$	4,425,900	$	3,202,000
Total Future Net Income					$	7,200,300	$	5,390,500

The following table presents information regarding proved reserves of gas attributable to our Aurora division's Michigan Antrim Shale projects as of December 31, 2004. This information is based on a reserve report prepared by Data & Consulting Services, a division of Schlumberger Technology Corporation of Pittsburgh, Pennsylvania. According to this report, over 86% of our proved reserves are classified as either "proved developed non-producing" or "proved undeveloped." The following reserve report (and table) do not include information on the New Albany Shale gas reserves located in Indiana, the gas reserves associated with the Crossroads project located in Ohio, or any oil reserves. No reserve report has been prepared for these properties.

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We only obtain a reserve report that follows SEC reporting requirements annually at the end of each fiscal year. We have received a reserve report for our Michigan Antrim Shale properties as of August 1, 2005, but it was prepared for financing purposes and does not meet SEC reporting requirements.

The December 31, 2004 reserve report described below is prepared using the assumption that each well will produce for 40 years. Antrim Shale wells generally produce for extended periods of time. As noted above, the oldest Antrim Shale field in Michigan was drilled in the 1940s and it is still in production today. Estimates of our future net revenues from proved reserves are discounted to present value using an annual discount rate of 10% (the PV-10 Value), using gas prices in effect as of the date of the estimate held constant throughout the life of the properties. For the table below, except for the Alpena Beyer Unit, the Value of the reserves was calculated based on the spot price at which we sold our gas on December 31, 2004, which was $6.195 per MCF. For the Alpena Beyer Unit, the calculation was based on an existing contract price of $4.00 per MCF in 2004, $4.37 per MCF in 2005, and $5.00 per MCF for all later years.

AURORA SUBSIDIARY RESERVES AT DECEMBER 31, 2004

	Proved (1) Developed(2) Producing		Proved (1) Developed(2) Non-Producing		Proved(1) Undeveloped (2)		Total Proved Reserves
Estimated remaining net reserves (mmscf)		4,818.71		7,701.00		22,429.70		34,949.41
Undiscounted future net income before taxes	$	21,814,860	$	29,719,820	$	77,015,290	$	128,549,970
Future net income before taxes with PV-10 discount	$	8,130,430	$	12,987,160	$	26,890,550	$	48,008,140

(1) Proved reserves are those quantities of gas which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable from known reservoirs and under current economic conditions, operating methods, and government regulations.

(2) Developed reserves are expected to be recovered from existing wells. Undeveloped reserves are expected to be recovered: (a) from new wells on undrilled acreage; (b) from deepening existing wells to a different reservoir; or (c) where relatively large expenditure is required to recomplete an existing well or install production or transportation facilities for primary or improved recovery projects.

The report also places an estimated net present value on our interest in the Hudson Unit Pipelines at $2,503,490.

For purposes of calculating collateral coverage, our loan agreement with TCW Energy, et al., requires the use of a formula that is based in part on historical monthly averages instead of year-end prices. The reserve report prepared using this formula shows total proved reserves valued at $43,795,180 at December 31, 2004. Because of the inherent uncertainty in predicting future oil and gas prices, the present value of reserve assets cannot be determined with certainty.

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Production Information

The following tables summarize sales volumes, sales prices, and production cost information for our Cadence division's net oil and gas production for the two-year period ended September 30, 2005. "Net" production is production that is owned by our Cadence division directly or indirectly and is produced to our interest after deducting royalty, and other similar interests. This table includes information from production from the oil wells in Wilbarger County, Texas, and Eddy County, New Mexico and from gas wells in De Soto Parish, Louisiana and from Alpena County, Michigan.

Cadence Production

Oil Production	Twelve months Ended September 30,
	2005		2004
Total Net Revenues	$	800,103	$	837,305
Net Sales Volume (Bbls)		16,885		25,887
Average Sales Price (per Bbl.)	$	51.64	$	36.11
Average Production Cost (per Bbl.)	$	3.32	$	2.61

Gas Production	Twelve months Ended September 30,
	2005		2004
Total Net Revenues	$	1,449,393	$	1,676,948
Net Sales Volume (mcf)		199,703		294,718
Average Sales Price (per mcf.)	$	7.26	$	5.69
Average Production Cost (per mcf.)	$	2.47	$	1.12

The following tables summarize sales volumes, sales prices, and production cost information for our Aurora division's net oil and gas production for the two-year period ended December 31, 2004. "Net" production is production that is owned by our Aurora division directly or indirectly and is produced to Aurora's interest after deducting royalty and other similar burdens. This table includes information about natural gas production from the Hudson, Treasure Island, Black Bean, Beyer, Blue Spruce, Timm, Devil River and Paxton Quarry Antrim Shale projects in Michigan and oil production from the Bergsasi well and the Church Lake field in Michigan.

Aurora Production

Gas Production	Twelve months Ended December 31,
	2004			2003
Net Revenues
Michigan	$	726,333			810,424
Indiana	$	7,076		$	87,537
Total	$	733,409		$	897,961
Net Sales Volume (mcf)
Michigan		149,502			192,787
Indiana		1,739			21,665
Total		151,241			214,452
Average Sales Price (per mcf)	$	4.91		$	4.27	(2)
Average Production Cost (per mcf)	$	3.51	(1)	$	3.00	(2)

Oil Production	Twelve months Ended December 31,
	2004			2003
Total Net Revenues (Michigan)	$	226,600		$	196,650
Net Sales Volume (Bbls) (Michigan)		4,798			6,953
Average Sales Price (per Bbl)	$	47.22		$	26.10	(2)
Average Production Cost (per Bbl)	$	18.65	(1)	$	12.65	(2)

(1) The average gas production cost for 2004 is increased due to additional operating expenses incurred in one particular project area which was shut-in most of the year. If this project was removed from the calculation, the average production cost per mcf would be $3.14. The Paxton Quarry field has higher production costs than the average because it was acquired from another operator and is in need of repairs. Additional wells are not expected to be added to this field. Production costs in other fields are expected to decline on a per-mcf basis as more wells are put on line. Accordingly, management expects the average production costs to decline to below $3.14 per mcf over time, consistent with the industry average from other operators who operate wells in the Michigan Antrim.

(2) The 2003 numbers for average sales price and average production cost are approximate, based on estimated sales volumes. The software our Aurora division used in 2003 did not record per-unit sales volume.

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Oil and Gas Wells

The following table sets forth the number of gross and net productive wells owned by our Cadence division on the stated dates.

	Oil Wells		Gas Wells		Total Wells
September 30, 2005
Gross(1)		9.00		11.00		20.00
Net(1)		5.10		4.70		9.86
September 30, 2004
Gross(1)		6.00		10.00		16.00
Net(2)		3.70		2.30		6.00

(1) Gross wells are the total wells in which a working interest is owned.

(2) Net wells are the sum of fractional working interests owned in gross wells.

The following table sets forth the number of gross and net productive wells owned by our Aurora division on the stated dates.

	Oil Wells		Gas Wells		Total Wells
December 31, 2004
Gross(1)		8.00		192.00		200.00
Net(2)		1.86		40.49		42.35
December 31, 2003
Gross(1)		8.00		105.00		113.00
Net(2)		1.86		42.8		44.66

(1) Gross wells are the total wells in which a working interest is owned.

(2) Net wells are the sum of fractional working interests owned in gross wells.

(3) The increase in gross wells with a corresponding decrease in net wells from 2003 to 2004 was attributable largely to the sale of 80% of the leaseholds in the Michigan Antrim to Samson during 2004, as described above.

(4) Most of the productive wells our Aurora division owned at December 31, 2004 were drilled during the third and fourth quarters of 2004, and saw little actual production during the year. Using a weighted average approach for the time of actual production, our Aurora division had 10.6 net wells in actual production for the entire 2004 year.

All of our Aurora division's productive wells are located in Michigan.

Oil and Gas Acreage

The following table sets forth the number of acres of oil and gas leases owned by our Cadence divisions of September 30, 2005.

	Developed(1)				Undeveloped(2)
	Gross		Net		Gross		Net
Louisiana		4800		2032		0		0
Texas		2290		1165		0		0
Michigan		1891		425		0		0
Kansas		160		160		27,840		27,840
Total		9,141		3,782		27,840		27,840

(1) The number of acres which are allocated or assignable to producing wells or wells capable of production.

(2) Lease acreage on which wells have not been participated in or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

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The following table sets forth the number of acres of oil and gas leases owned by our Aurora division at December 31, 2004. These are rounded to whole numbers.

	Developed(1)				Undeveloped(2)
	Gross		Net		Gross		Net
Gas
Michigan		7,956		2,739		100,324		52,799
Indiana		–		–		284,576		214,487
Ohio		–		–		15,350		1,044
Illinois		–		–		1,632		1,632
Kentucky		–		–		6,497		6,497
Total		7,956		2,739		408,379		276,459

(1) "Developed" refers to the number of acres which are allocated or assignable to producing wells or wells capable of production.

(2) "Undeveloped" refers to lease acreage on which wells have not been developed or completed to a point that would permit the production of commercial quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

Drilling Activities

The following table sets forth our Cadence division's drilling results for the twelve months ended September 30, 2005, and 2004:

			Gross Wells								Net Wells
Fiscal Year	Type of Well		Total		Productive (2)		Dry(2)		Abandoned(4)		Total		Productive		Dry		Abandoned
2005		Exploratory(1)		2		1		1		0		2		1		1		0
		Development(1)		7		6		1		0		3.45		2.95		0.5		0
2004		Exploratory(1)		3.0		1		1		0		2		2		1.0		0
		Development(1)		11		7		2		2		4.3		2.5		0.9		0.9

(1) An exploratory well is a well drilled either in search of a new, as yet undiscovered oil or gas reservoir or to greatly extend the known limits of a previously discovered reservoir. A development well is a well drilled within the presently proved productive area of an oil or gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir.

(2) A productive well is an exploratory or development well found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

(3) A dry well is an exploratory or development well that is not a producing well.

(4) An abandoned well is a well that has either been plugged or has been converted to another use. We have converted this Texas well to a salt water disposal well. Two of the DeSoto Parish wells produced limited quantities of gas for a time, but are no longer producing any gas and are considered abandoned for the purposes of this table.

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The following table sets forth our Aurora division's drilling results for the twelve months ended December 31, 2004 and 2003. The table does not include salt water disposal wells drilled. In 2004, our Aurora division drilled 6 gross and 2.39 net salt water disposal wells. In 2003, our Aurora division drilled 1.00 gross and 0.07 net salt water disposal wells.

Gross Wells

Net Wells

Fiscal Year

Type of Well

Total

Productive (2)

Dry(3)

Abandoned(4)

Total

Productive(2)

Dry(3)

Abandoned(4)

2004

Exploratory(1)

Michigan

–

–

--

--

–

–

–

–

Indiana

–

–

–

–

–

–

–

–

Total

–

–

–

–

–

–

–

–

Development(1)

Michigan

87

84

3

–

26.24

25.06

1.18

–

Indiana

4

–

–

4

0.20

–

--

0.20

Total

91

84

3

4

26.44

25.06

1.18

0.20

2003

Exploratory(1)

Michigan

–

–

–

–

–

–

–

–

Indiana

–

–

–

–

–

–

–

–

Total

–

–

–

–

–

–

–

–

Development(1)

Michigan

27

27

–

–

5.06

5.06

–

–

Indiana

–

–

–

–

–

–

–

–

Total

27

27

–

–

5.06

5.06

–

–

(1) An exploratory well is a well drilled either in search of a new, as yet undiscovered oil or gas reservoir or to greatly extend the known limits of a previously discovered reservoir. A development well is a well drilled within the presently proved productive area of an oil or gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir.

(2) A productive well is an exploratory or development well found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

(3) A dry well is an exploratory or development well that is not a producing well.

(4) An abandoned well is a well that has either been plugged or has been converted to another use.

Drilling Techniques and Arrangements

For gas wells, our Aurora division uses a production system that is designed to achieve low pressure on the wells, pipelines, facilities and reservoir. This is done by keeping natural fractures open to the well bore, and by using low-pressure gas processing near well sites. Using this low-pressure production approach, our Aurora division seeks to increase the recoverability of gas production that would otherwise be held in the reservoir.

Our Aurora division usually uses a simple proven completion procedure. This procedure involves drilling through several pay zones, setting and cementing casing, and drilling a rat-hole, which is used for gas-water separation. The use of specially designed cement around the casing helps avoid plugging off natural fractures. Imaging logs are used to identify which zones are best fractured and will yield commercial gas production.

In order to contain costs, our Aurora division tries to keep facilities for gas processing decentralized. Salt water disposal wells are drilled close to the compression facilities, central to each field's wells. Skid mounted separators that can be easily downsized are used at the site of the salt water disposal wells. The localized disposal of water reduces power demand. Different reservoirs contain different amounts of water. Aurora cannot accurately predict the actual amount of time required for dewatering with respect to each well. The period of time when the volume of gas that is produced is limited by the dewatering process could be as much as two years, thereby delaying revenue production.

Skid mounted compressors are used by our Aurora division in a series to maximize compression to the transportation line. Our Aurora division will also seek to maintain low pressure in the gathering systems. Gas will be drawn at low wellhead pressure using a five and one-half inch or seven inch production casing.

One strategy that our Aurora division uses to minimize costs is to minimize the use of land surface. This is accomplished by using small well sites in open areas near roads, and by not building central processing facilities, but instead using localized facilities as described above. Truck mounted drilling rigs may be used. Our Aurora division may use other drilling, completion and operating procedures if, in management's opinion, these alternative procedures will produce a higher rate of gas from the shale.

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Our Aurora division's gas wells will be drilled by outside drilling companies. We have two turnkey drilling agreements in place for our Michigan Antrim drilling areas that give us preferential access to two drilling rigs. Management believes that there is currently enough capacity available in the areas in which Aurora is working that we will not have a problem finding one or more drilling companies available to meet our time schedule for drilling wells. However, over time, circumstances could change as development activity in the industry picks up.

The availability of experienced and competent drilling, completion and facilities installation production laborers and vendors could affect the timing of when the wells are completed and producing revenues. If there is a shortage of field workers, it will take longer to begin to generate revenues from new wells. From time to time, the oil and gas industry also experiences equipment shortages, resulting in back orders for needed equipment. If this occurs before the wells are drilled, completed and put into production, it will take longer for the wells to begin to generate revenues.

The oil and gas industry has historically experienced periods of rapidly increasing drilling and production costs, frequently during times of increased drilling activities. If significant cost increases occur with respect to our development activity, we may have to reduce the number of wells we drill.

After the wells are completed and put into production, we may decide that additional work needs to be done beyond routine maintenance. It is frequently the case that at some point in the life of a well additional work may be appropriate in order to increase production, such as reworking, recompletion, deepening or sidetracking of existing wells; or the installation of secondary tertiary or other enhanced recovery methods. We reserve the right to engage in production-enhancing operations of this type, even if it results in a temporary reduction in cash flow.

Sale and Production

We use different strategies for gas sales depending on the location of the field and the local markets. In some locations, we use proprietary CO2 reduction units to process our own gas and sell it to nearby local markets. In other cases, we connect to nearby high pressure pipelines. We are not currently aware of any problems with pipeline availability. However, because of the nature of natural gas development, there may be periods of time when pipeline capacity is inadequate to meet our transportation needs. It is often the case that as new development comes on line, pipelines are close to or at capacity before new pipelines are built.

During periods when pipeline capacity is inadequate, if we are relying on pipeline transportation, we may be forced to reduce production or incur additional expense as existing production is compressed to fit into existing pipelines. As production increases, more compression is generally required to compress the production into the pipeline. As more compression is required, production costs increase, primarily because more fuel is required in the compression process. Furthermore, because compression is a mechanical process, a breakdown may occur that will prevent the delivery of gas until repairs are made.

We rely heavily on the spot markets to sell our gas. As a result, there is no assurance at what price we will be able to sell our gas. Only approximately 30% of the gas that is consumed in Michigan is produced in Michigan. As a result, gas produced in Michigan typically receives a premium above the New York Mercantile Exchange spot market price.

Prices for gas and oil fluctuate fairly widely based on supply and demand. Supply and demand are influenced by weather, foreign policy and industry practices. For example, demand for gas has increased in recent years due to a trend in the power plant industry to move away from using oil and coal as a fuel source, to using gas, because gas is a cleaner fuel. Nonetheless, in light of historical fluctuations in prices, there can be no assurance at what price we will be able to sell our gas and oil. It is possible that gas prices will be low at the time periods in which the wells are most productive, thereby damaging overall returns. It is possible that prices will drop so low that production will become uneconomical. Ongoing production costs that will continue include equipment maintenance, compression and pumping costs. If production becomes uneconomical, we may discontinue production until prices improve.

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Unitization of Production

The production of some or all of our wells may be unitized (connected by agreement) with the production from wells we have already drilled or from wells drilled by other owner/operators in the same fields. Any subsequent wells drilled within the fields may also be unitized with existing wells, including our wells. Typically, we only unitize a well that we have drilled or a well that we have has purchased from other companies.

If other companies are involved, the method used for the unitization will be to add together all of the acquisition and development costs from each of the participants within the field, and then calculate the working interest percentage of each participant based on the percentage of total costs that were contributed by that participant. Thus, working interest percentages will be recalculated each time a well or a group of wells are put into production. All costs are included in this calculation, including costs for infrastructure development as well as drilling costs.

The unitization of wells reduces the risk associated with any specific well in which we own a working interest. In addition, the sharing of infrastructure costs, such as the cost of the salt water disposal wells, should result in a lower per-well operating expense for all of the wells in the field. In fields with multiple owners where wells are being unitized, there may be certain disadvantages to earlier investors when a field is unitized

Credit Facilities

TCW

On August 12, 2004 our Aurora division through its AAN subsidiary, closed on a line of credit facility with TCW Energy, et al. ("TCW"). At closing, Aurora was given an initial credit availability of $10,000,000. As the assets in Aurora become proved reserves the credit availability was increased, up to a maximum of $30,000,000. On June 10, 2005 we drew an additional $10,000,000 in credit, and on September 30, 2005, we drew another $10,000,000 in credit. On December 8, 2005, we entered into an amendment to the credit facility with TCW, increasing the maximum amount available on the line of credit to $50 million. On December 13, 2005, we drew another $10 million in credit. Our principal balance outstanding as of December 13, 2005 is $40 million.

The TCW credit facility bears interest at a fixed rate of 11.5% per annum on the outstanding principal balance, calculated and payable in arrears. Interest payments are due on the second to last business day of each March, June, September and December (each a "Quarterly Payment Date"). The credit facility matures on September 30, 2009, at which time any outstanding principal is due and payable. Beginning on September 29, 2005, and on each Quarterly Payment Date thereafter, AAN is required to make a principal payment equal to 75% of adjusted net cash flow from the assets serving as collateral for the credit facility. In the event of default, this increases to 100%. So long as AAN is not in default and is in compliance with the financial covenants, AAN is allowed to distribute to us 25% of the adjusted net cash flow, plus $300,000 annually to fund general and administrative expenses.

At the closing of the financing, Aurora conveyed to TCW a 4% overriding royalty interest net to Aurora's interest, in all of Aurora's existing oil and gas leases in the counties of Alcona, Alpena, Charlevoix, Cheboygan, Montmorency and Otsego in the State of Michigan. Additionally, Aurora is required to convey a 4% overriding royalty interest, net to its interest, in any new leases acquired in these counties while the loan is outstanding. The overriding royalty interest conveyed to TCW will not bear any operation, transportation, marketing, compression or similar charges except for those expenses paid to parties not affiliated with Aurora.

The notes issued to TCW may be prepaid after August 15, 2006, but a prepayment penalty will be imposed for prepayments made prior to August 15, 2008. TCW has been granted observer rights to the board of managers of AAN and the Board of Directors of Aurora. Aurora is required to provide TCW with a semi-annual engineering report. Aurora is required to pay an affiliate of TCW a 1.5% origination fee for each advance taken.

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Northwestern Bank Line of Credit

On October 12, 2005, our Aurora division entered into a $7,500,000 line of credit promissory note with Northwestern Bank of Traverse City, Michigan ("Northwestern Bank"). This credit facility is being used as a typical line of credit, with draws being made periodically as needed, and payments being made when funds are available. The principal balance therefore fluctuates often.

The Northwestern Bank line of credit matures on October 15, 2006. It carries interest at Wall Street Prime, initially 6.75% per year. Interest is payable monthly. Principal is payable at maturity, subject to the Northwestern Bank's right to accelerate the due date in the event of default. The loan is secured by the personal guaranties of William W. Deneau, Thomas W. Tucker and John V. Miller, Jr. It is also secured by all of the personal property of JetX, L.L.C., a company that is owned in equal shares by Messrs. Deneau, Tucker and Miller. Messrs. Deneau, Tucker and Miller have also agreed to pledge 10% of their shares of Cadence common stock as collateral on the loan. We have agreed that the indebtedness to TCW will at no time exceed 55% of the total modified NPV 10 reserves held as collateral by TCW. We are also required to provide Northwestern Bank a revised independent reserve study every six months during the time the loan is outstanding, with the next report due no later than January 31, 2006. We are required to maintain a collateral coverage ratio not to exceed 1.2, as calculated twice per year.

Mortgage Loan

On September 19, 2005, our Aurora division obtained an office condominium mortgage loan from Northwestern Bank in the amount of $2,950,000. The repayment schedule is monthly interest only for three successive months starting on November 1, 2005, and beginning on February 1, 2006, principal and interest in 32 monthly payments of $21,969. The loan bears interest at the rate of 6.5% per year. The maturity date is October 1, 2008. The loan proceeds were used to purchase the office condominium and to pay for interior improvements to the premises.

Insurance

The oil and gas business involves operating hazards such as well blowouts, craterings, explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks. Personal injuries, damage to property and equipment, reservoir damage, or loss of reserves may occur if such a catastrophe occurs, any one of which could cause us to experience substantial losses. In addition, we may be liable for environmental damage caused by previous owners of properties we purchase or lease.

Our Aurora division maintains insurance for potential losses at the level management deems reasonable. However, certain risks of loss are either uninsurable or not economically insurable. An uninsured loss may hurt our financial performance and condition. We currently have the following insurance coverage which is effective until

December 31, 2005:

POLICY TYPE	LIMIT
Worker's Compensation & Employment Liability	Worker's Compensation; Statutory Employer's Liability - $1,000,000
General Liability	Each occurrence - $1,000,000; Damages to Rented Premises - $100,000; Medical Exp - $10,000; Personal & Adv. Injury - $1,000,000; General Aggregate - $2,000,000; Products-Comp -$2,000,000
Automobile	$1,000,000 per occurrence
Excess/Umbrella Liability	$5,000,000 per occurrence and aggregate
Property/Pollution	$1,059,600 (property coverage); $1,000,000 (pollution limit)
Well Control	$2,000,000 limit

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Employees

As of November 15, 2005, we have 31 full time employees and one part time employee. We are not a party to any collective bargaining agreements.

Service Mark

We have been granted a service mark registration (Registration No. 2,214,144) from the United States Patent and Trademark Office for the Aurora logo. The registration date is December 29, 1998, and the registration is valid for 10 years. We do not own any other patents, trademarks, licenses, franchises or concessions.

Legal Proceedings

There are no currently threatened or pending claims against us.

Risks Related to our Business

THE INTEGRATION OF THE CADENCE AND AURORA BUSINESSES MAY BE COSTLY AND THE FAILURE TO SUCCESSFULLY EFFECT THE INTEGRATION MAY ADVERSELY AFFECT OUR BUSINESS, RESULTS OF OPERATIONS AND FINANCIAL CONDITION.

Our ability to realize some of the anticipated benefits of the acquisition of Aurora will depend in part on our ability to integrate Aurora's operations and Cadence's operations in a timely and efficient manner. The integration process may require significant efforts from each company, although the fact that we do not have offices to dismantle or staff to integrate may make this process easier in this case than is true for many other mergers. Nonetheless, the integration process may distract our management's attention from the day-to-day business of the combined company. If we are unable to successfully integrate the operations of the two companies or if this integration process is delayed or costs more than expected, our business, operating results and financial condition may be negatively impacted.

WE CONTINUE TO EXPERIENCE SIGNIFICANT OPERATING LOSSES.

We reorganized our business in July 2001 to pursue oil and gas exploration and development opportunities and in October 2005 increased our business activities through the acquisition of Aurora. We have a limited operating history in our current form. Since July 2001, our Cadence division's operating costs have exceeded its revenue in each quarter. Our Cadence division has incurred cumulative net losses of approximately $13,477,034 from June 30, 2001 through September 30, 2005. We may also experience a loss in our Cadence division in 2006. Our Cadence division may not be able to obtain or maintain any level of revenues, natural gas and crude oil reserves or production. If our Cadence division is unsuccessful in these efforts it may never achieve profitability.

Our Aurora division reported profit from operations during the twelve months ended December 31, 2002 and 2003, and a loss from operations during the twelve months ended December 31, 2004. The loss for the twelve months ended December 31, 2004 was directly attributable to financing expenses and expenses associated with the sale of assets. We also expect that our Aurora division will operate at a loss for the twelve months ended December 31, 2005. Part of the reason for this is an accounting issue associated with the acquisition of Aurora, which required us to amortize Cadence's intangible assets over a period of three years. This will result in a non-cash expense deduction of approximately $1,535,000 on our profit and loss statement for the twelve months ended December 31, 2005. In addition, our Aurora division has been drilling wells in 2005 from which cash flow from production will not be generated until 2006. Our Aurora division may be unable to return to and maintain profitability.

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WE MAY BE UNABLE TO MAKE ACQUISITIONS OF PRODUCING PROPERTIES OR PROSPECTS OR SUCCESSFULLY INTEGRATE THEM INTO OUR OPERATIONS.

Acquisitions of producing properties and undeveloped oil and gas leases have been an essential part of our long-term growth strategy. We may not be able to identify suitable acquisitions in the future or to finance these acquisitions on favorable terms or at all. In addition, we compete against other companies for acquisitions, many of whom have substantially greater managerial and financial resources than us. The successful acquisition of producing properties and undeveloped oil and gas leases require an assessment of such properties' potential oil and gas resources, future oil and gas prices, development costs, operating costs, potential environmental and other liabilities and other factors beyond our control. These assessments are necessarily inexact and their accuracy inherently uncertain. Such a review may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geological characteristics or geographic location than existing properties. Our acquisitions may not be integrated successfully into our operations and may not achieve desired profitability objectives.

WE DO NOT HAVE COMPLETE MANAGEMENT CONTROL OVER ALL OUR PROPERTIES.

Our Cadence division does not operate any of the properties in which we have an interest. Our Aurora subsidiary conducts most of its oil and gas exploration, development and production activities in joint ventures with others. In some cases, Aurora acts as operator and retains significant management control. In other cases, Aurora has reserved only an overriding royalty interest and has surrendered all management rights. In still other cases, Aurora has reserved the right to participate in management decisions, but does not have ultimate decision-making authority. As a result of these varying levels of management control, in a large portion of the properties in which we have an interest, we have no control over:

·    the number of wells to be drilled;

·    the location of wells to be drilled;

·    the timing of drilling and recompleting of wells;

·    the field company hired to drill and maintain the wells;

·    the timing and amounts of production;

·    the approval of other participants in drilling wells;

·    development and operating costs;

·    capital calls on working interest owners; and

·    negative gas balance conditions.

These and other aspects of the operation of our properties and the success of our drilling and development activities will in many cases be dependent on the expertise and financial resources of our joint venture partners and third-party operators.

WE MAY LOSE KEY MANAGEMENT PERSONNEL.

Our current management team has substantial experience in the oil and gas business. We do not have employment agreements with any members of our management team. The loss of any of these individuals could adversely affect our business. If one or more members of our management dies, becomes disabled or otherwise voluntarily terminates employment with us, there is no assurance that a suitable or comparable substitute will be found.

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MOST OF OUR AURORA DIVISION'S PROVED RESERVES ARE NOT YET PRODUCING.

Of our Aurora division's proved reserves at December 31, 2004, approximately 22% are classified as "proved developed non-producing" and approximately 64% are classified as "proved undeveloped." Production revenues from estimated proved developed non-producing reserves will not be realized until some time in the future, after we have installed supporting infrastructure or taken other necessary steps. It will be necessary to incur additional capital expenditures to install this required infrastructure. Production revenues from estimated proved undeveloped reserves will not be realized until after such time, if ever, as we make significant capital expenditures with respect to the development of such reserves, including expenditures to fund the cost of drilling wells and building the supporting infrastructure. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of the costs associated with developing these reserves in accordance with industry standards, no assurance can be given that our estimates of capital expenditures will prove accurate, that our financing sources will be sufficient to fully fund our planned development activities, or that development activities will be either successful or in accordance with our schedule. We cannot control the performance of our joint venture partners on whom we depend for development of a substantial number of properties in which we have an economic interest and which are included in our reserves. Further, any significant decrease in oil and gas prices or any significant increase in the cost of development could result in a significant reduction in the number of wells drilled. No assurance can be given that any wells will yield commercially viable quantities.

OUR AURORA DIVISION'S CREDIT FACILITY HAS OPERATING RESTRICTIONS AND FINANCIAL COVENANTS THAT LIMIT ITS FLEXIBILITY AND MAY LIMIT ITS BORROWING CAPACITY.

The TCW Energy credit facility limits the amount of earnings from production that our Aurora division has access to for the properties pledged as collateral on the loan, and has numerous other operational restrictions that limit our Aurora division's flexibility. The credit facility also requires our Aurora division's borrowing subsidiary to maintain certain ratios of collateral asset values to debt and proved developed producing reserves value to debt. If the ratio requirements are not satisfied, curative action may be required, such as repaying a part of the outstanding principal or pledging more assets as collateral, and our Aurora division's borrowing subsidiary will be unable to draw more funds to use in development.

The value of the assets held by our Aurora division's borrowing subsidiary will depend on the then current commodity prices for natural gas. If prices drop significantly, our Aurora division may have trouble satisfying the ratio covenants of the credit facility. As noted below, oil and gas prices are volatile. If our Aurora division is unable to make use of this credit facility, it may be difficult to find replacement sources of financing to use for working capital, capital expenditures, drilling, technology purchases or other purposes. Even if replacement financing is available, it may be on less advantageous terms than the TCW Energy, credit facility.

SOME OF OUR AURORA DIVISION’S BANK ACCOUNTS ARE NOT FULLY INSURED.

Some of our Aurora division's bank accounts periodically exceed the $100,000 limit of FDIC insurance for deposits. In the unlikely event that Aurora's bank should fail, it is possible that our Aurora division will lose some of its funds on deposit.

OUR DRILLING ACTIVITIES MAY BE UNSUCCESSFUL.

We cannot predict prior to drilling and testing a well whether the well will be productive or whether we will recover all or any portion of our investment in the well. Our drilling for oil and natural gas may involve unprofitable efforts, not only from dry holes but from wells that are productive but do not produce sufficient quantities to cover drilling and completion costs, and thus which are not economically viable. Our efforts to identify commercially productive reservoirs, such as studying seismic data, the geology of the area and production history of adjoining fields, do not conclusively establish that oil and gas is present in commercial quantities. If our drilling efforts are unsuccessful, our profitability will be adversely affected.

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PRODUCTION LEVELS CANNOT BE PREDICTED WITH CERTAINTY.

Until a well is drilled and has been in production for a number of months, we will not know what volume of production we can expect to achieve from the well. Even after a well has achieved its full production capacity, we cannot be certain how long the well will continue to produce or the production decline that will occur over the life of the well. Estimates as to production volumes and production life are based on studies of similar wells, and therefore speculative and not fully reliable. As a result, our revenue budgets for producing wells may prove to be inaccurate.

PRODUCTION DELAYS MAY OCCUR.

In order to generate revenues from the sale of oil and gas production from new wells, we must complete significant development activity. Delays in receiving governmental permits, adverse weather conditions, a shortage of labor or parts, and/or dewatering time frames may cause production delays, as discussed below. These delays will mean that we will be delayed in achieving revenues from these new wells.

Oil and gas producers often compete for experienced and competent drilling, completion and facilities installation vendors and production laborers. The unavailability of experienced and competent vendors and laborers may cause development and production delays.

From time to time, vendors of equipment needed for oil and gas drilling and production become backlogged, forcing delays in development until suitable equipment can be obtained.

For each new well, before drilling can commence, we will have to obtain a drilling permit from the state in which the well is located. We will also have to obtain a permit from the United States Environmental Protection Agency for each salt water disposal well. It is possible that for reasons outside of our control, the issuance of the required permits will be delayed, thereby delaying the time at which production is achieved.

Adverse weather may foreclose any drilling or development activity, forcing delays until more favorable weather conditions develop. This is more likely to occur during the winter and spring months, but may occur at other times of the year.

Different natural gas reservoirs contain different amounts of water. The actual amount of time required for dewatering with respect to each well cannot be predicted with accuracy. The period of time when the volume of gas that is produced is limited by the dewatering process may be extended, thereby delaying revenue production.

OIL AND GAS PRICES ARE VOLATILE. A SUBSTANTIAL DECREASE IN OIL AND NATURAL GAS PRICES COULD ADVERSELY AFFECT OUR BUSINESS.

Our revenues, profitability and future growth depend in part on prevailing natural gas and crude oil prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of natural gas and crude oil that we can economically produce. It is possible that prices will be low at the time periods in which the wells are most productive, thereby damaging overall returns. It is possible that prices will drop so low that production will become uneconomical. Ongoing production costs that will continue include equipment maintenance, compression and pumping costs. If production becomes uneconomical, we may decide to discontinue production until prices improve.

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Prices for natural gas and crude oil fluctuate widely, as evidenced by the volatility in natural gas prices in response to the war between the United States and Iraq. The prices for oil and natural gas are subject to a variety of factors beyond our control, including:

·    the level of consumer product demand;

·    weather conditions;

·    domestic and foreign governmental regulations;

·    the price and availability of alternative fuels;

·    political conditions in oil and gas producing regions;

·    the domestic and foreign supply of oil and gas;

·    market uncertainty; and

·    worldwide economic conditions.

PIPELINE CAPACITY MAY BE INADEQUATE.

Because of the nature of natural gas development, there may be periods of time when pipeline capacity is inadequate to meet our gas transportation needs. It is often the case that as new development comes on line, pipelines are close to or at capacity. 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.

OUR RELIANCE ON THIRD PARTIES FOR GATHERING AND DISTRIBUTION COULD CURTAIL FUTURE EXPLORATION AND PRODUCTION ACTIVITIES.

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 IS A POTENTIAL FOR INCREASED COSTS.

The oil and gas industry has historically experienced periods of rapidly increasing drilling and production costs, frequently during times of increased drilling activity. If significant cost increases occur with respect to our development activity, we may have to reduce the number of wells we drill, which may adversely affect our financial performance.

WE MAY INCUR COMPRESSION DIFFICULTIES AND EXPENSE.

As production of natural gas increases, more compression is generally required to compress the production into the pipeline. As more compression is required, production costs increase, primarily because more fuel is required in the compression process. Furthermore, because compression is a mechanical process, a breakdown may occur that will cause us to be unable to deliver gas until repairs are made.

UNITIZATION PRESENTS SOME RISKS.

Some or all of our wells will be unitized with wells owned by other owners within the same field. Because unitization of production combines the operating results of more than one owner of wells, there is a risk that the performance of the wells we do not own will lower our financial performance if the wells we do not own do not perform as well as the wells we do own. In addition, it may be argued that the owners of wells developed later in a field have an advantage because they have more production history upon which to evaluate the investment, they are able to use their money for other purposes before committing their resources to the wells in the field, and they are getting the benefit of all reserves when some of the reserves have already been depleted. Nonetheless, in management's opinion, these risks may be outweighed in some circumstances by the benefit of spreading the costs of infrastructure over a greater number of wells, thereby reducing the costs per well for all owners of wells in the field.

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THE FAILURE TO DEVELOP RESERVES COULD ADVERSELY AFFECT OUR PRODUCTION AND CASH FLOWS.

Our success depends upon our ability to find, develop or acquire oil and gas reserves that are economically recoverable. We will need to conduct successful exploration or development activities or acquire properties containing proved reserves, or both. The business of developing or acquiring oil and gas reserves is capital intensive. We may not be able to make the necessary capital investment to expand our oil and natural gas reserves from cash flows and external sources of capital may be limited or unavailable. Our drilling activities may not result in significant reserves and we may not have continuing success drilling productive wells. Exploratory drilling involves more risk than development drilling because exploratory drilling is designed to test formations for which proved reserves have not been discovered. Additionally, while our revenues may increase if prevailing oil and gas prices increase significantly, our finding costs for reserves also could increase and we may not be able to finance additional exploration or development activities.

THE OIL AND NATURAL GAS RESERVE DATA INCLUDED IN THIS DOCUMENT ARE ESTIMATES BASED ON ASSUMPTIONS THAT MAY BE INACCURATE AND EXISTING ECONOMIC AND OPERATING CONDITIONS THAT MAY DIFFER FROM FUTURE ECONOMIC AND OPERATING CONDITIONS.

Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and is based upon assumptions that may vary considerably from actual results. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. Information regarding discounted future net cash flows should not be considered as the current market value of the estimated oil and natural gas reserves that will be attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation. The reserve report for Aurora's properties assumes that production will be generated from each well for a period of 40 years. Because production is expected for such an extended period of time, the probability is enhanced that conditions at the time of production will vary materially from the current conditions used to calculate future net cash flows. In addition, the 10% discount factor, which is required by the Financial Accounting Standards Board in Statement of Financial Account Standards No. 69 to be used on calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks that will be associated with our operations or the oil and natural gas industry in general.

WE MAY HAVE DIFFICULTY FINANCING OUR PLANNED GROWTH.

We have experienced and expect to continue to experience substantial capital expenditure and working capital needs, particularly as a result of our property acquisition and development drilling activities. We may require additional financing, in addition to cash generated from our operations, to fund our planned growth. If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, additional financing may not be available to us on acceptable terms or at all. If additional capital resources are unavailable, we may be forced to curtail our acquisition, development drilling and other activities or to sell some of our assets on an untimely or unfavorable basis.

WE MAY NOT HAVE GOOD AND MARKETABLE TITLE TO OUR PROPERTIES.

It is customary in the oil and gas industry that upon acquiring an interest in a non-producing property, only a preliminary title investigation be done at that time and that a drilling title opinion be done prior to the initiation of drilling, neither of which can substitute for a complete title investigation. We have followed this custom and intend to continue to follow this custom in the future. Furthermore, title insurance is not available for mineral leases, and we will not obtain title insurance or other guaranty or warranty of good title. If the title to our prospects should prove to be defective, we could lose the costs that we have incurred in their acquisition, or incur substantial costs for curative title work.

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COMPETITION IN OUR INDUSTRY IS INTENSE, AND WE ARE SMALLER AND HAVE A MORE LIMITED OPERATING HISTORY THAN MOST OF OUR COMPETITORS.

We will compete with major and independent oil and gas companies for property acquisitions and for the equipment and labor required to operate and develop these properties. Most of our competitors have substantially greater financial and other resources than we do. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and productive natural gas and oil 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 explore for oil and gas prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to complete transactions in this highly competitive environment.

OIL AND NATURAL GAS OPERATIONS INVOLVE VARIOUS RISKS.

The oil and gas business involves operating hazards such as well blowouts, craterings, explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks. Personal injuries, damage to property and equipment, reservoir damage, or loss of reserves may occur if such a catastrophe occurs, any one of which could cause us to experience substantial losses. In addition, we may be liable for environmental damage caused by previous owners of properties purchased or leased by us.

Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions all could adversely affect our ability to produce and market our natural gas and crude oil. Production from gas wells in many geographic areas of the United States, including Louisiana and Texas, has been curtailed or shut-in for considerable periods of time due to a lack of market demand, and such curtailments may continue for a considerable period of time in the future. There may be an excess supply of gas in areas where our operations will be conducted. In such event, it is possible that there will be no market or a very limited market for our production.

As a result of operating hazards, regulatory risks and other uninsured risks, we could incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate funds available for exploration, development or acquisitions.

WE LACK INSURANCE THAT COULD LOWER RISKS TO OUR INVESTORS.

As of September 30, 2005, our Cadence division had procured an errors and omissions policy for its directors and officers, but had not obtained any other insurance policies. Our Cadence division has historically chosen to rely only on the insurance provided by the well operators, and over which our Cadence division has no control. Our Cadence division's properties are therefore at risk of loss in the event of a catastrophic event.

Our Aurora division has procured insurance policies for general liability, property/pollution, well control, workers' compensation and automobile, as well as a $5 million excess liability umbrella policy. Nonetheless, the policy limits may be inadequate in the case of a catastrophic loss, and there are some risks that are not insurable. An uninsured loss could adversely affect our financial performance.

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WE ARE SUBJECT TO COMPLEX FEDERAL, STATE AND LOCAL LAWS AND REGULATIONS THAT COULD ADVERSELY AFFECT OUR BUSINESS.

Oil and gas operations are subject to various federal, state and local government laws and regulations, which may be changed from time to time in response to economic or political conditions. Matters that are typically regulated include:

·    discharge permits for drilling operations;

·    drilling bonds;

·    reports concerning operations;

·    spacing of wells;

·    unitization and pooling of properties;

·    environmental protection; and

·    taxation.

From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below allowed production capacity to conserve supplies of natural gas and crude oil. We also are subject to changing and extensive tax laws, the effects of which we cannot predict.

The development, production, handling, storage, transportation and disposal of natural gas and crude oil, by-products and other substances and materials produced or used in connection with oil and gas operations are subject to laws and regulations primarily relating to protection of human health and the environment. The discharge of natural gas, crude oil or pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties and may result in the assessment of civil or criminal penalties or require us to incur substantial costs of remediation.

Legal and tax requirements frequently are changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. Existing laws or regulations, as currently interpreted or reinterpreted in the future, could harm our business, results of operations and financial condition.

Risks Related to the Ownership of Our Stock

WE MAY EXPERIENCE VOLATILITY IN OUR STOCK PRICE, WHICH COULD NEGATIVELY AFFECT YOUR INVESTMENT, AND YOU MAY NOT BE ABLE TO RESELL YOUR SHARES AT OR ABOVE THE PRICE YOU PAID FOR IT.

The market price of our common stock may fluctuate significantly in response to a number of factors, some of which are beyond our control, including:

·    quarterly variations in operating results;

·    changes in financial estimates by securities analysts;

·    changes in market valuations of other similar companies;

·    announcements by us or our competitors of new products or of significant technical innovations, contracts, acquisitions, strategic partnerships or joint ventures;

·    additions or departures of key personnel;

·    any deviations in net sales or in losses from levels expected by securities analysts; and

·    future sales of common stock.

In addition, the stock market has recently experienced extreme volatility that has often been unrelated to the performance of particular companies. These market fluctuations may cause our stock price to fall regardless of our performance.

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BECAUSE OUR SECURITIES TRADE ON THE OTC BULLETIN BOARD, YOUR ABILITY TO SELL YOUR SHARES IN THE SECONDARY MARKET MAY BE LIMITED.

Our shares of common stock have been listed and principally quoted on the Nasdaq OTC Bulletin Board since May 1994. Because our securities currently trade on the OTC Bulletin Board, they are subject to the rules promulgated under the Securities Exchange Act of 1934, as amended, which impose additional sales practice requirements on broker-dealers that sell securities governed by these rules to persons other than established customers and "accredited investors" (generally, individuals with a net worth in excess of $1,000,000 or annual individual income exceeding $200,000 or $300,000 jointly with their spouses). For such transactions, the broker-dealer must determine whether persons that are not established customers or accredited investors qualify under the rule for purchasing such securities and must receive that person's written consent to the transaction prior to sale. Consequently, these rules may adversely effect the ability of purchasers to sell our securities and otherwise affect the trading market in our securities. Because our shares are deemed "penny stocks," you may have difficulty selling them in the secondary trading market.

The Securities and Exchange Commission has adopted regulations which generally define a "penny stock" to be any equity security that has a market price (as defined in the regulations) less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. Additionally, if the equity security is not registered or authorized on a national securities exchange or Nasdaq, the equity security also would constitute a "penny stock." As our common stock falls within the definition of penny stock, these regulations require the delivery, prior to any transaction involving our common stock, of a risk disclosure schedule explaining the penny stock market and the risks associated with it. Disclosure is also required to be made about compensation payable to both the broker-dealer and the registered representative and current quotations for the securities. In addition, monthly statements are required to be sent disclosing recent price information for the penny stocks. The ability of broker/dealers to sell our common stock and the ability of shareholders to sell our common stock in the secondary market would be limited. As a result, the market liquidity for our common stock would be severely and adversely affected. We can provide no assurance that trading in our common stock will not be subject to these or other regulations in the future, which would negatively affect the market for our common stock.

A LARGE NUMBER OF SHARES WILL BE ELIGIBLE FOR FUTURE SALE AND MAY DEPRESS OUR STOCK PRICE.

Our shares that are eligible for future sale may have an adverse effect on the market price of our common stock. As of December 15, 2005, there were 59,041,685 our common stock outstanding. As of December 15, 2005 over 31,134,704 shares of our common stock will be freely tradeable without substantial restriction or the requirement of future registration under the Securities Act of 1933, as amended. The majority of the remainder of our outstanding shares, most of which are held by our officers, directors and greater than 5% shareholders, may be sold without registration under the exemption from registration provided by Rule 144 under the Securities Act. However, in connection with the merger of Cadence and Aurora, certain of our officers directors and shareholders have agreed not to sell more than 10% of their respective holdings of our common stock, measured immediately prior to the merger, for a period of 36 months following the merger, representing an aggregate of approximately 770,745 shares of our common stock. In addition, William Deneau, John Miller and John Tucker, our President, Vice President of Exploration & Production and Vice President of Land & Development, respectively, and each of their affiliates, have executed lock-up agreements in which they agree not to sell more than 10% of the shares of our common stock that they receive in the merger for a period of 36 months, representing an aggregate of approximately 974,288 shares of our common stock. In addition, as of December 15, 2005, an additional 11,967,418 shares were subject to outstanding options or warrants or were issuable upon the conversion of our Class A Preferred Shares.

Sales of substantial amounts of our common stock, or a perception that such sales could occur, and the existence of options or warrants to purchase shares of our common stock at prices that may be below the then current market price of the common stock, could adversely affect the market price of our common stock and could impair our ability to raise capital through the sale of our equity securities.

-36-

WE DO NOT HAVE CUMULATIVE VOTING AND A SMALL NUMBER OF EXISTING SHAREHOLDERS CONTROL CADENCE, WHICH COULD LIMIT YOUR ABILITY TO INFLUENCE THE OUTCOME OF SHAREHOLDER VOTES.

Our shareholders do not have the right to cumulative votes in the election of our directors. Cumulative voting, in some cases, could allow a minority group to elect at least one director to our board. Because there is no provision for cumulative voting, a minority group will not be able to elect any directors. Accordingly, the holders of a majority of the shares of common stock, present in person or by proxy, will be able to elect all of the members of our board of directors.

In connection with the closing of the merger of Cadence and Aurora, certain of our shareholders, including certain former Aurora shareholders who became shareholders of us in connection with the merger, executed and delivered voting agreements pursuant to which they agreed, for a period of 36 months, to vote an aggregate of 22,740,830 of their shares of our common stock in favor of (i) five directors designated by William W. Deneau, who shall initially be William W. Deneau, Earl V. Young, Gary J. Myles, Richard Deneau, and Ronald E. Huff; and (ii) two directors designated by William W. Deneau from among our Board of Directors immediately before the closing of the merger, who shall initially be Howard Crosby and Kevin Stulp. In addition, such shareholders agreed to vote all of their shares of common stock to ensure that the size of our Board of Directors will be set and remain at seven directors. In addition, also in connection with the closing of the merger, certain of our shareholders executed and delivered irrevocable proxies naming, for a period of 36 months, William W. Deneau and Lorraine King as proxies to vote an aggregate of 10,102,286 shares of our common stock held by such shareholders in the manner determined by such proxies. These provisions will limit your ability to influence the outcome of shareholder votes including votes concerning the election of directors, the adoption or amendment of provisions in our articles of incorporation or bylaws and the approval of mergers and other significant corporate transactions for a period of three years following closing of the merger.

OUR ARTICLES OF INCORPORATION CONTAIN PROVISIONS THAT DISCOURAGE A CHANGE OF CONTROL.

Our articles of incorporation contain provisions that could discourage an acquisition or change of control without our board of directors' approval. Our articles of incorporation authorize our board of directors to issue preferred stock without shareholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire control of us, even if that change of control might be beneficial to our shareholders.

-37-

CADENCE Pro Forma Information

CADENCE RESOURCES CORPORATION

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

SEPTEMBER 30,2005

							Pro Forma Adjustments				Combined
	Cadence			Aurora			(See detailed summary in Note (g)				Pro Forma
							DR		CR		Balance
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,694,838		$	10,937,632		$	-			$	12,632,470
Accounts receivable		491,324			4,542,815							5,034,139
Other Current Assets		103,348			246,481							349,829
TOTAL CURRENT ASSETS		2,289,510			15,726,928			-		-		18,016,438
OIL AND GAS PROPERTIES
FULL COST		-			33,198,842			15,212,303		52,850		48,358,295
OIL AND GAS PROPERTIES
SUCCESSFUL EFFORTS		3,081,428			-			52,850		3,134,278		-
PROPERTY AND EQUIPMENT, NET		2,167			295,643			-		-		297,810
OTHER ASSETS
Goodwill		-			-			16,277,096		-		16,277,096
Identifiable Intangibles (net)		-			-			4,605,000		1,023,333		3,581,667
Other assets		1,067,717			2,255,610			633,521		750,000		3,206,848
TOTAL ASSETS	$	6,440,822			51,477,023		$	36,780,770	$	4,960,461	$	89,738,154
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued expenses	$	446,166		$	4,491,624		$	-	$	-		4,937,790
Notes payable - related party					-			-		-		-
Other Liabilities		119,147			236,850			-		-		355,997
TOTAL CURRENT LIABILITIES		565,313			4,728,474			-		-		5,293,787
LONG-TERM DEBT		-			30,080,905			-		-		30,080,905
MINORITY INTEREST IN NET ASSETS
OF SUBSIDIARIES		-			-			-		-		-
REDEEMABLE PREFERRED STOCK		59,925			-			-		-		59,925
STOCKHOLDERS' EQUITY
Common stock		209,113			19,046			6,000		367,878		590,037
Additional paid-in capital		30,918,122			19,351,780			28,771,797		35,730,766		57,228,872
Accumulated deficit		(24,797,883	)		(2,703,182	)		3,885,369		28,384,830		(3,001,604	)
Accumulated other comprehensive loss		(513,768	)		-			-		-		(513,768	)
TOTAL STOCKHOLDERS' EQUITY		5,815,584			16,667,644			32,663,166		64,483,475		54,303,537
TOTAL LIABILITIES AND
STOCKHOLDERS' EQUITY	$	6,440,822		$	51,477,023		$	69,443,935	$	69,443,936	$	89,738,154

See accompanying notes to unaudited pro forma financial statements.

-38-

CADENCE RESOURCES CORPORATION

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

YEAR ENDED SEPTEMBER 30, 2005

							Pro Forma				Combined
	Cadence (1)			Aurora			Adjustments				Proforma
							DR		CR
REVENUES
Oil and gas sales	$	2,413,046		$	3,103,990						$	5,517,036
Other income		100,000			499,403							599,403
Total Revenues		2,513,046			3,603,393			-		-		6,116,439
OPERATING AND ADMINISTRATIVE EXPENSES
Depreciation, depletion and amortization		2,683,279			470,437			1,263,329				4,417,044
Officers' and directors' compensation		1,105,328			-							1,105,328
Consulting & other professional services		104,595			-							104,595
Oil and gas lease expenses		612,624			-					612,624		-
Oil and gas consulting		165,000			-					165,000		-
Exploration and drilling		235,959			-					235,959		-
Production and lease operating expenses		178,437			1,377,878							1,556,315
State Taxes		-			334,199							334,199
Other general and administrative		996,127			2,205,557							3,201,684
Total Expenses		6,081,349			4,388,072			1,263,329		1,013,583		10,719,166
LOSS FROM OPERATIONS		(3,568,303	)		(784,678	)		1,263,329		1,013,583		(4,602,727	)
OTHER INCOME (EXPENSE)
Interest income		10,173			263,223							273,396
Interest expense and loan fees		(1,138,987	)		(540,113	)						(1,679,100	)
Other income		846			-							846
Loss on sale of investment		(66,006	)		-							(66,006	)
Loss on disposition and impairment of assets		-			-							-
Total Other Income (Expense)		(1,193,974	)		(276,890	)		-		-		(1,470,864	)
LOSS BEFORE MINORITY INTEREST ALLOCATION
AND INCOME TAX PROVISION		(4,762,277	)		(1,061,568	)		1,263,329		1,013,583		(6,073,591	)
OTHER COMPREHENSIVE INCOME (LOSS)
Unrealized gain (loss) on market value of investments		(49,201	)		-			-		-		(49,201	)
MINORITY INTEREST IN LOSS OF SUBSIDIARIES		-			147,413			-		-		147,413
LOSS BEFORE INCOME TAX PROVISION		(4,811,478	)		(914,155	)		1,263,329		1,013,583		(5,975,379	)
INCOME TAX PROVISION		-			-							-
NET LOSS	$	(4,811,478	)	$	(914,155	)		1,263,329		1,013,583	$	(5,975,379	)
PROFORMA LOSS PER SHARE
Including effect of
subsequent stock issuances												(0.10	)
Excluding effect of
subsequent stock issuances												(0.15	)

See accompanying notes to unaudited pro forma financial statements.

-39-

CADENCE RESOURCES CORPORATION

NOTES TO PRO FORMA FINANCIAL STATEMENTS

NOTE 1 - MERGER AGREEMENT

On January 31, 2005, Cadence Resources Corporation (Cadence) entered into a definitive merger agreement with Aurora Energy, Ltd. (Aurora) whereby Cadence will acquire 100% of the outstanding stock and options of Aurora. Consideration in this transaction will consist of the issuance of two shares of common stock of Cadence for every one share of outstanding stock of Aurora, and the issuance of two options for the purchase of stock in Cadence for each option outstanding of Aurora.

Evaluation of the facts in this transaction indicates that the Aurora stockholder group will receive the largest portion of the voting rights, will have the majority number of members of the board of directors, and will dominate senior management. Accordingly, under FAS 141, Aurora is treated as the acquirer for accounting purposes and, accordingly reverse acquisition accounting has been applied to this business combination. As the registrant, the equity structure of Cadence remains the equity structure of the ongoing entity.

The merger will be accounted for as a reverse acquisition application of the purchase method of accounting by Cadence, with Aurora treated as the accounting acquirer. As such, the purchase price assigned to this transaction is equal to $41,546,351 determined as follows:

Fair value of Cadences’ common stock outstanding at January 1, 2005:	$	33,951,817
Fair value of Cadences’ stock options outstanding at January 1, 2005		536,210
Fair value of Cadence’s warrants outstanding at January 1, 2005		7,058,324
Total purchase price	$	41,546,351

The $33,951,816 is computed as 20,702,327 shares of Cadence multiplied by $1.64 (per share sales price of Cadence common stock as reported on the OTC Bulletin Board as of January 31, 2005).

The accompanying pro forma financial statements contain adjustments to characterize the transactions of Cadence as those of Aurora for the periods presented. Both the Cadence and Aurora pro forma statements of operations are presented for the twelve months ended September 30, 2005.

The pro forma balance sheet is presented at September 30, 2005 for Aurora and Cadence. In compiling this balance sheet, the $41,546,351 purchase price has been allocated between the following categories (1) Unproved oil and gas properties, (2) Other investments (3) Intangible assets and (3) goodwill. This pro forma balance sheet is based on management’s preliminary estimates of acquired fair values as of the date of the merger.

40

CADENCE RESOURCES CORPORATION

NOTES TO PRO FORMA FINANCIAL STATEMENTS

									Cadence
	Balances			FMV		Adjusted			Activity			Balances
Book Value of Cadence Assets	1/31/2005			Adjustments		Balances			2/1-9/30			9/30/05
Current Assets		8,600,202					8,600,202			(6,310,692	)		2,289,510
Oil & Gas Properties, Property & Equip		3,653,613			11,353,113		15,006,726			(570,018	)		14,436,708
Investments		938,955			633,521		1,572,476			(68,644	)		1,503,832
Mineral rights		197,406					197,406			-			197,406
Non Compete					3,265,000		3,265,000						3,265,000
Proprietary Business Relationship					1,340,000		1,340,000						1,340,000
Goodwill					16,277,096		16,277,096						16,277,096
							-						-
Less: Liabilities as of 9/30/05							-						-
Accounts payable and accrued expenses		(400,154	)				(400,154	)		(165,159	)		(565,313	)
Notes Payable-Long Term		(4,252,476	)				(4,252,476	)		4,252,476			-
Other Liabilities		-					-						-
Redeemable Preferred Stock		(59,925	)				(59,925	)					(59,925	)
													-
Other Adjustments:													-
Cadence activity from date of merger													-
through September 30, 2005		-								2,862,037			2,862,037
Total Purchase Price allocated		8,677,621			32,868,730		41,546,351			-			41,546,351

NOTE 2 - SUMMARY OF PRO FORMA ADJUSTMENTS

PRO FORMA ADJUSTMENTS - September 30, 2005

(a) To reclassify the working interest in properties owned by Aurora and purchased by Cadence. Additionally, reclassification of the depletion and/or amortization of the property have been completed to the proper owner.

(b) To increase the outstanding shares of Aurora on a two-for-one basis in accordance with the definitive merger agreement and to adjust par value of the revised outstanding shares of common stock of Aurora to the par value of Cadence.

(c) To eliminate the accumulated deficit of Cadence to additional paid-in capital as part of the value of the acquisition upon merger.

(d) To reflect the fair market value at January 31, 2005, the date of the definitive merger agreement, the shares outstanding in Cadence were multiplied the per share sales price as listed on the OTC Bulletin Board as of January 31, 2005 ($1.64), with the resulting increase in value allocated between oil and gas properties, other investments, goodwill and other intangible assets. Amortization has been computed in the accompanying pro forma as follows; $4,605,000 of estimated intangible assets amortized over 36 months (estimated useful life of the other intangible assets) for a total of $1,023,333 in amortization expense.

(e) To conform the oil and gas properties owned by Cadence to the full cost method as used by Aurora, the accounting acquirer. Note, the oil and gas exploration and intangible drilling expenses of Cadence under the successful efforts method have been adjusted to give pro forma effect to conform to the treatment of these expenditures under the full cost method used by Aurora. The net addition to oil and gas properties in converting from successful efforts to full cost is $724,912 and is recorded on the balance sheet as an addition to the oil and gas properties and adjustment to net deficit.

41

CADENCE RESOURCES CORPORATION

NOTES TO PRO FORMA FINANCIAL STATEMENTS

The table below sets out in detail the effect of changing to full cost by period to highlight the amounts reflected in the statements of operations for the period ended September 30, 2005

	Summary of Difference by Reporting Period
	2005			2004			2003			2002			Totals
Net exploration costs added back		1,013,583			805,136			422,172			260,786			2,501,677
Depletion, depreciation and amortization and
impairment under respective methods		(239,995	)		(1,323,975	)		(192,718	)		(20,076	)		(1,776,765	)
Net Change in asset value		773,588			(518,839	)		229,454			240,710			724,912

(f) To eliminate the investment in Aurora by Cadence.

42

CADENCE RESOURCES CORPORATION

NOTES TO PRO FORMA FINANCIAL STATEMENTS

(j) The effects of the above transactions are summarized as follows:

BALANCE SHEET ACCOUNT	Note Ref		AMOUNT
(2) OIL AND GAS PROPERTIES (NET) USING FULL COST
Beginning Balance (combined companies)			$	33,198,842
Reclassification of working interest in properties owned by Aurora and purchased by Cadence,		(a)		528,503
Reclassification of depletion and/or amortization associated with above reclassification of working interest		(a)		(52,850	)
Estimated allocation of purchase price to oil and gas properties based on fair market valuation of unproved Cadence properties		(d)		11,353,113
Reclassification of Cadence properties from successful efforts to full cost		(e)		2,626,496
Record upward net adjustment from successful efforts to full cost		(e)		732,510
Total pro forma adjustments to oil and gas properties under full cost				15,187,772
Ending pro forma balance			$	48,386,614
(3) OIL AND GAS PROPERTIES (NET) USING SUCCESSFUL EFFORTS
Beginning Balance (combined companies)			$	3,102,149
Reclassification of working interest in properties owned by Aurora and purchased by Cadence,		(a)		(528,503	)
Reclassification of depletion and/or amortization associated with above reclassification of working interest		(a)		52,850
Reclassification of Cadence properties from successful efforts to full cost		(d)		(2,626,496	)
Total pro forma adjustments to oil and gas properties under successful efforts			$	(3,102,149	)
Ending pro forma balance			$	-
			$	3,102,149
(4) GOODWILL
Beginning Balance (combined companies)			$	-
Estimated allocation of purchase price to goodwill based on estimated fair market valuation		(d)		16,277,096
Ending pro forma balance			$	16,277,096
(4) OTHER INTANGIBLE ASSETS (NET)
Beginning Balance (combined companies)				-
Estimated allocation of purchase price to intangibles based on estimated fair market valuation		(d)		4,605,000
Amortization expense ($4,605,000 estimated intangibles over 36 months)		(d)		(1,023,333	)
Ending pro forma balance				3,581,667
(4) OTHER ASSETS
Beginning Balance (combined companies)				3,323,327
Estimated allocation of purchase price to other investments based on estimated fair market valuation		(d)		633,251
Eliminate Cadence investment in Aurora Stock		(d)		(750,000	)
Ending pro forma balance				3,206,578
(5) COMMON STOCK
Beginning Balance (combined companies)				228,159
Issuance of Cadence Stock for Aurora Stock on a 2-for 1 basis		(d)		19,046
Adjust par value of revised outstanding shares of common stock of Aurora to par value of Cadence		(d)		348,832
Remove the investment in Aurora by Cadence		(f)		(6,000	)
Total pro forma adjustments				361,878
Ending pro forma balance				590,037
(6) ADDITIONAL PAID IN CAPITAL
Beginning Balance (combined companies)				50,269,902
Issuance of Cadence Stock for Aurora Stock on a 2-for 1 basis		(b)		(19,046	)
Adjust par value of revised outstanding shares of common stock of Aurora to par value of Cadence		(b)		(348,832	)
To close the accumulated deficit of Cadence		(c)		(27,727,754	)
Record net purchase price after allocation to Cadence net assets ($41,546,351 - $5,781,667)		(d)		35,764,684
Remove the investment in Aurora by Cadence		(f)		(744,000	)
Total pro forma adjustments				6,925,052
Ending pro forma balance				57,194,954
(7) ACCUMULATED DEFICIT
Beginning Balance (combined companies)				27,534,982
To close the accumulated deficit of Cadence		(c)		(27,727,754	)
Adjust for Cadence 2/1/05-6/30/05 activity after allocation of net 1/31/05 assets		(d)		2,895,954
Record 8 months amortization on intangible assets ($4,605,000 over 36 months)		(d)		1,023,333
Record upward net adjustment from successful efforts to full cost		(e)		(732,510	)
Total pro forma adjustments				(24,540,977	)
Ending pro forma balance				2,994,005

43

Item 2.  Description of Properties

In addition to the properties described above in Item 1, we have certain non-oil and gas properties as described below.

On September 19, 2005, we purchased a commercial condominium unit in the Copper Ridge Professional Center Five. This condominium project is located in Traverse City, Michigan. Our space is approximately 14,645 square feet on the second floor of the building, plus common areas and 15 covered parking spaces. We moved into this space on December 5, 2005.

We are subject to an existing lease on our previous office space with South 31, L.L.C. This lease runs through March 31, 2007. Monthly rent is $8,700. We are in negotiations to buy out the balance of this lease. Its status is not yet resolved.

We also have non-oil and gas mineral rights in a number of properties, although we do not presently consider them to be material to our business on a going forward basis.

44

Item 3.  Legal Proceedings

There are no currently threatened or pending claims against Cadence.

Item 4.  Submission of Matters to a Vote of Security Holders

There were no matters submitted to a vote of security holders for the quarter ended September 30, 2005.

PART II

Item 5.  Market for Common Equity and Related Stockholder Matters

Market for Our Common Stock

Our common stock trades under the symbol CDNR.BB on the Over-the-Counter Bulletin Board Electronic Quotation System maintained by the National Association of Securities Dealers, Inc. Approximately 15 professional market makers hold themselves out as willing to make a market in our common stock. Following is information about the range of high and low bid prices for our common stock for each fiscal quarter in the last two fiscal years. These quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission, and may not necessarily represent actual transactions.

Quarter Ended	High Bid Quotation		Low Bid Quotation
December 31, 2003	$	3.60	$	2.75
March 31, 2004	$	4.60	$	3.25
June 30, 2004	$	3.40	$	1.62
September 30, 2004	$	2.50	$	0.88
December 31, 2004	$	1.65	$	0.98
March 31, 2005	$	1.70	$	1.09
June 30, 2005	$	2.65	$	2.11
September 30, 2005	$	3.35	$	1.86

Equity Compensation Plan Information

Our Board of Directors adopted a written stock option plan which was approved by our shareholders in 2004. This plan provides for the grant of options or restricted share amounts for up to 1,000,000 shares of common stock. From time to time our Board of Directors has in the past, and may in the future, issue to consultants or other third parties options or warrants that are not pursuant to the plan for compensatory purposes or pursuant to financings. The table below sets forth certain information as of September 30, 2005 regarding the shares of our common stock (i) available for grant or granted pursuant to outstanding stock options or (ii) issuable upon exercise of options or warrants granted as compensation for services.

	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities in the first column of this table)
Compensatory warrants or options approved by security holders		400,000	$	2.29		399,500
Compensatory warrants or options not approved by security holders		880,140	$	1.69		N/A

45

Holders

As of December 15, 2005, there were 537 holders of record of our common stock, although we believe that there are additional beneficial owners of our common stock who own their shares in “street name.”

Dividends

There have been no cash dividends declared on our common stock since our company was formed. Dividends are declared at the sole discretion of our board of directors. It is not anticipated that any dividends will be declared for the foreseeable future on our common stock.

Recent Sales of Unregistered Equity Securities

At the time of issuance, each investor or recipient of unregistered securities was either an accredited investor or a sophisticated investor. Each investor had access to Cadence's most recent Form 10-KSB, all quarterly and periodic reports filed subsequent to such Form 10-KSB and Cadence's most recent proxy materials.

Between April and June 2002, Cadence sold an aggregate of 1,932,802 units to 5 accredited investors, each unit consisting of one share of common stock and a warrant to purchase one share of common stock, for an aggregate of $579,840.60. Each warrant was exercisable at a price of $.15 per share and have all been exercised. No sales commissions were paid in connection with this transaction. The Units were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act. On October 23, 2002, Cadence issued 1,815,316 shares of common stock to four accredited investors upon the cashless exercise of the warrants granted in the April through June 2002 offering. On September 15, 2003, Cadence issued 141,668 shares of its common stock to three accredited investors upon the cashless exercise of the warrants granted in the April through June 2002 offering. No sales commissions were paid in connection with the exercise of the warrants. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

Between November 2002 and March 2003, Cadence issued 34,950 shares of Class A Preferred Shares to 8 investors who were not US persons under Regulation S of the Securities Act for an aggregate of $52,425. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Regulation S of the Securities Act.

During fiscal 2003, Howard M. Crosby made two loans to Cadence. One loan in December 2002 was in the principal amount of $70,000, bearing interest at 5% and the other loan made in February 2003 in the principal amount of $50,000 bearing interest at a rate of 8%. Cadence issued 14,000 shares of its common stock as an inducement to making the $70,000 loan and 20,000 shares as an inducement to making the $50,000 loan. Cadence repaid $60,000 and has agreed to issue 4,000 shares of its common stock in repayment of the remaining $10,000 principal amount outstanding on the $70,000 loan. Cadence repaid $25,000 of the $50,000 loan in cash and issued 25,000 shares of its common stock to repay the remaining $25,000 principal amount outstanding. No sales commissions were paid in connection with these transactions. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

In February 2003, Kevin Stulp, one of Cadence's directors, made a bridge loan to Cadence in the principal amount of $50,000, bearing interest of 8% per annum. Cadence issued 20,000 shares of its stock to Mr. Stulp as an inducement to making the loan. On May 28, 2003, Cadence repaid $25,000 of the loan. At September 30, 2004, the Company issued 25,000 shares of its stock in full payment of the remaining loan principal of $25,000. In July 2003, Cadence issued 100,000 shares of common stock to Mr. Stulp upon the exercise of a warrant at $.75 per share. No sales commissions were paid in connection with these transactions. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On February 4, 2003, Cadence issued an aggregate of 150,000 shares of its common stock to four of its officers and/or directors in consideration of services provided to Cadence. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

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On February 19, 2003, Cadence issued 5,000 shares of its common stock to one sophisticated investor in consideration of certain consulting services provided to Cadence. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On February 19, 2003, Cadence issued 40,000 shares of its common stock to an accredited investor as an inducement for making a loan to Cadence of $100,000. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

Between April and May 2003, Cadence issued an aggregate of 44,000 shares of its common stock to two sophisticated investor in consideration of certain consulting services provided to Cadence. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On May 7, 2003, Cadence issued an aggregate of 75,000 shares of its common stock to four of its officers and/or directors in consideration of services provided to Cadence. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On May 7, 2003, Cadence issued 10,000 shares of its common stock to one sophisticated investor in consideration of certain consulting services provided to Cadence. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

Between May and August 2003, Cadence sold an aggregate of 730,000 shares of its common stock to 16 accredited investors for an aggregate of $710,000. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On February 19, 2003, Cadence issued 6,000 shares of its common stock to one sophisticated investor in consideration for a loan of $30,000, which was subsequently repaid.

In June 2003, Nathan Low loaned $300,000 to Cadence Resources Corporation Limited Partnership, of which Cadence was the sole general partner and Mr. Low was the sole limited partner. As partial inducement for making this loan, Cadence issued Mr. Low 120,000 shares of common stock. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

In July 2003, CGT Management, Ltd. loaned Cadence $300,000 at 10% interest. See "Related Parties Transactions." As an inducement for making the loan, Cadence issued 120,000 shares to CGT Management. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On July 1, 2003, Cadence issued an aggregate of 95,000 shares of its common stock to four of its officers and/or directors in consideration of services provided to Cadence. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

In August 2003, Cadence issued 102,000 shares of its common stock to four sophisticated investors in consideration of certain consulting services provided to Cadence. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

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On September 15, 2003, Cadence issued an aggregate of 95,000 shares of its common stock to four of its officers and/or directors in consideration of services provided to Cadence. No sales commissions were paid in connection with this transaction. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

Between September and October 2003, Cadence sold an aggregate of 1,721,400 shares of its common stock to 29 accredited investors for an aggregate of $4,303,500. Sales commissions consisting of (i) $376,565 in cash, (ii) 11,000 shares of common stock valued at $2.90 per share or $31,900 in the aggregate and (iii) options to purchase 162,140 shares of common stock at $2.50 per share to one finder or an entity controlled by such finder, and additional fees totaling $11,250 to two other finders. All finders are accredited investors. The shares and warrant were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On January 23, 2004, Cadence issued 5,000 shares of its common stock and an option to purchase 75,000 shares of its common stock to each of Glenn DeHekker and Jeffrey M. Christian in consideration of their becoming directors of Cadence. The shares and options were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On January 23, 2004, Cadence issued an option to purchase 250,000 shares of its common stock to Douglas Newby in consideration of his becoming a Vice President of Cadence. The options were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On February 25, 2004, Cadence issued 15,000 shares to David Nahmias and 15,000 shares to Lyons Capital, LLC in consideration of services provided to Cadence. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On April 2, 2004, Cadence sold 120 units, each of which consisted of a note in the principal amount of $50,000 and a warrant to purchase 6,375 shares of Common Stock, exercisable at $4.00 per share, to seven accredited investors for an aggregate sales price of $6,000,000. As compensation for his services in connection with this private placement, Cadence paid Nathan A. Low, an accredited investor, $300,000 and issued him a warrant to purchase 76,500 shares of Common Stock, exercisable at $4.00 per share. On January 31, 2004, Cadence paid off the notes without a prepayment penalty in exchange for the exercise price of the warrants being reduced to $1.25. All the warrants described in this paragraph expire on April 2, 2007. The shares and warrant were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On April 15, 2004 Cadence issued 10,000 shares each to Glenn DeHekker, Jeff Christian, and Kevin Stulp for Director services for two quarters. On the same date Cadence also issued 5,000 shares each to Howard Crosby and John Ryan for Director services for one quarter, and 5,000 shares each to Howard Crosby, John Ryan, and Doug Newby for Officer services for one quarter. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On June 2, 2003, Cadence issued 6,000 shares to Proteus Capital Corp. in consideration of services rendered to the Company. On the same date Cadence issued 10,000 shares to Robert Denison upon exercise of warrants at $1.35. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On August 20, 2004 Cadence issued 25,000 shares to Howard Schraub and 17,500 shares to Lyons Capital LLC for professional services rendered. On the same date Cadence issued 5,000 shares to Glenn DeHekker, Kevin Stulp and Jeff Christian for quarterly services as Directors to the Company, and issued 5,000 shares to Doug Newby for quarterly services as an Officer of the Company. Also on the same date Cadence issued 15,000 shares to RMB International (Dublin), Limited as a break-up fee for a proposed debt financing. In each case the shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On January 31, 2005, Cadence issued 7,810,000 shares of common stock and warrants to purchase 14,050,000 shares of common stock at an exercise price of $1.75 per shares to 22 accredited investors for $9,762,500. Sunrise Securities Corporation, an affiliate of Nathan Low (a shareholder of Cadence), will receive a commission equal to $926,250 and a warrant to purchase 2,186,000 shares of Cadence's common stock at an exercise price of $1.75 per share for services rendered as the placement agent in the transaction. All the warrants described in this paragraph expire on January 31, 2009. The shares were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On September 30, 2005, Cadence issued options to purchase 50,000 shares of our common stock to each of the five members of our board of directors (i.e., options to purchase an aggregate of 250,000 shares).  These options are exercisable for $1.42 per share.  The options were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

On October 31, 2005, Cadence issued warrants to purchase 37,500 shares of our common stock to each of three individuals (i.e., warrants to purchase an aggregate of 112,500 shares) upon the individuals’ resignations from our Board of Directors. Of the warrants issued to each such individual, warrants to purchase 12,500 shares (or an aggregate of 37,500 for all three individuals) were exercisable for $2.23 a share, warrants to purchase 12,500 shares (or an aggregate of 37,500 for all three individuals) were exercisable for $2.53 a share and warrants to purchase 12,500 shares (or an aggregate of 37,500 for all three individuals) were exercisable for $3.28 a share. The warrants were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act.

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Item 6.  Management’s Discussion and Analysis or Plan of Operations

You should read the following discussion in conjunction with the Cadence Resources Corporation financial statements, together with the notes to those statements, included elsewhere in this report. The following discussion contains forward-looking statements that involve risks, uncertainties, and assumptions such as statements of our plans, objectives, expectations, and intentions. Our actual results may differ materially from those discussed in these forward-looking statements because of the risks and uncertainties inherent in future events.

Overview

General. We were incorporated in Utah on April 7, 1969 to explore and mine natural resources under the name Royal Resources, Inc. In January 1983, we changed our name to Royal Minerals, Inc. In March 1994, we changed our name to Consolidated Royal Mines, Inc. In September 1995, we changed our name to Royal Silver Mines, Inc. On May 2, 2001 we changed our name to Cadence Resources Corporation in connection with a corporate reorganization to focus our operations on oil and gas exploration.

As a result of our recent acquisition of Aurora Energy, Ltd. (“Aurora”) which, as described below, was consummated after the date of the most recent financial statements contained in this report on Form 10-KSB, we manage our business through two divisions - Cadence and Aurora. Our audited financial statements set forth beginning on page F-1 to this report on Form 10-KSB reflect financial information pertaining to our Cadence division prior to the acquisition of Aurora. Included at the end of Item 2 of this report on Form 10-KSB are pro forma financial statements containing certain financial information of Cadence and Aurora together.

The management discussion and analysis in this section, except as otherwise specifically stated, pertains to the financial condition and results of operation of our Cadence division during periods prior to the acquisition of Aurora. References in this management discussion and analysis to “we” and “our” and similar pronouns and other terms refer to our Cadence division prior to the Aurora acquisition, unless otherwise stated.

Acquisition of Aurora. We acquired Aurora on October 31, 2005 through the merger of our wholly-owned subsidiary with and into Aurora. As a result of that merger, Aurora became our wholly-owned subsidiary. The acquisition of Aurora will be accounted for as a reverse merger, with Aurora being the acquiring party for accounting purposes. Aurora’s revenues for the nine-month period ended September 30, 2005 were $3,644,698, compared with our revenues of $1,783,287 during the nine-month period ended June 30, 2005. Aurora’s total assets as of September 30, 2005 were $51,477,023, compared with our total assets of $6,414,653 as of the same date.

In connection with the acquisition of Aurora, we issued an aggregate of 37,512,366 shares of our common stock to the former shareholders of Aurora, and have reserved an additional 10,497,328 shares of our common stock for issuance upon exercise of options or warrants that had been issued by Aurora prior to the acquisition and that were previously exercisable for shares of the common stock of Aurora.

As a result of the acquisition of Aurora, we will revise certain of our accounting principles applicable to our oil and gas properties, and have changed our accounting fiscal year to end on December 31, commencing December 31, 2005. See the caption " - Future Changes in Accounting Principles” within this management discussion and analysis.

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We are engaged in acquiring, exploring, developing, and producing oil and gas properties. We have operations in Wilbarger County, Texas, DeSoto Parish, Louisiana, Eddy County, New Mexico and Alpena County, Michigan. We also have leased interests in western Kansas and southern Texas. We also own a number of non-producing properties described below that are in various stages of development.

Our goal is to generate revenues from the sale of oil and gas production sufficient to support ongoing development. Once wells are drilled and in production, the underlying gas reserves will be characterized as proved developed producing reserves. As a general rule, once the underlying resources are characterized as proved developed producing reserves, the underlying assets can be pledged to support debt financing.

January 2005 Private Placement. On January 31, 2005, we sold to 22 accredited investors in a private placement transaction, for $9,762,500, 7,810,000 shares of common stock and warrants to purchase 14,050,000 shares of common stock at an exercise price of $1.75 per share. For services rendered in connection with the transaction, we compensated a principal stockholder in the form of $976,250 in cash, 859,000 shares of our common stock warrants to purchase 781,000 shares of common stock at an exercise price of $1.25 a share. Of the proceeds raised in our January 31, 2005 private placement, $5,000,000 was used to prepay outstanding promissory notes issued by us in April 2004. In addition, on January 31, 2005, Aurora sold to six accredited investors in a private placement transaction, for $12,550,000, shares of Aurora common stock and warrants to purchase Aurora common stock that, as a result of the merger, became 10,040,000 shares of our common stock and warrants to purchase 3,800,000 shares of our common stock at an exercise price of $1.75 per share. For services rendered in connection with the Aurora private placement, we compensated a principal stockholder in the form of $1,255,000 in cash, shares of Aurora common stock and warrants to purchase Aurora common stock that, as a result of the merger, became 1,104,400 shares of our common stock and warrants to purchase 1,004,000 shares of our common stock at an exercise price of $1.25 per share. The proceeds of the Aurora private placement were used substantially in Aurora’s expanded drilling program during 2005 and for general working capital purposes.

Continuing Losses. We have had net losses from operations each year since inception, and there can be no assurance that we will be profitable in the future. Our financial results depend upon many factors that impact our results of operations including:

·    The sales prices of natural gas and crude oil.

·    The volume of sales of natural gas and crude oil.

·    The availability of financial resources to meet cash flow needs.

·    The level and success of exploitation and development activity.

Results of Operation

Comparison of Fiscal Year Ended September 30, 2005

to Fiscal Year ended September 30, 2004

Revenues

We derive revenues from the sale of oil and gas produced at wells in which we have an economic interest. All sales of oil and gas production are arranged by our partners who operate the wells and with whom we are developing the respective oil and gas properties. Revenue for oil and gas sales reported in our statements of operations and comprehensive loss are stated after deducting royalty amounts payable to property owners and other third parties.

During the fiscal year ended September 30, 2005 (“fiscal 2005”), revenues from oil and gas sales were $2,413,046, reflecting a decrease of $128,401, or 5.1%, compared with revenues from oil and gas sales of $2,541,447 during the fiscal year ended September 30, 2004 (“fiscal 2004”). This decrease was attributable to decreased quantities of production during fiscal 2005 compared with fiscal 2004 which were substantially offset by higher commodity prices realized in fiscal 2005 and, to a lesser extent, by additional production resulting from the commencement of pumping at certain additional wells at the West Electra Lake Prospect late in fiscal 2005

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Revenues for fiscal 2005 were primarily from production from our wells in Texas, Louisiana and Michigan. These revenues were derived from the sale of 16,885 net barrels of oil at an average price of $51.64 per barrel from our wells in Texas and 199,703 MCF of natural gas at an average price of $7.26 per MCF from our wells in Louisiana and Michigan. The decrease in production from our wells during fiscal 2005 compared with fiscal 2004 was primarily attributable to:

·    A decrease in the quantities pumped from Virgin Reef Prospect well #1A, in which we have 60% of the working interest. During September 2004, this well produced an average of approximately 50 net working interest barrels per day; by September 2005, production at this well had declined to less than 20 net working interest barrels per day.

·    A general decrease in the quantities pumped from the initial West Electra Lake Prospect wells in which we have an interest.

As of September 30, 2005 we had interests in nine producing oil wells in Wilbarger County, Texas, eleven producing natural gas wells in DeSoto Parish, Louisiana, an interest in nine producing gas wells in Alpena County, Michigan and a minority interest in a producing well in Eddy County, New Mexico. As of September 30, 2005 we had 20 gross (9.86 net) oil and gas wells, 7,250 gross (3,357 net) acres of developed wells and 27,840 gross (27,840 net) acres of undeveloped wells. Using the net proceeds from the private placement in January 2005, after repayment of promissory notes we issued in 2004 and payment of commissions,, we expanded our drilling program during fiscal 2005.

As a result of our evaluation of the performance of our natural gas wells in DeSoto Parish, which we have been developing with our partner Bridas Energy, we determined not to drill additional wells at that location. In the first two quarters of fiscal 2005, we drilled four new wells on our West Electra Lake Unit and a new well on our E lease, all in Wilbarger County, TX, completed the seismic evaluation process on the north block of our Kansas acreage, participated for a working interest in development wells being drilled in Eddy County, NM and participated for a working interest in an exploratory well in Tennessee.

Expenses

Our expenses principally fall within two general categories: oil and gas operating expenses and general and administrative expenses. Oil and gas operating expenses include consulting fees for technical and professional services related to oil and gas activities, leases, drilling expenses, exploration expenses, depletion, depreciation and amortization of oil and gas properties and related equipment, and other expenses related to the procurement and development of oil and gas properties. General and administrative expenses include officer compensation, rent, travel, accounting, auditing and legal fees associated with SEC filings, directors fees, investor relations and related consulting fees, stock transfer fees and other items associated with the costs of being a public entity.

The following table is a comparison of our two general categories of expenses for fiscal 2005 and fiscal 2004, and the percentages each of these categories comprise of total expenses:

	YEAR ENDED SEPTEMBER 30,
	2005					2004
	2005		% of 2005 Total Expenses			2004		% of 2004 Total Expenses
Expenses from Oil and Gas Operations	$	3,875,299		62.3	%	$	3,643,666		58.8	%
Corporate and Administrative Overhead	$	2,341,258		37.7	%	$	2,551,269		41.2	%
Total Expenses	$	6,216,557		100	%	$	6,194,935		100	%

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The comparable year-to-year increases in oil and gas related expenditures are summarized in the following table, which reflects the major expense categories for expenses from oil and gas operations for fiscal 2005 and fiscal 2004.

	YEAR ENDED SEPTEMBER 30,
	2005					2004
	2004		% of Total Expenses			2003		% of Total Expenses
Exploration and drilling	$	235,959		6.1	%	$	134,452		3.7	%
Depreciation, depletion and amortization		2,683,279		69.2	%		2,663,695		73.1	%
Oil and gas lease and operating expenses		611,143		15.8	%		565,148		15.5	%
Oil and gas production costs		178,437		4.6	%		174,836		4.8	%
Oil and gas consulting		165,000		4.3	%		105,535		2.9	%
Total Expenses from oil and gas operations	$	3,875,299		100	%	$	3,643,666		100	%

Oil and Gas Operating Expenses. Exploration and drilling expenses increased to $235,959 in fiscal 2005 from $134,452 in fiscal 2004, an increase of $101,507, or 75.5%, and oil and gas consulting expenses increased to $165,000 in fiscal 2005 from $105,535 in fiscal 2004, an increase of $59,465, or 56.3%. These increases were a result of our increased drilling activities beginning during the second quarter of fiscal 2005 which we funded from the net proceeds of the January 31, 2005 private placement.

Depreciation, depletion and amortization increased to $2,683,279 in fiscal 2005 from $2,663,695 in fiscal 2004, an increase of $19,584, or 0.7%. We recognize depletion of well-specific expenditures based on the amount of production during the year compared with the estimate of proved reserves at the beginning of the year. During fiscal 2005 we recognized depletion of substantially all of the depletable expenditures at the Texas properties due to the due to the fact that our independent engineer’s report as of October 1, 2004 estimated that our total reserves at the Texas properties were less than the amount of actual production from those properties during fiscal 2005. Similarly, the relatively high level of our depletion expense during fiscal 2004 resulted from the fact that our independent engineer’s report as of October 1, 2003 estimated that our total reserves were less than the amount of oil and gas was actually produced during fiscal 2005. In addition, deprecation during fiscal 2005 was increased over fiscal 2004 due to the greater amount of depreciable assets recorded after our expenditures associated with our increased drilling activities.

Oil and gas lease and operating expenses increased to $612,624 in fiscal 2005 from $565,148 in fiscal 2004, an increase of $47,476, or 8.4%, and oil and gas production costs increased to $178,437 in fiscal 2005 from $174,836 in fiscal 2004, an increase of $3,601, or 2.1%. These increases are attributable to the fact that we had a greater number of wells in operation during fiscal 2005 compared with fiscal 2004, and the fact that service providers to the oil and gas industry were generally busier during fiscal 2005 compared with fiscal 2004, resulting in higher prices being charged generally by service providers; the effects of these two factors were partially offset by the impact on these expense categories of our reduced production of oil and gas during fiscal 2005.

General and Administrative. During fiscal 2005, management and the Compensation Committee of our Board of Directors determined to reduce cash salaries and bonuses to our executives and reduce the extent we rely on outside consultants for management services. In addition to reduced cash compensation, we compensated our directors and officers with equity grants, including stock options. As a result of cash and equity compensation, officers and directors compensation increased to $991,403 in fiscal 2005 from $725,485 in fiscal 2004. Consulting expenses decreased to $70,166 in fiscal 2005 from $319,338 in fiscal 2004, a decrease of $249,172, or 78.0%. Other general and administrative expenses decreased to $1,252,267 in fiscal 2005 from $1,506,446 in fiscal 2004, a decrease of $254,179, or 16.9%, which was attributable to the fact that the fiscal 2004 amount included a greater amount of expenses attributable to debt and equity financings and the expenses of registering shares of our common stock for secondary sales by certain of our stockholders.

Other Income (Expenses). The principal significant changes in these expenses included (i) a reduction of $92,821 in interest expense and loan fees due to the fact that we repaid the $6 million of promissory notes we issued in an April 2004 private placement; these notes were repaid from the proceeds of the January 31, 2005 private placement; (ii) recognition of $660,559 as a loss on repayment of debt which consisted of unamortized deferred financing costs from our April 2004 loan financing and which were written off upon the repayment of the loans in connection with the January 31, 2005 private placement; and (iii) the absence of any impairment charge on assets during fiscal 2005, whereas in fiscal 2004 we recognized an impairment of $1,236,365 in connection with wells drilled during fiscal 2004 at our Desoto Parish, Louisiana properties.

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Comparison of Fiscal Year Ended September 30, 2004

to Fiscal Year ended September 30, 2003

Revenues

During fiscal 2004, revenues from oil and gas sales were $2,541,447, reflecting an increase of more than five times the revenues from oil and gas sales of $337,355 during the fiscal year ended September 30, 2003. This increase was primarily attributable to increased quantities of production and higher commodity prices realized in fiscal 2004. Revenues for fiscal 2004 were primarily from production from our wells in Texas, Louisiana and Michigan. Revenue during fiscal 2004 came from the sale of 25,887 net barrels of oil at an average price of $36.11 per barrel from Cadence's wells in Texas and 37,517 MCF of natural gas at an average price of $5.83 per MCF from Cadence's wells in Louisiana and Michigan. Revenues from oil and gas sales during the fiscal year ended September 30, 2003 came from the sale of 11,447 net barrels of oil at an average price of $29.47 per barrel. There was no production from Cadence's wells in Louisiana or Michigan in fiscal 2003. Cadence also realized a cash receipt of $50,000 in April 2003 from Bridas Energy upon transfer of drilling and production rights in Cadence's leasehold acreage in DeSoto Parish, Louisiana that Cadence is currently exploring with them on a joint basis.

During the year ended September 30, 2004, substantially all of our revenues were derived from our interests in five producing oil wells in Wilbarger County, Texas and eleven producing natural gas wells in DeSoto Parish, Louisiana. We received small revenues from our interest in nine producing gas wells in Alpena County, Michigan and in September 2004 received its first production revenue from a minority interest in a producing well in Eddy County, New Mexico.

Expenses

The following table is a comparison of our two general categories of expenses for fiscal 2004 and the year ended September 30 2003 (“fiscal 2003”), and the percentages each of these categories comprise of total expenses:

	YEAR ENDED SEPTEMBER 30,
	2004					2003
	2004		% of 2004 Total Expenses			2003		% of 2003 Total Expenses
Expenses from Oil and Gas Operations	$	3,643,666		58.8	%	$	583,393		28.7	%
Corporate and Administrative Overhead	$	2,551,269		41.2	%	$	1,446,756		71.3	%
Total Expenses	$	6,194,935		100.0	%	$	2,030,149		100.0	%

Year-to-year comparisons in oil and gas related expenditures are summarized in the following table, which reflects the major expense categories for expenses from oil and gas operations for fiscal 2004 and fiscal 2003.

	YEAR ENDED SEPTEMBER 30,
	2004					2003
	2004		% of Total Expenses			2003		% of Total Expenses
Exploration and drilling	$	134,452		3.7	%	$	109,968		18.8	%
Depreciation, depletion and amortization		2,663,695		73.1	%		57,310		9.8	%
Oil and gas lease expenses		565,148		15.5	%		302,204		51.8	%
Oil and gas production costs		174,836		4.8	%		34,577		6.0	%
Oil and Gas lease operating expenses		0		0.0	%		19,334		3.3	%
Oil and gas consulting		105,535		2.9	%		60,000		10.3	%
Total Expenses from oil and gas operations	$	3,643,666		100	%	$	583,393		100	%

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In the aggregate, oil and gas operating expenses increased over six-fold from the prior year, primarily as a result of our increased drilling activity during fiscal 2004. We recognized as expense substantially all of the depletable costs incurred during fiscal 2004 because our engineer’s report as of October 1, 2003 estimated that our total reserves were less than the amount of our production during fiscal 2004. Although our exploration and drilling expenses and oil and gas lease expenses increased by some $24,000 from fiscal 2003, by far the largest increase in oil and gas related expenses resulted from our decision to impair the carrying value of five De Soto Parish gas wells, as mentioned above, as well as a downward adjustment in the total gas reserves as determined by Ralph E Davis and Associates, the independent petroleum engineers.

Our general and administrative expenses increased from fiscal 2003 to fiscal 2004 by approximately $1,104,000, principally because of increased legal costs paid to outside counsel in connection with the filing of two separate SB-2 registration statements during the course of the fiscal year. These registration statements also substantially increased the amounts paid to outside accountants as well.

Capital Resources and Liquidity

Since September 30, 2002, we have funded our operations principally through the private sale of equity securities, borrowings from third party individuals and, to an increasing extent in recent months, cash flow from the sale of oil and gas produced by our wells. With the acquisition of Aurora, we will consider continuing Aurora’s practice of funding operations partly through credit facilities with industry lenders, and will review other alternative financing options appropriate to the increased size of our operations and asset base.

The level of our current assets at September 30, 2005, approximately $2.2 million, was relatively constant compared with the $2.3 million of our current assets at September 30, 2004. We maintained this relatively stable level of current assets as a result of the net proceeds of the January 31, 2005 private placement of equity securities (approximately $7.8 million) and expenditures on the repayment of indebtedness ($5.0 million), on oil and gas properties and on certain investments.

In February 2004, we borrowed $410,000 in short term notes from three directors and a company of which two officers and directors are also affiliated. These notes bore interest at the rate of 12% per annum, and were repaid in full in April 2004. On April 2, 2004, we issued $6,000,000 of senior secured notes to seven individual investors. Each $50,000 principal amount of the notes was accompanied by warrants to purchase 6,375 shares of our common stock, or an aggregate of 765,000 shares, at a price of $4.00 per share. The warrants expire on April 2, 2007. During this reporting period these secured notes were repaid in full. In conjunction with early repayment of the notes, the exercise price of the warrants was reduced to $1.25.

We realized net proceeds of $941,900 from the sale of our common stock and warrants during fiscal year 2002, net proceeds of approximately $4,830,000 from the sale of our common stock, preferred stock and warrants during the year ended September 30, 2003. Additionally, we received net proceeds of $288,500 from the sale of common stock and exercise of warrants during the year ended September 30, 2004.

In the periods ended September 30, 2003, 2004 and 2005, we received approximately $16,000, $14,000 and $48,000, respectively, from the sale of investments in various public companies. The sales of these investments were made to fund our working capital needs. Prior to our refocus upon the exploration and development of oil and gas properties, we would from time to time make investments in public companies. These investments were passive in nature and were generally relatively small. Given our focus on oil and gas, future investments of this nature are likely to be limited to opportunities that are of some strategic value to our core oil and gas business and are likely to be less passive in nature.

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During the year ended September 30, 2003, we had total borrowings of $600,000, of which $140,000 was repaid in cash. As of September 30, 2003, $50,000 was owed to Nathan Low Family Trust, a shareholder, $85,000 was owed to Mr. Crosby, $25,000 was owed to Kevin Stulp, a director, and $300,000 was owed to CGT Management Ltd. All of such amounts were repaid by in October of 2003. During the year ended September 30, 2004, we borrowed $410,000 in short-term notes from certain of our officers, directors, and other insiders, as well as $1,000,000 of non-interest bearing short-term notes received in late March 2004. These liabilities were repaid in full in April 2004.

On January 31, 2005, we entered into a share purchase agreement with twenty-two accredited investors pursuant to which the investors purchased 7,810,000 shares of common stock and common stock warrants enabling the warrant holders to purchase 14,050,000 shares of common stock at an exercise price of $1.75 per share. The aggregate proceeds from the security sales were $9,762,500 before commissions. The proceeds of this financing were used in part to retire the April 2, 2004 debt financing and all accrued interest thereon.

We spent $321,538 in fiscal 2003, $565,148 in fiscal 2004 and $612,624 in fiscal 2005 for oil and gas lease expenses and lease operating expenses. In the same periods we spent $145,000, $308,000 and $414,396, respectively, for oil and gas drilling, production and operating expenses. Historically, we have obtained professional oil and gas geologic and engineering services solely on a consulting basis. We spent approximately $591,000 in fiscal 2003, $424,873 in fiscal 2004 and $262,588 in fiscal 2005 for consulting services in various disciplines.

Recent Accounting Pronouncements

Reference is made to Note 2 to the Financial Statements included elsewhere in this report for a description of certain recently issued accounting pronouncements. We do not expect any of such recently issued accounting pronouncements to have a material effect on our consolidated financial position or results of operations.

Future Changes in Accounting Principles

As a result of the acquisition of Aurora, we will changes certain of our accounting policies, as described below. These changes will be reflected in our financial statements for the fiscal year ending December 31, 2005 to be included in a form 10-KSB to be filed with the U.S. Securities and Exchange Commission.

·    Aurora will be treated as the acquirer for accounting purposes, and accordingly, reverse acquisition accounting will be applied to the business combination, with Aurora as the accounting acquirer.

·    We will measure the cost of the business acquired by reference to the fair value of the target’s securities (i.e., shares of Cadence common stock, including outstanding options and warrants to purchase such shares) at the date of the merger agreement, January 31, 2005, or approximately $41,500,000.

·  Cadence will uniformly apply the full cost method to all of its oil and gas operations in both its divisions, accordingly, the successful efforts method that had previously been used by the Cadence division will be changed to the full cost method.

·  Cadence will initially use the intrinsic value method under APB Opinion 25 in accounting for stock-based compensation, until adoption of FAS 123(R). However, stock options outstanding as of the date of the merger will not be accounted for under APB Opinion 25 nor FAS 123 because those options were fully vested and their fair value will be included in the cost of the business acquired, as discussed above.

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Item 7.  Financial Statements

The Financial Statements of the Company appear at pages F-1 to F-27.

Item 8. Changes in and Disagreements with Accountants.

There have been no disagreements with accountants on accounting and financial disclosures from the inception of the Company through the date of this Annual Report.

Item 8A. Controls and Procedures.

The Company conducted an evaluation, under the supervision and with the participation of the Company's Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures, as defined in rules promulgated under the Securities Exchange Act of 1934, as amended, as of September 30, 2005. Based upon the evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that these disclosure controls and procedures are effective.

There have been no changes in the Company's internal controls over financial reporting that has materially affected or is reasonably likely to materially affect the Company's internal controls over financial reporting.

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PART III

Item 9. Directors, Executive Officers, Promoters and Control Persons

The following table sets forth the name, age and position of each of our officers and directors as of December 15, 2005.

Name	Age	Position(s) with the Company
William W. Deneau	61	Director, President, Chairman of Board of Directors
Howard M. Crosby	53	Director, Vice Chairman of Board of Directors
Lorraine M. King	40	Chief Financial Officer
John V. Miller, Jr.	47	Vice President of Exploration and Production
Thomas W. Tucker	63	Vice President of Land and Development
John P. Ryan	43	Secretary
Kevin D. Stulp	49	Director
Ronald E. Huff	50	Director, Treasurer
Richard Deneau	59	Director
Gary J. Myles	60	Director
Earl V. Young	64	Director

To the best of our knowledge, none of our directors have been convicted in a criminal proceeding, excluding traffic violations or similar misdemeanors, or has been a party to any judicial or administrative proceeding during the past five years, except for matters that were dismissed without sanction or settlement, that resulted in a judgment, decree or final order enjoining the person from future violations of, or prohibiting activities subject to, federal or state securities laws, or a finding of any violation of federal or state securities laws.

William W. Deneau has served as Cadence's President and Chairman of the Board of Directors since October 2005. Mr. Deneau became an employee of Aurora at the time he sold his interest in Jet/LaVanway Exploration, L.L.C. to Aurora in exchange for Aurora's stock on April 22, 1997. From April 1997 to October2005, Mr. Deneau was responsible for managing Aurora's affairs and officially became a Director of Aurora on June 25, 1997 and the President of Aurora on July 17, 1997. Since 1987, Mr. Deneau has also been the President, a Director, and the sole owner of White Pine Land Services, Inc. of Traverse City, Michigan. Prior to March 1, 1997, White Pine Land Services, Inc. was a 35-member company engaged in the business of providing real estate services to oil and gas companies. On March 1, 1997, White Pine Land Services, Inc. sold its business to a newly formed corporation, White Pine Land Company. White Pine Land Services, Inc. continues to exist for the purpose of managing its investments. William W. Deneau is the brother of Richard Deneau, one of our directors

Howard Crosby has served as Cadence's Vice Chairman of the Board of Directors since October 2005 and as a Director since February 1994. From February 1994 to October 2005 Mr. Crosby served as Cadence's President and from January 1998 until October 2005 he served as Cadence's Treasurer. Since 1989, Mr. Crosby has been president of Crosby Enterprises, Inc., a family-owned business advisory and public relations firm. Mr. Crosby received a B.A. degree from the University of Idaho. Mr. Crosby is also an officer and director of White Mountain Titanium Corporation., a publicly traded mining exploration company, High Plains Uranium, Inc., Sundance Diamonds Corporation, Dotson Exploration Company and Nevada-Comstock Mining Company (formerly Caledonia Silver-Lead Mines Company), all of the latter being privately held companies.

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Lorraine M. King has served as Cadence's Chief Financial Officer since October 2005. Ms. King became an employee of Aurora on May 29, 2001 and from March 2003 to October 2005 served as its Chief Financial Officer. From November 1, 1992 through May 4, 2001, Ms. King served as Chief Financial Officer of Wepco Energy, LLC, an independent gas producer based in Traverse City, Michigan. Ms. King began her career in public accounting with BDO Seidman, where she spent four years as a tax manager working primarily with oil and gas clients.

John V. Miller has served as Cadence's Vice President of Exploration and Production since October 2005. Mr. Miller became an employee of Aurora at the time he sold his interest in Jet/LaVanway Exploration, L.L.C. to Aurora in exchange for Aurora's stock on April 22, 1997. From April 1997 to October 2005, he was responsible for overseeing exploration and development activities for Aurora. From June 1997 to October 2005 he served as a Director of Aurora and from July 1997 to October 2005 he served as Vice President of Exploration and Production of Aurora. In 1994, Mr. Miller joined Jet Exploration, Inc. of Traverse City, Michigan as a Vice President with responsibility for getting Jet Exploration, Inc. into the shale gas play in Michigan and Indiana. He was the driving force behind the establishment of Jet/LaVanway Exploration, L.L.C. and its effort in southern Indiana. Mr. Miller left the position with Jet Exploration, Inc. to join Aurora. From 1988 to 1994, Mr. Miller worked for White Pine Land Services, Inc. of Traverse City, Michigan, as a land manager.

Thomas W. Tucker, has served as Cadence's Vice President of Land and Development since October 2005. Mr. Tucker became an employee of Aurora at the time he sold his interest in Jet/LaVanway Exploration, L.L.C. to Aurora in exchange for Aurora's stock on April 22, 1997. From April 1997 to October 2005 he has been responsible for overseeing land development activities for Aurora. From June 1997 to October 2005 he served as a Director of Aurora and from July 1997 to October 2005 he served as Vice President of Land and Development of Aurora. Mr. Tucker founded Jet Oil Corporation with his father in 1982. After his father's death, Mr. Tucker founded Jet Exploration, Inc. in 1987. Mr. Tucker has been the President of Jet Exploration, Inc. since its inception. Jet Exploration, Inc. no longer takes on any new projects, and its existing projects are being allowed to run out their course.

John P. Ryan, served as a Director of Cadence from April 1997 to October 2005 and has served as Cadence's Secretary since 1998. From September 1996 to October 2005 he served as Cadence's Vice President of Corporate Development. Mr. Ryan is a degreed mining engineer. From August, 2000 to the present, he has served as a Director and the Chief Financial Officer of Trend Mining Company, a publicly traded mineral exploration and development company and since February 2004 he has served as an officer and director of White Mountain Titanium Corporation, a publicly traded mining exploration company. Other companies with which Mr. Ryan holds an officer and/or director position include Bio-Quant, Inc., Nevada-Comstock Mining Company, High Plains Uranium, Inc., GreatWall Gold Corporation, Sundance Diamonds Corporation, TN Oil Co., and Dotson Exploration Company. Many of these companies have only minimal activity and require only a small amount of Mr. Ryan's time. Mr. Ryan is a former U.S. Naval Officer and obtained a B.S. in Mining Engineering from the University of Idaho and a Juris Doctor from Boston College Law School.

Kevin D. Stulp, has served as a Director of Cadence since March 1997. Since August 1995, Mr. Stulp has variously worked as consultant with Forte Group, on the board of the Bible League, and is active with various other non-profit organizations. From December 1983 to July 1995, Mr. Stulp held various positions with Compaq Computer Corporation, including industrial engineer, new products planner, manufacturing manager, director of manufacturing and director of worldwide manufacturing reengineering. Mr. Stulp holds a B.S.L.E. from Calvin College, Grand Rapids, Michigan, a B.S.M.E. in Mechanical Engineering, and an M.B.A. from the University of Michigan.

Ronald E. Huff, CPA, has served as Cadence's Treasurer since October 2005 and has served as a Director of Cadence since November 21, 2005. Mr. Huff is currently the Chief Financial Officer and Vice President of Finance for Visual Edge Technology, Inc., a position he has held since 2004. Visual Edge Technology, Inc. is a California holding company engaged in acquiring imaging companies. From 1999 to 2004, Mr. Huff was a Principal and Founder of TriMillennium Ventures, LLC, a private equity investment company located in the Columbus, Canton, Akron, Cleveland, Ohio corridor. Mr. Huff worked for Belden & Blake Corporation from 1986 to 1999 as its Chief Financial Officer and was also its President from 1997 to 1999. Belden & Blake Corporation acquires properties, explores for and develops oil and gas reserves and markets natural gas, primarily in the Appalachian and Michigan Basins. It went through a successful initial public offering in 1992, and was acquired by Texas Pacific Group in 1997. From 1983 to 1986 Mr. Huff was the Chief Accounting Officer of Zilkha Petroleum, from 1980 to 1983 he was a financial analyst for Southern Natural Resources, a natural gas marketing company, and from 1977 to 1980 he was a corporate accountant with Transco Companies Incorporated. Mr. Huff has agreed to chair Cadence's Audit Committee.

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Richard Deneau, has served as a Director of Cadence since November 21, 2005. Mr. Deneau retired from Anchor Glass Container Corporation ("Anchor") in 2004, where he served as a Director and President from 1997 to 2004. He was also the Chief Operating Officer from 1997 to 2002, and the Chief Executive Officer from 2002 until his retirement. Anchor, which is publicly traded and listed on NASDAQ, is the third largest glass container manufacturer in the United States, with annual revenues of about $750 million. When Richard Deneau joined Anchor, it was a financially troubled company. He designed and implemented strategies to turn its financial performance around. One of the strategies involved a Chapter 11 bankruptcy filing in April, 2002. The purpose of this filing was to provide assurance to a new investor that all prior claims had been extinguished. Prior to working for Anchor, Richard Deneau served in management at Ball Foster Glass Container Corp., American National Can, Foster Forbes Glass and First National Bank of Lapeer. He served as an auditor with Ernst & Ernst after graduating from Michigan State University in 1968. Richard Deneau is the brother of William Deneau, who is the President, CEO and a Director of Aurora. Richard Deneau is the brother of William W. Deneau our President and Chairman of the Board of Directors.

Gary J. Myles, has served as a Director of Cadence since November 21, 2005. From June 1997 to October 2005 Mr. Myles served as a Director of Aurora. He is currently retired. Prior to his retirement, Mr. Myles served as Vice President and Consumer Loan Manager for Fifth Third Bank of Northern Michigan (previously Old Kent Mortgage Company), a wholly owned subsidiary of Fifth Third Bank (previously Old Kent Financial Corporation). As the Affiliate Consumer Loan Manager , Mr. Myles was based in Traverse City, Michigan, and had full bottom line responsibility for the mortgage and indirect consumer loan departments generating net revenue of $3,500,000 annually. Mr. Myles had been with Fifth Third Bank and its predecessor, Old Kent Mortgage Company, since July 1988. Mr. Myles also owns Foster Care, Ltd., a closely held company for which he serves as a Director, President and Treasurer.

Earl V. Young, has served as a Director of Cadence since November 21, 2005. From March 2001 to October 2005 Mr. Young served as Director of Aurora. He is currently President of Earl Young & Associates of Dallas, Texas, which he founded in 1999. From 1996 to 1999, Mr. Young was the Senior Vice President of Corporate Development for American Mineral Fields, Inc. of Dallas, Texas. From 1993 to 1996, Mr. Young was a principal in Young & Lowe, which offered business consulting services to small capitalization companies. Prior to 1993, Mr. Young was involved in the investment banking business. He is President of the US/Madagascar Business Council headquartered in Washington, D.C. and a Director of the Corporate Council on Africa in Washington D.C. Mr. Young was a gold medalist in the Summer Olympic Games in 1960 in track, has served as President of the Southwest Chapter of Olympians, and was the founding chairman of the Olympians for Olympians Relief Committee.

To our knowledge, no director, officer or affiliate of the Company, and no owner of record or beneficial owner of more than five percent (5%) of our securities, or any associate of any such director, officer or security holder is a party adverse to us or has a material interest adverse to us in reference to pending litigation.

Indemnification

Our bylaws provide that our directors and officers will be indemnified to the fullest extent permitted by the Utah Corporation Code. However, such indemnification does not apply to acts of intentional misconduct, a knowing violation of law, or any transaction where an officer or director personally received a benefit in money, property, or services to which the director was not legally entitled.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the small business issuer pursuant to the foregoing provisions, or otherwise, we have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable.

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Board of Directors' Meetings and Committees

During the fiscal year ended September 30, 2005, our audit and compensation committees consisted of Messrs. Christian, DeHekker and Stulp. As a result of the resignations of Messrs. Christian and DeHekker from the Board of Directors effective October 31, 2005, Mr. Stulp was the sole remaining member of these committees.

On December 5, 2005, our Board of Directors reconstituted our Board Committees as follows:

· Audit Committee: Ronald E. Huff (Chairperson), Gary J. Myles and Earl V. Young;

· Compensation Committee: Howard M. Crosby, Kevin D. Stulp and Earl V. Young (Earl Young has been elected chairperson); and

· Nominating and Corporate Governance Committee: Gary J. Myles, Howard M. Crosby and Kevin D. Stulp.

The Board of Directors has designated the following directors as independent directors: Gary J. Myles, Ronald E. Huff, Kevin D. Stulp and Earl V. Young.

Nominations for Directors

Our Nominating and Corporate Governance Committee will propose, and our Board will adopt, a formal policy regarding qualifications of director candidates. Currently, in evaluating director nominees, our Board considers a variety of factors, including the appropriate size of our Board of Directors; the needs of our company with respect to the particular talents and experience of our directors; the knowledge, skills and experience of nominees, including experience in the oil and gas industry, finance, administration or public service, in light of prevailing business conditions and the knowledge, skills and experience already possessed by other members of our Board; experience with accounting rules and practices; and the desire to balance the benefit of continuity with the periodic injection of the fresh perspective provided by new Board members.

To date, we have not engaged third parties to identify or evaluate or assist in identifying potential nominees, although we reserve the right in the future to retain a third party search firm, if necessary.

During the fiscal year ended September 30, 2005, our Board of Directors met six times, and our Audit and Nominating Committees each met twice. No director attended fewer than 75% of the meetings of our Board or of each committee of which he was a member.

Our Board of Directors does not currently provide a process for securityholders to send communications to our Board of Directors as our management believes that until this point it has been premature given the limited liquidity of our common stock to develop such processes. Our Nominating and Corporate Governance Committee is now working on a stockholders’ communications policy to be adopted by our Board of Directors.

In connection with the closing of the merger or Cadence and Aurora, certain of our shareholders, including certain former Aurora shareholders who became shareholders of the Cadence in connection with the merger, executed and delivered voting agreements pursuant to which they agreed, for a period of 36 months, to vote an aggregate of 22,740,830 of their shares of our common stock in favor of (i) five directors designated by William W. Deneau, who shall initially be William W. Deneau, Earl V. Young, Gary J. Myles, Richard Deneau, and Ronald E. Huff; and (ii) two directors designated by William W. Deneau from among the our Board of Directors immediately before the closing of the merger, who shall initially be Howard M. Crosby and Kevin D. Stulp. In addition, such shareholders agreed to vote all of their shares of our common stock to ensure that the size of our Board of Directors will be set and remain at seven directors.

In addition, also in connection with the closing of the merger, certain of our shareholders executed and delivered irrevocable proxies naming, for a period of 36 months, William W. Deneau and Lorraine King as proxies to vote an aggregate of 10,102,286 shares of our common stock held by such shareholders in the manner determined by such proxies.

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Audit Committee

The audit committee: (i) appoints the Company’s independent auditors and monitors the independence of the Company’s independent auditors; (ii) reviews the Company’s policies and procedures on maintaining its accounting records and the adequacy of its internal controls; (iii) reviews management’s implementation of recommendations made by the independent auditors and internal auditors; (iv) considers and pre-approves the range of audit and non-audit services performed by independent auditors and fees for such services; and (v) reviews and votes on all transactions between the Company and any of its officers, directors or other affiliates.

We have appointed an audit committee comprised of Ronald E. Huff, Gary J. Myles and Earl V. Young, each of whom is an independent outside director, and one of whom, Ronald E. Huff, is a financial expert with knowledge of financial statements, generally accepted accounting principles and accounting procedures and disclosure rules.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires certain defined persons to file reports of and changes in beneficial ownership of a registered security with the Securities and Exchange Commission and the National Association of Securities Dealers in accordance with the rules and regulations promulgated by the Commission to implement the provisions of Section 16. Under the regulatory procedure, officers, directors, and persons who own more than ten percent of a registered class of a company's equity securities are also required to furnish the Company with copies of all Section 16(a) forms they file.

To the Company's knowledge, based solely on a review of the copies of Forms 3, 4 and 5 furnished to the Company between October 1, 2004 through September 30, 2005, the Company's officers, directors and greater than 10% beneficial owners complied with all Section 16(a) filing requirements except as follows: Rubicon Master Fund filed a late Form 3 for two transactions that occurred on January 31, 2005; Jeffrey M. Christian filed a late Form 4 for the two transactions that occurred on January 7, 2005; Glenn DeHekker filed a late Form 4 for the one transaction that occurred on June 8, 2005 and a late Form 4 for six transactions that occurred March 1, 2004, January 7, 2005 and June 8, 2005; Nathan A. Low filed a late Form 4 for seven transactions that occurred on January 1, 2005; John P. Ryan filed a late Form 4 for four transactions that occurred on January 7, 2005; Kevin D. Stulp filed a late Form 4 for one transaction that occurred on December 31, 2004 and a late Form 4 for one transaction that occurred on January 17, 2005; Glenn DeHekker filed a late Form 5 for three transactions that occurred on March 31, 2004, August 20, 2004 and January 17, 2005; and Kevin D. Stulp filed a late Form 5 for two transactions that occurred on April 21, 2004 and September 27, 2004.

Code of Ethics

We have adopted a Code of Ethics that applies to our principal executive officer and senior financial officers. Please see Item 13, Exhibit 14.

Item 10. Executive Compensation

Prior to the date of the merger of Cadence and Aurora, the Company's executive officers functioned as executive officers of, and were compensated by, Cadence or Aurora, as the case may be. The following sets forth the annual and long-term compensation for services in all capacities to Cadence for the fiscal years ended September 30, 2005, 2004 and 2003 paid to our Chief Executive Officer and the other executive officer who was serving as an executive officer at the end of the last completed fiscal year. Messrs. Crosby and Ryan served as President and Treasurer and Vice President and Secretary, respectively, of Cadence prior to the merger of Cadence and Aurora. This compensation information relates to compensation received by the named executive officer while employed by Cadence prior to the merger of Cadence and Aurora.

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Summary Compensation Table

								Long-Term Compensation
								Awards
	Annual Compensation							Restricted		Securities Underlying
Name and Principal Position	Year		Salary ($)			Bonus		Stock		Options/SARs
Howard M. Crosby		2005		133,775			–		30,000		50,000
President and Treasurer		2004		61,500			–		–		–
		2003		62,500(1	)		–		80,000		–
John P. Ryan		2005		142,425			–		30,000		50,000
Vice President and Secretary		2004		70,336			–		–		–
		2003		62,500 (2	)		–		80,000		–

(1) The cash portion of Mr. Crosby’s salary for fiscal 2003 was $62,500, of which he received $18,000 in fiscal 2003, payment of the remaining $44,500 having been deferred until after the end of fiscal 2003. In addition, he received 80,000 shares of Cadence common stock, 20,000 per quarter. These were valued at 50% of the closing price at the end of the quarter for which the shares were awarded: $17,000 for the first quarter, $14,500 for the second quarter, $17,000 for the third quarter and $32,500 for the fourth quarter, for a total of $80,500 in stock compensation and $143,500 in total compensation.

(2) The cash portion of Mr. Ryan’s salary for fiscal 2003 was $62,500. In addition, he received 80,000 shares of Cadence common stock, 20,000 per quarter. These were valued at 50% of the closing price at the end of the quarter for which the shares were awarded: $17,000 for the first quarter, $14,500 for the second quarter, $16,500 for the third quarter and $32,500 for the fourth quarter, for a total of $80,500 in stock compensation and $143,500 in total compensation.

OPTION GRANTS IN LAST FISCAL YEAR (October 1, 2004 - September 30, 2005)

NAME	Number Of Securities Underlying Options Granted (1)		% Of Total Options Granted To Employees In The Fiscal Year		Exercise Price		Expiration Date		Potential Realizable Value at Assumed Annual Rate of Stock Price Appreciation For Option Term
									5%		10%
Howard M. Crosby		50,000		50	$	1.21		January 7, 2008	$	110,259	$	144,896
John P. Ryan		50,000		50	$	1.21		January 7, 2008	$	110,259	$	144,896

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AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR-END

AND FISCAL YEAR-END OPTION VALUES TABLE

The following table contains information concerning the number of shares acquired and value realized from the exercise of options by the named executive officers during fiscal 2004 and the number of unexercised options held by the named executive officers at September 30, 2005.

	NUMBER OF SHARES OF COMMON STOCK UNDERLYING UNEXERCISED OPTIONS AT YEAR END (SEPTEMBER 30 2005)				VALUE OF UNEXERCISED IN-THE-MONEY OPTIONS AT YEAR END (SEPTEMBER 30 2005) (1)
NAME	EXERCISABLE		UNEXERCISABLE		EXERCISABLE		UNEXERCISABLE
Howard M. Crosby		50,000		–	$	107,000		–
John P. Ryan		50,000		–	$	107,000		–

(1)    Options are “in-the-money” if the market price of a share of common stock exceeds the exercise price of the option.

Cadence has no retirement, pension or profit sharing program for the benefit of its directors, officers or other employees, but the Board of Directors may recommend one or more such programs for adoption in the future.

Compensation of Directors

All directors are reimbursed for out-of-pocket expenses in connection with attendance at meetings of the Board of Directors. We have in the past compensated our directors in cash and in shares of our common stock, and has generally in the past granted options to Directors upon joining the Board. During the fiscal year ended September 30, 2005, each non-employee director received (1) $5,000 and 5,000 shares of restricted stock per quarter of completed service, (2) 2,500 restricted shares of common stock for each year of service on any committee of the Board of Directors, (3) $2,500 for chair of the Audit Committee and $1,000 for any other committee which they chair; and each Director (employee or non employee) was entitled to an option to purchase 50,000 shares of our common stock on the anniversary of his appointment to the Board. Board members may be granted additional stock options pursuant to Board recommendation and approval. We also have in the past paid our non-employee directors $1,600 for each board meeting they attend in person and $750 for each telephonic meeting and employee directors $600 for each board meeting they attend in person.

During the fiscal year ended September 30, 2005, Messrs. Christian, DeHekker and Stulp, the three non-employee directors, each received options to purchase 50,000 shares of our common stock at an exercise price of $1.42 per share, and Messrs. Crosby and Ryan, the employee directors, each received options to purchase 50,000 shares of our common stock at an exercise price of $1.21 per share. Also for the 2005 fiscal year, Messrs. Christian, Crosby, DeHekker, Ryan and Stulp each received 15,000 shares of our common stock per quarter for the first three quarters of 2005 as compensation for the service on the board of directors. Messrs. DeHekker and Stulp received an additional 4,000 shares of our common stock for their service on a committee of the board of directors.

In addition, subsequent to September 30, 2005, each of Messrs. Christian, DeHekker and Ryan, the resigning directors, received warrants to purchase an aggregate of 37,500 shares of our common stock, consisting of a warrant to purchase 12,500 shares of our common stock for a purchase price of $2.53 per share, a warrant to purchase 12,500 shares of our common stock for a purchase price of $2.23 per share, a warrant to purchase 12,500 shares of our common stock for a purchase price of $3.28 per share.

There are no contractual arrangements with any member of the Board of Directors.

Bonuses and Deferred Compensation

We do not have any bonus, deferred compensation or retirement plan.

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Stock Options

In February, 2004 the Board adopted the 2004 Stock Option and Stock Award Plan which was approved by our shareholders in May, 2004 and under which up to 1,000,000 shares of our common stock could be awarded as share awards or options and based upon merit of work performed as well as a retention tool. As of September 30, 2005, 625,500 shares or options have been awarded under this plan, of which 400,000 options are currently outstanding and exercisable.

Prior to the 2004 Stock Option and Stock Award Plan, our Board of Directors chose to make option or warrant awards to select officers, directors, consultants, or shareholder/investors in order to induce them to assist it in implementing its business plan and to provide long term additional incentive. These options or warrants, as awarded, were not awarded pursuant to a plan but were specific individual awards with varying terms and conditions. In some instances, our Board of Directors reserved the right to cancel these awards for non-performance or other reasons, or established a vesting schedule pursuant to which the award is earned.

Employment Contracts, Termination of Employment and Change of Control Arrangements

There are no compensatory plans or arrangements, including payments to be received from us, with respect to any person named in the Summary Compensation Table above, that would in any way result in payments to any such person because of his resignation, retirement, or other termination of such person’s employment with us or the our subsidiaries, or any change in control of us, or a change in the person’s responsibilities following a change of control.

Compensation Committee Report

Compensation Philosophy. The philosophy of the our Compensation Committee for the fiscal year ended September 30, 2005 was to provide competitive levels of compensation that are appropriate given the performance and commitment of the Company’s executive officers compared with similarly situated executives in the oil and gas industry; link management’s pay to the achievement of the Company’s annual and long-term performance goals; and assist the Company in attracting and retaining qualified management. However, because of the limited number of companies that can be compared to the Company in terms of stage of resource development, net income, and similar items, a significant amount of subjectivity was involved in the decisions of the Compensation Committee.

Base Salaries. Base salaries for management employees are determined initially by evaluating the responsibilities of the position held and the experience of the individual, and by reference to the competitive marketplace for management services, including a comparison of base salaries for comparable positions at comparable companies within the oil and gas industry. Annual salary adjustments are determined by evaluating the competitive marketplace, the performance of the Company, the performance of the executive, and any increased responsibilities assumed by the executive. The Compensation Committee believes the base salaries of executive officers are at or below those of similarly situated executives in the oil and gas industry.

Bonus Arrangement. To encourage and reward outstanding corporate and individual performance, the Company from time to time considers awarding merit bonuses to its executive officers, based on the Company’s operating results and the achievement of certain defined major business objectives.

Compensation of Chief Executive Officer. The amount of the Chief Executive Officer’s compensation for the fiscal year ended September 30, 2005 was determined in accordance with the principles discussed in the foregoing paragraphs and was based upon a subjective evaluation by the Committee of the leadership demonstrated by Mr. Crosby during the fiscal year.

Item 11. Security Ownership of Certain Beneficial Owners and Management

The following table sets forth, as of November 1, 2005, certain information regarding the ownership of voting securities of Cadence by each stockholder known to our management to be (i) the beneficial owner of more than 5% of our outstanding Common Stock, (ii) our directors, (iii) our current executive officers and (iv) all executive officers and directors as a group. We believe that, except as otherwise indicated, the beneficial owners of the Common Stock listed below, based on information furnished by such owners, have sole investment and voting power with respect to such shares.

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Unless otherwise specified, the address of each of the persons set forth below is in care of Cadence Resources Corporation, 4110 Copper Ridge Drive, Suite 100, Traverse City, Michigan, 49684.

Name and Address of Beneficial Owner (1)	Amount and Nature of Beneficial Ownership(2)			Percent of Outstanding Shares(2)
Howard M. Crosby		1,477,808 (3	)		2.50	%
John P. Ryan		1,006,124 (4	)		1.70	%
Kevin D. Stulp		527,500 (5	)		0.89	%
Nathan A. Low Roth IRA and affiliates 641 Lexington Avenue New York, New York 10022		5,052,142 (6	)		8.56	%
Thomas Kaplan 154 West 18th Street New York, New York 10011		3,090,992 (7	)		5.23	%
Rubicon Master Fund (8) c/o Rubicon Fund Management LLP P103 Mount Street London W1K 2TJ, UK		8,000,000 (9	)		13.55	%
Crestview Capital Master, LLC 95 Revere Drive, Suite A Northbrook, Illinois, 60062		4,000,000(10	)		6.77	%
William W. Deneau		4,232,500 (11	)		7.17	%
Gary J. Myles		259,998 (12	)		0.44	%
Earl V. Young		386,204 (13	)		0.65	%
Richard Deneau		–			–
Ronald E. Huff		–			–
John V. Miller, Jr.		3,289,762 (14	)		5.57	%
Thomas W. Tucker		3,848,194(15	)		6.52	%
Lorraine M. King		360,000 (16	)		0.61	%
All executive officers and directors as a group (11 persons)		15,382,390 (17	)		26.05	%

(1) Addresses are only given for holders of more than 5% of the outstanding Common Stock of Cadence.

(2) A person is deemed to be the beneficial owner of a security if such person has or shares the power to vote or direct the voting of such security or the power to dispose or direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities if that person has the right to acquire beneficial ownership within 60 days of the date hereof. Except as otherwise indicated the named entities or individuals have sole voting and investment power with respect to the shares of Common Stock beneficially owned.

(3) Includes 270,000 shares of Company Common Stock held by Crosby Enterprises, Inc., 40,000 shares of Company Common Stock owned by the Crosby Family Living Trust, 130,000 shares of Company Common Stock owned by CORK Investments, Inc. and options to purchase 50,000 shares of Company Common Stock.

(4) Includes options currently exercisable for 50,000 shares of Company Common Stock and warrants currently exercisable for 37,500 shares of Company Common Stock, 172,875 shares of Company Common Stock owned by Nancy Martin-Ryan, 45,000 shares of Company Common Stock owned by John Ryan as custodian for Karen Ryan, 45,000 shares of Company Common Stock owned by John Ryan as custodian for Patrick Ryan, 150,000 shares of Company Common Stock owned by J.P. Ryan Company, Inc., and 87,500 shares of Company Common Stock owned by Andover Capital Corporation.

(5) Includes options currently exercisable for 50,000 shares of Company Common Stock and warrants currently exercisable for 100,000 shares of Company Common Stock, 2,750 shares of Company Common Stock owned by the Kevin Dale Stulp IRA and 1,750 shares of Company Common Stock owned by the Kevin and Marie Stulp Charitable Remainder Unitrust of which Mr. Stulp is a co-trustee.

(6) Based on information included in an amendment to Schedule 13D/A filed with the SEC on November 10, 2005, Nathan A. Low has the sole power to vote or direct the vote of, and the sole power to direct the disposition of, the shares held by the Nathan A. Low Roth IRAs and the shares held by him individually, which total 4,034,767 shares of Company Common Stock, which includes 108,375 shares of Company Common Stock issuable upon exercise of warrants. Although Nathan A. Low has no direct voting or dispositive power over an aggregate 1,017,375 shares of Company Common Stock held by Lisa Low as trustee for the Nathan A. Low Family Trust and as custodian for the Neufeld minor children, he may be deemed to beneficially own those shares because his wife, Lisa Low, is the trustee of the Family Trust and custodian for the Neufeld children. Similarly, Nathan A. Low may be deemed to beneficially own those shares of Company Common Stock underlying options and warrants (a total of 157,375 shares of Company Common Stock) held for the benefit of his children, because his wife has sole voting and dispositive power over such shares. Therefore, Nathan A. Low reports shared voting and dispositive power over 5,052,142 shares of Company Common Stock.

(7) Consists of 480,811 shares of Company Common Stock owned by LCM Holdings LDC; 480,811 shares of Company Common Stock owned by Electrum Resources, LLC; and 1,329,370 shares of Company Common Stock owned by Electrum Capital, LLC. Does not include warrants to purchase 800,000 shares of Company Common Stock, which warrants were acquired January 31, 2005.

(8) Pursuant to investment agreements, each of Rubicon Fund Management Ltd., a company organized under the laws of the Cayman Islands, which we refer to in this footnote as Rubicon Fund Management Ltd., and Rubicon Fund Management LLP, a limited liability partnership organized under the laws of the United Kingdom, which we refer to in this footnote as Rubicon Fund Management LLP, Mr. Paul Anthony Brewer, Mr. Jeffrey Eugene Brummette, Mr. William Francis Callanan, Mr. Vilas Gadkari, Mr. Robert Michael Greenshields and Mr. Horace Joseph Leitch III, share all investment and voting power with respect to the securities held by Rubicon Master Fund. Mr. Brewer, Mr. Brummette, Mr. Callanan, Mr. Gadkari, Mr. Greenshields and Mr. Leitch control both Rubicon Fund Management Ltd. and Rubicon Fund Management LLP. Each of Rubicon Fund Management Ltd., Rubicon Fund Management LLP, Mr. Brewer, Mr. Brummette, Mr. Callanan, Mr. Gadkari, Mr. Greenshields and Mr. Leitch disclaim beneficial ownership of these securities.

(9) Based on Form 3 - Initial Statement of Beneficial Ownership of Securities filed with the Securities and Exchange Commission by Rubicon Master Fund on April 13, 2005. Does not include warrants to purchase 8,000,000 shares of Company Common Stock, which warrants were acquired January 31, 2005.

(10) Does not include warrants to purchase 4,000,000 shares of Company Common Stock, which warrants were acquired January 31, 2005.

(11) Includes 3,272,000 shares of Company Common Stock held by the Patricia A. Deneau Trust, 340,500 shares of Company Common Stock owned by the Denthorn Trust, 20,000 shares of Company Common Stock held by White Pine Land Services and options currently exercisable for 600,000 shares of Company Common Stock.

(12) Includes options currently exercisable for 199,998 shares of Company Common Stock.

(13) Includes options currently exercisable for 199,998 shares of Company Common Stock.

(14) Includes 1,000,000 shares of Company Common Stock held by Miller Resources, Inc., 1,689,762 shares of Company Common Stock owned by Circle M, LLC and options currently exercisable for 600,000 shares of Company Common Stock.

(15) Includes 1,607,574 shares of Company Common Stock held by the Sandra L. Tucker Trust, 24,646 shares of Company Common Stock owned by Jet Exploration, Inc., 1,615,974 shares of Company Common Stock owned by the Thomas W. Tucker Trust and options currently exercisable for 600,000 shares of Company Common Stock.

(16) Includes options currently exercisable for 160,000 shares of Company Common Stock.

(17) Includes options and warrants currently exercisable for an aggregate of 2,597,497 shares of Company Common Stock.

65

Item 12. Certain Relationships and Related Transactions

On January 31, 2005, Cadence entered into a purchase agreement (the "Purchase Agreement") with twenty two accredited investors pursuant to which the investors purchased 7,810,000 shares of common stock and warrants to purchase 14,050,000 shares of common stock at an exercise price of $1.75 per share for $9,762,500. The Nathan A. Low Family Trust dated 4/12/96 and Bear Stearns as Custodian for Nathan A. Low Roth IRA, both of which are controlled by Nathan Low, a greater than 10% holder of Cadence's common stock, invested in Cadence pursuant to the Purchase Agreement. Sunrise Securities Corporation, an affiliate of Nathan Low, received a commission equal to $976,250 and a warrant to purchase 2,186,000 shares of Cadence's common stock for services rendered as the placement agent in the transaction.

On January 31, 2005, Cadence entered into an agreement with the seven accredited investors in its April 2004 private placement pursuant to which the Company was permitted to repay the $6,000,000 in notes held by such investors without any prepayment penalties in exchange for the exercise price of the warrants to purchase 765,000 shares of common stock issued in the April 2004 private placement being reduced from $4.00 per share to $1.25 per share. $5,000,000 of the notes were repaid in cash and $1,000,000 of the notes were converted into common stock and warrants of Cadence pursuant to the Purchase Agreement. Nathan Low, a greater than 10% holder of Cadence's common stock, and Lisa Low, Nathan Low's wife, as Custodian for Gabriel S. Low UNYGMA were two of the eight accredited investors involved in this transaction. In connection with this transaction, the exercise price of the warrants to purchase 76,500 shares of common stock held by Nathan A. Low, who acted as a finder in the April 2004 private placement, were also reduced to $1.25 per share.

Our Aurora subsidiary has a lease for office and storage space from South 31, L.L.C. William W. Deneau and Thomas W. Tucker each own one-third of South 31, L.L.C. The storage building contains four other storage units that are leased to unrelated third parties at the same rate that our Aurora subsidiary pays. We are negotiating with South 31, L.L.C. for a release of the office lease, which runs through March 31, 2007.

Messrs. Deneau, Tucker and Miller, who are officers and directors of us, are all involved as equity owners in numerous corporations and limited liability companies that are active in the oil and gas business. Existing affiliations involving co-ownership of projects in which our Aurora subsidiary is active, are itemized below.

Messrs. Deneau, Tucker and Miller own equal shares in JetX, LLC, an exploration company that owns a 10% working interest in the Treasure Island project.

Mr. Miller has an ownership interest in Miller Resources, Inc., Miller Resources 1994-1, and Miller Resources 1996-1, which own working interests of 1%, 0.5% and 1% respectively, in the Beyer project. Mr. Miller also has an ownership interest in Energy Ventures, LLC, which owns a .75% working interest in the Black Bean project.

Messrs. Deneau, Tucker and Miller own Jet Exploration, Inc. which owns an approximate 1% working interest in the Beregasi well.

It is probable that on occasion, we will find it necessary or appropriate to deal with other entities in which Messrs. Deneau, Tucker and Miller have an interest.

On September 7, 2004, the Patricia A. Deneau Trust, DTD 10/12/95, borrowed $100,000 from our Aurora subsidiary to purchase shares of Aurora common stock from an Aurora stockholder. This trust is controlled by William W. Deneau. The loan was evidenced by an unsecured demand promissory note bearing interest at the rate of 4.5% per year. The promissory note has been repaid in full. The shares purchased by the trust were subsequently sold by the trust to Ms. King.

66

Item 13. Exhibits

(a) Exhibits

Exhibit No.	Document Description
3.1(1)	Restated Articles of Incorporation of Cadence Resources Corporation
3.2(2)	Bylaws of Cadence Resources Corporation
4.1(1)	Articles of Amendment to the Articles of Incorporation, relating to the Class A Preferred Stock
4.2(3)	Form of Promissory Note in favor of the investors in the April 2, 2002 private placement 4.3(3) Form of Warrant issued to the investors in the April 2, 2002 private placement 4.4(4) Voting Agreement between Cadence Resources Corporation and its stockholders 5.1 Opinion of Troutman Sanders LLP, as to the validity of the Securities being registered hereunder
9.1	Voting Agreement executed in connection with the merger
10.1(1)	Form of Joint Exploration Agreement with Bridas Energy USA, Inc. dated April 30, 2003
10.2(1)	Lease Acquisition and Participation Agreement with Aurora Energy, Ltd. dated December 8, 2002
10.3(1)	Consulting Agreement with Lucius C. Geer dated August 1, 2003
10.4(1)	Agreement dated effective September 30, 2003 with Nathan A. Low, Sunrise Securities Corporation and Cadence Resources Corporation Limited Partnership
10.5(3)	Securities Purchase Agreement between Cadence Resources Corporation and the investors signatory thereto, dated April 2,2004
10.6(3)	Security Agreement between Cadence Resources Corporation and the investors signatory thereto, dated April 2, 2004
10.7(4)	Agreement and Plan Of Merger dated as of January 31, 2005 between Cadence Resources Corporation, Aurora Acquisition Corp. and Aurora Energy, Ltd.
10.84)	Development Agreement between Aurora Energy, Ltd. and Oil & Gas engineering GmbH, dated March 31, 2004
10.9(4)	Exploration Agreement between Aurora Energy, Ltd. and Samson Resources Company, dated May 14, 2004
10.10	First Amended and Restated Note Purchase Agreement between Aurora Antrim North, LLC, et. al. and TCW Asset Management Company, dated December 8, 2005
10.11(5)	Amendment No.1 to Agreement and Plan of Merger
14(6)	Code of Ethics
21.1	Subsidiaries
23.1	Consent of Ralph E. Davis Associates, Inc.
23.2	Consent of Williams & Webster, P.S.

31.1	Rule 13a-14(a) Certification of Principal Executive Officer.
31.2	Rule 13a-14(a) Certification of Principal Financial and Accounting Officer.
32.1	Section 1350 Certification of Principal Executive Officer.
32.2	Section 1350 Certification of Principal Financial and Accounting Officer.

 

(1) Filed as an exhibit to the registrant's 10-KSB for the fiscal year ended September 30, 2003, filed with the SEC on January 13, 2004

(2) Filed as an exhibit to the registrant's Current Report on Form 8-K, filed with the SEC on December 9, 2005

(3) Filed as an exhibit to the registrant's Current Report on Form 8-K dated April 5, 2004, filed with the SEC on April 5, 2004

(4) Filed as an exhibit to the registrant's Form S-4 Registration Statement filed with the SEC on May 13, 2005.

(5) Filed as an exhibit to Amendment No. 1 to the registrant's Form S-4 Registration Statement filed with the SEC on August 23, 2005

(6) Filed as an exhibit to the Company’s 10-KSB for the fiscal year ended September 30, 2003, filed January 13, 2004, and incorporated by reference herein.

67

Item 14. Principal Accountant Fees And Services

The Company's Board and Audit Committee reviews and approves audit and permissible non-audit services performed by Williams & Webster P.S., as well as the fees charged by Williams & Webster P.S. for such services. In its review of non-audit service fees and its appointment of Williams & Webster P.S. as the Company's independent accountants, the audit committee considered whether the provision of such services is compatible with maintaining the independence of Williams & Webster P.S. All of the services provided and fees charged by Williams & Webster P.S. in 2005 were pre-approved by the Audit Committee.

Audit Fee

The aggregate fees billed by Williams & Webster P.S. for professional services for the audit of the annual financial statements of the Company, reviews of the financial statements included in the Company's quarterly reports on Form 10-QSB for 2005 and 2004, and review of the S-4 registration statement and two SB-2 registration statements filed by the Company during the reporting period were approximately $130,000 and $107,000, respectively, net of expenses.

Audit Related Fees

There were no other fees billed by Williams & Webster P.S. during the last two fiscal years for assurance and related services that were reasonably related to the performance of the audit or review of the Company's financial statements and not reported under "Audit Fees" above.

Tax Fees

There were an additional $9,936 of fees billed by Williams & Webster P.S. during the last two fiscal years for professional services rendered by Williams & Webster P.S. for tax compliance.

All Other Fees

There were no other fees billed by Williams & Webster P.S. during the last two fiscal years.

68

SIGNATURES

In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report on Form 10-KSB to be signed on its behalf by the undersigned thereto duly authorized.

	CADENCE RESOURCES CORPORATION
Date:  December 28, 2005	By:	/s/ WILLIAM W. DENEAU
		Name:   William W. Deneau Title:      President

Pursuant to the requirements of the Securities Exchange Act of 1934, this annual report on Form 10-KSB has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

SIGNATURE	OFFICE	DATE
/s/ William W. Deneau	President and Director	December 28, 2005
William W. Deneau	(Principal Executive Officer)
/s/ Lorraine M. King	Chief Financial Officer	December 28, 2005
Lorraine M. King	(Principal Financial Officer)
/s/ Howard M. Crosby	Director	December 28, 2005
Howard M. Crosby
/s/ Kevin D. Stulp	Director	December 28, 2005
Kevin D. Stulp
/s/ Ronald E. Huff	Director	December 28, 2005
Ronald E. Huff
/s/ Richard Deneau	Director	December 28, 2005
Richard Deneau
/s/ Gary J. Myles	Director	December 28, 2005
Gary J. Myles
/s/ Earl V. Young	Director	December 28, 2005
Earl V. Young

69

The Board of Directors

Cadence Resources Corporation

Traverse City, Michigan

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have audited the accompanying balance sheet of Cadence Resources Corporation as of September 30, 2005, 2004 and 2003, and the related statements of operations, stockholders’ equity and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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 financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 financial statements referred to above present fairly, in all material respects, the financial position of Cadence Resources Corporation as of September 30, 2005, 2004 and 2003, and the results of its operations, stockholders equity and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ Williams & Webster, P.S. 

Williams & Webster, P.S.

Certified Public Accountants

Spokane, Washington

December 27, 2005

F-1

CADENCE RESOURCES CORPORATION

BALANCE SHEETS

	September 30,
	2005			2004			2003
ASSETS
CURRENT ASSETS
Cash	$	1,694,838		$	1,922,993		$	3,619,345
Oil & gas revenue receivable		491,324			335,407			84,575
Receivable from working interest owners		–			–			12,873
Notes receivable		20,720			8,720			3,720
Prepaid expenses		82,203			39,410			5,925
Other current assets		425			425			425
TOTAL CURRENT ASSETS		2,289,510			2,306,955			3,726,863
OIL AND GAS PROPERTIES, USING
SUCCESSFUL EFFORTS ACCOUNTING
Proved properties		6,865,384			5,731,108			590,747
Unproved properties		661,672			505,501			833,836
Wells and related equipment and facilities		1,090,263			855,562			202,886
Support equipment and facilities		585,602			506,427			151,963
Prepaid oil and gas leases		473,056			456,219			395,973
Less accumulated depreciation, depletion, amortization and impairment		(6,594,549	)		(3,911,939	)		(61,611	)
TOTAL OIL AND GAS PROPERTIES		3,081,428			4,142,878			2,113,794
PROPERTY AND EQUIPMENT
Furniture and equipment		4,785			4,785			1,660
Less accumulated depreciation		(2,618	)		(1,949	)		(1,451	)
TOTAL PROPERTY AND EQUIPMENT		2,167			2,836			209
OTHER ASSETS
Investments		870,311			238,088			394,454
Mineral properties available for sale		197,406			197,406			246,757
TOTAL OTHER ASSETS		1,067,717			435,494			641,211
TOTAL ASSETS	$	6,440,822		$	6,888,163		$	6,482,077

The accompanying notes are an integral part of these financial statements

F-2

CADENCE RESOURCES CORPORATION

BALANCE SHEETS

	September 30,
	2005			2004			2003
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	446,166		$	358,588		$	584,866
Revenue distribution payable		23,410			32,387			68,929
Payable to related party		–			300,000			550,000
Accrued compensation		80,000			–			94,920
Accrued interest - related party		–			3,548			15,752
Accrued Dividends		15,737			–			–
Interest payable - secured notes		–			1,233			–
Notes payable - related party		–			-			460,000
TOTAL CURRENT LIABILITIES		565,313			695,756			1,774,467
LONG-TERM DEBT
Secured notes, net of discount		–			5,071,147			–
COMMITMENTS AND CONTINGENCIES		–			–			–
REDEEMABLE PREFERRED STOCK		59,925			59,925			59,925
STOCKHOLDERS' EQUITY
Common stock, $0.01 par value; 100,000,000
shares authorized,20,991,327, 12,892,327,
and 12,512,827 shares issued and outstanding,
respectively		209,113			128,923			125,128
Additional paid-in capital		24,316,680			18,995,458			18,343,422
Stock options		2,128,330			1,642,614			1,210,704
Stock warrants		4,473,112			794,512			51,375
Accumulated deficit		(24,797,883	)		(20,035,605	)		(14,863,687	)
Accumulated other comprehensive loss		(513,768	)		(464,567	)		(219,257	)
TOTAL STOCKHOLDERS' EQUITY		5,815,584			1,061,335			4,647,685
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY	$	6,440,882		$	6,888,163		$	6,482,077

The accompanying notes are an integral part of these financial statements

F-3

CADENCE RESOURCES CORPORATION

STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS

	Years Ended September 30,
	2005			2004			2003
REVENUES
Oil and gas sales	$	2,413,046		$	2,541,447		$	337,355
Sale of drilling and production rights		100,000			–			50,000
Total Revenues		2,513,046			2,541,447			387,355
OPERATING AND ADMINISTRATIVE EXPENSES
Depreciation, depletion and amortization		2,683,279			2,663,695			57,310
Officers' and directors' compensation		1,105,328			725,485			528,727
Consulting		104,595			319,338			531,137
Oil and gas lease and operating expenses		612,624			565,148			321,538
Oil and gas consulting		165,000			105,535			60,000
Exploration and drilling		235,959			134,452			109,968
Oil and gas production costs		178,437			174,836			34,577
Other general and administrative		996,128			1,506,446			386,892
Total Expenses		6,081,350			6,194,935			2,030,149
LOSS FROM OPERATIONS		(3,568,304	)		(3,653,488	)		(1,642,794	)
OTHER INCOME (EXPENSE)
Interest income		10,173			18,874			136
Interest expense and loan fees		(1,138,987	)		(302,955	)		(227,978	)
Partnership income (loss)		–			–			(15,200	)
Gain (loss) on debt forgiveness		–			–			(4,699	)
Gain (loss) on repayment of debt					–			–
Other income		846			11,172			–
Loss on sale of investment		(66,006	)		(9,156	)		–
Loss on disposition and impairment of assets		–			(1,236,365	)		(67,020	)
Total Other Income (Expense)		(1,193,974	)		(1,518,430	)		(314,761	)
LOSS BEFORE TAXES		(4,762,278	)		(5,171,918	)		(1,957,555	)
INCOME TAXES BENEFIT		–			–			–
NET LOSS		(4,762,278	)		(5,171,918	)		(1,957,555	)
OTHER COMPREHENSIVE INCOME (LOSS)
Unrealized gain (loss) in market value of
investments		(49,201	)		(245,311	)		29,297
COMPREHENSIVE LOSS	$	(4,811,479	)	$	(5,417,229	)	$	(1,928,258	)
LOSS PER COMMON SHARE BASIC AND DILUTED:
NET LOSS PER COMMON SHARE	$	(0.26	)	$	(0.41	)	$	(0.21	)
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING,
BASIC AND DILUTED		18,279,285			12,715,619			9,348,374

The accompanying notes are an integral part of these financial statements

F-4

CADENCE RESOURCES CORPORATION
STATEMENTS OF STOCKHOLDERS' EQUITY
																	Accumulated
	Common Stock				Additional												Other			Total
	Number				Paid-in			Stock			Stock			Accumulated			Comprehensive			Stockholders'
	of Shares		Amount		Capital			Options			Warrants			Deficit			Loss			Equity
Balance
October 1, 2002		6,866,210	$	68,662	$	13,291,965		$	626,790		$	233,334		$	(12,906,132	)	$	(248,554	)	$	1,066,065
Shares issued for cash with
warrants
attached at an average of $0.52
per unit		212,500		2,125		56,500			-			51,375			-			-			110,000
Shares issued to officers, directors
and others for services at $0.78
to $1.80		496,500		4,965		535,710			-			-			-			-			540,675
Shares issued for loan
consideration
at $1.08 per share		220,000		2,200		204,800			-			-			-			-			207,000
Shares issued for exercise of
options
at $0.75 per share		100,000		1,000		142,100			(68,100	)		-			-			-			75,000
Shares issued from exercise of
warrants		1,956,984		19,569		213,765			-			(233,334	)		-			-			-
Shares issued for cash at $0.80 to $2.50 per share, net of financing
fee of $347,850		2,525,183		25,252		4,216,347			-			-			-			-			4,241,599
Options issued for financing		-		-		(429,671	)		429,671			-			-			-			-
Shares issued for related party
loan
fee at $1.00 per share		120,000		1,200		118,800			-			-			-			-			120,000
Conversion of shares of
Celebration
for shares of Cadence common
stock		14,250		143		(143	)		-			-			-			-			-
Options issued to consultants for
services		-		-		-			222,343			-			-			-			222,343
Miscellaneous adjustment		1,200		12		(12	)		-			-			-			-			-
Dividends paid on preferred stock		-		-		(6,739	)		-			-			-			-			(6,739	)
Net loss for the year ended
September 30, 2003		-		-		-			-			-			(1,957,555	)		-			(1,957,555	)
Unrealized gain on market value
of
investments (unaudited)		-		-		-			-			-			-			29,297			29,297
Balance, September 30, 2003		12,512,827	$	125,128	$	18,343,422		$	1,210,704		$	51,375		$	(14,863,687	)	$	(219,257	)	$	4,647,685

F-5

CADENCE RESOURCES CORPORATION

STATEMENTS OF STOCKHOLDERS' EQUITY

																	Accumulated
	Common Stock				Additional												Other			Total
	Number				Paid-in			Stock			Stock			Accumulated			Comprehensive			Stockholders'
	of Shares		Amount		Capital			Options			Warrants			Deficit			Loss			Equity
Balance
September 30, 2003		12,512,827	$	125,128	$	18,343,422		$	1,210,704		$	51,375		$	(14,863,687	)	$	(219,257	)	$	4,647,685
Issuance of common stock for cash
at $2.50 per share		110,000		1,100		273,900			–			–			–			–			275,000
Shares issued for services at
$0.88 to $2.50 per share		99,500		995		143,960			–			–			–			–			144,955
Shares issued for officer and
director fees at $0.76 to $2.23
per share		120,000		1,200		183,200			–			–			–			–			184,400
Share issued for exercise of
warrants @ $1.35 per share		10,000		100		15,500			–			(2,100	)		–			–			13,500
Shares issued for financing expense
at $0.76 per share		15,000		150		11,475			–			–			–			–			11,625
Shares issued for repayment of
related party loan at $1.00 per
share		25,000		250		24,750			–			–			–			–			25,000
Options issued for financing fees									71,910												71,910
Options issued to officers and
directors for services		–		–		–			360,000												360,000
Dividends paid		–		–		(749	)		–			–			–			–			(749	)
Deferred financing cost		–		–		–			–			745,237			–			–			745,237
Net loss for the year ended
September 30, 2004		–		–		–			–			–			(5,171,918	)		–			(5,171,918	)
Unrealized loss on market value
of investments		–		–		–			–			–			–			(245,310	)		(245,310	)
Balance September 30, 2004		12,892,327		128,923		18,995,458			1,642,614			794,512			(20,035,605	)		(464,567	)		1,061,335
Issuance of common stock and warrants for
cash at $1.25 per unit		7,010,000		70,100		4,300,275			–			3,415,875			–			–			7,786,250
Issuance of common stock and warrants for
payment of note payable at $1.25 per unit,
less expenses of offering of $976,250		800,000		8,000		722,000			–			270,000			–			–			1,000,000
Common stock issued to officers
and directors at an average of $1.47
per share		160,500		1,605		233,985			–			–			–			–			235,590
Shares issued from exercise of
warrants		27,500		275		44,125			–			(7,275	)		–			–			37,125
Shares issued from cashless exercise of options		21,000		210		36,574			(36,784	)		–			–			–			–
Options issued to officers and
directors for services		–		–		–			522,500			–			–			–			522,500
Accrued Dividends		–		–		(15,737	)		–			–			–			–			(15,737	)
Net loss for the year ended
September 30, 2005		–		–		–			–			–			(4,762,278	)		–			(4,762,278	)
Unrealized loss on market value
of investments		–		–		–			–			–			–			(49,201	)		(49,201	)
Balance September 30, 2005		20,911,327	$	209,113	$	24,316,680		$	2,128,330		$	4,473,112		$	(24,797,883	)	$	(513,768	)	$	5,815,584

The accompanying notes are an integral part of these financial statements

F-6

CADENCE RESOURCES CORPORATION

STATEMENTS OF CASH FLOWS

	Year Ended
	September 30,
	2005			2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(4,762,278	)	$	(5,171,918	)	$	(1,957,555	)
Adjustments to reconcile net loss to net cash
used by operating activities:
Loss (gain) on sale of investments		66,006			9,156			67,020
Impairment of long-lived assets		–			1,236,365			–
Partnership loss		–			–			15,200
Gain (loss) on debt forgiveness		–			–			4,699
Depreciation, depletion and amortization		2,683,279			2,663,695			57,310
Issuance of common stock for services		235,590			144,955			540,675
Issuance of common stock for
expenses		–			196,025			–
Amortization of deferred financing fees		928,853			279,919			-
Issuance of common stock for loan
repayment		–			25,000			-
Issuance of common stock for loan
consideration		–			–			327,000
Issuance of stock options for
services		522,500			360,000			222,343
Issuance of stock options for
financing fees		–			71,910			–
Investment given for services		–			–			14,700
Changes in assets and liabilities:
Oil & gas revenue receivable		(155,917	)		(250,832	)		(58,452	)
Receivable from working interest owners		–			12,873			3,164
Notes receivable		–			(5,000	)		6,058
Prepaid expenses		(42,793	)		(33,485	)		21,575
Deposit		–			–			6
Prepaid mineral leases		(16,837	)		–			(218,796	)
Accounts payable		87,578			(226,278	)		1,082
Revenue distribution payable		(8,977	)		(36,542	)		54,094
Deferred working interest		–			–			(22,184	)
Accrued expenses		95,737			(94,920	)		28,659
Interest payable		(3,548	)		(12,204	)		15,752
Interest payable-secured notes		(1,233	)		1,233			–
Payable to related parties		-			(550,000	)		(2,500	)
Net cash provided (used) by operating activities		(372,040	)		(1,380,048	)		(880,150	)
CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of investments		(749,040	)		(112,360	)		(32,795	)
Purchase and development of proved and
unproved properties		(1,290,447	)		(4,542,760	)		(629,383	)
Purchase of fixed assets		(387,728	)		(981,660	)		(182,587	)
Sale of investments		47,725			14,420			16,614
Net cash provided (used) by investing activities		(2,379,490	)		(5,622,360	)		(828,151	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of common stock for cash		7,823,375			288,500			4,728,324
Issuance of redeemable preferred stock		–			–			59,925
Issuance of warrants for cash		–			–			46,125
Payments of preferred stock dividends		–			(749	)		(6,739	)
Proceeds from secured notes payable		–			5,920,000			–
Payments of note payable to related party		(300,000	)		–			–
Proceeds from notes payable and loans payable		–			115,000			600,000
Payments of notes payable		(5,000,000	)		(1,016,695	)		(140,000	)
Net cash provided by financing activities		2,523,375			5,306,056			5,287,635
Net increase (decrease) in cash	$	(228,155	)	$	(1,696,352	)	$	3,579,334

The accompanying notes are an integral part of these financial statements

F-7

CADENCE RESOURCES CORPORATION

STATEMENTS OF CASH FLOWS

	Year Ended
	September 30,
	2005			2004			2003
Net increase (decrease) in cash (balance forward)	$	(228,155	)	$	(1,696,352	)	$	3,579,334
Cash, beginning of period		1,922,993			3,619,345			40,011
Cash, end of period	$	1,694,838		$	1,922,993		$	3,619,345
SUPPLEMENTAL CASH FLOW DISCLOSURE:
Income taxes paid	$	–		$	–		$	–
Interest paid	$	–		$	–		$	–
NON-CASH INVESTING AND FINANCING
ACTIVITIES:
Common stock issued for services rendered,
accrued compensation and prepaid expenses	$	235,590		$	144,955		$	540,675
Common stock issued for exchange of debt	$	1,000,000		$	25,000		$	–
Common stock issued in exchange for investments	$	–		$	–		$	–
Common stock issued for reimbursement
of expenses paid	$	–		$	196,025		$	–
Common stock issued for loan consideration	$	–		$	–		$	327,000
Investment given for related party receivable	$	–		$	–		$	–
Investment given for consulting services	$	–		$	–		$	14,700
Stock options issued for services	$	522,500		$	360,000		$	222,343
Stock options issued for financing fees	$	–		$	71,910		$	–
Exchange of unproved property leases for
interest in limited partnership	$	–		$	–		$	–
Stock issued for exercise of warrants	$	37,125		$	–		$	233,334
Issuance of accounts payable to related party
for financing fees	$	–		$	300,000		$	–
Conversion of investment to note receivable	$	12,000		$	–		$	–

The accompanying notes are an integral part of these financial statements

F-8

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

NOTE 1 - ORGANIZATION AND DESCRIPTION OF BUSINESS

Cadence Resources Corporation (formerly Royal Silver Mines, Inc.) hereinafter (“Cadence” or “the Company”) was incorporated in April 1969 under the laws of the State of Utah primarily for the purpose of acquiring and developing mineral properties. The Company changed its name from Royal Silver Mines, Inc. to Cadence Resources Corporation on May 2, 2001. On October 31, 2005, the Company acquired Aurora Energy, Ltd (“Aurora) in a transaction that will be accounted for as a reverse merger with Aurora as the acquiring party for accounting purposes (the “Aurora Acquisition”).

The Company has elected a September 30 fiscal year-end. Subsequent to the closing of the Aurora Acquisition, the Company’s board of directors has elected to change the fiscal year-end of the Company to December 31, in order to coincide with the fiscal year-end of Aurora.

On July 1, 2001, Cadence developed a plan for acquisition, exploration and development of oil and gas properties and accordingly began a new exploration stage as an energy project development company. Prior to this, Cadence conducted its business as a “junior” mineral resource company, meaning that it intended to receive income from property sales or joint ventures of its mineral projects with larger companies. The Company continues to hold several mineral properties, which are described in Note 3.

The costs of prepaid oil and gas leases ($473,056 and $456,219, respectively) included in the accompanying balance sheets as of September 30, 2005 and 2004 are principally related to natural gas properties. The Company has not determined whether the properties located in New Mexico contain economically recoverable gas reserves. The ultimate realization of the Company’s investment in oil and gas properties in these locations is dependent upon finding and developing economically recoverable reserves, the ability of the Company to obtain financing or make other arrangements for development and upon future profitable production. The ultimate realization of the Company’s investment in these oil and gas properties cannot be determined at this time and, accordingly, no provision for any asset impairment that may result in the event the Company is not successful in developing these properties, has been made in the accompanying financial statements. The Company has completed reserve studies on each of its properties located, except for those located in New Mexico.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

This summary of significant accounting policies of Cadence Resources Corporation is presented to assist in understanding the Company’s financial statements. The financial statements and notes are representations of the Company’s management, which is responsible for their integrity and objectivity. These accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of the financial statements.

Accounting Method

The Company’s financial statements are prepared using the accrual method of accounting in accordance with accounting principles generally accepted in the United States of America.

Cash Equivalents

The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.

Derivative Instruments

The Financial Accounting Standards Board issued Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB No. 133”, and SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” and SFAS No. 149, “Amendment of Statement No. 133 on Derivative Instruments and Hedging Activities.” These standards establish accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. They require that an entity recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value.

F-9

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

If certain conditions are met, a derivative may be specifically designated as a hedge, the objective of which is to match the timing of gain or loss recognition on the hedging derivative with the recognition of (i) the changes in the fair value of the hedged asset or liability that are attributable to the hedged risk or (ii) the earnings effect of the hedged forecasted transaction. For a derivative not designated as a hedging instrument, the gain or loss is recognized in income in the period of change.

Historically, the Company has not entered into derivatives contracts to hedge existing risks or for speculative purposes.

At September 30, 2005 and for the periods covered in these statements, the Company has not engaged in any transactions that would be considered derivative instruments or hedging activities.

Environmental Remediation and Compliance

Expenditures for ongoing compliance with environmental regulations that relate to current operations are expensed or capitalized as appropriate. Expenditures resulting from the remediation of existing conditions caused by past operations that do not contribute to future revenue generations are expensed. Liabilities are recognized when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated.

Estimates of such liabilities are based upon currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other societal and economic factors, and include estimates of associated legal costs. These amounts also reflect prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by The Environmental Protection Agency or other organizations. Such estimates are by their nature imprecise and can be expected to be revised over time because of changes in government regulations, operations, technology and inflation. Recoveries are evaluated separately from the liability and, when recovery is assured, the Company records and reports an asset separately from the associated liability. At September 30, 2005, the Company had no accrued liabilities for compliance with environmental regulations.

Estimates

The process of preparing financial statements in conformity with accounting principles generally accepted in the United States of America requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues, and expenses. Such estimates primarily relate to the valuation assigned to options and warrants utilizing the Black-Scholes calculation, depletion expense utilizing oil and gas reserve studies and unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts.

Fair Value of Financial Instruments

The carrying amounts for cash, receivables, deposits, payables, and advances from related parties approximate their fair value.

Fair Value Standards

The Company has adopted the fair value accounting rules to record all transactions in equity instruments for goods or services.

F-10

Impaired Asset Policy

The Company adopted Statement of Financial Accounting Standards No. 144 titled “Accounting for Impairment of Disposal of Long-Lived Assets.” In complying with this standard, the Company reviews its long-lived assets quarterly to determine if any events or changes in circumstances have transpired which indicate that the carrying value of its assets may not be recoverable. The Company determines impairment by comparing the undiscounted future cash flows estimated to be generated by its assets to their respective carrying amount whenever events or changes in circumstances indicate that an asset may not be recoverable. Due to significant write-downs and write-offs taken in 2004 and in prior years, the Company does not believe any further adjustments are needed to the carrying value of its assets at September 30, 2005. See Note 3.

Investments

Investments, principally consisting of equity securities of private and small public companies, are stated at current market value.

Loss Per Share

Loss per share was computed by dividing the net loss by the weighted average number of shares outstanding during the year. The weighted average number of shares was calculated by taking the number of shares outstanding and weighting them by the amount of time they were outstanding. Outstanding options and warrants were not included in the computation of diluted loss per share because their inclusion would be antidilutive.

Mineral Properties

Costs of acquiring, exploring and developing mineral properties are capitalized by project area. Costs to maintain the mineral rights and leases are expensed as incurred. When a property reaches the production stage, the related capitalized costs will be amortized, using the units of production method on the basis of periodic estimates of ore reserves. At September 30, 2005, 2004, and 2003 the cost of the Company’s mineral properties are included in other assets in the accompanying financial statements, as the Company has changed its focus from minerals exploration to oil and gas.

Mineral properties are periodically assessed for impairment of value and any losses are charged to operations at the time of impairment.

Should a property be abandoned, its capitalized costs are charged to operations. The Company charges to operations the allocable portion of capitalized costs attributable to properties sold. Capitalized costs are allocated to properties sold based on the proportion of claims sold to the claims remaining within the project area.

Oil and Gas Properties

The Company uses the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed.

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Other unproved properties are amortized based on the Company’s experience of successful drilling and average holding period. Capitalized costs of producing oil and gas properties, after considering estimated dismantlement and abandonment costs and estimated salvage values, are depreciated and depleted by the unit-of-production method. Support equipment and other property and equipment are depreciated over their estimated useful lives.

F-11

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

On the sale or retirement of a complete unit of a proven property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proven property, the cost is charged to accumulated depreciation, depletion, and amortization with a resulting gain or loss recognized in income.

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any unrecorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Principles of Consolidation

The financial statements include those of the Cadence Resources Corporation and Celebration Mining Company. All significant inter-company accounts and transactions have been eliminated. The financial statements are not considered consolidated statements since Cadence Resources Corporation was the successor by merger to Celebration Mining Company.

Provision For Taxes

Income taxes are provided based upon the liability method of accounting pursuant to Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” (herein after "SFAS No. 109"). Under this approach, deferred income taxes are recorded to reflect the tax consequences in future years of differences between the tax basis of assets and liabilities and their financial reporting amounts at each year-end. A valuation allowance is recorded against deferred tax assets if management does not believe the Company has met the “more likely than not” standard imposed by SFAS No. 109 to allow recognition of such an asset.

Recent Accounting Pronouncements

In May 2005, the Financial Accounting Standards Board, or FASB, issued Statement of Financial Accounting Standards, “Accounting Changes and Error Corrections” (hereinafter "SFAS No. 154")  which replaces Accounting Principles Board Opinion No. 20, “Accounting Changes,” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements -- An Amendment of APB Opinion No. 28.” SFAS No. 154 provides guidance on accounting for and reporting changes in accounting principle and error corrections. SFAS No. 154 requires that changes in accounting principle be applied retrospectively to prior period financial statements and is effective for fiscal years beginning after December 15, 2005. The Company does not expect SFAS No. 154 to have a material impact on our consolidated financial position, results of operations, or cash flows.

In December 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 153. This statement addresses the measurement of exchanges of nonmonetary assets. The guidance in APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in that opinion, however, included certain exceptions to that principle. This statement amends Opinion 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. This statement is effective for financial statements for fiscal years beginning after June 15, 2005. Earlier application is permitted for nonmonetary asset exchanges incurred during fiscal years beginning after the date of this statement is issued. Management believes the adoption of this statement will have no impact on the financial statements of the Company.

In December 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 152, which amends FASB statement No. 66, “Accounting for Sales of Real Estate,” to reference the financial accounting and reporting guidance for real estate time-sharing transactions that is provided in AICPA Statement of Position (SOP) 04-2, “Accounting for Real Estate Time-Sharing Transactions.” This statement also amends FASB Statement No. 67, “Accounting for Costs and Initial Rental Operations of Real Estate Projects,” to state that the guidance for (a) incidental operations and (b) costs incurred to sell real estate projects does not apply to real estate time-sharing transactions. The accounting for those operations and costs is subject to the guidance in SOP 04-2. This statement is effective for financial statements for fiscal years beginning after June 15, 2005. Management believes the adoption of this statement will have no impact on the financial statements of the Company.

F-12

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

In December 2004, the Financial Accounting Standards Board issued a revision to Statement of Financial Accounting Standards No. 123R, “Accounting for Stock Based Compensation.” This satement supercedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and its related implementation guidance. This statement establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. This statement focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. This statement does not change the accounting guidance for share based payment transactions with parties other than employees provided in Statement of Financial Accounting Standards No. 123. This statement does not address the accounting for employee share ownership plans, which are subject to AICPA Statement of Position 93-6, “Employers’ Accounting for Employee Stock Ownership Plans.” The Company believes adoption of this statement will have an immaterial effect on the financial statements of the Company, as the Company currently accounts for stock based compensation under SFAS 123.

In November 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 151, “Inventory Costs— an amendment of ARB No. 43, Chapter 4.” This statement amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). Paragraph 5 of ARB 43, Chapter 4, previously stated that “. . . under some circumstances, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs may be so abnormal as to require treatment as current period charges. . . .” This statement requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” In addition, this statement requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. This statement is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. Management does not believe the adoption of this statement will have any immediate material impact on the Company as the Company maintains no inventory.

Reclassifications

Certain amounts from prior periods have been reclassified to conform to the current period presentation. These reclassifications have resulted in no changes to the Company’s accumulated deficit and net losses presented.

Revenue Recognition

Cadence began producing revenues during July 2002. Oil and gas revenues are recorded using the sales method. Under this method, the Company recognizes revenues based on actual volumes of oil and gas sold to purchasers.

NOTE 3 - MINERAL PROPERTIES

Over the last three fiscal years, the Company’s mineral properties have for the most part been disposed of or written off as the Company’s focus and direction has shifted to oil and gas production.

F-13

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

Utah Property

The Company has elected to retain its 25% undivided interest in the Vipont Mine located in northwest Utah. This interest was carried on the Company’s books at $246,757 at September 30, 2003 and 2002. During the year ended September 30, 2004, the Company elected to reduce the interest’s carrying value to $197,406 in order to better reflect its market value. This asset is included in “other assets” on the Company’s balance sheet.

Mineral Properties in North Idaho

At September 30, 2005, the Company, directly and through its subsidiary, Celebration Mining Company, held unpatented mining claims in the Coeur d’Alene Mining District in distinct groups called the South Galena Group, Moe Group, Rock Creek Group and Palisades Group. The Company has undertaken only minimal exploration and development work on these properties, such as general geological reconnaissance and claim-staking activities. All of these claims have been written off as permanently impaired.

During fiscal 2005, the Company entered into a mineral lease with Gold Creek Mines, Inc. on the Gold Creek claims consisting of 27 patented and 5 unpatented mining claims. The lease is for an initial term of twenty years and so long thereafter as minerals are produced from the property. The Company is obligated to spend $50,000 during the first two years of the lease on mineral exploration activities. Additionally, during the first two years of the lease, the Company is obligated to pay advance royalty payments of $750 per month, increasing to $1,000 per month during the second two year period, and $1,500 per month thereafter. At the inception of the lease, the Company made a one time advance royalty payment of $53,000 to the lessor.

Other Mineral Property Information

Celebration Mining Company (“Celebration”), a wholly owned subsidiary of Cadence, was incorporated for the purpose of identifying, acquiring, exploring and developing mining properties. Celebration was organized on February 17, 1994 as a Washington corporation. Celebration has not yet realized any revenues from its operations.

On August 8, 1995, Cadence and Celebration completed an agreement and plan of reorganization whereby the Company issued 207,188 shares of its common stock and 72,750 warrants in exchange for all of the outstanding common stock of Celebration. Immediately prior to the agreement and plan of reorganization, the Company had 118,773 common shares issued and outstanding.

The acquisition was accounted for as a purchase by Celebration of Cadence, because the shareholders of Celebration controlled the Company after the acquisition. Therefore, Celebration is treated as the acquiring entity. There was no adjustment to the carrying value of the assets or liabilities of Cadence in the exchange as the market value approximated the net carrying value. Cadence is the acquiring entity for legal purposes and Celebration is the surviving entity for accounting purposes.

As a result of the Company’s entering a new exploration stage on July 1, 2001, the Company elected to dispose of its mineral properties and has accordingly reclassified those remaining properties, which total $197,406 at September 30, 2005, as other assets. The Company has not determined whether these mineral exploration properties contain ore reserves that are economically recoverable, and is in the process of disposing of these properties. The ultimate realization of the Company’s investment in these properties cannot be determined at this time and, accordingly, no provision for any asset impairment that may result in the event the Company is not successful in selling these properties has been made in the accompanying financial statements.

F-14

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

NOTE 4 - PROPERTY AND EQUIPMENT

Property and equipment are recorded at cost. Major additions and improvements are capitalized. Minor replacements, maintenance and repairs that do not increase the useful life of the assets are expensed as incurred. Depreciation of property and equipment is determined using the straight-line method over the expected useful lives of the assets of five to ten years. Depreciation, depletion and amortization expense for the years ended September 30, 2005, 2004, and 2003 was $2,683,279, $2,663,695 and $57,310, respectively.

NOTE 5 - INVESTMENTS

The Company’s investment securities are classified as available for sale securities which are recorded at fair value on the balance sheet as investments. The change in fair value during the period is excluded from earnings and recorded net of tax as a component of other comprehensive income. The Company has no investments which are classified as trading securities.

At September 30, 2005, 2004, and 2003, the market values of stock investments were as follows:

	2005		2004		2003
Elite Logistics, Inc.	$	204	$	204	$	656
Ashington Mining Company		–		5,709		5,709
Enerphaze Corporation		261		655		982
Integrated Pharmaceuticals, Inc.		10,520		27,984		9,406
Metalline Mining Company		–		1,605		925
Nevada-Comstock (formerly Caledonia Silver-Lead Mines, Inc.)		–		12,000		–
Rigid Airship Tech		–		310		310
Trend Mining Company		17,923		27,083		24,483
Western Goldfields, Inc.		16,053		102,148		351,373
TN Oil Co		65,000		50,000		–
White Mtn Titanium		7,350		9,940		–
Aurora Energy		750,000		–		–
Abot Mining		3,000		–		–
Other investments		–		450		610
Total	$	870,311	$	238,088	$	394,454

The carrying value of these shares is reevaluated at each reporting period and adjustments, if appropriate, are made to the carrying value of these securities. Of all the aforementioned investments owned by the Company at September 30, 2005, only Trend Mining Company, Abot Mining, Metalline Mining Company, Western Goldfields, Inc., White Mtn Titanium, and Integrated Pharmaceuticals are public companies with a trading market.

Other information regarding the Company’s investments follows:

Enerphaze Corporation

In October 2001, the Company received 8,000 shares of Enerphaze Corporation common stock in payment of a $15,000 note receivable. In January and February 2002, the Company received 65,000 shares of Enerphaze Corporation common stock in exchange for 400,000 shares of the Company’s common stock. No gain or loss was recognized on these transactions.

F-15

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

Nevada-Comstock Mining Company (formerly Caledonia Silver-Lead Mines, Inc.)

The Company on October 31, 2001 received 3,501,980 shares of the $0.10 par value common stock of Caledonia Silver-Lead Mines, Inc. (an affiliated company) in exchange for its Kil Group

and West Mullan Group claims. The stock received was recorded at its par value of $350,198 which, in the opinion of management, approximates its fair value. At September 30, 2003, this investment was written off to reflect the mining company’s dormancy. In the year ended September 30, 2004, the Company’s investment in the mining company increased to $12,000 as funds were advanced to cover annual filing fees on patented mining claims. During the year ended September 30, 2005, this investment was converted to a note receivable, to more accurately reflect the actual character of the payment of the filing fees.

TN Oil Company

In August 2004, the Company acquired a 25% equity ownership in TN Oil Company, which owns oil leases in central and north central Tennessee. Due to additional investments by outside parties, the ownership interest in the TN Oil Company has been reduced to 14% at September 30, 2005.

Western Goldfields, Inc.

In 2002, the Company exchanged fully depreciated mining equipment for shares of a privately held business, Calumet Mining Company, which was eventually acquired by Western Goldfields, Inc. Upon completion of the acquisition, the Company received 160,000 shares of Western’s common stock. During 2003, the Company acquired an additional 21,200 shares of Western stock for $24,730. At September 30, 2005, the fair market value of the Company’s holdings in Western was $16,053.

NOTE 6 - COMMON STOCK

During the year ended September 30, 2005, the Company issued 160,500 shares of its common stock to officers and directors for services valued at $235,590. Additionally, the Company issued 800,000 units consisting of stock and warrants in payment of loans of $1,000,000, and 7,010,000 units consisting of stock and warrants in a private placement for net cash proceeds of $7,786,250. The Company paid a finder’s fee to a related party in the amount of $976,250, for assistance in this private placement. The Company also had 27,500 previously issued warrants exercised at $1.35 per share and issued 21,000 shares of its common stock upon a cashless exercise of warrants.

During the year ended September 30, 2004, the Company issued 219,500 shares of its common stock to officers, directors and consultants for services valued at $329,355, 25,000 shares in repayment of a related party loan of $25,000, 15,000 shares for financing expense valued at $11,625, 110,000 shares for cash proceeds of $275,000. Warrants previously issued were exercised for 10,000 shares at $1.35 per share.

During the year ended September 30, 2003, the Company sold 212,500 units to investors at prices ranging from $0.50 to $0.80 per unit in a private placement. Each unit consists of one share of common stock and one warrant exercisable at $1.35 per common share for three years. Sales of these units generated cash proceeds of $110,000. Warrants previously issued (2,320,175) were exercised for 1,956,984 shares of common stock in “cashless” redemptions. (See Note 9.) During this same period the Company sold 2,625,183 shares of its common stock for $4,316,599 net of expenses of $347,850. The Company also issued 496,500 shares of its common stock to officers, directors and consultants for services valued at $540,675 and 220,000 shares for loan consideration valued at $207,000. In addition, the Company issued to a related party an additional 120,000 shares valued at $120,000 as an inducement for a loan. The value of this inducement was used to reduce the payable to related party.

F-16

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

NOTE 7 - REDEEMABLE PREFERRED STOCK

On April 23, 2001, the Company’s board of directors authorized 20,000,000 shares of preferred stock with a par value of $0.01 per share and rights and preferences to be determined. No shares were issued and outstanding as of September 30, 2002. During the year ended September 30, 2003, the Company issued 34,950 shares of its Class A preferred stock to investors at prices ranging from $1.50 to $2.00 per share for aggregate proceeds of $59,925. The shares are convertible to common stock at a price of $1.50 to $2.00 per share under certain terms and conditions. At September 30, 2003, the shares carried a preferred dividend of 15% per annum. During the year ended September 30, 2004, the dividend feature was temporarily suspended because certain conditions, which required the payment of dividends, were considered satisfied. The Class A shares mature seven years from the date of issuance. At maturity, the Class A shares will be redeemed for cash or common stock at Cadence’s option in an amount equal to the amount paid by the investors for the shares plus any accrued and unpaid dividends. If shares of common stock are to be issued at maturity, the conversion price shall be determined by the average closing bid price for the 20 trading days prior to the maturity date.

At September 30, 2005,  the Company owed $15,737 of accrued dividends to preferred shareholders. There were no accrued dividends outstanding at September 30, 2004 and 2003.

NOTE 8 - COMMON STOCK OPTION AND AWARD PLAN

In January 1992, the shareholders of Cadence approved a 1992 Stock Option and Stock Award Plan under which up to ten percent of the issued and outstanding shares of the Company’s common stock could be awarded based on merit or work performed. As of September 30, 2005, the Company had awarded 638 shares of common stock under the Plan.

The Company has a stock-based compensation plan whereby the Company’s board of directors may grant common stock to its employees and directors. Over the years, a total of 72,750 options have been granted under the plan. These options have been forfeited and none have been exercised through the year ending September 30, 2005. The old existing options are attributed to the merger of Celebration Mining Company with Royal in August 1995.

The Company’s board of directors has made option awards to select officers, directors, consultants and shareholder/investors. These common stock options were not awarded pursuant to a qualified plan and carry various terms and conditions. The Company granted a total of 750,000 common stock options at an average exercise price of $1.08 per share during the year ended September 30, 2002 and granted 287,140 common stock options at an average exercise price of $2.23 during the year ended September 30, 2003.

During the year ended September 30, 2005, the Company granted 250,000 options to officers and directors with an exercise price of $1.42. These options were granted as compensation  to said officers and directors.

During the year ended September 30, 2004, the Company issued 400,000 stock options to two directors and one officer with an exercise price of $3.73. These options were granted upon the acceptance by the individual of the position of officer and/or director and the approval of the Company’s qualified stock option plan at its April 2004 annual shareholders meeting. The Company also granted during the year ended September 30, 2004 an option to purchase 76,500 shares of stock to a shareholder valued at $71,910 as a fee for his services in relation to finding investors for the senior secured notes. See Note 9 and Note 12.

All options granted were exercisable immediately. The Company’s board of directors has reserved the right to cancel these awards for non-performance or other reasons. Further, in accordance with the terms of the stock option plan, under most circumstances, officer and director options must be exercised within 90 days of the departure of an officer or director from the Company. As a result, 250,000 of the options granted with an exercise price of $3.73 expired in the year ended September 30, 2005

The following assumptions were made in estimating fair value during the year ended September 30, 2005: risk free interest rate of 4%, volatility of 41%, expected life of 2.33 years and no expected dividends. The value of these options, in the aggregate amount of $522,500 is included in the Company’s statement of operations for 2005. The following assumptions were made in estimating fair value during the year ended September 30, 2004: risk free interest rate of 4%, volatility of 39%, expected life of three years and no expected dividends. The value of these options, in the aggregate amount of $431,910, was included in the Company’s statement of operations for 2004. The following assumptions were made in estimating fair value during the year ended September 30, 2003: risk-free interest rate of 3% to 4%, volatility of 106% to 337%, expected life of 4 to 5 years and no expected dividends. The value of these options in the amount of $222,343 was included in the Company’s statement of operations for 2003. The value of options issued in 2003 for financing fees in the amount of $429,671 was deducted against additional paid-in capital, as a cost of selling common stock.

F-17

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

Following is a summary of the stock options during the years ended September 30, 2005, 2004, and 2003:

	Number of Shares Under Options			Weighted Average Exercise Price
Outstanding at 10/1/2002		750,000		$	1.08
Granted		287,140			2.23
Exercised		(100,000	)		(0.68	)
Expired or forfeited		–			–
Outstanding at 9/30/2003		937,140		$	1.47
Options exercisable at 9/30/2003		937,140		$	1.47
Weighted average fair value of options granted during the year ended 9/30/2003	$	2.27
Outstanding at 10/1/2003		937,140		$	1.47
Granted		476,500			3.77
Exercised		–			–
Expired or forfeited		–			–
Outstanding at 9/30/2004		1,413,640		$	2.25
Options exercisable at 9/30/2004		1,413,640		$	2.25
Weighted average fair value of options granted during the year ended 9/30/2004	$	0.91
Outstanding at 10/1/2004		1,413,640		$	2.25
Granted		250,000			1.42
Exercised		–			–
Expired or forfeited		(500,000	)		(2.62	)
Outstanding at 9/30/2005		1,163,640		$	1.91
Options exercisable at 9/30/2005		1,163,640		$	1.91
Weighted average fair value of options granted during the year ended 9/30/2005	$	2.09

F-18

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

Exercise Date	Number of Shares Under Options		Weighted Average Price per Share
On or before March 1, 2007		450,000	$	1.74
On or before April 2, 2007		76,500	$	4.00
On or before July 8, 2007		100,000	$	1.35
On or before June 18, 2007		50,000	$	1.70
On or before June 1, 2007		75,000	$	2.00
On or before January 7, 2008		250,000	$	1.42
On or before September 30, 2008		162,140	$	2.50

In July 2003, 100,000 of the outstanding options were exercised for the purchase of 100,000 shares of the Company’s common stock.

The following table gives information about the Company’s common stock that may be issued upon the exercise of options under all of the Company existing stock option plans as of September 30, 2005

					Remaining
Exercise	Number of		Weighted Average		Contractual Life		Number		Weighted Average
Prices	Shares Under Options		Exercise Price		(in years)		Exercisable		Exercise Price
$0.75		300,000	$	0.75		.42		300,000	$	0.75
1.35		100,000		1.35		.75		100,000		1.35
1.42		250,000		1.42		2.33		250,000		1.42
1.70		50,000		1.70		.75		50,000		1.70
2.00		75,000		2.00		1.67		75,000		2.00
2.50		162,140		2.50		3.00		162,140		2.50
3.73-4.00		226,500		3.82		2.50		226,500		3.82
		1,163,640	$	1.91				1,163,640	$	1.91

Stock Award Plan

During the year ended September 30, 2001, the Company’s board of directors approved the issuance of 15,000 shares of the Company’s common stock per quarter to each entitled director as compensation for service to the Company and 5,000 shares of the Company’s common stock per quarter to officers in addition to their salaried compensation for services.

NOTE 9 - COMMON STOCK WARRANTS

During the year ended September 30, 2003, the Company issued 212,500 shares of stock with 212,500 warrants attached, and 25,000 warrants related to a July 2002 purchase. The warrants were valued at $51,375 using the Black-Scholes Option Price Calculation. The following assumptions were made is estimating fair value: risk free interest rate is 5%, volatility is 100%, expected life is 3 years and no expected dividends. These warrants may be used to purchase 237,500 shares of the Company’s common stock at $1.35 per share. The warrants remain exercisable through October 15, 2005. As of the date of these financial statements, 200,000 of these warrants remain outstanding and exercisable.

During the year ended September 30, 2004, the Company issued certain note holders warrants to purchase a total of 765,000 shares of common stock, exercisable at $4.00 per share, expiring in three years. Both the number of warrants and the exercise price are adjustable, dependent upon certain future equity transactions of the Company. The warrants were valued at $745,237 using the Black-Scholes Option Price Calculation. The following assumptions were made in estimating fair value: risk-free interest rate is 5%, volatility is 100%, expected life is three years and no expected dividends. During the year ended September 30, 2005, the Company paid back the notes which were related to these warrants. As an incentive to the note holders to allow the Company to redeem the notes prematurely, the Company modified the exercise price of the warrants to $1.75. Using current Black-Scholes calculations, the Company incurred no additional charges to its financial statements with this modification.

During the year ended September 30, 2005, the Company issued warrants to purchase a total of 14,050,000 shares of stock. These warrants were attached to 7,810,000 shares of stock which were issued for cash and debt. The warrants were valued at $3,685,875 using the Black-Scholes Option Price Calculation. The following assumptions were made in estimating fair value during the year ended September 30, 2005: risk free interest rate of 4%, volatility of 41%, expected life of 3 years and no expected dividends. See Note 6.

F-19

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

NOTE 10 - OIL AND GAS PROPERTIES

The Company’s oil and gas producing activities are subject to laws and regulations controlling not only their exploration and development, but also the effect of such activities on the environment. Compliance with such laws and regulations may necessitate additional capital outlays, affect the economics of a project, and cause changes or delays in the Company’s activities. The Company’s oil and gas properties are valued at the lower of cost or net realizable value.

Louisiana

During the fourth quarter of the year ended September 30, 2001, the Company began leasing acreage in a natural gas field in Desoto Parish, Louisiana. As of the date of these financial statements, the Company has leased over 4,250 acres. At September 30, 2005 and September 30, 2004, Louisiana leases of $42,711 and $42,711, respectively, are included in the attached financial statements as part of proved properties. Under the terms of a joint operating agreement with Bridas Energy USA, Bridas commenced drilling wells, 13 of which were completed and of these 9 are producing at September 30, 2005. The Company has various working interests in and net revenue interests in the wells drilled. Bridas is the operator of all of Cadence’s properties in Louisiana.

Texas

During the year ended September 30, 2002, the Company acquired an exploration permit and lease option agreement for an oil well project in Wilbarger County, Texas known as the Waggoner Ranch Project. During the quarter ended March 31, 2002 under the terms of a joint operating agreement with the W.T. Waggoner Estate, Waggoner drilled an initial test well. By September 30, 2005, Waggoner had drilled a total of eight wells in Wilbarger County, of which five were producing oil. The W.T. Waggoner Estate is the operator of all of Cadence’s properties in Wilbarger County and the sole purchaser of all production from these properties.

During the year ended September 30, 2002, the Company sold 40% of the working interest in its initial well in this area (known as the “1A” well) to private investors and two officers of the Company for $210,000. The Company’s initial cost in the portion of the prospect sold totaled $3,200.

During February 2003, the Company completed the West Electra Lake Well on the Waggoner Ranch Project. The Company entered into a 45% working interest joint operating agreement with the Waggoner Ranch for the operations conducted on this acreage. In the quarter ending September 30, 2003, the Company drilled and completed two additional wells on the West Electra Lake joint venture operating area on the Waggoner Ranch. The Company owns a 50% working interest in these last two wells.

At September 30, 2005, 2004 and 2003, prepaid oil and gas leases relating to Texas property of $13,954, $6,500 and $4,500, respectively, are included in the attached financial statements.

Michigan

In December 2002, the Company began participating in a natural gas drilling program in Alpena County, Michigan with Aurora Energy, Ltd. As of September 30, 2005, Cadence had a 22.5% working interest (before payout, 20% after payout), 18% net revenue interest (before payout, 16% after payout), in ten producing wells in Alpena County. Production commenced from this field in June 2003. Aurora is the operator of all of Cadence’s properties in Alpena County. At September 30, 2005, and 2004, Michigan leases totaling $ $96,375 are included in the attached financial statements as unproved property.

F-20

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

Kansas

During the year ended September 30, 2003, and 2004, the Company leased over 26,000 acres of land in the Anadarko Basin in west central Kansas. No drilling has commenced on any of this acreage. Cadence holds a 100% working interest and 82% net revenue interest in these leases.

At September 30, 2005, $270,669 of the leases in Kansas are included as proved properties and in 2004, $253,213 of leases in Kansas are included as unproved property in the Company’s financial statements.

New Mexico

At September 30, 2005 and 2004, $9,600 and $57,420, respectively, of leases in New Mexico are included in the attached financial statements as unproved property.

In June 2004, the Company began participating for a 20% working interest and 15% net revenue interest in the Santa Nina Prospect in Eddy County. Earlier in the year, the Company signed an agreement with SDX Resources to participate for up to a 25% working interest and 20% net revenue interest in up to 17 development wells in a project called the Sparkplug Unit.

NOTE 11 - NOTES PAYABLE - RELATED PARTIES

All of the Company’s notes payable are considered short-term. At September 30, 2005 and 2004, the Company had no outstanding notes payable to related parties. At September 30, 2003, the Company owed the following notes:

	2003
Nathan Low Family Trust (a shareholder of the Company), secured by assignment of a prorata interest in gas producing properties located in Alpena County, Michigan, interest at 8%, dated February 24, 2003, originally due on April 4, 2003, extended to December 31, 2003.	$	50,000
Kevin Stulp (a shareholder of the Company),interest at 8%, dated February 24, 2003, originally due on April 5, 2003, extended to December 31, 2003.		25,000
Howard Crosby (an officer and shareholder of the Company), interest at 8%, dated February 24, 2003, originally due on April 5, 2003, extended to December 31, 2003.		25,000
Howard Crosby (an officer and shareholder of the Company), unsecured, interest at 5%, dated January 9, 2003, originally due on February 28, 2003, extended to December 31, 2003.		60,000
CGT Management Ltd., unsecured, interest at 10%, dated July 16, 2003 (paid in full October 2, 2003).		300,000
Total	$	460,000

F-21

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

NOTE 12 - LONG-TERM DEBT

In April 2004, the Company completed a private placement of $6,000,000 of senior secured notes from a group of institutional and individual lenders. A financing fee of $380,000  paid in connection with securing of this debt was recorded as a discount on long-term debt, and will be written off ratably over the life of the debt. For the period ending September 30, 2004, $70,000 of this financing fee was written off. The notes accrued interest at the rate of 10% per year, were originally payable on March 31, 2006 and were secured by all of the assets of Cadence.

As part of the private placement, the note holders received warrants to purchase a total of 765,000 shares of common stock. (See Note 9.) The value of the warrants upon issuance of $745,237 was recorded as a discount on long-term debt, and will be written off ratably over the life of the debt. For the period ended September 30, 2004, $186,309 of this discount was written off. Additionally, a related party was granted 76,500 options valued at $71,910 as a finder’s fee related to these notes. These notes were paid in full during the year ended September 30, 2005. At the time these notes were repaid, there was a balance in deferred financing fees in the amount of $660,559. This amount is included in interest expense and loan fees in the accompanying financial statements. During the year ended September 30, 2005, the Company paid back the notes which were related to these warrants. As an incentive to the note holders to allow the Company to redeem the notes prematurely, the Company modified the exercise price of the warrants to $1.75. Using current Black-Scholes calculations, the Company incurred no additional charges to its financial statements with this modification.

NOTE 13- COMMITMENTS AND CONTINGENCIES

Litigation

The Company was a defendant in a lawsuit alleging that the Company failed to transfer common stock in exchange for a mining property interest. In June 1999, Box Elder County Superior Court rejected the plaintiff’s lawsuit and let stand the Company’s countersuit alleging fraudulent misrepresentation. Although the plaintiff filed an appeal (regarding the originally filed lawsuit), the Utah Supreme Court rejected the appeal in a judgment rendered on July 31, 2001.

The Company’s countersuit, which sought both full title to the aforementioned mineral property and compensatory damages as well as punitive damages, was rejected in a jury trial in October 2002. Although the Company filed an appeal, it expects the jury verdict will stand. As a result, the Company has and will continue to hold an undivided 25% interest in the Vipont Mine. See Note 3.

Environmental Issues

The Company is engaged in oil and gas exploration and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures as they relate to the drilling of oil and gas wells and the operation thereof. In the Company’s acquisition of existing or previously drilled wells, the Company may not be aware of environmental safeguards that were taken at the time such wells were drilled or during such time the wells were operated.

The Company could incur significant costs, including cleanup costs resulting from a release of hazardous material, third-party claims for property damage and personal injuries fines and sanctions, as a result of any violations or liabilities under environmental or other laws. Changes in or more stringent enforcement of environmental laws could also result in additional operating costs and capital expenditures. In the course of routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials do occur, and the Company may incur costs for waste handling and environmental compliance.

F-22

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

The Company was previously engaged in exploration of mineral properties. These properties are classified as assets from discontinued operations or were previously written off as permanently impaired. Although the Company has discontinued the exploration of mineral properties, the possibility exists that environmental cleanup or other environmental restoration procedures could remain to be completed or be mandated by law, causing unpredictable and unexpected liabilities to arise. At the date of this report, the Company is not aware of any environmental issues related to any of its assets from discontinued operations.

Capital Commitments

At September 30, 2005, the Company’s future capital commitments are dependent upon the Company’s decision to proceed with additional well development. See Note 10. No accruals have been made in the accompanying financial statements for these amounts.

Lease Commitments

The Company began leasing office facilities in Walla Walla, Washington commencing in June 2001. After a three-year lease with monthly payments of $400 expired in June 2004, the Company began a month to month tenancy, again paying $400 per month. Total rent paid for this office space during the year ended September 30, 2003 was $4,800. There were no rentals recorded for this space during fiscal year ended September 30, 2005.

The Company began leasing additional office space in Hilton Head Island, South Carolina in August 2003. The one-year lease calls for monthly rental payments of $550. For the year ended September 30, 2004, the Company expended $4,967 for this rental space. There were no rentals recorded for this space during the year ended September 30, 2005. 

Cadence Resources Corporation Limited Partnership

On August 8, 2002, the Company formed a limited partnership in the State of Washington whereby the Company became the managing general partner and an outside individual investor became the initial limited partner. The entity, Cadence Resources Corporation Limited Partnership (“CRCLP” or the “Partnership”) was formed to invest in oil and gas properties in Texas and Louisiana.

In connection with the formation of the Partnership, the Company agreed to contribute $12,500 in cash and its leasehold interest in an oil well (“2B”, which ultimately was a dry hole) in Wilbarger County, Texas and the limited partner contributed $250,000 in cash.

Effective September 30, 2003, Cadence purchased the limited partner’s interest in the Partnership and thereby terminated the limited partner’s security interest in the equipment and fixtures affixed to wells 1A and 1B in Wilbarger County, Texas. In this transaction, Cadence made a cash payment of $250,000 in October 2003 to the limited partner and received, from the limited partner his 5% working interest in the West Electra Lake #1 oil well in Wilbarger, Texas.

In connection with the aforementioned transaction, Cadence also repaid in October 2003 to the limited partner the unsecured sum of $300,000. These funds were previously advanced to the Partnership in June 2003 for the exploration of natural gas interests in the Black Bean Unit in Michigan in return for the limited partner’s receiving 120,000 shares of Cadence stock and a working interest in each well drilled in the unit. Upon repayment of the $300,000 advance, the limited partner’s working interest in each well drilled in the Black Bean Unit was fixed at 2%.

Consulting Commitments

In June 2002, the Company entered into an agreement with Memphis Consulting Group (“Memphis”) for financial consulting and public relations services beginning on August 1, 2002 through August 1, 2003. The agreement called for monthly payments of $3,000, and an initial 50,000 stock options exercisable through August 1, 2005 at $1.50 per share. See Note 8. This agreement was terminated during the quarter ended March 31, 2003.

F-23

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

In September 2001, the Company entered into a consulting agreement with American Financial Group for promotion to investors. The agreement called for monthly payments of $2,000 to cover all expenses, 20,000 shares of the Company’s common stock (which were issued in October 2001) and an override of 2.5% of monies raised in private placements from referrals or directed business. The agreement was terminated during the quarter ended March 31, 2003.

In June 2003, the Company entered into a corporate advisory agreement with Proteus Capital Corp. calling for a monthly fee of $3,000 in cash and 2,000 restricted shares of the common stock of the Company. Additionally, Proteus received an option for 50,000 shares exercisable at $1.75 for a period of four years, such shares bearing certain registration rights should the Company file a registration statement on behalf of other shareholders. This agreement with Proteus Capital Corp. was terminated during the fiscal year ended September 30, 2005.

Lucius C. Geer, a consultant to the Company who manages its acquisition, exploration and production operations, has entered into several agreements with Cadence and has contractually received a 2% overriding royalty interest in oil, gas and mineral leases in Wilbarger County, Texas and a 1% overriding royalty interest in oil and gas leases in Desoto Parish, Louisiana.

Effective August 1, 2003, Cadence agreed to pay Mr. Geer $7,500 per month plus an overriding royalty interest of 2% of the sales price received for all oil, gas and minerals from leases which Geer acquires for Cadence. Effective August 1, 2004, the agreement with Mr. Geer was changed to increase the monthly fee from $7,500 to $10,000. The agreement with Mr. Geer has been extended through June 30, 2006.

Other Commitments

The Company entered into an exploration agreement with the W.T. Waggoner Estate (Waggoner) and its trustees on August 1, 2002. This agreement calls for exploration of the West Electra Lake Project located in Wilbarger County, Texas. See Note 10.

On August 13, 2002, the Company entered into a public relations retainer agreement for one year whereby the Company agreed to issue 60,000 shares of its common stock during this period for services received. The agreement also calls for reimbursement of expenses incurred pursuant to terms of this agreement. This agreement was terminated in the quarter ending September 30, 2003.

NOTE 14 - RELATED PARTY TRANSACTIONS

At September 30, 2005, 2004 and 2003, the Company had related party accounts payable outstanding in the amounts of $0, $300,000 and $550,000, respectively. At September 30, 2005, 2004 and 2003, the Company had related party notes payable outstanding in the amounts of $0, $0 and $460,000, respectively.

In February 2004, the Company borrowed $250,000 from an officer, a total of $95,000 from two directors, and $50,000 from Dotson Exploration Company, a related entity. All of these borrowings were repaid by Cadence in April 2004.

In January 2004, Cadence hired Mr. Douglas Newby as a vice president; Mr. Newby is the president and owner of Proteus Capital Corp., with whom the Company has a consulting agreement. See Note 13.

During the year ended September 30, 2002, the Company sold several mineral properties located in Shoshone County, Idaho to Caledonia Silver-Lead Mines, Inc., later renamed Nevada-Comstock Mining Company (“NCMC”). Two officers of the Company collectively own 2.4% of this entity and Cadence owns 35%. During 2004, the Company paid $12,000 to cover annual filing fees on patented claims held by NCMC. This amount was converted to a loan during 2005.

F-24

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

Two officers of the Company collectively own in excess of 40% of the stock of Dotson Exploration Company and are the sole officers and directors of Dotson. Dotson owns 109,000 shares of the Company’s common stock. During fiscal year 2002 and the first quarter of fiscal year 2003, Cadence repaid Dotson a loan in the amount of $10,000 and made two new loans to Dotson, one for $35,000 and one for $20,000, each at an interest rate of 10% per annum. Dotson transferred to Cadence marketable securities in the form of common stock of two unaffiliated companies, Enerphaze Corporation and The Williams Companies, Inc., valued by Cadence’s board of directors at $33,380, as partial payment of the amount loaned. During the nine months ended June 30, 2003, Dotson repaid the $20,000 loan in cash. At September 30, 2005, 2004 and 2003, Dotson owed Cadence $3,720, which amount is payable on demand and bears interest at 10% per annum. Subsequent to the year ended September 30, 2005, this loan was paid in full.

Because Dotson Exploration Company, Oxford Metallurgical, Inc. and Nevada-Comstock Mining Company are controlled by two officers of Cadence, these transactions cannot be considered to be the product of an arms-length negotiation.

During fiscal 2003, the Company’s president made two loans to Cadence. One loan in December 2002 was in the principal amount of $70,000, bearing interest at 5% and the other loan made in February 2003 was in the principal amount of $50,000 bearing interest at a rate of 8%. Cadence issued 14,000 shares of its common stock valued at $10,920, as an inducement to making the $70,000 loan and 20,000 shares valued at $15,600, as an inducement to making the $50,000 loan. Cadence repaid $60,000 and has agreed to issue 4,000 shares of its common stock in repayment of the remaining $10,000 principal amount outstanding on the $70,000 loan. Cadence repaid $25,000 of the $50,000 loan in cash and issued 25,000 shares of its common stock in the year ending September 30, 2004 to repay the remaining $25,000 principal amount.

In February 2003, a Company director made a bridge loan to Cadence in the principal amount of $50,000, bearing interest of 8% per annum. Cadence issued 20,000 shares of its stock valued at $15,600 as an inducement for the director to make the loan. Cadence repaid $25,000 of the $50,000 loan in 2003 and settled the remaining amount in 2004 with common stock. In July 2003, the director exercised a warrant to purchase 100,000 shares of common stock at $0.75 per share.

On August 8, 2002, the Company formed a limited partnership whereby the Company became the managing general partner and an outside individual investor (a Company shareholder) became the initial limited partner. During the year ended September 30, 2003, the limited partner advanced $300,000 to the limited partnership in exchange for an unsecured note, which was repaid in October 2003.

In October 2002, the Nathan A. Low Roth IRA and various entities controlled by Thomas Kaplan, shareholders of Cadence, exercised warrants in separate cashless transactions whereby each party surrendered a total of 175,676 shares of common stock valued at $325,000 to exercise warrants for the acquisition of 1,083,334 shares of Cadence common stock.

Other related party transactions are disclosed in Notes 3, 5, 6, and 11.

NOTE 15 - INCOME TAXES

At September 30, 2005, the Company had net deferred tax assets calculated at an expected rate of 34% of approximately $6,703,000 as indicated below. As management of the Company cannot determine that it is more likely than not that the Company will realize the benefit of the net deferred tax asset, a valuation allowance equal to the net deferred tax asset has been established at September 30, 2005.

The significant components of the deferred tax asset at September 30, 2005, 2004 and 2003 were as follows:

	2005			2004		2003
Net operating loss carryforwards	$	5,746,000		$	4,317,000	$	2,829,000
Stock options and warrants issued		723,000			623,000		622,000
Section 1231 loss carryforwards		146,000			146,000		151,000
Capital loss carryforwards		88,000			586,000		1,532,000
Total deferred tax asset		6,703,000			5,672,000		5,134,000
Less valuation allowance		(6,703,000	)		5,672,000		5,134,000
Net deferred tax asset	$	–		$	–	$	–

F-25

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

At September 30, 2005, the Company has net operating loss carryforwards of approximately $16,900,000, which expire in the years 2009 through 2024. In addition, the Company has net Section 1231 loss carryforwards of approximately $432,000, which expire in 2006, and net capital loss carryforwards of approximately $194,000, which expire in the years 2006 through 2009. The change in the allowance account from September 30, 2004 to September 30, 2005 was $1,031,000, which was primarily due to the Company’s operating losses and the expiration of capital losses.

The Company may have had a control change as defined under the Internal Revenue Code, because of new stock issuances and changes in ownership. The effect of such control changes has not been calculated but may limit the future use of net operating losses.

NOTE 16 - ACQUISITION OF AURORA ENERGY, LTD.

The Company acquired Aurora Energy, Ltd. (hereinafter "Aurora"), a privately held company based in Traverse City, Michigan, on October 31, 2005, through the merger of the Company’s wholly-owned subsidiary with and into Aurora. The acquisition of Aurora was the culmination of a process that officially began November 19, 2004 when the Company and Aurora signed a letter of intent contemplating the acquisitions, followed, on January 31, 2005 by Cadence and Aurora entering into a definitive merger agreement providing for the acquisition of all Aurora’s outstanding capital stock in consideration for which (i) Cadence will issue two shares of its common stock for each share of outstanding Aurora common stock, (ii) each option and warrant to purchase a share of Aurora common stock will become an option or warrant (as applicable) to purchase two shares of Cadence common stock at one-half the previous exercise price, and (iii) Aurora will become a wholly owned subsidiary of Cadence.

On May 13, 2005, the Company filed Form S-4, registering up to 48,297,694 shares of its common stock, 10,205,328 shares of which are issuable upon exercise of options and warrants for issuance to the former shareholders and option holders of Aurora.

As noted below, the acquisition of Aurora will be accounted for as a reverse merger, with Aurora being the acquiring party for accounting purposes. In connection with the acquisition of Aurora, Cadence issued an aggregate of 37,512,366 shares of Cadence common stock to the former shareholders of Aurora, and has reserved and additional 10,497,328 shares of Cadence common stock for issuance upon exercise of options or warrants that had been issued by Aurora prior to the acquisition and that were previously exercisable for shares of common stock of Aurora.

As a result of the acquisition of Aurora, Cadence has relocated its operational headquarters to Aurora’s offices in Traverse City and the board of directors and management of Cadence have been significantly restructured. The merger between Cadence and Aurora was finalized on October 31, 2005.

As a result of the acquisition of Aurora, the Company will revise certain of its accounting principles applicable to its oil and gas properties and change its accounting fiscal year end to December 31, commencing December 31, 2005. See Note 17.

F-26

CADENCE RESOURCES CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

September 30, 2005

NOTE 17 - ACCOUNTING CHANGES IN CONNECTION WITH ACQUISITION OF AURORA ENERGY, LTD

As a result of the acquisition of Aurora Energy, Ltd. (hereinafter "Aurora"), the Company will change certain of its accounting policies as described below. These changes will be reflected in the financial statements for the fiscal year ending December 31, 2005.

Aurora will be treated as the acquirer for accounting purposes, and accordingly, reverse acquisition accounting will be applied to the business combination.

The Company will measure the cost of the business acquired by reference to the fair value of the Company’s securities (i.e. shares of Cadence common stock including outstanding options and warrants to purchase such shares) at the date of the merger agreement, January 31, 2005, or approximately, $41,500,000.

Cadence will uniformly apply the full cost method to all of its oil and gas operations in both its divisions. Accordingly, the successful efforts method, which had previously been used by the Cadence division, will be changed to the full cost method.

Cadence will initially use the intrinsic value method under APB Opinion 25 in accounting for stock based compensations, until adoption of SFAF 123(R). However, stock options outstanding as of the date of the merger will not be accounted for under APB 25, as those options were fully vested, and their fair value included in the cost of the business acquired as discussed above.

NOTE 18 - SUBSEQUENT EVENTS

Subsequent to September 30, 2005, the Company issued an additional 300,000 shares of its common stock for $435,000 upon exercise of options and warrants, and 35,492 shares upon a cashless exercise of options.

F-27