Edgar Filing: MILLER PETROLEUM INC

U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10-KSB

x Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended April 30, 2006

¨ Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from _______ to _______

Commission File No. 033-02249-FW

MILLER PETROLEUM, INC.

(Name of small business issuer in its charter)

Tennessee	62-1028629
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)

3651 Baker Highway

Huntsville, Tennessee 37756

(Address of Principal Executive Offices)

(423) 663-9457

(Registrant’s Telephone Number, Including Area Code)

Securities Registered Under Section 12(b) of the Act: None

Securities Registered Under Section 12(g) of the Act: None

Check whether the issuer is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act.

Check whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 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 No ¨

Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B 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. ¨

The Registrant’s revenues for the fiscal year ended April 30, 2006 were $2,538,772.

The aggregate market value of the Common Stock held by non-affiliates, based on the average closing bid and asked price of the Common Stock on August 11, 2006, was $5,393,981.

There are approximately shares of common voting stock of the Registrant held by non-affiliates. On August 11, 2006 the average bid and asked price was $0.90.

As of August 11, 2006, there were 14276,856 shares of common stock outstanding.

Forward-Looking Statements

This annual report on Form 10-KSB (“Annual Report”) for the period ending April 30, 2006 (“fiscal year 2006”), contains forward-looking statements as that term is defined in the Private Securities Litigation Reform Act of 1995. These statements relate to future events or our future financial performance. In some cases, you can identify forward-looking statements by terminology such as "may", "will", "should", "expects", "plans", "anticipates", "believes", "estimates", "predicts", "potential" or "continue" or the negative of these terms or other comparable terminology. These statements are only predictions and involve known and unknown risks, uncertainties and other factors, including the risks in the section entitled "Risk Factors” that may cause our or our industry's actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by these forward-looking statements.

Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. Except as required by applicable law, including the securities laws of the United States, we do not intend to update any of the forward-looking statements to conform these statements to actual results.

Disclosure Regarding Forward-Looking Statements Included in this report are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this Form 10-KSB which address activities, events or developments which we expect or anticipate will or may occur in the future are forward-looking statements

As used in this Annual Report, the terms “we”, “us”, and “our” mean Miller Petroleum, Inc.

Glossary of Terms

We are engaged in the business of exploring for and producing oil and natural gas. Oil and gas exploration is a specialized industry. Many of the terms used to describe our business are unique to the oil and gas industry. The following glossary clarifies certain of these terms that may be encountered while reading this report:

"Bcf" means billion cubic feet, used in this annual report in reference to gaseous hydrocarbons.

"BcfE" means billions of cubic feet of gas equivalent, determined using the ratio of six thousand cubic feet of gas to one barrel of oil, condensate or gas liquids.

"Farmout" involves an entity's assignment of all or a part of its interest in or lease of a property in exchange for consideration such as a royalty.

"Gross" oil or gas well or "gross" acre is a well or acre in which we have a working interest.

"Mcf" means thousand cubic feet, used in this annual report to refer to gaseous hydrocarbons.

"McfE" means thousands of cubic feet of gas equivalent, determined using the ratio of six thousand cubic feet of gas to one barrel of oil, condensate or gas liquids.

"MMcf" means million cubic feet, used in this annual report to refer to gaseous hydrocarbons.

"MBbl" means thousand barrels, used in this annual report to refer to crude oil or other liquid hydrocarbons.

"Net" oil and gas wells or "net" acres are determined by multiplying "gross" wells or acres by our percentage interest in such wells or acres.

"Oil and gas lease" or "Lease" means an agreement between a mineral owner, the lessor, and a lessee which conveys the right to the lessee to explore for and produce oil and gas from the leased lands. Oil and gas leases usually have a primary term during which the lessee must establish production of oil and or gas. If production is established within the primary term, the term of the lease generally continues in effect so long as production occurs on the lease. Leases generally provide for a royalty to be paid to the lessor from the gross proceeds from the sale of production.

"Prospect" means a location where both geological and economical conditions favor drilling a well.

"Proved oil and gas reserves" are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Reservoirs are considered proved if economic recovery by production is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can reasonably be judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

"Proved developed oil and gas reserves" are those proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas reserves expected to be obtained through the application of fluid injection or other improved secondary or tertiary recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed recovery program has confirmed through production response that increased recovery will be achieved.

"Proved undeveloped oil and gas reserves" are those proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves attributable to any acreage do not include production for which an application of fluid injection or other improved recovery technique is required or contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

"Royalty interest" is a right to oil, gas, or other minerals that are not burdened by the costs to develop or operate the related property.

"Working interest" is an interest in an oil and gas property that is burdened with the costs of development and operation of the property.

FORM 10-KSB

FOR THE FISCAL YEAR ENDED APRIL 30. 2006

INDEX

Page

PART I

Item 1	Description of Business	6
Item 2	Description of Property	14
Item 3	Legal Proceedings	18
Item 4	Submission of Matters to a Vote of Security Holders	18

PART II

Item 5	Market for Common Equity and Related Stockholder Matters	18
Item 6	Management’s Discussion and Analysis or Plan of Operations	19
Item 7	Financial Statements	24
Item 8	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	47
Item 8A	Controls and Procedures	47
Item 8B	Other Information	47

PART III

Item 9	Directors, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of the Exchange Act	47
Item 10	Executive compensation	49
Item 11	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	50
Item 12	Certain Relationships and Related Transactions	51
Item 13	Exhibits	52
Item 14	Principal Accountant Fees and Services	53

PART I

Item 1 Description of Business

Corporate History

We were founded in 1967 by Deloy Miller, our Chief Executive Officer, as a sole proprietorship. On January 22, 1978, we were incorporated under the laws of the State of Tennessee as “Miller Contract Drilling, Inc.” We changed our name to Miller Petroleum, Inc. on January 13, 1997.

Current Business

We are actively engaged in the exploration, development, production and acquisition of crude oil and natural gas primarily in eastern Tennessee. In December 2005 we entered into a joint venture agreement with Wind City Oil & Gas, LLC (“Wind City”) to form Wind Mill Oil & Gas, LLC (the “Wind Mill Joint Venture”). We own 49.9% of the Wind Mill Joint Venture and Wind City owns 50.1%. We contributed approximately 43,000 acres, which we held under lease in Tennessee, to the Wind Mill Joint Venture for oil and gas exploration, development and exploitation of undeveloped wells. The joint venture will only encompass new drilling projects. We retained our working interest in the developed and producing wells located on such leases. In connection with the development of wells by the Wind Mill Joint Venture, we will also receive revenue for providing labor and equipment.

Principal Products or Services and Markets

The principal markets for our crude oil and natural gas are refining companies, utility companies and private industry end users. Direct purchases of our crude oil are made statewide at our well sites by South Kentucky Purchasing Company, a refinery located in Somerset, Kentucky (“South Kentucky Purchasing”).

Our natural gas has multiple markets throughout the eastern United States through gas transmission lines. Access to these markets is presently provided by four companies in North-Eastern Tennessee. Cumberland Valley Resources (“CV Resources”) purchases our natural gas that is produced from the "Delta Leases." Nami Resources Company (“Nami Resources”) purchases our gas from the Jellico West field and Tengasco services the Swan Creek production. Local markets in Tennessee are served by Citizens Gas Utility District (‘Citizens Gas”) and the Powell Clinch Utility District. Surplus gas is placed in storage facilities or transported to East Tennessee Natural Gas which serves Tennessee and Virginia.

We anticipate that our products will be sold to the aforementioned companies; however, no assurance can be given that we will be able to make such sales or that if we do, we will be able to receive a price that is sufficient to make our operations profitable.

Distribution Methods of Products or Services

Crude oil is stored in tanks at the well site until the purchaser retrieves it by tank truck. Natural gas is delivered to the purchaser via gathering lines into the main gas transmission line.

Competitive Business Conditions

Our oil and gas exploration activities in Tennessee are undertaken in a highly competitive and speculative business environment. In seeking any other suitable oil and gas properties for acquisition, we compete with a number of other companies located in Tennessee and elsewhere, including large oil and gas companies and other independent operators, many with greater financial resources than us.

At the local level, we have several competitors in the areas of the acreage which we have under lease in the State of Tennessee, five of which may be deemed to be significant. These are Consol Energy, Inc., Can Argo Energy Corporation (“CNR”), Champ Oil, John Henry Oil and Tengasco. These companies are in competition with us for oil and gas leases in known producing areas in which we currently operate, as well as other potential areas of interest.

Although, our management generally does not foresee difficulties in procuring logging, cementing and well treatment services in the area of our operations, several factors, including increased competition in the area, may limit the availability of logging equipment, cementing and well treatment services in the future. If such an event occurs, it may have a significant adverse impact on the profitability of our operations.

The prices of our products are controlled by the world oil market and the United States natural gas market; thus, competitive pricing behaviors in this regard are considered unlikely; however, competition in the oil and gas exploration industry exists in the form of competition to acquire the most promising acreage blocks and obtaining the most favorable prices for transporting the product.

Dependence on One or a Few Major Customers

We are dependent on local purchasers of hydrocarbons to purchase our products in the areas where our properties are located. The loss of one or more of our primary purchasers may have a substantial adverse impact on our sales and on our ability to operate profitably.

Currently, we are selling natural gas to the following purchasers:

Citizens Gas purchases natural gas from our wells in Scott County, Tennessee. Citizens is paying the Inside FERC Tn Zone 1 (Louisiana) monthly index less transportation costs. Sales to Citizens is less than 1% of our total natural gas sales.

Nami Resources purchases our gas from the Jellico Field. The sales price varies each month but will not be less than $6.00 per Mcf. Sales to Nami Resources at the present time are approximately 25% of our total natural gas sales.

Tengasco purchases natural gas from wells in the Swan Creek Field. Tengasco, Inc. is paying the New York Mercantile Exchange first of the month posting plus $0.05 less transportation charges. Sales to Tengasco are about 10 % of total natural gas sales.

CV Resources purchases the gas produced from the joint venture with Delta Producers, Inc. in the Jellico East Field, Tennessee. The sales price is Appalachian Index minus Columbia transportation and fuel. Cumberland Valley Resources purchases approximately 20% of total natural gas sales.

PCUD purchases the gas from the Lindsay Land Company lease which is another joint venture with Delta Producers. The sales price is Inside FERC Tn Zone 1 (Louisiana) monthly index less transportation costs. About 44% of our gas sales are to the PCUD.

South Kentucky Purchasing purchases all of our crude oil. South Kentucky Purchasing’s purchase price is based on postings for the Illinois Basin less $2.50.

Patents, Trademarks, Licenses, Franchises, Concessions, Royalty Agreements or Labor Contracts

Royalty agreements relating to oil and gas production are standard in the industry. The amounts of the royalty payments which we receive varies from lease to lease. (See Description of Business - “Current Business” in this Annual Report.)

Governmental Approval and Regulation

The production and sale of oil and gas are subject to regulation by federal, state and local authorities. None of the principal products that we offer require governmental approval, although permits are required for the drilling of oil and gas wells.

Our sales of natural gas are affected by intrastate and interstate gas transportation regulation. Beginning in 1985, the Federal Energy Regulatory Commission (“FERC”), which sets the rates and charges transportation and sale of natural gas, adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. The stated purpose of FERC’s changes are to promote competition among the various sectors of the natural gas industry. In 1995, FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas by pipeline. Every five years, FERC will examine the relationship between the change in the applicable index and the actual cost changes experienced by the industry. We are not able to predict with certainty what effect, if any, these regulations will have on us.

Tennessee law requires that we obtain state permits for the drilling of oil and gas wells and to post a bond with the Tennessee Gas and Oil Board (the “Oil and Gas Board”) to ensure that each well is reclaimed and properly plugged when it is abandoned. The reclamation bonds cost $1,500 per well. The cost for the plugging bonds are $2,000 per well or $10,000 for ten wells. Currently, we have several of the $10,000 plugging bonds. For most of the reclamation bonds, we have deposited a $1,500 Certificate of Deposit with the Oil and Gas Board.

The state and regulatory burden on the oil and natural gas industry generally increases our cost of doing business and affects our profitability. While we believe we are presently in compliance with all applicable federal, state and local laws, rules and regulations, continued compliance (or failure to comply) and future legislation may have an adverse impact on our present and contemplated business operations. Because such federal and state regulation are amended or reinterpreted frequently, we are unable to predict with certainty the future cost or impact of complying with these laws.

Research and Development

We did not incur any research and development expenditures during the fiscal year ended April 30, 2006.

Environmental Compliance

We are subject to various federal, state and local laws and regulations governing the protection of the environment, such as the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”), and the Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), which affect our operations and costs. In particular, our exploration, development and production operations, our activities in connection with storage and transportation of oil and other hydrocarbons and our use of facilities for treating, processing or otherwise handling hydrocarbons and related wastes may be subject to regulation under these and similar state legislation. These laws and regulations:

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

impose substantial liabilities for pollution resulting from our operations.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties or the imposition of injunctive relief. Changes in environmental laws and regulations occur regularly, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those in the oil and natural gas industry in general. While we believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse impact on us, there is no assurance that this trend will continue in the future.

As with the industry generally, compliance with existing regulations increases our overall cost of business. The areas affected include:

unit production expenses primarily related to the control and limitation of air emissions and the disposal of produced water;

capital costs to drill exploration and development wells primarily related to the management and disposal of drilling fluids and other oil and natural gas exploration wastes; and

capital costs to construct, maintain and upgrade equipment and facilities.

CERCLA, also known as “Superfund,” imposes liability for response costs and damages to natural resources, without regard to fault or the legality of the original act, on some classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the “owner” or “operator” of a disposal site and entities that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the Environmental Protection Agency (“EPA”) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our ordinary operations, we may generate waste that may fall within CERCLA’s definition of a “hazardous substance.” We may be jointly and severally liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these wastes have been disposed.

We currently lease properties that for many years have been used for the exploration and production of oil and natural gas. Although we and our predecessors have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed or released on, under or from the properties owned or leased by us or on, under or from other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose actions with respect to the treatment and disposal or release of hydrocarbons or other wastes were not under our control. These properties and wastes disposed on these properties may be subject to CERCLA and analogous state laws. Under these laws, we could be required:

to remove or remediate previously disposed wastes, including wastes disposed or released by prior owners or operators;

to clean up contaminated property, including contaminated groundwater; or to perform remedial operations to prevent future contamination.

At this time, we do not believe that we are associated with any Superfund site and we have not been notified of any claim, liability or damages under CERCLA.

The Resource Conservation and Recovery Act (“RCRA”) is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements and liability for failure to meet such requirements on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because our operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.

The Clean Water Act imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. The Clean Water Act requires us to construct a fresh water containment barrier between the surface of each drilling site and the underlying water table. This involves the insertion of a seven-inch diameter steel casing into each well, with cement on the outside of the casing. The cost of compliance with this environmental regulation is approximately $10,000 per well. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans.

The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

Our operations are also subject to laws and regulations requiring removal and cleanup of environmental damages under certain circumstances. Laws and regulations protecting the environment have generally become more stringent in recent years, and may in certain circumstances impose "strict liability," rendering a corporation liable for environmental damages without regard to negligence or fault on the part of such corporation. Such laws and regulations may expose us to liability for the conduct of operations or conditions caused by others, or for acts which may have been in compliance with all applicable laws at the time such acts were performed. The modification of existing laws or regulations or the adoption of new laws or regulations relating to environmental matters could have a material adverse effect on our operations.

In addition, our existing and proposed operations could result in liability for fires, blowouts, oil spills, discharge of hazardous materials into surface and subsurface aquifers and other environmental damage, any one of which could result in personal injury, loss of life, property damage or destruction or suspension of operations. We have an Emergency Action and Environmental Response Policy Program in place. This program details the appropriate response to any emergency that management believes to be possible in our area of operations. We believe we are presently in compliance with all applicable federal and state environmental laws, rules and regulations; however, continued compliance (or failure to comply) and future legislation may have an adverse impact on our present and contemplated business operations.

The foregoing is only a brief summary of some of the existing environmental laws, rules and regulations to which our business operations are subject, and there are many others, the effects of which could have an adverse impact on our business. Future legislation in this area will no doubt be enacted and revisions will be made in current laws. No assurance can be given as to what effect these present and future laws, rules and regulations will have on our current future operations.

Insurance

Our operations are subject to all the risks inherent in the exploration for, and development and production of oil and gas including blowouts, fires and other casualties. We maintain insurance coverage customary for operations of a similar nature, but losses could arise from uninsured risks or in amounts in excess of existing insurance coverage.

Employees

We currently have 15 full-time employees.

Risk Factors

Any investment in our Common Stock involves a high degree of risk. You should carefully consider the risks and uncertainties described below and the other information included in this Annual Report before purchasing our Common Stock. Although the risks described below are the risks that we believe are material, they are not the only risks relating to our business and our Common Stock. Additional risks and uncertainties, including those that are not yet identified or that we currently believe are immaterial, may also adversely affect our business, financial condition or results of operations. If any of the events described below occur, our business and financial results could be materially and adversely affected. The market price of our Common Stock could decline due to any of these risks, perhaps significantly, and you could lose all or part of your investment.

General Risks Related To Our Business

The termination of the Wind Mill Joint Venture could have a material adverse effect on our financial condition.

On December 23, 2005 we entered into a joint venture agreement with Wind City Oil & Gas, LLC to form Wind Mill Oil & Gas, LLC to explore, drill and develop certain oil and gas properties. As part of the agreement, Wind City Oil & Gas, LLC purchased 2,900,000 common shares for $4,350,000 on December 23, 2005. The stock purchase agreement contains a put whereby Wind City Oil & Gas, LLC can put the stock back to us until September 30, 2006, thereby requiring us to repurchase the 2,900,000 shares. If this were to occur, we would have a significant cashflow shortfall, which would require additional financing arrangements and could impact our ability to continue as a going concern. There is no assurance that such financing could be obtained on favorable terms, or at all. In such event, our financial condition could be adversely affected.

Our business may fail if we do not succeed in our efforts to develop and replace oil and gas reserves.

Our future success will depend upon our ability to find, acquire and develop additional economically recoverable oil and gas reserves. Our proved reserves will generally decline as they are produced, except to the extent that we conduct revitalization activities, or acquire properties containing proved reserves, or both. To increase reserves and production, we must continue our development drilling and completion programs, identify and produce previously overlooked or bypassed zones in shut-in wells, acquire additional properties or undertake other replacement activities. Our current strategy is to increase our reserve base, production and cash flow through the development of our existing oil and gas fields and selective acquisitions of other promising properties where we can use new, existing technology. Despite our efforts, our planned revitalization, development and acquisition activities may not result in significant additional reserves, and we may not be able to discover and produce reserves at economical exploration and development costs. If we fail in these efforts, our business may also fail.

Our revenues may be less than expected if our oil and gas reserve estimates are inaccurate.

Oil and gas reserve estimates and the present values attributed to these estimates are based on many engineering and geological characteristics as well as operational assumptions that generally are derived from limited data. Common assumptions include such matters as the anticipated future production from existing and future wells, future development and production costs and the ultimate hydrocarbon recovery percentage. As a result, oil and gas reserve estimates and present value estimates are frequently revised to reflect production data obtained after the date of the original estimate. If reserve estates are inaccurate, production rates may decline more rapidly than anticipated, and future production revenues may be less than estimated. In addition, significant downward revisions of reserve estimates may hinder our ability to borrow funds in the future, or may hinder other financing arrangements that we may consider.

In addition, any estimates of future net revenues and their present value are based on period ending prices and on cost assumptions that only represent our best estimate. If these estimates of quantities, prices and costs prove inaccurate and we are unsuccessful in expanding our oil and gas reserves base, or if oil and gas prices decline or become unstable, we may have to write down the capitalized costs associated with our oil and gas assets. We will also largely rely on reserve estimates when we acquire producing properties. If we overestimate the potential oil and gas reserves of a property to be acquired, or if our subsequent operations on the property are not successful, the acquisition of the property could result in substantial losses.

We are implementing a growth strategy which, if successful, will place significant demands on us and subject us to numerous risks.

Growing businesses often have difficulty managing their growth. If our growth strategy is successful, significant demands will be placed on our management, accounting, financial, information and other systems and on our business. We will have to expand our management and continue recruiting and employing experienced executives and key employees capable of providing the necessary support. In addition, to manage our anticipated growth we will need to continue to improve our financial, accounting, information and other systems in order to effectively manage our growth, and in doing so could incur substantial additional expenses that could harm our financial results. We cannot assure you that our management will be able to manage our growth effectively or successfully, or that our financial, accounting, information or other systems will be able to successfully accommodate our external and internal growth. Our failure to meet these challenges could materially impair our business.

We may not be able to compete successfully in acquiring prospective reserves, developing reserves, marketing oil and natural gas, attracting and retaining quality personnel and raising additional capital.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry. Our inability to compete successfully in these areas could have a material adverse effect on our business, financial condition or results of operations.

A substantial or extended decline in oil and natural gas prices could reduce our future revenue and earnings.

The price we receive for future oil and natural gas production will heavily influence our revenue, profitability, access to capital and rate of growth. Oil and natural gas are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and currently oil and natural gas prices are significantly above historic levels. These markets will likely continue to be volatile in the future and current record prices for oil and natural gas may decline in the future. The prices we may receive for any future production, and the levels of this production, depend on numerous factors beyond our control. These factors include the following:

changes in global supply and demand for oil and natural gas;

actions by the Organization of Petroleum Exporting countries, or OPEC;

political conditions, including embargoes, which affect other oil-producing activities;

levels of global oil and natural gas exploration and production activity;

levels of global oil and natural gas inventories;

weather conditions affecting energy consumption;

technological advances affecting energy consumption; and

prices and availability of alternative fuels.

Lower oil and natural gas prices may not only decrease our future revenues but also may reduce the amount of oil and natural gas that we can produce economically. A substantial or extended decline in oil or natural gas prices may reduce our earnings, cash flow and working capital.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could substantially increase our costs and reduce our profitability.

Oil and natural gas exploration is subject to numerous risks beyond our control, including the risk that drilling will not result in any commercially viable oil or natural gas reserves. Failure to successfully discover oil or natural gas resources in properties in which we have oil and gas leases may materially adversely affect our operations and financial condition.

The total cost of drilling, completing and operating wells will be uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:

delays imposed by or resulting from compliance with regulatory requirements;

pressure or irregularities in geological formations;

shortages of or delays in obtaining equipment and qualified personnel;

equipment failures or accidents;

adverse weather conditions;

reductions in oil and natural gas prices;

land title problems; and

limitations in the market for oil and natural gas.

Oil and gas operations involve many physical hazards.

Natural hazards, such as excessive underground pressures, may cause costly and dangerous blowouts or make further operations on a particular well financially or physically impractical. Similarly, the testing and completion of oil and gas wells involves a high degree of risk arising from operational failures, such as blowouts, fires, pollution, collapsed casing, loss of equipment and numerous other mechanical and technical problems. Any of these hazards may result in substantial losses to us or liabilities to third parties. These could include claims for bodily injuries, reservoir damage, loss of reserves, environmental damage and other damages to people or property. Any successful claim against us would probably require us to spend large amounts on legal fees and any successful claim may make us liable for substantial damages.

Our dependence on outside equipment and service providers may hurt our profitability.

We need to obtain logging equipment and cementing and well treatment services in the area of our operations. Several factors, including increased competition in the area, may limit their availability. Longer waits and higher prices for equipment and services may reduce our profitability.

The oil and gas industry is highly competitive and there is no assurance that we will be successful in acquiring any further leases.

The oil and gas industry is intensely competitive. We compete with numerous individuals and companies, including major oil and gas companies, which have substantially greater technical, financial and operational resources and staffs. Accordingly, there is a high degree of competition for desirable oil and gas leases, suitable properties for drilling operations and necessary drilling equipment, as well as access to funds. We cannot predict if the necessary funds can be raised. There are also other competitors that have operations in our potential areas of interest and the presence of these competitors could adversely affect our ability to acquire additional leases.

If we lose the services of Deloy Miller, our operations may suffer.

We are substantially dependent upon the continued services of Deloy Miller, our CEO and a director. Mr. Miller has been with us since our inception. The relationships that he has formed in our industry and in the local area where our principal operations are conducted are invaluable, and could be lost to us without his services. Mr. Miller is in good health; however, his retirement, disability or death would seriously hurt our business operations. If his services become unavailable, we will have to retain other qualified personnel. We may not be able to recruit and hire another qualified person on acceptable terms. We do not have an employment contract with Mr. Miller. Similarly, the oil and gas exploration industry requires the use of personnel with substantial technical expertise. If our current technical personnel become unavailable, we will need to hire qualified personnel to take their place. If we are not able to recruit and hire new people on mutually acceptable terms, our operations will suffer.

Oil and gas operations are subject to comprehensive regulation which may cause substantial delays or require capital outlays in excess of those anticipated, causing an adverse effect on our Company.

Oil and gas operations are subject to federal, state, and local laws relating to the protection of the environment, including laws regulating removal of natural resources from the ground and the discharge of materials into the environment. Oil and gas operations are also subject to federal, state, and local laws and regulations which seek to maintain health and safety standards by regulating the design and use of drilling methods and equipment. Various permits from government bodies are required for drilling operations to be conducted; no assurance can be given that such permits will be received. Environmental standards imposed by federal, provincial, or local authorities may be changed and any such changes may have material adverse effects on our activities. Moreover, compliance with such laws may cause substantial delays or require capital outlays in excess of those anticipated, thus causing an adverse effect on us. Additionally, we may be subject to liability for pollution or other environmental damages. To date we have not been required to spend any material amount on compliance with environmental regulations. However, we may be required to do so in future and this may affect our ability to expand or maintain our operations.

Risks Related To Our Common Stock

The limited trading volume in our common stock may depress our stock price.

Our common stock is currently traded on a limited basis on the Over-the-Counter Bulletin Board (“OTCBB”). The quotation of our common stock on the OTCBB does not assure that a meaningful, consistent and liquid trading market currently exists. We cannot predict whether a more active market for our common stock will develop in the future. In the absence of an active trading market, investors may have difficulty buying and selling our common stock. Market visibility for our common stock may be limited. A lack of visibility of our common stock may have a depressive effect on the market price for our common stock.

The issuance of shares upon exercise of outstanding warrants may cause immediate and substantial dilution of our existing shareholders.

The issuance of shares upon exercise of warrants may result in substantial dilution to the interests of other shareholders since the selling shareholders may sell the full amount issuable on exercise. In addition, such shares would increase the number of shares in the “public float” and could depress the market price for our Common Stock.

If we fail to remain current on our reporting requirements, we could be removed from the OTC Bulletin Board which would limit the ability of broker-dealers to sell our securities and the ability of shareholders to sell their securities in the secondary market.

Companies trading on the OTCBB, such as us, must be reporting issuers under Section 12 of the Securities Exchange Act of 1934, as amended, and must be current in their reports under Section 13, in order to maintain price quotation privileges on the OTCBB. If we fail to remain current on our reporting requirements, we could be removed from the OTCBB. As a result, the market liquidity for our securities could be severely adversely affected by limiting the ability of broker-dealers to sell our securities and the ability of shareholders to sell their securities in the secondary market.

We have never declared or paid cash dividends on our Common Stock. We currently intend to retain future earnings to finance the operation, development and expansion of our business.

We do not anticipate paying cash dividends on our Common Stock in the foreseeable future. Payment of future cash dividends, if any, will be at the discretion of our board of directors and will depend on our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors that our board of directors considers relevant. Accordingly, investors will only see a return on their investment if the value of our securities appreciates.

New legislation, including the Sarbanes-Oxley Act of 2002, may make it difficult for us to retain or attract officers and directors.

We may be unable to attract and retain qualified officers, directors and members of board committees required to provide for our effective management as a result of the recent and currently proposed changes in the rules and regulations which govern publicly-held companies. The enactment of the Sarbanes-Oxley Act of 2002 has resulted in a series of rules and regulations by the Securities and Exchange Commission that increase responsibilities and liabilities of directors and executive officers. The perceived increased personal risk associated with these recent changes may deter qualified individuals from accepting these roles.

Our Common Stock is Subject to the "Penny Stock" Rules of the SEC and the Trading Market in Our Securities is Limited, Which Makes Transactions in Our Stock Cumbersome and May Reduce the Value of an Investment in Our Stock.

The Securities and Exchange Commission has adopted Rule 15g-9 which establishes the definition of a "penny stock," for the purposes relevant to us, as any equity security that has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require:

that a broker or dealer approve a person’s account for transactions in penny stocks; and

that broker or dealer receives from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.

In order to approve a person’s account for transactions in penny stocks, the broker or dealer must:

obtain financial information and investment experience objectives of the person; and

make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the Commission relating to the penny stock market, which, in highlight form:

sets forth the basis on which the broker or dealer made the suitability determination; and

that the broker or dealer received a signed, written agreement from the investor prior to the transaction.

Generally, brokers may be less willing to execute transactions in securities subject to the "penny stock" rules. This may make it more difficult for investors to dispose of our Common Stock and cause a decline in the market value of our stock.

Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissions payable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks

Item 2 Description of Property

Our executive offices presently comprise approximately 6,300 square feet on 14 acres of land in Huntsville, Tennessee that the company owns.

Oil and Gas Leases

We are an exploration and production company that utilizes seismic data, and other technologies for geophysical exploration and development of oil and gas wells. In addition to our engineering and geological capabilities, we have work-over rigs, dozers, roustabout crews and equipment to set pumping units, tanks and lay flow lines, winch trucks and trailers for traveling support, backhoes, ditchers, fusion machines and welders for pipeline and compression installation, as well as other equipment necessary to take a drilling program from the development stage to completion. The company also sells rigs, oilfield trailers, compressors and other miscellaneous oil and gas production equipment. In addition to this equipment, our Wind Mill Joint Venture has purchased a new Atlas Copco RD20 drilling rig, used RD 20 drilling rig and placed an order for two new SS185 Speed Star rigs to be delivered in December 2006.

Through the Wind Mill Joint Venture, we are presently developing leases referred to as the Koppers North Field and Carden Tract to form 10,500 contiguous acres, the Koppers South Field with 20,700 contiguous acres and the Lindsay Field with 3,400 contiguous acres. The Koppers, Carden and Lindsay Fields are in Campbell County, Tennessee. Additionally, we are developing prospects in Roane County, Tennessee to include 3,500 acres and 5,600 acres in Anderson County, Tennessee. All of these prospects are located in the Appalachian Basin. In addition to our prospects in the Appalachian Basin, drilling has been completed to a total depth of 10,873 on the Hodnett #1 prospect in Brazoria County, Texas. This well is located in the South Rowan Field.. There are no market restrictions in any of the mentioned areas.

In Roane County, the Eula Butler Et Al #1 and the Edwards - Fowler Unit # 1 has been completed . The 2850 foot zone of the Edwards has been completed in the Trenton where a 24 hour open flow test indicates natural gas flowing through a 3/8” choke at 210 psi or about 750 mcfgd. We anticipate that production on this well will begin on August 14, 2006 and that future recovery of natural gas from the Edwards will be in excess of 500 MMcf. The Stonesriver section in the Butler has not been that encouraging. We are currently considering treating the same prolific Trenton zone as in the Edwards.

Lease and Royalty Terms

The following leases are held through our Wind Mill Joint Venture. We retained our working interest in the developed and producing wells which were located on such leases as of December 23, 2005. Through the Wind Mill Joint Venture we hold half of the working interest in wells developed and producing subsequent to December 23, 2005.

Koppers Lease or "ARCO/GULF Farmout"

Located in Campbell County in Tennessee, this is the largest acreage block we have under lease. This acreage was acquired through a farmout agreement with Atlantic Richfield (“ARCO”), which has since merged into British Petroleum. We currently own a 50% working interest in approximately 27,000 acres. This lease provides for a landowner royalty of 12.5% and an overriding royalty interest of 7.5% with an 80% net royalty interest. The lease is split into two parcels. A 6,300 acre northern parcel borders the Kentucky state line and a 20,700 acre parcel borders the city of LaFollette, Tennessee. As of December 2005, there were ten producing oil wells on the southern tract of this lease, consisting of Koppers 9b, 10b, 18b, 20b, 22b, 23b, 26b, 27b, 28b, 32b The ten wells have produced 170,881 barrels of oil from the “Big Lime” Formation through April 30, 2006. The Koppers North and the Cardin tracts are producing gas from five wells in the “Devonian Shale”. An extensive gathering system is in place to transport gas to the Delta Natural Gas sales line. This lease remains in effect for as long as there is production. We have leased and are currently leasing smaller tracts of 50 to 1,000 acres adjacent to or near the Koppers South Fields acreage. We will engage in future development on this acreage through the Wind Mill Joint Venture.

Carden Tract

This lease includes 4,200 acres in which we have a 100% working interest and an 81.25% net royalty interest in wells developed and producing prior to December 23, 2005. This tract joins the Koppers North parcel of 6,300 acres to form a 10,500 acre contiguous block in the north. The Koppers North and the Cardin tracts are producing gas from five wells in the “Devonian Shale”. The lease has a three-year term with a five well drilling commitment. As of December 2005, three of these wells were drilled. Through the Wind Mill Joint Venture, the Koppers #6A, 7A and Carden #1A, 2A & 3A were all drilled on the Koppers North and Carden acreage to encompass a contiguous tract of 10,300 acres, located in Campbell County, Tennessee. These wells were drilled in a blanketed fault thickened Devonian Age Shale (Chattanooga Shale) to well depths of approximately 3200’. Production casing has been run and the wells have been stimulated. The wells have been producing since completion, with gas being sold through the Delta Natural Gas system.

Delta Producers, Inc. Joint Venture

We are continuing our joint venture with Delta Producers, Inc. of Greenville, Mississippi ("Delta Producers"). Currently, we are jointly producing ten gas wells in the Jellico, Tennessee area northwest of the Pine Mountain Thrust Fault. We have an average 33% working interest in these wells as well as interest in several oil and gas leases consisting of approximately 2,000 acres (collectively the "Delta Leases"). All of the Delta Leases are subject to a 12.5% landowner's royalty. These leases remain in effect for as long as there is production.

We have drilled nine wells with Delta Producers, the Lindsay Field #9, #10, #11, #12, #13, #14, #15, #16 and #17 wells. The #11 well may not be completed. The #17 well is currently being completed and the #16 well will be completed considering the results of #17. The remaining wells are all producing with gas being sold to the Powell-Clinch Utility District (“PCUD”), which serves the Harriman, Lake City and Lafollette, Tennessee areas. The production of gas in the Lindsay Field is from the “Big Lime” Formation. We have a 40% working interest in the Lindsay Field lease. The lease also provides for a landowner’s royalty of 12.5%. With Delta Producers, we purchased and built more than four miles of three-inch and four-inch gathering lines to carry the gas to the market. This lease remains in effect for as long as there is production.

	Date Began	Amount of Natural
	Sales of	Gas Sold as of
Well #	Natural Gas	April 30, 2006 (Mcf)
9	03/02	104,186
10	01/03	32,709
11	*	*
12	03/02	217,969
13	08/03	47,993
14	08/03	32,466
15	11/03	29,011
16	*	*
17	*	394

* This well is awaiting completion.

Harriman Prospect Joint Venture

The Harriman Prospect Joint Venture includes several small leases in Roane County, Tennessee with a total acreage of approximately 3,500 acres. The net royalty interest is 87.5% with the landowners receiving a 12.5% royalty. We have a 50% working interest in these leases. There are several smaller leases that expire at different times. When drilled, as in the Butler and Edwards wells, they will be held by production. We will engage in future development on this prospect through our Wind Mill joint Venture

Additional Oil and Gas Leases and Wells

We have several small leases in Campbell, Fentress, Morgan and Overton Counties in Tennessee totaling approximately 2,500 acres. Each of these leases is subject to a 12.5% to 20% landowner's royalty. As of April 30, 2006 there were eight producing oil wells and eight producing natural gas wells on these leases that have produced 175,789 barrels of oil and 796,233 Mcf of natural gas.

Oil and Gas Reserve Analyses

Our estimated net proved oil and gas reserves and the present value of estimated cash flows from those reserves are summarized below. The reserves were estimated by Netherland Sewell and Associates, Inc., independent petroleum engineers, in accordance with regulations of the Securities and Exchange Commission, using market or contract prices at the end of each of the years presented in the consolidated financial statements. These prices were held constant over the estimated life of the reserves.

Ownership interests in estimated quantities of proved oil and gas reserves and changes in net proved reserves, all of which are located in the continental United States, are summarized below for each of the years presented in the consolidated financial statements.

	Oil (Bbls)			Gas (Mcf)
Proved reserves
Balance, April 30, 2004		350,936			8,696,519
Discoveries and extensions		35,400			220,000
[Revisions of previous estimates]		(284,979	)		(7,592,419	)
Production		(7,532	)		(74,534	)

Balance April 30, 2005		93,825			1,249,566
Discoveries and extensions		-			73,980
[Revision of previous estimates]		3,084			10,695
Production		(5,630	)		(60,914	)

Balance April 30, 2006		91,279			1,273,327

Proved developed producing reserves at April 30, 2006		58,188			686,580

Proved developed producing reserves at April 30, 2005		60,734			697,916

Our standardized measure of discounted future net cash flows from our estimated proved oil and gas reserves is provided for the financial statement user as a common base for comparing oil and gas reserves of enterprises in the industry and may not represent the fair market value of our oil and gas reserves or the present value of future cash flows of equivalent reserves due to various uncertainties inherent in making these estimates. Those factors include changes in oil and gas prices from year-end prices used in the estimates, unanticipated changes in future production and development costs and other uncertainties in estimating quantities and present values of oil and gas reserves.

The following table presents the standardized measure of discounted future net cash flows from our ownership interests in proved oil and gas reserves as of the end of each of the years presented in the consolidated financial statements. The standardized measure of future net cash flows as of April 30, 2006 and 2005 are calculated using weighted average process in effect as of those dates. Those prices were $6.94 and $6.75 respectively, per Mcf of natural gas, and $61.75 and $44.50 respectively, per barrel of oil. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the estimated proved reserves based on year-end cost levels. Future income taxes are based on year-end statutory rates, adjusted for any operating loss carry forwards and tax credits. The future net cash flows are reduced to present value by applying a 10% discount rate.

Standardized measures of discounted future net cash flows at April 30, 2006 and 2005 are as follows:

	2006			2005
Future cash flows	$	14,470,000		$	12,747,600
Future production costs and taxes		(1,898,000	)		(1,939,000	)
Future development costs		(568,100	)		(745,000	)
Future income tax expense		(3,721,209	)		(3,119,716	)
Future cash flows		8,282,691			6,943,884
Discount at 10% for timing of cash flows		(4,199,324	)		(3,463,248	)
Discounted future net cash flows from proved reserves	$	4,083,367		$	3,480,636

Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table summarized the changes in the standardized measure of discounted future net cash flows from estimated production of our proved oil and gas reserves after income taxes for each of the years presented in the consolidated financial statements.

The following table sets forth the changes in the standardized measure of discounted future net cash flows from proved reserves for April 30, 2006 and 2005.

	April 30,
	2006			2005
Balance, beginning of year	$	3,480,636		$	23,149,947
Sales, net of production costs and taxes		(721,440	)		(784,409	)
Changes in prices and production costs		1,484,124			7,490,059
Revisions of quantity estimates		264,640			(39,206,898	)
Development costs incurred		176,900			3,995,000
Net changes in income taxes		(601,493	)		8,836,937
Balances, end of year	$	4,083,367			3,480,636

The reserves presented in this Report were evaluated in accordance with Rule 4-10 of Regulation S-X promulgated by the Securities and Exchange Commission (“SEC”).

Item 3 Legal Proceedings

None.

Item 4 Submission of Matters to a Vote of Security Holders

No proposals were submitted for approval by our shareholders during the fourth quarter ended April 30, 2006.

PART II

Item 5 Market for Common Equity and Related Stockholder Matters

Market Information

Our common stock is quoted on the National Association of Securities Dealers Over-the-Counter Bulletin Board (“OTCBB”) under the symbol “MILL.” The following quotations, obtained from National Quotation Bureau, reflect the high and low bids for our shares for the periods indicated and are based on inter-dealer prices, without retail mark-up, mark-down or commission and may not represent actual transactions.

	Bid Prices ($)
	High		Low
Quarter Ended:

July 31, 2005		1.45		1.20
October 31, 2005		1.24		1.10
January 31, 2006		1.30		1.30
April 30, 2006		1.02		1.00

July 31, 2004		1.01		1.01
October 31, 2004		0.45		0.38
January 31, 2005		0.38		0.38
April 30, 2005		0.90		0.90

Holders

There were approximately 385 stockholders of record of our common stock as of April 30, 2006.

Dividends

We have not paid or declared any cash dividends to date and do not anticipate paying any in the foreseeable future. There are no present restrictions that limit our ability to pay dividends or that are likely to do so in the future. We intend to retain earnings, if any, to support the growth of our business.

Shares Issuable Under Equity Compensation Plans

The table below provides information, as of April 30, 2006, concerning securities authorized for issuance under equity compensation plans.

Plan category	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 reflected in column (a))
	(a)	(b)	(c)
Equity compensation plans approved by shareholders	--	--	--
Equity compensation plans not approved by shareholders	150,000	0.8142	--
Total	150,000	0.8142	--

Recent Sales of Unregistered Securities

None.

Share Repurchases

None.

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

Introduction

The following discussion is intended to facilitate an understanding of our business and results of operations and includes forward-looking statements that reflect our plans, estimates and beliefs. It should be read in conjunction with our audited consolidated financial statements and the accompanying notes to the consolidated financial statements included herein. Our actual results could differ materially from those discussed in these forward-looking statements.

Overview

We are actively engaged in the exploration, development, production and acquisition of crude oil and natural gas primarily in eastern Tennessee. In December 2005, we entered into a joint venture agreement with Wind City Oil & Gas, LLC (“Wind City”) to form Wind Mill Oil & Gas, LLC (the “Wind Mill Joint Venture”). We own 49.9% of the Wind Mill Joint Venture and Wind City owns 50.1%. We contributed approximately 43,000 acres, which we held under lease in Tennessee, to the Wind Mill Joint Venture for oil and gas exploration, development and exploitation of undeveloped wells. Wind City contributed $10,000,000. The joint venture will only encompass new drilling projects. We retained our working interest in the developed and producing wells located on such leases. In connection with the development of wells by the Wind Mill Joint Venture, we will also receive reimbursement for certain salaried employees and revenue for providing labor and equipment. Including the leases that were contributed to the Wind Mill Joint Venture, we have approximately 50,000 acres under lease. About 90% of such leases are held by production.

Most of our current oil and gas production is from the Big Lime Formation. However, there are more than 160 development drilling locations that target the Devonian (Chattanooga Shale) as well as the Big Lime Formation. We completed the drilling and fracing of the first five wells on Koppers North and Carden Prospect in Campbell County, Tennessee, which consist of, the Koppers 6A and 7A and the Carden 1A, 2A and 3A. The wells have been drilled to approximately 3,000 feet in depth to fully penetrate a thickened Devonian Shale, with up to 828 feet of potential hydrocarbon entry. Gathering lines have been installed and the wells are producing approximately 200 Mcf per month.

In June 2001, we made a conventional Big Lime gas discovery, on the Lindsay Land Company lease that we jointly own with Delta Producers, Inc. There are currently seven producing wells on the property. Two wells were drilled in June 2005, the Lindsay #16 and #17. These wells fully penetrated the Big Lime and Devonian Shale to depths of approximately 4,700 feet. The Lindsay #17 has been foam fraced in the Devonian Shale the Big Lime. The wells are producing approximately 2,000 Mcf per month. There are at a minimum twenty-three additional drill sites on this 3,400 acre lease which is situated near Caryville, Tennessee. The balance of this lease was assigned to the Wind Mill Joint Venture.

On January 5, 2006, we drilled the Edwards/Fowler #1 gas well to 4,632 feet. This well is the first well to be drilled under the Wind Mill Joint Venture pursuant to which Wind Mill Oil & Gas, LLC will have a 25% net interest in the wells, of which we will own 49.9%. In early June 2006 a twelve hour test produced gas flow at a rate of 1,127 Mcf per day. The well will be attached to the Powell-Clinch gas line and is expected to begin producing at 200 to 250 Mcf per day. An additional well will be drilled on this lease in August 2006.

In May 2006 the Wind Mill Joint Venture drilled the Hodnett #1 Prospect in Brazoria County, Texas to a total depth of 10,873 ft. Production casing has been run to produce natural gas from 9,130 ft and oil from 8,600 ft and 8,800 ft zones. The well is still being tested and its status is not certain at this time.

In July 2006 the Wind Mill Joint Venture drilled three wells on Koppers South. All three wells were deemed to be commercial wells and the Koppers 38B drilled to 3,600 ft has confirmed an open flow test of 720 Mcf of natural gas per day. We are continuing to drill additional wells to prepare for production and to determine the size of the field. To market the gas from the Koppers South field, a six mile, six inch gas pipeline must be constructed to tie into the Powell-Clinch pipeline. Approximately 90% of the right-of-ways for this pipeline have been acquired and construction is expected to be completed by December 2006.

In July 2006 two wells were drilled to 3,800 ft on the Lake City lease in Anderson County, Tennessee. The early tests on these wells indicate that these wells may not be commercial wells.

We are continuing our leasing efforts in the Eastern Tennessee portion of the Eastern Overthrust Belt, which runs from Eastern Canada through Appalachia into Alabama. Acreage is being leased there in selected areas, which will be a part of the Wind Mill Joint Venture.

Results of Operations

For the Fiscal Year Ended	Increase /
	April 30				(Decrease)
	2006		2005		2005 to 2006
REVENUES

Oil and gas revenue	$	810,607	$	784,409	$	26,198
Service and drilling revenue		1,728,165		245,627		1,482,538

Total Revenue		2,538,772		1,030,036		1,508,736

COSTS AND EXPENSES

Cost of oil and gas revenue		89,167			177,287			(88,120	)
Cost of service and drilling revenue		1,523,376			82,730			1,440,646
Selling, general and administrative		1,911,739			341,587			1,570,152
Salaries and wages		161,583			262,453			(100,870	)
Plugged and abandoned wells		624,255			624,255
Depreciation, Depletion and amortization		376,461			366,279			10,182

Total Costs and Expenses		4,686,581			1,230,336			3,456,245

INCOME (LOSS) FROM OPERATIONS		(2,147,809	)		(200,300	)		(1,947,509	)

OTHER INCOME (EXPENSE)

Interest income		959			875			84
Gain on sale of equipment		157,562			(157,562	)
Interest expense and financing cost		(1,443,084	)		(219,561	)		(1,223,523	)

Total Other Income (Expense)		(1,442,125	)		(61,124	)		(1,381,001	)

NET INCOME (LOSS)	$	(3,589,934	)	$	(261,424	)	$	(3,328,510	)

Revenue

Oil and gas revenue was $810,607 for the year ended April 30, 2006 as compared to $784,409 for the year ended April 30, 2005, an increase of $26,198. This resulted primarily from an increase in the price of oil and gas.

Service and drilling revenue was $1,728,165 for the year ended April 30, 2006 as compared to $245,627 for the year ended April 30, 2005, an increase of $1,482,538. This resulted from an increase in drilling activity with Norwest Energy, NL of Perth, Australia and Golden Triangle Energy of Houston, Texas in the amount of $1,175,000.

Cost and Expense

The cost of oil and gas revenue was $89,167 for the year ended April 30, 2006 as compared to $177,827 for the year ended April 30, 2005, a decrease of $88,660. This decrease resulted from the fact that several oil wells were rehabilitated during the year ended April 30, 2005.

The cost of service and drilling revenue was $1,523,376 for the year ended April 30, 2006 as compared to $82,730 for the year ended April 30, 2005, an increase of $1,440,646. This increase is due to the increase in drilling activities with Norwest Energy, NL of Perth, Australia and Golden Triangle Energy of Houston, Texas.

Selling, general and administrative expense was $1,911,739 for the year ended April 30, 2006 as compared to $341,587 for the year ended April 30, 2005, an increase of $1,570,152. This increase resulted from an increase in stock compensation of approximately $931,000, increased legal and professional fees of approximately $360,000, and a general increase in selling, general and administrative expense.

Salaries and wages expense was $161,583 for the year ended April 30, 2006 as compared to $262,453 for the year ended April 30, 2005, a decrease of $100,870. This decrease resulted from the addition of new employees, less cost being capitalized in lease acquisitions, and the reimbursement by Wind Mill of $276,491 of salaries during the year ended April 30, 2006.

Depreciation, depletion and amortization expense was $376,461 for the year ended April 30, 2006 as compared to $366,279 for the year ended April 30, 2005, an increase of $10,182. This increase resulted from more wells and equipment being placed into service.

There was no gain on the sale of equipment for the year ended April 30, 2006 as compared to a gain of $157,562 for the year ended April 30, 2005, a decrease of $157,562. The gain for the year ended April 30, 2005 resulted from the sale of a drilling rig. There were no sales of equipment during the year ended April 30, 2006.

Interest expense and financing cost was $1,443,084 for the year ended April 30, 2006 as compared to $219,561 for the year ended April 30, 2005, an increase of $1,223,523. This resulted from increased interest cost, loan cost, warrants and penalty warrants associated with loans.

	Average Net Production
Fiscal Year	Gas / MBTU		Sales Price / MBTU
2005		75,000	$	6.28
2006		60,914		6.94


		Average Net
Fiscal Year		Barrels of Oil		Sales Price
2005		7,500	$	40.48
2006		5,630		61.75


	2004	2005	2006
Net Productive Wells	20.20	20.20	22.84
Developed Acreage	1,480	1,480	1,840
Undeveloped Acreage	41,120	41,120	46,920
Net Productive Exploratory Wells	0	0	0
Net Dry Exploratory Wells	0.30	0.30	0.25
Net Productive Developmental Wells	1.420	1.20	2.64
Net Dry Developmental Wells	0	0	0

Liquidity

Cash used by operating activities was $1,921,555 for fiscal 2006, a reduction of $2,076,135 from cash provided by operating activities in fiscal 2005 of $154,580. Our principal source of liquidity has been oil and gas revenues, loans from related parties and directors, private placement transactions of our common stock, and participation with investors in various oil and gas wells. The increase in oil and gas prices and the fact that we have approximately 50,000 acres under lease in Tennessee enhances our ability to attract investors and to pursue joint ventures in oil and gas. This is reflected by the our entry into a convertible loan on May 9, 2005 for $4,150,000, secured by our assets which paid off most of our liabilities and provided approximately $800,000 for operations and drilling and completing oil and gas wells. Also, during May and June of 2005 we received $1,175,000 as a part of our joint venture with GTE and Norwest for the initial drilling and completion of five (5) wells.

On December 23, 2005 we entered into the Wind Mill Oil & Gas LLC Agreement (“Wind Mill”) and also sold 2,900,000 shares of common stock to Wind City Oil & Gas, LLC (“Wind City”) for $4,350,000. These funds were used to pay off the $4,150,000 of loans and to provide some working capital. Wind City also contributed $10,000,000 to Wind Mill and we contributed oil and gas leases as part of the Wind Mill agreement. For the year ended April 30, 2006 we received $276,491 of administrative salary reimbursements and revenue of $153,096 for various labor, parts and use of equipment. The continued receipt of salary reimbursements and revenue from Wind Mill is a significant factor in our cash flow as we are completing wells to obtain revenue. The anticipated completion of the pipeline for Koppers South in December 2006, should increase the sale of gas significantly.

Our long-term cash flows are subject to a number of variables including the level of production and prices as well as various economic conditions that have historically affected the oil and gas business. A material drop in oil and gas prices or a reduction in production and reserves would reduce our ability to fund capital expenditures, reduce debt, meet financial obligations and remain profitable. We operate in an environment with numerous financial and operating risks, including, but not limited to, the inherent risks of the search for, development and production of oil and gas, the ability to buy properties and sell production at prices which provide an attractive return and the highly competitive nature of the industry. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset future declines in production and proved reserves.

Item 7 Financial Statements

INDEX TO FINANCIAL STATEMENTS

Report of Independent Certified Public Accountants	25

Consolidated Balance Sheet	26-27

Consolidated Statements of Operations	28

Consolidated Statements of Stockholders' Equity	29

Consolidated Statements of Cash Flows	30

Notes to the Consolidated Financial Statements	31-46

MILLER PETROLEUM, INC.

CONSOLIDATED FINANCIAL STATEMENTS

April 30, 2006 and 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors Miller Petroleum, Inc. and Subsidiary

Huntsville, Tennessee

We have audited the accompanying consolidated balance sheets of Miller Petroleum, Inc. and its subsidiary as of April 30, 2006 and April 30, 2005 and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 consolidated financial statements are free of material misstatement. The Company has determined that it is not required to have, nor was it engaged to perform, an audit of internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Miller Petroleum, Inc. and its Subsidiary as of April 30, 2006 and 2005, and the results of its operations and cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has suffered recurring losses from operations, and $2,900,000 of the Company’s common stock is subject to a put option, which the Company does not have the current capability of funding. This raises substantial doubt about the Company’s ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ Rodefer Moss & Co, PLLC

Knoxville, Tennessee

August 15, 2006

Miller Petroleum, Inc.

Consolidated Balance Sheets

	April 30,			April 30,
	2006			2005

ASSETS

CURRENT ASSETS

Cash	$			$	$2,362
Accounts receivable		311,286			182,951
Accounts receivable - related parties		347,060
Note receivable		43,000			47,000
Inventory		97,388			67,389
Unbilled service and drilling costs		76,944
Deferred offering costs					88,842
Total Current Assets		875,678			388,544

FIXED ASSETS
Machinery		880,904			941,601
Vehicles		321,895			333,583
Buildings		315,835			313,335
Office equipment		23,028			72,549
		1,541,662			1,661,068
Less: accumulated depreciation		(782,971	)		(939,579	)

Net Fixed Assets		758,691			721,489


OIL AND GAS PROPERTIES		1,576,950			2,941,832
(On the basis of successful efforts accounting)


PIPELINE FACILITIES		193,948			206,298

OTHER ASSETS
Investment in joint venture at cost		801,319
Land		496,500			496,500
Investments		500			500
Well equipment and supplies		440,712			431,462
Cash - restricted		83,000			71,000

Total Other Assets		1,822,031			999,462

TOTAL ASSETS	$	5,227,298		$	5,257,625

See notes to consolidated financial statements.

Miller Petroleum, Inc.

Consolidated Balance Sheets

	April 30,			April 30,
	2006			2005

LIABILITIES, TEMPORARY EQUITY
AND PERMANENT STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES

Bank overdraft	$	27,253		$	-
Accounts payable - trade		305,494			330,620
Accrued expenses		43,189			224,306
Current portion of notes payable		16,636			-

Total Current Liabilities		392,572			554,926

LONG-TERM LIABILITIES

Notes payable
Related parties		-			1,673,693
Other		323,898			655,646

Total Long-Term Liabilities		323,898			2,329,339

Total Liabilities		716,470			2,884,265

TEMPORARY EQUITY
Common stock subject to put rights; 2,900,000
and 0 shares, respectively		4,350,000			-

PERMANENT STOCKHOLDERS’ EQUITY

Common Stock: 500,000,000 shares authorized
at $0.0001 par value, 11,466,856 and 9,396,856
shares issued and outstanding		1,146			939
Additional paid-in capital		6,624,683			4,495,498
Unearned compensation		(751,990	)
Accumulated deficit		(5,713,011	)		(2,123,077	)

Total Stockholders’ Equity		160,828			2,373,360


TOTAL LIABILITIES, TEMPORARY EQUITY
AND PERMANENT STOCKHOLDERS’ EQUITY	$	5,227,298		$	5,257,625

See notes to consolidated financial statements.

Miller Petroleum, Inc.

Consolidated Statements of Operations

	For the			For the
	Year Ended			Year Ended
	April 30,			April 30,
	2006			2005
REVENUES
Oil and gas revenue	$	810,607		$	784,409
Service and drilling revenue		1,728,165			245,627

Total Revenue		2,538,772			1,030,036

COSTS AND EXPENSES
Oil and gas cost		89,167			177,287
Service and drilling cost		1,523,376			82,730
Selling, general and administrative		2,073,322			604,040
Impairment loss - plugged and abandoned wells		624,255
Depreciation, depletion and amortization		376,461			366,279

Total Costs and Expenses		4,686,581			1,230,336

INCOME (LOSS)
FROM OPERATIONS		(2,147,809	)		(200,300	)

OTHER INCOME (EXPENSE)
Interest income		959			875
Gain on sale of equipment					157,562
Interest expense and financing cost		(1,443,084	)		(219,561	)

Total Other Expense		(1,442,125	)		(61,124	)

INCOME TAXES

NET LOSS	$	(3,589,934	)	$	(261,424	)


BASIC AND DILUTED LOSS PER SHARE	$	(0.33	)	$	(0.03	)

BASIC WEIGHTED AVERAGE NUMBER
OF SHARES OUTSTANDING		10,812,774			9,030,738

See notes to consolidated financial statements.

MILLER PETROLEUM, INC.

Consolidated Statements of Permanent Stockholders’ Equity

					Additional
	Common		Shares		Paid-in			Unearned			Accumulated
	Shares		Amount		Capital			Compensation			Deficit			Total


Balance April 30, 2004		8,378,856	$	838	$	4,173,998		$			$	$(1,861,653	)	$	2,313,183

Sales of restricted shares
for cash at discounts from
market for free-trading
shares		275,000		27		79,974						-			80,001

Issuance of restricted shares
for services at prevailing
discounts from market for
free trading shares
		113,000		11		42,589						-			42,600
Issuance of restricted shares for
leasehold interests in mineral rights
at prevailing discount from market
price for free-trading shares		500,000		50		105,950						-			106,000

Issuance of shares for cash		20,000		2		15,998						-			16,000

Issuance of shares for services		110,000		11		76,989						-			77,000

Net loss for the year
ended April 30, 2005		-		-		-						(261,424	)		(261,424	)


Balance April 30, 2005		9,396,856		939		4,495,498						(2,123,077	)		2,373,360

Issuance of warrants as
prepayment of financing costs						370,392									370,392

Issuance of warrants for
financing cost penalty						66,000									66,000

Issuance of shares as payment
for services		1,650,000		165		1,682,835			(751,990	)					931,010

Issuance of shares for stock
sales commission		400,000		40		459,960									460,000

Cost of stock sales						(460,000	)								(460,000	)


Exercise of warrants		20,000		2		9,998									10,000

Net loss for the year
ended April 30, 2006												(3,589,934	)		(3,589,934	)


Balance April 30, 2006		11,466,856	$	1,146	$	6,624,683		$	(751,990	)	$	(5,713,011	)	$	160,828

See notes to consolidated financial statements.

Miller Petroleum, Inc.

Consolidated Statements of Cash Flows

	April 30,			April 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(3,589,934	)	$	(261,424	)
Adjustments to Reconcile Net Loss to
Net Cash from Operating Activities:
Depreciation, depletion and amortization		376,461			393,061
Gain on sale of equipment					(157,562	)
Impairment loss - plugged and abandoned wells		624,255
Options issued in exchange for services		436,392
Common Stock issued in exchange for services		931,010			119,600
Write off offering cost		88,842
Changes in Operating Assets and Liabilities:
Accounts receivable		(475,395	)		(65,784	)
Inventory		(29,999	)		(16,478	)
Unbilled service and drilling costs		(76,944	)
Prepaid expenses					39,808
Bank overdraft		27,253
Accounts payable		(25,126	)		(4,936	)
Accrued expenses		(181,117	)		108,295

Net Cash from Operating Activities		(1,894,302	)		154,580

CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of land					15,000
Purchase of equipment		(139,106	)		(1,500	)
Purchase of oil and gas properties		(335,905	)		(386,687	)
Proceeds from sale of equipment					187,682
Increase in restricted cash		(12,000	)
Changes in note receivable		4,000			28,125

Net Cash from Investing Activities		(483,011	)		(157,380	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of stock		4,360,000			96,001
Payments on Notes Payables		(6,135,049	)		(137,716	)
Proceeds from borrowings		4,150,000			44,461

Net Cash from Financing Activities		2,374,951			2,746

NET DECREASE IN CASH		(2,362	)		(54	)

CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		2,362			2,416

CASH AND CASH EQUIVALENTS, END OF YEAR	$	-		$	2,362

See notes to consolidated financial statements.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2006 and 2005

NOTE 1 - BASIS OF PRESENTATION, LIQUIDITY AND CONTINUING OPERATIONS

a. Organization and Basis of Presentation

These consolidated financial statements include the accounts of Miller Petroleum, Inc. and the accounts of its subsidiary, Miller Pipeline Company, Inc. All inter-company balances have been eliminated in consolidation.

The Company’s principal business consists of oil and gas exploration, production and related property management in the Appalachian region of eastern Tennessee and in the state of Texas. The Company’s corporate offices are in Huntsville, Tennessee. The Company operates as one reportable business segment, based on the similarity of activities

The Company formed Miller Pipeline Corporation Inc. (“MPC, Inc.”), a wholly-owned subsidiary, to manage the construction and operation of the gathering system used to transport natural gas to market.

b. Continuing Operations

The Company has incurred recurring losses over the past several years, and 2,900,000 shares of the Company’s common stock is subject to a put provision whereby a major stockholder and joint venture partner can put the stock back to the Company if notification is given thirty (30) days prior to September 30, 2006.

As discussed further in Note 2, Wind City Oil & Gas, LLC has an unwind provision in their stock purchase agreement whereby they can put the stock back to the Company if notification is given thirty days prior to September 30, 2006. If the stockholder should exercise the put option, the Company would have to repurchase the stock for $4,350,000 (2,900,000 shares at $1.50/share). Currently, the Company does not have the financial resources to repurchase the stock. In the event the put is exercised, the Company will attempt to obtain other investors or a loan to repay Wind City Oil & Gas, LLC for the stock.

Management is taking the following steps to improve the Company’s financial performance:

The Company, through Wind Mill Oil & Gas, LLC, has made gas discoveries in the Koppers South field and needs to complete a gas pipeline to the Powell-Clinch pipeline to sell the gas. All rights-of-way except one have been acquired for the pipeline and it is expected to be completed by December 2006 or January 2007. The completion of the pipeline and the revenue from selling the gas is expected to have a positive impact on the Company’s cash flow.

The operating agreement with Wind Mill restricts the Company’s ability to enter into drilling agreements with other parties and commits all our undeveloped acreage to the Wind Mill Joint Venture. Also, the Wind Mill agreement, as currently constituted, provides for ongoing exploration and drilling, activities for which the Company realizes substantial revenues and cost reimbursements. Under the Wind Mill agreement the Company believes it has addressed its operational difficulties, and the Company would expect to structure any future joint ventures in replacement of Wind Mill so that the Company’s future operations were similarly addressed. The Company has received a number of requests to participate in other drilling ventures, and in the event the put is exercised the Company will pursue other joint ventures.

However, if substantial losses continue or if we are unable to raise sufficient additional capital through debt and equity offerings, liquidity problems will cause us to curtail operations, liquidate or sell assets or entities or pursue other actions that could adversely affect future operations. These factors raise substantial doubt about our ability to continue as a going concern. These financial statements do not include any adjustments that could be required if the company was unable to continue as a going concern.

c. Accounting Method

The Company follows the successful efforts method of accounting for its oil and gas activities. Accordingly, costs associated with the acquisition, drilling and equipping of successful exploratory wells are capitalized. Geological and geophysical costs, delay and surface rentals and drilling costs of unsuccessful exploratory wells are charged to expense as incurred. Costs of drilling development wells are capitalized. Upon the sale or retirement of oil and gas properties, the cost thereof and the accumulated depreciation or depletion are removed from the accounts and any gain or loss is credited or charged to operations.

Depreciation, depletion and amortization of capitalized costs of proved oil and gas properties is provided on a pooled basis using the units-of-production method based upon proved reserves. Acquisition costs of proved properties are amortized by using total estimated units of proved reserves as the denominator. All other costs are amortized using total estimated units of proved developed reserves.

Pipeline and facilities are stated at original cost. Depreciation of pipeline and facilities is provided on a straight-line basis over the estimated useful life of the pipeline of forty years.

d. Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of

SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” requires that an asset be evaluated for impairment when the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flows of the asset. In accordance with the provisions of SFAS 144, the Company reviews the carrying values of its long-lived assets whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets we grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The long-lived assets of the Company, which are subject to evaluation, consist primarily of oil and gas properties. For the year ended April 30, 2006 the Company expensed $624,255 for impairment in connection with its assessment of remaining properties following the assignment of leases to Wind Mill Oil & Gas, LLC as discussed in Note 2.

e. Net earnings (loss) per share:

The Company presents “basic” earnings (loss) per share and, if applicable, “diluted” earnings per share pursuant to the provisions of Statement of Financial Accounting Standards No. 128, “Earnings Per Share” Basic earnings (loss) per share is calculated by dividing net income or loss by the weighted average number of common shares outstanding during each period. The calculation of diluted earnings per share is similar to that of basic earnings per share, except that the denominator is increased to include the number of additional common shares that would have been outstanding if all potentially dilutive common shares, such as those issuable upon the exercise of stock options and warrants, were issued during the period.

Since the Company had a net loss for the years ended April 30, 2006 and 2005, the assumed effects of the exercise of the options and warrants to purchase 1,550,000 and 540,000 shares of common stock that were outstanding at April 30, 2006 and 2005, respectively, and the application of the treasury stock method would have been anti-dilutive. Therefore, there are no diluted per share amounts in the 2006 and 2005 statements of operations.

f. Cash Equivalents

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

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2006 and 2005

NOTE 1 - BASIS OF PRESENTATION, LIQUIDITY AND CONTINUING OPERATIONS (Continued)

g. Principles of Consolidation

The consolidated financial statements include the accounts of the Company, and its wholly-owned subsidiary MPC, Inc. All significant intercompany transactions have been eliminated.

h. Fixed Assets

Fixed assets are stated at cost. Depreciation and amortization are computed using the straight-line method for financial reporting purposes and accelerated methods for income tax purposes. The estimated useful lives are as follows:

		Lives
Class		(Years)
Building		40
Machinery and equipment		5-20
Vehicles		5-7
Office equipment		5

Depreciation expense for the years ended April 30, 2006 and 2005 was $101,248 and $120,419 respectively.

i. Revenue Recognition

Oil and gas production revenue is recognized as income as production is extracted and sold. Service and drilling income is recognized at the time it is both earned and we have a contractual right to receive the revenue. Turnkey contracts not completed at year end are reported on the completed contract method of accounting. There were no uncompleted contracts at the end of fiscal 2006 and 2005. Retail sales of various parts and equipment is immaterial for the years ended April 30, 2006 and 2005 and has been combined with service and drilling revenue.

j. Concentrations of Credit Risk

Financial instruments which potentially subject the Company to concentrations of credit risk are primary cash and cash equivalents and accounts receivable. The Company places its cash investments, which at times may exceed federally insured amounts, in highly rated financial institutions.

Accounts receivable arise from sales of gas and oil, equipment and services. Credit is extended based on the evaluation of the customer’s creditworthiness, and generally collateral is not required. Accounts receivable more than 45 days old are considered past due. The Company does not accrue late fees or interest income on past due accounts. Management uses the aging of accounts receivable to establish an allowance for doubtful accounts. Credit losses are written off to the allowance at the time they are deemed not to be collectible. Credit losses have historically been minimal and within management’s expectations. The allowance for doubtful accounts was $5,183 and $6,944 at April 30, 2006 and 2005, respectively. Accounts receivable more than 90 days old were $58,503 at April 30, 2006 and $ 32,498 at April 30, 2005. Bad debt expense for the year ended April 30, 2006 was $14,659

k. Inventory

Inventory consists primarily of crude oil in tanks and is carried at market value.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2006 and 2005

NOTE 1 - BASIS OF PRESENTATION, LIQUIDITY AND CONTINUING OPERATIONS (Continued)

l. Well Equipment and Supplies

Well equipment represent equipment held by the Company and is carried at salvage value. When well equipment is acquired by the Company in basket purchases, the cost is applied only to the marketable portion of the equipment.

m. Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported on the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The most significant assumptions are for asset retirement obligation liabilities and estimated reserves of oil and gas. Oil and gas reserve estimates are developed from information provided by the Company’s management to Netherland Sewell and Associates, Inc., of Dallas Texas (“NSAI”) for the years ended April 30, 2006 and 2005, respectively. In 2005, management’s estimate of its proved reserves was revised downward from approximately 350,000 barrels of oil to about 94,000, and its proved reserves estimates for natural gas were revised from about 8,700,000 thousand cubic feet (“Mcf”) to about 1,200,000 Mcf. This revision was the result primarily of NSAI’s reclassification of proved reserves to probable and possible reserves. While reserves are not reflected on the Company’s balance sheet, the revision in estimate did affect the 2005 depletion expense associated with its oil and gas properties, which is calculated on the basis of proved reserves only. The change was accounted for as a revision in an estimate, and the effect on net income was approximately $160,000 or $0.02 per basic diluted share of common stock.

n. Reclassifications

Certain amounts and balances pertaining to the April 30, 2005 financial statements have been reclassified to conform with the April 30, 2006 financial statement presentations.

o. Stock Warrants

The Company measures its equity transactions with non-employees using the fair value based method of accounting prescribed by Statement of Financial Accounting Standards No. 123. The Company continues to use the intrinsic value approach as prescribed by APB Opinion No. 25 in measuring equity transactions with employees.

p. Income Taxes

The Company accounts for income taxes using the “asset and liability method.” Accordingly, deferred tax liabilities and assets are determined based on the temporary differences between the financial reporting and tax basis of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse. Deferred tax assets arise primarily from net operating loss carry forwards. Management evaluates the likelihood of realization of such assets at year-end reserving any such amounts not likely to be recovered in future periods.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2006 and 2005

NOTE 1 - BASIS OF PRESENTATION, LIQUIDITY AND CONTINUING OPERATIONS (Continued)

q. Recent Accounting Pronouncements

In March 2004, The Emerging Issues Task Force (“EITF”) reached a consensus that mineral rights, as defined in EITF Issue No. 04-02, “Whether Mineral Rights are Tangible or Intangible Asset,” are tangible assets and that they should be removed as examples of intangible assets in SFAS Nos. 141 and 142. The FASB has recently ratified this

consensus and directed the FASB staff to amend SFAS Nos. 141 and 142 through the issuance of FASB Staff Positions FSP FAS 141-1 and FSP FAS 142-1. Historically the Company has included the cost of such mineral rights as tangible assets, which is consistent with the EITF’s consensus. As such, EITF 04-02 did not affect the Company’s consolidated financial statements.

Effective February 1, 2006, the Company adopted the fair value recognition provisions of Statement of Financial Accounting Standard 123(R) “Share-Based Payment” (“SFAS 123R”) using the modified prospective transition method. In addition, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 107 “Share-Based Payment” (“SAB 107”) in March, 2005, which provides supplemental SFAS 123R application guidance based on the views of the SEC. Under the modified prospective transition method, compensation cost recognized in the fiscal year ended April 30, 2006 includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of February 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (b) compensation cost for all share-based payments granted beginning February 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS 123R. Expected pre-vesting forfeitures were estimated based on actual historical pre-vesting forfeitures over the most recent years ending April 30, 2006 for the expected option term. In accordance with the modified prospective transition method, results for prior periods have not been restated. The adoption of SFAS 123R resulted in no material stock compensation expense for the year ended April 30, 2006.

Prior to the adoption of SFAS 123R, the Company presented any tax benefits of deductions resulting from the exercise of stock options within operating cash flows in the condensed consolidated statements of cash flow. SFAS 123R requires tax benefits resulting from tax deductions in excess of the compensation cost recognized for those options (“excess tax benefits”) to be classified and reported as both an operating cash outflow and a financing cash inflow upon adoption of SFAS 123R. As a result of the Company’s net operating losses, the excess tax benefits that would otherwise be available to reduce income taxes payable have the effect of increasing the Company’s net operating loss carry forwards. Accordingly, because the Company is not able to realize these excess tax benefits, such benefits have not been recognized in the condensed statement of cash flow for the quarterly period ended June 30, 2006.

In April 2005, the FASB issued Staff Interpretation No. 19-1 FSP FAS 19-1 (“FSP 19-1”) “Accounting for Suspended Well Costs,” which provides guidance on the accounting for exploratory well costs and proposes an amendment to FASB Statement No. 19 (“FASB 19”), “Financial Accounting and Reporting By Oil and Gas Producing Companies.” The guidance in FSP 19-1 applies to enterprises that use the successful efforts method of accounting as described in FASB 19. The guidance in FSP 19-1 does not impact the consolidated financial position, result of operations or cash flows.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2006 and 2005

NOTE 1 - BASIS OF PRESENTATION, LIQUIDITY AND CONTINUING OPERATIONS (Continued)

r. Major Customers

The Company depends upon local purchasers of hydrocarbon in the areas where its properties are located. The Company has three major customers. The loss of one or more purchasers may substantially reduce its sales and ability to operate profitably. These major customers are:

Delta Producers, Inc. accounted for $301,461 of the Company’s total revenue, which was about 12% of the Company’s total revenue.

Nami Resources, LLC accounted for $119,509 of the Company’s total revenue, which was about 5% of the Company’s total revenue.

South Kentucky Purchasing Co. - South Kentucky accounted for $229,963 of the Company’s total revenue, which was about 9% of the Company’s total revenue. South Kentucky purchases all of the Company’s crude oil.

Wind Mill Oil & Gas, LLC - Wind Mill accounted for $153,096 of the Company’s total revenue, which was about 6% of the company’s total revenue.

Norwest Energy, NL of Perth, Australia and Golden Triangle energy of Houston, Texas accounted for $1,175,000 of the Company’s drilling revenue.

NOTE 2 - WIND MILL OIL & GAS, LLC JOINT VENTURE

On December 23, 2005 the Company executed an LLC agreement with Wind City Oil & Gas, LLC (“Wind City”) to form Wind Mill Oil & Gas, LLC (“Wind Mill”) for the purpose of locating, producing and selling oil and gas. Wind City contributed $10,000,000 of cash and received a 50.1% interest in Wind Mill. The Company contributed approximately 43,000 acres of oil and gas leases with a stated value of $3,000,000 and a cost basis of $801,319, and received a 49.9% interest in Wind Mill.

Under the Wind Mill agreement the Company is reimbursed for administrative salaries and receives revenue for Wind Mill’s use of the Company’s production equipment and employees. For the period from December 23, 2005 to April 30, 2006 the Company received salary reimbursements of $276,491 and drilling revenue of $153,096.

Under the Wind Mill agreement Wind City is to be allocated all of the initial losses until its capital account is reduced to zero, and then will be allocated all initial profits until the profits are equal to the initial losses allocated.

The Wind Mill agreement contains a provision to unwind the LLC at the option of Wind City based on certain well results from the initial drilling. The four commercial wells drilled have exceeded the minimum requirements contained in the agreement.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2006 and 2005

NOTE 2 - WIND MILL OIL & GAS, LLC JOINT VENTURE (Continued)

In the event that the Wind Mill agreement becomes subject to the unwind provision, the Company has no responsibility for funding any losses and would receive a reassignment of the oil and gas leases transferred by the Company to Wind Mill.

As part of the Wind Mill agreement Wind City purchased 2,900,000 shares of the Company’s common stock for $1.50 per share for a total of $4,350,000. Part of the stock purchase agreement allows Wind City to put the stock back to the Company if notification is given prior to September 30, 2006. The Company would then be required to repurchase the stock for the original selling price of $4,350,000.

NOTE 3 - STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURE

	2006		2005
CASH PAID FOR:
Interest	$	364,325	$	70,990
Loan fees and cost		553,524

NON-CASH FINANCING ACTIVITIES:
Financing costs from issuance of warrants		436,392
Stock issued for mineral rights				106,000
Common stock issued for services		2,143,000		119,600
Deferred offering cost		88,842

NOTE 4 - DEFERRED OFFERING COST

Through April 30, 2004, the Company issued 85,000 shares of its common stock valued at approximately $89,000 in connection with a proposed public offering of its common stock. In June, 2004, the Company postponed its proposed public offering due to market conditions. This planned offering was abandoned upon consummation of the Wind Mill Joint Venture, and the offering costs were expensed during the year ended April 30, 2006.

NOTE 5 - OIL AND GAS PROPERTIES - PIPELINE FACILITIES

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 carrying and retaining unproved properties are expensed. The Company amortizes the oil and gas properties using the unit-of-production method based on total proved reserves. The Company capitalized $335,905 and $549,687 of oil and gas properties for the years ended April 30, 2006 and 2005, respectively, and recorded $275,213 and $245,860 of amortization expense for the years ended April 30, 2006 and 2005, respectively.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2006 and 2005

NOTE 6 - LONG-TERM DEBT

The Company had the following debt obligations at April 30, 2006 and April 30 2005


	2006		2005
Note payable to First National Bank of Oneida secured by
stock and equipment, bearing interest at 7.5%, due in
quarterly payments of $15,000 beginning January 14, 2006	$		$	$85,097

Note payable to American Fidelity Bank secured by
A trust deed on property, bearing interest at prime, due in
monthly payments of $2,500, with the final payment due in
August 2008		340,534		353,891

Line of credit payable to First National Bank of the
Cumberlands, secured by equipment and accounts
receivable, bearing interest at 10,388%, due on
October 12, 2005				16,835

Note payable to supplier secured by assignment of royalty
income from five gas wells in Campbell County, Tennessee,
interest at prime 5.75% at April 30, 2005				199,824

Note payable to related party, unsecured, interest at 7.00%
with payments due annually, with the principal due in May 2005				59,692

Note payable to related party, secured by twelve oil and gas
wells, bearing interest at 9.00% and requiring interest payments
quarterly with the principal due in December 2004				1,110,000

Note payable to related party, bearing interest at 8.00%,
with principal due in December 2005				254,000

Note payable to related party, secured by twelve oil and gas
wells, bearing interest at 9.00% and requiring interest payments
quarterly with the principal due in December 2004				250,000

Total Notes Payable	$	340,534	$	2,329,339
Less current maturities		16,636		-
Notes Payable - Long-term	$	323,898	$	2,329,339

On May 9, 2005 the Company entered into a credit agreement with Prospect Energy Corporation, Inc. (“Prospect”) and Petro Capital III, LP (“Petro”). Under the agreement, the Company received an aggregate of $4,150,000 in debt financing under two convertible promissory notes with Prospect and Petro, for $3,150,000 and $1,000,000, respectively. Proceeds from this borrowing were used to satisfy the obligations existing at April 30, 2005. Accordingly, the maturities reflected above represent the maturities of the debt entered into subsequent to April 30, 2005.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2006 and 2005

NOTE 6 - LONG-TERM DEBT (Continued)

The Prospect and Petro notes were due on June 30, 2006, with interest only payments accruing at 12% during the interim. The notes were convertible into common stock at the lesser price of $1.50 per share or the price of common stock issued to investors in a then-planned equity offering of the Company.

When the stock was sold to Wind City in December 2005 the Prospect and Petro notes were paid off.

NOTE 7 - RELATED PARTY TRANSACTIONS

At April 30, 2006 the Company has an account receivable from Wind Mill in the amount of $294,038 and an account receivable from Herman Gettlefinger, a member of the board of directors, and his wife in the amount of $53,062. The Company also received salary reimbursement and compensation from Wind Mill as discussed in Note 2.

For the year ended April 30, 2006 the Company issued, as compensation, 500,000 shares of common stock to the Company’s President, Ernest Payne, and 400,000 shares of common stock to a consultant, Scott Boruff, the son-in law of the Company’s CEO, Deloy Miller.

The Company had a note payable to Sharon Miller (wife of Deloy Miller, majority stockholder) for $59,693 at April 30, 2005. The note was payable with a principle payment of $59,693 due in May 2006. The note was the balance remaining on the original purchase of the property that houses the Company’s offices. This note was paid off in May 2005.

The Company issued notes payable of $1,110,000 and $250,000 on August 13, 2003 at 9% with a one year term to Sherri Ann Parker Lee and William Parker Lee respectively. These notes payable were issued to raise working capital. The related party notes were due to members of the Company’s board of directors or their immediate families. These notes were paid off in May 2005.

NOTE 8 - ASSET RETIREMENT OBLIGATION

In 2001, the Financial Accounting Standards Board approved the issuance of SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement requires companies to record the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. The liability is capitalized as part of the related long-lived asset's carrying amount. Over time, accretion of the liability is recognized as an operating expense and the capitalized cost is depreciated over the expected useful life of the related asset.

The changes in the Company’s liability for the years ended April 30, 2005 and 2006 as follows:

Asset retirement obligation as of April 30, 2004	$	13,306
Accretion expense for 2005		1,890
Asset retirement obligation as of April 30, 2005		15,196
Accretion expense for 2006		2,353
Asset retirement obligation as of April 30, 2006	$	17,549

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2006 and 2005

NOTE 9 - ASSET IMPAIRMENT - PLUGGED AND ABANDONED WELLS

In connection with the assignment of leases to Wind Mill as discussed in Note 2, management assessed the remaining oil and gas properties and determined that $624,222 of well and lease cost should be written off as impaired.

NOTE 10 - INCOME TAXES

The Company provides deferred income tax assets and liabilities using the liability method for temporary differences between book and taxable income.

A reconciliation of the statutory U. S. Federal income tax and the income tax provision included in the accompanying consolidated statements of operations is as follows:

	2006			2005
Current Year Addition:
Federal statutory rate	34%			34%
Federal tax benefit at statutory rate	$	1,220,000		$	89,000
State income tax, net of benefit		126,000			19,600
Stock compensation		(93,000	)
Stock warrants		(126,000	)
		1,127,000			108,600
Increase in valuation allowance		(1,127,000	)		(108,600	)

Increase in deferred tax asset and valuation allowance	$	0		$	0

Cumulative Tax Benefit:
Net operating loss carryforward	$	2,452,000		$	1,451,000
Stock warrants		126,000
Valuation allowance		(2,578,000	)		(1,451,000	)

Net deferred tax benefit	$	0		$	0

The Company recorded a valuation allowance at April 30, 2006 and 2005 equal to the excess of deferred tax assets over deferred tax liabilities, as management is unable to determine that these tax benefits are more likely than not to be realized.

The Company had available, to offset taxable income, cumulative net operating loss carry forwards arising from the periods since the year ended April 30, 1997 of approximately $7,328,000 at April 30, 2006. The carry forwards begin expiring in 2012.

NOTE 11 - STOCKHOLDERS’ EQUITY

During the year ended April 30, 2006 the Company issued 2,050,000 free-trading common shares of stock for services valued at $2,143,000 and issued 2,920,000 free-trading common shares of stock for $4,360,000 of cash. The Company also issued 1,200,000 warrants in connection with the Prospect / Petro loan at an average exercise price of $0.61 per share.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2006 and 2005

NOTE 11 - STOCKHOLDERS’ EQUITY (Continued)

During the year ended April 30, 2005, the Company issued 130,000 free trading shares of its common stock for cash and services valued at $93,000. Also during fiscal 2005, the Company sold 275,000 shares of restricted common stock in private placements for proceeds of $80,000. The sales transpired at discounts ranging from 66% to 43% from prevailing prices for free-trading shares.

Further, the Company issued 113,000 restricted shares of its common stock for leasehold interests in oil and gas properties at a discount of 60% from prevailing prices for free-trading shares.

Additionally, the Company has warrants and options outstanding from prior periods. All warrants must be adjusted in the event of any forward or reverse split of outstanding common stock. The warrants have no voting rights or liquidation preferences, unless exercised in accordance with the particular warrant.

Prior to adoption of SFAS 123R, the fair value of the options granted was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used for grants in fiscal year 2006: 50% volatility, two and a half year life, zero dividend yield, and risk-free interest rate of 4.50%.

Information regarding the options and warrants at April 30, 2006 and 2005 is as follows:

	2006			2005
	Weighted Shares		Average Exercise Price	Weighted Shares		Average Exercise Price
Options outstanding,
beginning of year	540,000	$	1.30	2,235,000	$	0.88
Options canceled	170,000		1.01	1,695,000		0.77
Options exercised	20,000		0.50	-		0.00
Options granted	1,200,000		0.61	-		0.00
Options outstanding,
end of year	1,550,000	$	0.81	540,000	$	1.30
Options exercisable,
end of year	1,550,000	$	0.81	540,000	$	0.88
Option price range,
end of year		$	0.50 to 2.00		$	0.50 to 2.00
Option price range,
exercised shares			0.50			n/a
Options available for grant
at end of year			n/a			n/a
Weighted average fair value of
options granted during the year			0.36			n/a

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2006 and 20058

NOTE 12 - CONTINGENCIES

The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control in the United States. The company cannot predict what effect future regulations or legislation, enforcement policies, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. Although no assurances can be made, the Company’s management believes that absent the occurrence of an extraordinary event, compliance with existing laws, rules and regulations regulating the release of materials in the environment or otherwise relating to the protection of the environment will not have a material effect upon the Company’s financial position.

NOTE 13 - DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amount reported on the balance sheet for cash, accounts and notes receivable, accounts payable and accrued liabilities approximates fair value because of the immediate or short-term maturity of these financial instruments. The carrying value of notes payable approximate fair value due to the settlement at carrying value of these obligations subsequent to the balance sheet date (see Note 6, Long Term Debt).

NOTE 14 - S.F.A.S. 69 SUPPLEMENTAL DISCLOSURES (Unaudited)

(1) Capitalized Costs Relating to Oil and Gas Producing Activities at April 30, 2006 and 2005 are as follows:

	2006			2005
Proved oil and gas properties and related lease equipment
Developed	$	2,776,181		$	3,841,996
Non-developed		7,199			31,053
		2,783,380			3,873,049
Accumulated depreciation and depletion		(1,206,430	)		(931,217	)
Net Capitalized Costs	$	1,576,950		$	2,941,832

(2) Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities

		2006		2005
Acquisition of Properties Proved and Unproved	$	-	$	-
Exploration Costs		-		-
Development Costs		335,905		549,687
Total	$	335,905	$	549,687

(3) Results of Operations for Producing Activities

		2006		2005
Production revenues	$	810,607	$	784,409
Production costs		89,167		177,287
Depreciation and amortization		275,313		245,860
Results of operations for producing activities
(excluding corporate overhead and interest costs)	$	446,127	$	361,262

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2006 and 2005

NOTE 14 - S.F.A.S. 69 SUPPLEMENTAL DISCLOSURES (Unaudited) (Continued)

(4) Reserve Quantity Information

The following schedule estimates proved oil and natural gas reserves attributable to the Company. Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Reserves are stated in barrels of oil (Bbls) and thousands of cubic feet of natural gas (Mcf). Geological and engineering estimates of proved oil and natural gas reserves at one point in time are highly interpretive, inherently imprecise and subject to ongoing revisions that may be substantial in amount. Although every reasonable effort is made to ensure that the reserve estimates reported represent the most accurate assessments possible, these estimates are by their nature generally less precise than other estimates presented in connection with financial statement disclosures.

	Oil (Bbls)			Gas (Mcf)
Proved reserves
Balance, April 30, 2004		350,936			8,696,519
Discoveries and extensions		35,400			220,000
Revisions of previous estimates		(284,979	)		(7,592,419	)
Production		(7,532	)		(74,534	)

Balance, April 30, 2005		93,825			1,249,566
Discoveries and extensions		-			73,980
Revisions of previous estimates		3,084			10,695
Productions		(5,630	)		(60,914	)

Balance, April 30, 2006		91,279			1,273,327

Proved developed producing
reserves at April 30, 2006		58,188			686,580

Proved developed producing
reserves at April 30, 2005		60,734			697,916

In addition to the proved developed producing oil and gas reserves reported in the geological and engineering reports, the Company holds ownership interests in various proved undeveloped properties. The reserve and engineering reports performed for the Company were by Netherland Sewell and Associates, Inc. for the years ended April 30, 2006 and April 30, 2005. Although wells have been drilled and completed in each of these four properties, certain production and pipeline facilities must be installed before actual gas production will be able to commence. The most recent development plan for these properties indicates that facilities installation and commencement of production will be in the summer of 2006. However, such timing as well as the actual financing arrangements that will be secured by the Company is uncertain at this time.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2006 and 2005

NOTE 14 - S.F.A.S. 69 SUPPLEMENTAL DISCLOSURES (Unaudited) (Continued)

The following schedule presents the standardized measure of estimated discounted future net cash flows from the Company’s proved developed reserves for the years ended April 30, 2006 and 2005. Estimated future cash flows were based on independent reserves evaluation from Netherland Sewell & Associates, Inc. for the years ended April 30, 2006 and April 30, 2005. Because the standardized measure of future net cash flows was prepared using the prevailing economic conditions existing at April 30, 2006 and 2005, it should be emphasized that such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of the Company’s recoverable reserves or in estimating future results of operations.

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using current sales prices, along with estimates of the operating costs, production taxes and future development and abandonment costs (less salvage value) necessary to produce such reserves. The average prices used at April 30, 2006 and 2005 were $61.75 and $40.75 per barrel of oil and $6.94 and $7.14 per Mcf gas, respectively. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.

Operating costs and production taxes are estimated based on current costs with respect to producing gas properties. Future development costs are based on the best estimate of such costs assuming current economic and operating conditions.

Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved.

The future net revenue information assumes no escalation of costs or prices, except for gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.

Standardized measures of discounted future net cash flows at April 30, 2006 and 2005 are as follows:

	2006			2005
Future cash flows	$	14,470,000		$	12,747,600
Future production costs and taxes		(1,898,000	)		(1,939,000	)
Future development costs		(568,100	)		(745,000	)
Future income tax expense		(3,721,209	)		(3,119,716	)
Future cash flows		8,282,691			6,943,884
Discount at 10% for timing of cash flows		(4,199,324	)		(3,463,248	)
Discounted future net cash flows
from proved reserves	$	4,083,367		$	3,480,636

Of the Company’s total proved reserves as of April 30, 2006 and 2005, approximately 57% and 59%, respectively, were classified as proved developed producing, 31% and 11%, respectively, were classified as proved developed non-producing and 12% and 30%, respectively, were classified as proved undeveloped. All of the Company’s reserves are located in the continental United States.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2006 and 2005

NOTE 14 - S.F.A.S. 69 SUPPLEMENTAL DISCLOSURES (Unaudited) (Continued)

The following table sets forth the changes in the standardized measure of discounted future net cash flows from proved reserves for April 30, 2006 and 2005.

	April 30,
	2006			2005
Balance, beginning of year	$	3,480,636		$	23,149,947

Sales, Net of production costs and taxes		(721,440	)		(784,409	)

Changes in prices and production costs		1,484,124			7,490,059
Revisions of quantity estimates		264,640			(39,206,898	)
Development costs incurred		176,900			3,995,000
Net changes in income taxes		(601,493	)		8,836,937

Balances, end of year	$	4,083,367		$	3,480,636

Item 8 Changes In and Disagreements With Accountants On Accounting and Financial Disclosure

None.

Item 8A Controls and Procedures

Disclosure Controls and Procedures. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report (the “Evaluation Date”). Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded as of the Evaluation Date that our disclosure controls and procedures were not adequate and effective to ensure that our management is alerted to material information required to be included in our periodic filings. Nevertheless, our management has determined that all matters to be disclosed in this report have been fully and accurately reported. We are in the process of improving our processes and procedures to ensure full, accurate and timely disclosure in the current fiscal year, with the expectation of establishing effective disclosure controls and procedures as soon as reasonably practicable.

Internal Control over Financial Reporting. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we are responsible for establishing and maintaining an adequate system of internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934). During our most recent fiscal year ended April 30, 2006, there were no changes in our internal control over financial reporting that have materially affected or are reasonably likely to affect, our internal control over financial reporting.

Item 8B Other Information

None.

PART III

Item 9 Directors, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of the Exchange Act

Directors and Executive Officers

The following table shows the names, ages and positions held by our executive officers, directors and significant employees.

Name	Age	Position
Deloy Miller	59	Director and Chief Executive Officer
Ernest Payne	59	President
Lyle H. Cooper	63	Chief Financial Officer
Herbert J. White	80	Vice President and Director
Gary Bible	56	Vice President of Geology
Teresa Cotton	43	Secretary and Treasurer
Charles M. Stivers	44	Director
Herman E. Gettelfinger	73	Director

Business Experience

Deloy Miller has been Chairman of the Board of Directors since December 1996, and Chief Executive Officer since December 1997. Mr. Miller is a seasoned gas and oil professional with more than 30 years of experience in the drilling and production business in the Appalachian basin. During his years as a drilling contractor, he acquired extensive geological knowledge of Tennessee and Kentucky and received training in the reading of well logs. A native Tennessean, Miller is credited with being the leader in converting the Appalachian Basin from cable tool drilling to air drilling, using the Ingersoll-Rand T3 Drillmaster rigs. The introduction of air drilling sparked the 1969 drilling boom and Miller soon became a successful drilling contractor in the southern Appalachian basin. He served two terms as president of the Tennessee Oil & Gas Association and in 1978 the organization named Miller the Tennessee Oil Man of the Year. He continues to serve on the board of that organization. Mr. Miller was appointed by the Governor of Tennessee to be the petroleum industry's representative on the Tennessee Oil & Gas Board, the state agency that regulates gas and oil operations in the state.

Ernest Payne was appointed President on in August 2003. Mr. Payne rejoined the Miller Team after serving as Project Manager and Superintendent for Youngquist Brothers of Fort Myers, Florida from early 1994 through May of 2001. Mr. Payne has 20 years experience in oil and gas well design and stimulations as well as supervising the operation of drilling and workover rigs. He earned a B.S. in engineering at Tennessee Technological University. He originally joined Miller in the early 70's and was the general manager for 17 years. He directed the operation of 18 drilling and workover rigs. In the mid 1980's he formed his own company and managed large drilling jobs in Florida and Puerto Rico until joining Youngquist.

Lyle H. Cooper was appointed Chief Financial Officer on January 20, 2006. Mr. Cooper owns a private CPA firm where since 1991 he has specialized in providing accounting, auditing, tax and SEC related services. During 2002 and 2003 he served as Secretary of aurora Lighting Inc., a leading manufacturer of electronic ballasts. In 2003 and 2004 Mr. Cooper participated as principal in an oil drilling venture in Clinton County, Kentucky.

Charles M. Stivers has been a Director since 2004. He also served as our Chief Financial Officer from 2004 until January 2006. Mr. Stivers has over 18 years accounting experience and over 12 years of experience within the energy industry. He owns and operates Charles M. Stivers, C.P.A., which specializes in the oil and gas industry and has clients located in eight different states. His responsibilities include all forms of SEC audit work, SEC quarterly financial statement filings, oil and gas consulting work, and income tax work. Mr. Stivers served as Treasurer and CFO for Clay Resource Company and Senior Tax and Audit Specialist for Gallaher and Company. He received a Bachelor of Science degree in accounting from Eastern Kentucky University.

Herbert J. White has been a Vice President and Director since April 1997. Mr. White has more than 44 years of Petroleum related experience. After earning his BS degree from North Texas University, he became an engineer with Halliburton, handling Louisiana Gulf Coast and offshore operations and serving in Australia. In 1975 he joined Petroleum Development Corporation, a West Virginia-based public company, supervising engineering and operations in Southern Appalachian basin. He also has experience in Devonian Shale production, enhanced recovery and coal degasification. Miller Petroleum and its predecessor corporation have employed Mr. White as a Petroleum Engineer since July of 1985. In April, 1997, he became a director and Vice President of Development Engineering for Miller Petroleum.

Herman Gettelfinger has been a Director since 1997. Mr. Gettelfinger is a co-owner of Kelso Oil Company, Knoxville Tennessee and has been the President of Kelso since 1960. Kelso is one of eastern Tennessee's largest distributors of motor oils, fuels and lubricants to the industrial and commercial market. Mr. Gettelfinger has been active in the gas and oil drilling and exploration business for more than 35 years and has been associated with Miller Petroleum for more than 25 years.

Dr. Gary Bible was appointed Vice President of Geology in September 1997. Dr. Bible came from Alamco, where he had served since May of 1991 as Manager of Geology and Senior Geologist. Dr. Bible earned his BS Degree in Geology from Kent State University and his Msc. and PhD. Degrees in Geology from Iowa State University. He is a proven hydrocarbon finder who drilled his first successful wildcat as a Trainee Geologist. Dr. Bible brings to the Company 20 years experience as a Petroleum Geologist. In addition, Dr. Bible has spent more than 10 years in the Appalachian Basin in the exploration and development of reserves in the Big Lime, Devonian Shale and in deeper horizons. He is credited with managing a drilling program at Alamco that kept its finding cost the lowest in the nation.

Teresa Cotton was appointed Secretary/Treasurer in December 2001. Prior to joining the Miller Team, Mrs. Cotton was employed by Halliburton Services. She has more than twenty years experience in the oil and gas industry. Mrs. Cotton, a Tennessee native, earned an A.S. in Business Administration at Roane State Community College in Huntsville, Tennessee.

Term of Office

Our officers are appointed by our board of directors and hold office until removed by the board.

Audit Committee Financial Expert

We have an audit committee consisting of Deloy Miller, Herman Gettelfinger and Charles Stivers. Our board of directors has determined that Mr. Stivers is an “audit committee financial expert” based on his qualification as a certified public accountant and his prior experience.

Compliance With Section 16(a)

We have no securities registered under Section 12 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). We file our periodic and annual reports pursuant to Section 15(d) thereof. Accordingly, our directors, executive officers and 10% stockholders are not required to file statements of beneficial ownership of securities under 16(a) of the Exchange Act.

Code of Ethics

We have adopted a Code of Conduct that applies to our President, Chief Executive Officer, Chief Accounting Officer or Controller and any other persons performing similar functions. Our Code of Conduct is attached as an exhibit to our annual report on Form 10-KSB for the year ended April 30, 2004.

Item 10 Executive Compensation

Summary Compensation Table

The following table sets forth information for the periods indicated concerning compensation paid to our Chief Executive Officer and each of our other executive officer who received the highest compensation for services rendered to us with respect to 2006.

			ANNUAL COMPENSATION			LONG TERM COMPENSATION
Name	Title	Year	Salary	Bonus	Other Annual Compen- sation	AWARDS		PAYOUTS	All Other Compen- sation
						Restricted Stock Awarded	Options/ SARs* (#)	LTIP payouts ($)
Deloy Miller	Chief Executive Officer	2006 2005 2004	$185,500 180,000 183,000	0 0 0	0 0 0	0 0 0	0 0 0	0 0 0	0 0 0

Long-Term Incentive Plan

We do not have any long-term incentive plans, pension plans, or similar compensatory plans for our directors and executive officers.

Compensation of Directors

Directors receive an annual fee for Board service of $0 as compensation as well as attendance fees of $500 for each meeting of the Board attended in person and $0 for each meeting attended by telephone.

Employment Contracts, Termination of Employment and Change in Control Arrangements

We have a three-year contract with our President beginning February 21, 2006. In connection with this contract, the President was issued 500,000 shares of common stock.

Our company has no plans or arrangements in respect of remuneration received or that may be received by named executive officers of our company in fiscal year 2006 to compensate such officers in the event of termination of employment (as a result of resignation, retirement, change of control) or a change of responsibilities following a change of control.

Item 11 Security Ownership of Certain Beneficial Owners and Management

The following table sets forth certain information concerning the number of shares of our common stock owned beneficially as of August 11, 2006 by: (i) each person (including any group) known to us to own more than five percent (5%) of our common stock, (ii) each of our directors and each of our named executive officers and (iii) officers and directors as a group.

The number and percentage of shares beneficially owned is determined in accordance with Rule 13d-3 of the Securities Exchange Act of 1934, and is not necessarily indicative of beneficial ownership for any other purpose. Shares of Common Stock that a person has a right to acquire within 60 days are deemed outstanding for purposes of computing the percentage ownership of that person, but are not deemed outstanding for purposes of computing the percentage ownership of any other person, except with respect to the percentage ownership of all directors and executive officers as a group. We based our calculations of the percentage owned on 14,366,856 shares outstanding on August 11, 2006.

Except as otherwise indicated, each director and named executive officer (1) has sole investment and voting power with respect to the securities indicated or (2) shares investment and/or voting power with that individual’s spouse. The address of each director and named executive officer listed in the table below is c/o Miller Petroleum, Inc. 3651 Baker Highway, Huntsville, Tennessee 37756.

Name of Beneficial Owner	Amount and Nature of Beneficial Ownership		Percent of Class
*Directors and Officers*
Deloy Miller	4,090,343		28.5%
Ernest Payne	605,000	⁽¹⁾	4.2%
Charles M. Stivers	20,000		*
Herman E. Gettelfinger	342,901	⁽²⁾	2.4%
Herbert J. White	300		*
All directors and executive officers (6 persons)	5,058,544	⁽³⁾	34.9%

*Beneficial Owner of More Than 5%*
Prospect Energy Corporation	781,805⁽⁴⁾		5.16%
Wind City Oil & Gas LLC	2,900,000		16.8%

_________

* Represents less than 1% of our outstanding common stock.

(1) Includes 75,000 shares issuable upon the exercise of presently exercisable stock options.

(2) Includes 50,000 shares issuable upon the exercise of presently exercisable stock options and 100,000 shares held by Mr. Gettelfinger’s spouse.

(3) Includes 125,000 shares issuable upon the exercise of presently exercisable stock options.

(4) Represents 781,805 shares issuable upon the exercise of presently exercisable warrants.

Item 12 Certain Relationships and Related Transactions

On September 8, 2005, we agreed to issue 400,000 shares of Common Stock to Scott Boruff (son-in-law of Deloy Miller, our Chief Executive Officer), in consideration of consulting services.

The Company had a note payable to Sharon Miller (wife of Deloy Miller, our Chief Executive Officer) for $56,693 at July 31, 2005 for the balance remaining on the original purchase of the property which houses our executive offices. This note was settled May 2005.

The Company issued a note payable for $254,000 at 8% with principle due in December 2005 to Herman E. Gettelfinger. This note was settled May 2005.

The Company issued a note payable of $250,000 on August 13, 2003 at 9% with a one year term to William Parker Lee, a former member of our Board of Directors. This note was settled May 2005.

As of April 30, 2006 Wind Mill owed the Company $295,257 on an open account in connection with salary reimbursement and other contract services.

Other than the transactions disclosed above, there have been no material transactions, series of similar transactions or currently proposed transactions, to which we, or any of our subsidiaries was or is to be a party, in which the amount involved exceeds $60,000 and in which any director or executive officer or any security holder who is known to us to own of record or beneficially more than 5% of the Company's common stock, or any member of the immediate family of any of the foregoing persons, had a material interest.

Item 13 Exhibits

EXHIBIT NO.		DESCRIPTION
31.1		Certification of Chief Executive Officer pursuant to Section 302 of Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley”).
31.2		Certification of Chief Financial Officer pursuant to Section 302 of Sarbanes-Oxley.
32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley.

Item 14 Principal Accountants Fees and Service

The aggregate fees we paid to Rodefer Moss & Company, PLLC for the years ended April 30, 2006 and 2005 were as follows:

	2006		2005
Audit Fees	$	82,734	$	45,000
Audit-Related Fees		--		--
Total Audit and Audit-Related Fees		82,734		45,000

Tax Fees		--		--
All Other Fees		--		--
Total	$	82,734	$	45,000

The Audit Committee’s policy is that all audit and non-audit services to be performed by our independent auditors must be approved in advance. The policy permits the Audit Committee to delegate pre-approval authority to one or more of its members and requires any member who pre-approves such services pursuant to that authority to report his decision to the Committee.

SIGNATURES

In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	MILLER PETROLEUM, INC.

	By:	/s/ Deloy Miller
		Deloy Miller Chief Executive Officer

Dated: August 17, 2006

In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

/s/ Deloy Miller Deloy Miller	Chairman of the Board of Directors, and Chief Executive Officer	August 17, 2006

/s/ Lyle H. Cooper Lyle C. Cooper	Chief Financial Officer	August 17, 2006

/s/ Charles M. Stivers Charles M. Stivers	Director	August 17, 2006

______________ Herbert J. White	Director	August 17, 2006

/s/ Herman E. Gettelfinger Herman E. Gettelfinger	Director	August 17, 2006