Edgar Filing: MILLER PETROLEUM INC

Unassociated Document

U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

————————————————————

FORM 10-KSB/A

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

For the fiscal year ended April 30, 2005

¨ 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

(State or Other Jurisdiction of

Incorporation or Organization)

62-1028629

(I.R.S. Employer

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 (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 x 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, 2005 were $1,030,036.

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 July 25, 2005, was $6,440,780.80.

There are approximately 5,031,860 shares of common voting stock of the Registrant held by non-affiliates. On July 25, 2005 the average bid and asked price was $1.28.

As of July 25, 2005, there were 9,466,856 shares of common stock outstanding.

EXPLANATORY NOTE

This Amendment No. 1 on Form 10-KSB/A (“Form 10-KSB/A) to Miller Petroleum’s Annual Report on Form 10-KSB for the fiscal year ended April 30, 2004, initially filed with the Securities and Exchange Commission (the “SEC”) on August 30, 2005 (the “Original Annual Report”), is being filed to reflect responses to comments received from the SEC on February 1, 2006 concerning the Original Annual Report, as well as additional disclosure revisions deemed appropriate by current management.

In addition, the Original Filing has been amended to include currently dated certifications from our Chief Executive Officer and Chief Financial Officer, as required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002.

This Form 10-KSB/A does not reflect events occurring after the filing of the Original Annual Report or modify or update those disclosures affected by subsequent events.

Forward-Looking Statements

This annual report on Form 10-KSB (“Annual Report”) for the period ending April 30, 2005 (“fiscal year 2005”), 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.

PART I

Item 1. Description of Business.

General Overview

We are actively engaged in the exploration, development, production and acquisition of crude oil and natural gas. Our business involves the operation of oil and gas wells, the acquisition of oil and gas leases and the rebuilding and sale of oil field equipment. Our principal activities are the acquisition, exploration, development and production of proven, undeveloped and underdeveloped reserves independently and through joint venture drilling programs with other companies in the industry. Our properties are currently concentrated in eastern Tennessee.

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

Our business includes the operation of oil and gas wells, acquisition and development of oil and gas leases, rebuilding and sales of oil field equipment and the organization of joint venture drilling programs with other companies in the industry.

Oil and Gas Leases

We presently have approximately 43,000 acres under lease in Tennessee and seek to acquire additional strategic acreage. We utilize seismic data, and other advanced technologies for geophysical exploration and development of oil and gas wells. In addition to our engineering and geological capabilities, we also have work over rigs, dozers, roustabout crews and equipment to set pumping units and tanks and lay flow lines, winch trucks and trailers for traveling support, backhoes, ditchers, fusion machines and welders for pipeline and compression installation, and other equipment necessary to take a well drilling program from the development stage to completion. The company also sells rigs, oilfield trailers, compressors and other miscellaneous oil and gas production equipment.

We are presently developing leases referred to as the Koppers North Field (the “Koppers North”) and the Koppers South Field (the “Koppers South”), which are located in Tennessee’s Appalachian Basin. These areas, in addition to our recent acquisition of the Carden Tract, which adjoins the Koppers North, form a 10,500 acre contiguous block in Campbell County, Tennessee and have more than one hundred and fifty possible developmental well locations. We are also continuing to develop approximately 3,400 acres leased from the Lindsay Land Company (the “Lindsay Field”) located near Caryville, Tennessee in Campbell County, which has twenty five possible developmental well locations. Prospects in Harriman, Tennessee (Roane County) (the “Harriman Prospect”) have recently been defined by a seismic study. We have completed the drilling of one well and plan to drill at least two more wells there this year.

Our current drilling program calls for the development of 100 Devonian (Chattanooga) Shale gas wells in the Koppers North, sixty Big Lime Formation oil/gas wells in the Koppers South and ten gas wells in the Lindsay Field.

On April 21, 2005, we began drilling operations of the Eula Butler Et Al #1 well, a deep wildcat in Roane County, to a depth of 6200 feet to the Knox dolomite, as a part of our joint venture with a large Appalachian based oil and gas company. A seismic study revealed a possibility of significant quantities of oil and gas from the nearby Trenton-Stones River limestone formations. The target depth is around 6200 feet and we anticipate that this well will be completed at the beginning of the next fiscal year.

On April 11, 2005, we signed an agreement with Norwest Energy, NL of Perth, Australia (“Norwest”) and Golden Triangle Energy of Houston, Texas (“GTE”) to develop the Koppers North and Carden Tract. GTE and Norwest will pay 100% of the cost to drill and complete the first twenty wells in five, five and ten well packages. We will retain a 25% working interest. After the completion of the first twenty wells, should Norwest and GTE continue to participate in development of the remaining acreage, we will pay a portion of the development costs which are proportionate to our 25% working interest therein.

Lease and Royalty Terms

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 own a 100% 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. Currently, there are 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 163,983 barrels of oil from the Big Lime Formation through April 30, 2005. This lease remains in effect for as long as there is production. The Company has leased and is currently leasing smaller tracts of 50 to 1,000 acres adjacent to or near the Koppers South Fields acreage.

Carden Tract

This lease includes 4,200 acres in which we have a 100% working interest and an 81.25% net royalty interest. This tract joins the Koppers North parcel of 6,300 acres to form a 10,500 acre contiguous block in the north. We anticipate that this lease will produce gas because of previous drilling and production in the area by others in the industry. The lease has a three-year term with a five well drilling commitment.

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 25% working interest in gas wells in this area where 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.

As of April 30, 2005, we have drilled seven wells with Delta Producers, the Lindsay Field #9, #10, #11, #12, #13, #14 and #15 wells. The #11 well is awaiting completion and the remaining wells are producing and we are selling gas from them 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 50% working interest in the Lindsay Field lease. The lease also provides for a landowner’s royalty of 12.5%. We purchased and built with Delta Producers 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.

Well #	Date Began Sales of Natural Gas	Amount of Natural Gas Sold as of April 30, 2005 (Mcf)
9	3/02	85,165
10	1/03	29,057
11	*	*
12	3/02	194,432
13	8/03	38,090
14	8/03	24,721
15	11/03	20,707

(*) 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. In addition to the Eula Butler Et Al #1 well, additional wells are being planned on this area. There are several smaller leases that expire at different times. When drilled on, they will be held by production.”

Tengasco Farmout

We entered into a farmout agreement (the “Tengasco Farmout”) with Tengasco, Inc. (“Tengasco”) for ten wells to be drilled in the Swan Creek Field, located in Hancock County in Tennessee.

In August of 2000, we drilled our first oil well under the Tengasco Farmout, the Dewey Sutton #1 well, located in the Trenton formation. We have sold more than 16 MBbl and are currently producing about 200 barrels of oil per month from the Dewey Sutton #1 well.

Tengasco completed its pipeline and began buying natural gas from us on March 8, 2001 from the Worlie Purkey#1 well. We have sold 12,400 Mcf from this well. We started selling gas to Tengasco from the Worlie Purkey #3 well in May 2001. During the latter part of June 2001, we began selling from the Jeff Johnson #1 well. Through April 30, 2005, we have sold 50,080 Mcf of gas from the Worlie Purkey #3 and 78,249 Mcf of gas from the Jeff Johnson #1 to Tengasco. These leases will remain in effect for as long as there is production.

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. There are thirteen producing oil wells and eight producing natural gas wells on these leases that have produced 148,693 barrels of oil and 291,996 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, 2003		208,821			5,365,057
Discoveries and extensions		68,903			718,160
Revisions of previous estimates		79,169			2,642,073
Production		(5,957	)		(28,771	)

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

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

Proved developed producing reserves at April 30, 2004		62,106			1,035,850

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, 2005 and 2004 are calculated using weighted average process in effect as of those dates. Those prices were $6.75 and $6.25 respectively, per Mcf of natural gas, and $44.50 and $32.75 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 carryforwards 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, 2005 and 2004 are as follows:

	2005			2004

Future cash flows	$	12,747,600		$	65,105,641
Future production costs and taxes		(1,939,000	)		(2,769,464	)
Future development costs		(745,000	)		(4,740,000	)
Future income tax expense		(3,119,716	)		(17,854,815	)
Future cash flows		6,943,884			39,741,362
Discount at 10% for timing of cash flows		(3,463,248	)		(16,591,415	)
Discounted future net cash flows from proved reserves	$	3,480,636		$	23,149,947

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, 2005 and 2004.

	April 30,
	2005			2004
Balance, beginning of year	$	23,149,947		$	13,165,412
Sales, net of production costs and taxes		(784,409	)		(773,033	)
Changes in prices and production costs		7,490,059			9,737,935
Revisions of quantity estimates		(39,206,898	)		5,505,439
Development costs incurred		3,995,000			-
Net changes in income taxes		8,836,937			(4,485,806	)
Balances, end of year	$	3,480,636		$	23,149,947

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”).

Business Strategy: Growth through the Drillbit

Our goal is to maximize shareholder value through the execution of a business strategy designed to capitalize on our strengths and the continued expansion of our operations through the growth of our oil and gas reserves. We believe this can best be achieved by:

·	Focusing on the development, drilling and production of natural gas and crude oil in east Tennessee’s Appalachian Basin. Appalachian gas sells at a premium price to Henry Hub, due to its proximity to major consuming regions.

Manage risk exposure by market testing prospects and optimizing our working interest--Drilling and development capital will be raised through partnership drilling programs where Miller keeps up to a 50% working interest, therefore limiting our financial and operating risks by varying our level of participation. We also seek to operate our projects in order to control costs associated with drilling and the timing of the drilling.

Exploration Activities--During 2006 we plan to focus our exploration activities on projects that are near currently owned productive fields, we believe that we can successfully add growth through exploratory activities given the much improved technology, and our experienced technical staff. We have allocated approximately 1 million dollars to our 2006 development budget for exploration activities.

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.

Competition

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, 2005.

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.

·	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 11full-time employees, however, when we commence a full-scale drilling program, we may employ up to as many as 10 additional subcontractors or temporary employees.

Risk Factors

An investment in shares of our common stock involves a high degree of risk. Potential investors should consider the following factors, in addition to other information provided by us in our filings with the SEC, in evaluating our business and proposed activities before purchasing our shares.

General Risks Related To Our Business

Our business may fail if we do not raise additional money.

We will require additional funding to realize our future goals of conducting the oil and gas exploration operations on properties under lease and acquiring additional oil and gas properties for development. We anticipate that our additional funding will come from the sale of fractional working interests to investors participating in our oil and gas partnerships and equity or debt financing, which may be very difficult for our highly speculative enterprise. We can not assure you that any additional funding will be available to us, or if it is available, that the terms of the funding will be satisfactory to us.

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.

Our current petroleum engineering report has substantially revised downward previous estimates of our petroleum reserves.

Our current petroleum engineer, Netherland Sewell & Associates, Inc. (“NSAI”), in its report dated June 28, 2005, estimated that our current petroleum “proven” reserves, calculated on the basis of a discounted cash flow analysis, are valued at approximately $3.5 million. This estimate is a significant reduction from the estimate at April 30, 2004 of approximately $23 million of proven reserves previously provided to us by our former petroleum engineering firm.

Our future success will depend on the price of oil and gas.

Our revenue comes primarily from the sale of oil and gas. Prices and markets for oil and gas are unpredictable, highly volatile, potentially subject to government fixing, pegging, controls or any combination of these or other factors and respond to changes in domestic, international, political, social, and economic environments. If oil and gas prices go below our costs and expenses of operating our company, we will lose money.

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.

Compliance with governmental regulations can be costly and can limit our planned operations.

We face many state and federal laws, rules and regulations covering the safety of our operations, environmental conditions and other facets of our business. These laws, rules and regulations can be expensive and may seriously limit our ability to conduct our intended business operations. (See Description of Business--"Governmental Approvals and Regulation” and “Environmental Compliance.”)

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.

You will not be able to elect our directors or officers.

Deloy Miller, our CEO, currently owns 43% of our stock, on a fully diluted basis. Although he does not have absolute voting control, he is still in a position to exert substantial influence on the election of all directors, who in turn elect all of the officers. You will have little or no ability to influence the direction of Miller Petroleum.

Indemnification of Directors, Officers, Employees and Agents

Miller Petroleum currently does not have a Directors and Officers Insurance Policy.

Available Information

We file annual, quarterly and current reports and other information with the Securities and Exchange Commission. You may read and copy any document we file at the SEC’s public reference room at Room 1024, 450 Fifth Street, NW, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for information on the public reference room.

In addition, we are electronic filers and our reports and information filed with the SEC are available on the SEC’s website located at www.sec.gov.

Our website is located at www.millerpetroleum.com. Under the “Archive” section of the website, you may access our most recent press releases.

Item 2. Properties.

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

Please see “Current Business” for a description of our oil and gas leases. Please also refer Management’s Discussion and Analysis or Plan of Operation—“Results of Operations” for additional disclosure regarding our oil and gas operations in accordance with pursuant to Industry Guides 2 of the Securities and Exchange Act (the “Act”).

Item 3. Legal Proceedings.

None.

Item 4. Submission of Matters to a Vote of Stockholders.

No proposals were submitted for approval by our shareholders during the fourth quarter ended April 30, 2005.

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.

	High		Low
Quarter Ended:	Bid Prices ($)

July 31, 2003		0.55		0.55
October 31, 2003		0.68		0.45
January 31, 2004		0.45		0.35
April 30, 2004		0.91		0.59

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 275 stockholders of record of our common stock as of July 25, 2005.

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

EQUITY COMPENSATION PLAN INFORMATION

The table below provides information, as of April 30, 2005, 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	540,000(1)	1.30	--
Total	540,000	1.30	--

Recent Sales of Unregistered Securities

None.

Share Repurchases

None.

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

The following discussion is intended to facilitate an understanding of our business and results of operations. It should be read in conjunction with our consolidated financial and the accompanying notes to the consolidated financial statements included elsewhere in this Annual Report.

We have more than approximately 43,000 acres under lease in Tennessee. About 90% of these 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.

Currently, We are offering five to twenty well drilling programs to "accredited investors" or "sophisticated investors" to help spread the risk associated with drilling projects and to facilitate investor returns. We will sell up to a 70% working interest to investors while retaining a 30% working interest. Each program will be made up of five to fifteen Chattanooga Shale wells on its Koppers South acreage.

In June of 2001, we made a conventional Big Lime gas discovery, on the Lindsay Land Company lease jointly owned by Delta Producers, Inc. and Miller. Currently there are six producing wells on the property. There are at a minimum twenty five additional drill sites on this 3,400 acre lease which is situated near Caryville, Tennessee.

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.

Results of Operations

In fiscal 2005, we increased our capitalized costs of oil and gas properties from $2,638,005 to $2,941,832. Our development costs for oil and gas properties decreased from $565,779 to $549,687. Estimates of proved reserves of oil decreased from 350,937 barrels to 93,825 and estimates of proved reserves of natural gas decreased from 8,696,519 Mcf to 1,249,566 Mcf. Proved developed producing reserves of oil decreased to 60,734 barrels from 62,106 barrels and proved developed producing reserves of natural gas decreased to 697,916 Mcf from 1,035,850 Mcf. These decreases were primarily due to a change in the evaluations by our new engineering firm NSAI, which reclassified previous estimates of proved reserves as possible and probable. (See Description of Business—“Oil and Gas Reserve Analyses.” in this Annual Report.) During fiscal 2005, future cash flows discounted 10% after income taxes from proved reserves decreased from $23,149,947 to $3,480,639. Our oil and gas revenue was $784,409 for fiscal 2005, up from $773,033 for fiscal 2004. Volatile changes in the price of natural gas and oil partially offset by normal declines in our production curves brought about this increase. During fiscal 2005, service and drilling revenue was $209,680, down from $1,186,823, in part due to the disposal of a drilling rig. Cost of revenue from service and drilling decreased by $682,943 from Fiscal 2004 to Fiscal 2005. The drilling rig was old and in need of major repairs. To acquire new drill pipe, hammers and a compressor would cost $320,000, and likely the motor would need to be replaced to continue using the rig. The cost of repairs, combined with high worker’s compensation insurance rates, would have resulted in a negative cash flow to the Company. At the time the rig was sold it was not being utilized, and management believed that it was in the best interests of the Company sell the rig and use the funds to enhance the Company’s oil and gas leases. Retail sales increased from $6,939 in fiscal 2004, to $35,947 in fiscal 2005 primarily due to the market volatility, and are included in service and drilling revenue for financial statement purposes.

During fiscal 2005, Miller Petroleum produced 75 MMBTUs of natural gas, with an average price of $6.28 per MMBTU. Production decreased from about 88 MMBTUs in fiscal 2004, and the average price per MMBTU was $5.63. The following tables reflect our production figures for the fiscal years ended April 30, 2005, and 2004

Fiscal Year	Average Net Production Gas /MBTU		Sales Price /MMBTU
2004		88,000	$	5.63
2005		75,000	$	6.28

Fiscal Year	Average Net Barrels of Oil		Sales Price
2004		10,100	$	27.30
2005		7,500	$	40.48

	2003		2004		2005
Net Productive Wells		22.60		20.20		20.20
Developed Acreage		1,480		1,480		1,480
Undeveloped Acreage		41,120		41,120		41,120
Net Productive Exploratory Wells		0		0		0
Net Dry Exploratory Wells		0.24		0.30		0.30
Net Productive Developmental Wells		1.408		1.20		1.20
Net Dry Developmental Wells		0		0		0

Liquidity

Cash provided by operating activities was $154,580 for fiscal 2005, a reduction of $203,287 from operating activities of $357,867 in fiscal 2004. 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 43,000 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. 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.

Subsequent to year end, we drilled ten (10) gas wells on four (4) properties. Based on flow tests, seven (7) of the wells are producing gas. Our net production volume was expected to be about 600,000 Mcf per month. We expect these wells to produce an additional $8,000 to $10,000 per month in net gas revenues beginning in October to November 2005.

Item 7. Financial Statements.

INDEX TO FINANCIAL STATEMENTS

Report of Independent Certified Public Accountants	21

Consolidated Balance Sheet	22-23

Consolidated Statements of Operations	24

Consolidated Statements of Stockholders' Equity	25

Consolidated Statements of Cash Flows	26

Notes to the Consolidated Financial Statements	27-43

MILLER PETROLEUM, INC.

CONSOLIDATED FINANCIAL STATEMENTS

April 30, 2005 and 2004

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, 2005 and April 30, 2004 and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audit 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 is not required to have, nor were we engaged to perform, an audit of its 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, 2005 and 2004, 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.

As discussed in Note 2 to the financial statements, the Company has restated its financial statements for the year ended April 30, 2004 to properly reflect transactions in its common stock.

/s/ Rodefer Moss & Co, PLLC

Knoxville, Tennessee

July 28, 2005

Miller Petroleum, Inc.

Consolidated Balance Sheets

	April 30, 2005			Restated April 30, 2004
ASSETS
CURRENT ASSETS

Cash	$	2,362		$	2,416
Accounts receivable		182,951			117,167
Current portion of note receivable		47,000			18,875
Inventory		67,389			50,911
Deferred offering costs		88,842			88,842
Prepaid expenses		—			66,590
Total Current Assets		388,544			344,801
FIXED ASSETS
Machinery		941,601			1,036,802
Vehicles		333,583			385,465
Buildings		313,335			313,335
Office equipment		72,549			72,549
Less: accumulated depreciation		(939,579	)		(905,531	)
Total Fixed Assets		721,489			902,620
OIL AND GAS PROPERTIES		2,941,832			2,638,005
(On the basis of successful efforts accounting)

PIPELINE FACILITIES		206,298			218,637
OTHER ASSETS
Land		496,500			511,500
Investments		500			500
Well equipment and supplies		431,462			443,942
Long-term notes receivable		—			56,338
Cash - restricted		71,000			71,000
Total Other Assets		999,462			1,083,280
TOTAL ASSETS	$	5,257,625		$	5,187,343

See notes to consolidated financial statements.

Miller Petroleum, Inc.

Consolidated Balance Sheets

	April 30,			Restated April 30,
	2005			2004
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES

Accounts payable - trade	$	330,620		$	335,556
Accrued expenses		224,306			116,011
Current portion of notes payable
Related parties		—			1,360,000
Other		—			176,624
Total Current Liabilities		554,926			1,988,191

LONG-TERM LIABILITIES

Notes payable
Related parties		1,673,693			269,230
Other		655,646			616,739
Total Long-Term Liabilities		2,329,339			885,969
Total Liabilities		2,884,265			2,874,160

STOCKHOLDERS’ EQUITY

Common Stock: 500,000,000 shares authorized at $0.0001 par value, 9,396,856 and 8,378,856 shares issued and outstanding		939			838
Additional paid-in capital		4,495,498			4,173,998
Accumulated deficit		(2,123,077	)		(1,861,653	)
Total Stockholders’ Equity		2,373,360			2,313,183
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	5,257,625		$	5,187,343

See notes to consolidated financial statements.

MILLER PETROLEUM, INC.

Consolidated Statements of Operations

	For the Year Ended April 30,			Restated For the Year Ended April 30,
	2005			2004
REVENUES
Oil and gas revenue	$	784,409		$	773,033
Service and drilling revenue		245,627			1,193,762
Total Revenue		1,030,036			1,966,795

COSTS AND EXPENSES
Oil and gas cost		177,287			228,301
Service and drilling cost		82,730			765,673
Selling, general and administrative		604,040			567,112
Depreciation, depletion and amortization		366,279			233,439
Total Costs and Expenses		1,230,336			1,794,525
INCOME (LOSS) FROM OPERATIONS		(200,300	)		172,270
OTHER INCOME (EXPENSE)
Interest income		875			1,918
Gain on sale of equipment		157,562			42,897
Interest expense		(219,561	)		(228,436	)
Total Other Expense		(61,124	)		(183,621	)
INCOME TAXES		—			—
NET LOSS	$	(261,424	)	$	(11,351	)
BASIC AND DILUTED
LOSS PER SHARE	$	(0.03	)	$	(0.00	)
BASIC WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING		9,030,738			8,350,048

See notes to consolidated financial statements.

MILLER PETROLEUM, INC.

Consolidated Statements of Stockholders’ Equity

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

Restated balance, April 30, 2003		8,293,856	$	830	$	4,000,871		($1,850,302	)	$	2,151,399

Issuance of shares in connection with deferred offering		85,000		8		88,834		—			88,842

Issuance of warrants as prepayment of financing costs		—		—		59,293		—			59,293

Issuance of options for services		—		—		25,000		—			25,000

Net loss for the year ended April 30, 2004		—		—		—		(11,351	)		(11,351	)

Restated 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

See notes to consolidated financial statements.

Miller Petroleum, Inc.

Consolidated Statements of Cash Flows

	April 30,			Restated April 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(261,424	)	$	(11,351	)
Adjustments to Reconcile Net Loss to
Net Cash Provided by Operating Activities:
Depreciation, depletion and amortization		393,061			265,950
Gain on sale of equipment		(157,562	)		(42,897	)
Options issued in exchange for services		—			25,000
Common Stock issued in exchange for services		119,600			—
Changes in Operating Assets and Liabilities:
Increase in accounts receivable		(65,784	)		(8,894	)
Increase in inventory		(16,478	)		(13,092	)
Decrease (increase) in prepaid expenses		39,808			(10,398	)
Increase (decrease) in accounts payable		(4,936	)		121,729
Increase in accrued expenses		108,295			31,820
Net Cash Provided by Operating Activities		154,580			357,867
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of investments		—			12,812
Proceeds from sale of land		15,000			—
Purchase of equipment		(1,500	)		(113,834	)
Purchase of oil and gas properties		(386,687	)		(565,779	)
Proceeds from sale of equipment		187,682			392,499
Decrease in restricted cash		—			3,000
Changes in note receivable		28,125			14,201
Net Cash Used by Investing Activities		(157,380	)		(257,101	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of stock		96,001			—
Payments on Notes Payables		(137,716	)		(502,376	)
Proceeds from borrowings		44,461			400,662
Net Cash Provided (Used) by Financing Activities		2,746			(101,714	)
NET DECREASE IN CASH		(54	)		(948	)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		2,416			3,364
CASH AND CASH EQUIVALENTS, END OF YEAR	$	2,362		$	2,416

See notes to consolidated financial statements.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2005 and 2004

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

a. Oganization and Basis of Presentation

These consolidated financial statements include the accounts of Miller Petroleum, Inc. (“The Company”) formerly Triple Chip Systems, 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. 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 field by field basis using the units-of-production method based upon proved reserves. Acquisition costs are amortized by using total proved reserves as the denominator. Development costs are amortized using proved developed reserves, rather than total proved reserves, as the denominator.

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.

c. 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 years ended April 30, 2005 and 2004 the Company has recognized no changes or allowances for impairment.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2005 and 2004

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

d. 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, 2005 and 2004, the assumed effects of the exercise of the options and warrants to purchase 555,177 and 2,435,672 and shares of common stock that were outstanding at April 30, 2005 and 2004, respectively, and the application of the treasury stock method would have been anti-dilutive. Therefore, there are no diluted per share amounts in the 2005 and 2004 statements of operations.

e. Cash Equivalents

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

f. 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.

g. 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:

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

Depreciation expense for the years ended April 30, 2005 and 2004 was $120,419 and $182,047 respectively.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2005 and 2004

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

h. 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 2005 and 2004. Retail sales of various parts and equipment is recognized as income at the time the item is sold and, under the 10% rule, has been combined with service and drilling revenue.

i. 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 $6,944 and $8,684 at April 30, 2005 and 2004, respectively. Accounts receivable more than 90 days old were $32,498 at April 30, 2005 and $ 22,722 at April 30, 2004.

j. Inventory

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

k. 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.

l. 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”) and Glover Petroleum Consultants, of Crossville, Tennessee (“Glover”), for the years ended April 30, 2005 and 2004, 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.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2005 and 2004

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

m. Reclassifications

Certain amounts and balances pertaining to the April 30, 2004 financial statements have been reclassified to conform with the April 30, 2005 financial statement presentations.

n. 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.

o. 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.

p. Recent Accounting Pronouncements

In June 2003, the FASB approved SFAS 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. This Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. SFAS 150 did not have an effect on the Company’s financial position.

In December 2003, the FASB issued a revised interpretation No 46, “Consolidation of Variable Interest Entities.” The interpretation clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to certain types of entities. Adoption did not have an impact on the Company’s financial statements.

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 is not expected to affect the Company’s consolidated financial statements.

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” This statement is a revision to SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” This statement establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services, primarily focusing on the accounting for transactions in which an entity obtains employee services in share-based payment transactions. Companies will be required to measure the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service, the requisite service period (usually the vesting period), in exchange for the award. The grant date fair value of employee share options and similar instruments will be estimated using option-pricing models.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2005 and 2004

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

If an equity award is modified after the grant date, incremental compensation cost will be recognized in an amount equal to the excess of the fair value of the modified award over the fair value of the original award immediately before the modifications for small business issuers. SFAS No. 123R will be effective for periods beginning after December 15, 2005. Accordingly, the Company will adopt SFAS No. 123R in its fourth quarter of fiscal 2006. The Company is currently evaluating the provisions of SFAS No. 123R and has not determined the impact that this Statement will have on its results of operations or financial position.

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 is not expected to impact the consolidated financial position, result of operations or cash flows.

q. 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 $406,246 of the Company’s total revenue which was about 39% of the Company’s total revenue.

Nami Resources, LLC accounted for $79,111 of the Company’s total revenue which was about 8% of the Company’s total revenue.

South Kentucky Purchasing Co. - South Kentucky accounted for $256,235 of the Company’s total revenue which was about 25% of the Company’s total revenue. South Kentucky purchases all of the Company’s crude oil.

NOTE 2 - RESTATEMENT OF FINANCIAL STATEMENTS

The Company previously issued its financial statements as of and for the year ended April 30, 2004, which were included in its Form 10KSB filed on July 29, 2004. The filing included a report, dated July 20, 2004, which expressed an unqualified opinion on those statements by independent accountants who had not registered with the Public Companies Accounting Oversight Board (PCAOB). Additionally, the report, failed to note the conduct of the audit in accordance with the standards of the PCAOB. Because of these failures, the Company’s financial reporting was not in compliance with rules established by the Securities Exchange Commission, and accordingly, the Company engaged other auditors to conduct a PCAOB-compliant audit of its April 30, 2004 financial statements.

In connection with the PCAOB-compliant audit of the 2004 financial statements, management identified errors in amounts previously reported in the Company’s financial statements for the years ended April 30, 2002, 2003 and 2004. The Company made an error in failing to record, in total, bad debt expense of approximately $237,500 in relation to the non-payment of a stockholder receivable in 2002, resulting in a misstatement of retained earnings in 2002, 2003 and 2004. In 2004 the Company’s previously issued financial statements failed to include compensation and interest expense of approximately $57,000 in connection with issuances of options and warrants. The Company, therefore, is restating its financial statements beginning with financial position at April 30, 2002 and including its annual financial statements for 2003 and 2004.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2005 and 2004

NOTE 3 - STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURE

	2005		2004

CASH PAID FOR:
Interest	$	70,990	$	195,919
Income Taxes		—		—

NON-CASH FINANCING ACTIVITIES:
Financing costs from issuance of warrants		—		59,293
Common stock issued for deferred offering costs		—		88,842
Stock issued for mineral rights		106,000		—
Common stock issued for services		119,600		—
Conversion of account to note payable		—		250,689
Amortization of prepaid interest		26,786		32,511

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. If the proposed offering were to be permanently abandoned, the costs incurred would be charged to expense in the period the decision is made. If the proposed offering is successful, the contribution to shareholders’ equity will be reduced by these costs.

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 $549,687 and $565,779 of oil and gas properties for the years ended April 30, 2005 and 2004, respectively, and recorded $245,860 and $43,800 of amortization expense for the years ended April 30, 2005 and 2004, respectively.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2005 and 2004

NOTE 6 - LONG-TERM DEBT AND SUBSEQUENT EVENT

The Company had the following debt obligations at April 30, 2005 and April 30 2004

		2005		2004
Note payable to First National Bank of Oneida secured by stock and equipment, bearing interest at 7.50% due in quarterly payments of $15,000 on January 14, 2006	$	85,097	$	136,650

Note payable to American Fidelity Bank secured by equipment, bearing interest at 4.00% due in monthly payments of $2,272 with final payment due in August 2008	$	353,891	$	366,724

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	$	19,380

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	$	250,688

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2005 and 2004

NOTE 6 - LONG-TERM DEBT AND SUBSEQUENT EVENT (Continued)

	2005		2004
Note payable to related party, unsecured, interestat 7.00% with payments due yearly with the principle due in May of 2005	$	59,692	$	15,230

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

Note payable to related party bearing interest at 8.00% with principle due in December 2005	$	254,000	$	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 principle due in December 2004	$	250,000	$	250,000

Note payable to Home Federal Bank secured by equipment, bearing interest at 9.75% due in monthly payments with final payment due in August 2005		—	$	7,001

Note payable to General Motors Acceptance Corporation secured by a pickup truck, bearing interest at 0.00% due in monthly payments of $721 with final payment due in October 2004		—	$	5,768

Note payable to General Motors Acceptance Corporation Secured by a Suburban, bearing interest at 0.00% due in monthly payments of $894 with final payment due in October 2004		—	$	7,152

Total notes payable	$	2,329,339	$	2,422,593
Less current maturities		—		1,536,624
Notes payable - long-term	$	2,329,339	$	885,969

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 the balance sheet date. 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, 2005 and 2004

NOTE 6 - LONG-TERM DEBT AND SUBSEQUENT EVENT (Continued)

The notes are due on June 30, 2006, with interest only payments accruing at 12% during the interim. The notes are convertible into common stock at the lesser price of $1.50 per share or the price of common stock issued to investors in a planned equity offering of the Company. The notes contain restrictive covenants pertaining to debt to equity, asset and liquidity ratios, and imposes other affirmative conditions upon the Company. Upon event of default, the interest rate of the note resets to the highest rate allowed by law.

NOTE 7 - RELATED PARTY TRANSACTIONS

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

The Company issued a note 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. This note payable was issued to raise working capital. The related party notes were due to members of the Company’s board of directors or their immediate families.

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 Company's asset retirement obligations relate primarily to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and gas properties. Prior to adoption of this statement, such obligations were accrued ratably over the productive lives of the assets through its liability for such amounts. The Company adopted SFAS 143 beginning on May 1, 2003 and using a credit-adjusted risk free rate of 12%, an estimated useful life of wells ranging from five to forty-five years and estimated plugging and abandonment cost of $1,000 per well, the Company recorded a non-cash charge related to the cumulative effect of a change in accounting principle of $7,592.

The changes in the Company’s liability from adoption at July 1, 2004 to April 30, 2005 were as follows:

Liability from adoption of SFAS No. 143 May 1, 2003	$	11,538

Accretion expense for 2004		1,768

Asset retirement obligation as of December 31, 2003		13,306

Accretion expense for 2004		1,890

Asset retirement obligation as of December 31, 2004	$	15,196

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2005 and 2004

NOTE 9 - 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:

	2005			2004

Federal statutory rate		34	%		34	%
Federal tax benefit at statutory rate	$	89,000		$	13,000
State income tax benefit		19,600			2,800

Increase in deferred tax asset and valuation allowance	$	108,600		$	15,800


		2005			2004

Net operating loss carryforward	$	1,451,000		$	1,362,000

		1,451,000			1,362,000

Valuation allowance		(1,451,000	)		(1,362,000	)

Net deferred taxes	$	—		$	—

The Company recorded a valuation allowance at April 30, 2005, and 2004 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, 1989 of approximately $ 4,000,000 at April 30, 2005. The carry forwards begin expiring in 2005.

NOTE 10 - STOCKHOLDERS’ EQUITY

During the year ended April 30, 2004, the Company issued 85,000 shares for services in connection with a planned offering. The Company recorded $88,842 in deferred offering costs on its balance sheet in connection with the transaction.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2005 and 2004

NOTE 10 - STOCKHOLDERS’ EQUITY (Continued)

In August 2003, the Company issued 1,110,000 warrants to Sherri Ann Parker Lee and 250,000 warrants to William Parker Lee. The warrants were issued along with the note payable to them dated August 13, 2003 and can be exercised for $0.80 per share, and expired on January 1, 2005. The warrants were recorded as $59,293 of prepaid financing costs and will be amortized to interest expense over the term of the loan. Interest expense connected with the warrants was $26,782 for the year ended April 30, 2005.

In March 2004, the Company issued 100,000 options in exchange for services. The warrants can be exercised for $0.50 per share, and expire in March 2006. In connection with the transaction the Company recorded an expense of $25,000.

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 restricted common stock in private placements for proceeds of $80,000. The sales transpired at discounts ranging from 66% to 43% from prices prevailing for free-trading shares.

Further, the Company issued 113,000 restricted shares of its common stock in exchange for services and 500,000 shares of its restricted common stock for leasehold interests in oil and gas properties at a discount of 60% from prices prevailing 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.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2005 and 2004

NOTE 10 - STOCKHOLDERS’ EQUITY (Continued)

Information regarding the warrants at April 30, 2005 and 2004 is as follows:

	2005				2004
	Weighted Shares		Average Exercise Price		Weighted Shares		Average Exercise Price

Options outstanding beginning of year		2,235,000	$	0.88		875,000	$	1.19
Options canceled		1,695,000		0.77		100,000		2.00
Options exercised		—		n/a		—		n/a
Options granted		—		0.00		1,460,000	$	0.78

Options outstanding, end of year		540,000	$	1.30		2,235,000	$	0.88

Options exercisable, end of year		540,000	$	1.30		2,435,672	$	0.88

Option price range, end of year			$	0.50 to 2.00			$	0.46 to 2.00

Option price range, exercised shares				n/a				n/a

Options available for grant at end of year				n/a				n/a

Weighted average fair value of options granted during the year				n/a			$	0.05

For non-employees, the fair value of stock options used to compute pro forma net loss and loss per share disclosures is the estimated present value at grant date using the Black-Scholes option-pricing model with the following weighted average assumptions for 2004. Expected volatility of 40%; a risk free interest rate of 3.00% and an expected option life of 1 year, five months.

NOTE 11 - 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.

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2005 and 2004

NOTE 12 - 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 13 - S.F.A.S. 69 SUPPLEMENTAL DISCLOSURES (Unaudited)

(1) Capitalized Costs Relating to Oil and Gas Producing Activities at April 30, 2005 and 2004 is as follows:

	2005			2004

Proved oil and gas properties and related lease equipment

Developed	$	3,841,996		$	3,362,316
Non-developed		31,053			31,053
		3,873,049			3,393,369
Accumulated depreciation and depletion		(931,217	)		(755,364	)
Net Capitalized Costs	$	2,941,832		$	2,638,005


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

		2005			2004

Acquisition of Properties Proved and Unproved	$	—		$	—
Exploration Costs		—			—
Development Costs		549,687			565,779
Total	$	549,687		$	565,779

(3) Results of Operations for Producing Activities

		2005			2004

Production revenues	$	784,409		$	773,033

Production costs		177,287			228,301
Depreciation and amortization		245,860			43,800

Results of operations for producing activities (excluding corporate overhead and interest costs)	$	361,262		$	500,932

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2005 and 2004

NOTE 13 - 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, 2003		208,821			5,365,057
Discoveries and extensions		68,903			718,160
Revisions of previous estimates		79,169			2,642,073
Productions		(5,957	)		(28,771	)

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

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

Proved developed producing reserves at April 30, 2004		62,106			1,035,850

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. and Glover Petroleum Consultants of Crossville, Tennessee for the year ended April 30, 2005 and April 30, 2004, respectively. 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

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2005 and 2004

NOTE 13 - S.F.A.S. 69 SUPPLEMENTAL DISCLOSURES (Unaudited) (Continued)

uncertain at this time. Therefore, these proven undeveloped reserves are not being included in the presentation of the oil and gas reserves at April 30, 2005, nor are such reserves being considered in calculating depreciation, depletion and amortization expense for the year based on the April 30, 2005 and April 30, 2004 balance of the proven developed producing reserves set forth above.

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, 2005 and 2004. Estimated future cash flows were based on independent reserves evaluation from Netherland Sewell & Associates, Inc. and Glover Petroleum Consultants for the years ended April 30, 2005 and April 30, 2004, respectively. Because the standardized measure of future net cash flows was prepared using the prevailing economic conditions existing at April 30, 2005 and 2004, 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, 2005 and 2004 were $44.50 and $32.75 per barrel of oil and $6.75 and $6.25 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, less applicable carry forwards, for both regular and alternative minimum tax.

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, 2005 and 2004 is as follows:

	2005			2004
Future cash flows	$	12,747,600		$	65,105,641
Future production costs and taxes		(1,939,000	)		(2,769,464	)
Future development costs		(745,000	)		(4,740,000	)
Future income tax expense		(3,119,716	)		(17,854,815	)

Future cash flows before income taxes		6,943,884			39,741,362

Discount at 10% for timing of cash flows		(3,463,248	)		(16,591,415	)

Discounted future net cash flows from proved reserves	$	3,480,636		$	23,149,947

MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2005 and 2004

NOTE 13 - S.F.A.S. 69 SUPPLEMENTAL DISCLOSURES (Unaudited) (Continued)

Of the Company’s total proved reserves as of April 30, 2005 and 2004, approximately 59% and 7%, respectively, were classified as proved developed producing, 11% and 4%, respectively, were classified as proved developed non-

producing and 30% and 89%, respectively, were classified as proved undeveloped. All of the Company’s reserves are located in the continental United States.

The following table sets forth the changes in the standardized measure of discounted future net cash flows from proved reserves for April 30, 2005 and 2004.

	April 30,
	2005			2004

Balance, beginning of year	$	23,149,947		$	13,165,412

Sales, Net of production costs and taxes		(784,409	)		(773,033	)

Changes in prices and production costs		7,490,059			9,737,935
Revisions of quantity estimates		(39,206,898	)		5,505,439
Development costs incurred		3,995,000			—
Net changes in income taxes		8,836,937			(4,485,806	)
Balances, end of year	$	3,480,636		$	23,149,947

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, 2005, 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	58	Director and Chief Executive Officer
Ernest Payne	58	President
Charles M. Stivers	43	Chief Financial Officer and Director
Herbert J. White	79	Vice President and Director
Herman E. Gettelfinger	72	Director
Gary Bible	55	Vice President of Geology
Teresa Cotton	42	Secretary and Treasurer

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.

Charles M. Stivers was appointed Chief Financial Officer in 2004. 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.

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.

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, Greg Love 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 2005.

			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	2005 2004 2003	$180,000 183,000 180,000	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 currently do not have any employment contracts with members of our management; however, depending on our future operations and requirements, we may offer long term contracts to directors, executive officers or key employees in the future.

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 2005 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 July 25, 2005 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 9,466,856 shares outstanding on July [25], 2005.

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		43.2%
Ernest Payne	105,000	⁽¹⁾	*
Charles M. Stivers	50,000	⁽²⁾	*
Herman E. Gettelfinger	342,901	⁽³⁾	3.62%
Herbert J. White	300		*
All directors and executive officers (6 persons)	4.588,544	⁽⁴⁾	48.5%

*Beneficial Owner of More Than 5%*
Ratliff Farms, Inc.	500,000		5.28%

_________

* 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.

(3) Includes 100,000 shares held by Mr. Gettelfinger’s spouse.

(4) Includes 225,000 shares issuable upon the exercise of presently exercisable stock options.

Item 12. Certain Relationships and Related Transactions.

The Company has a note payable to Sharon Miller (wife of Deloy Miller, a majority stockholder), for $59,693 at April 30, 2005. The note is payable with interest in May 2005. The note is the balance remaining on the original purchase of the property that houses the offices.

The Company issued a note payable of $1,110,000 on August 13, 2003 at 9% with a one year term to Sherri Ann Parker Lee, and wife of William Parker Lee, a member of our Board of Directors.

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 member of our Board of Directors.

The company issued a note payable to William M. Thomas for $199,824 secured by twelve oil and gas wells bearing interest at 9.00% and requiring interest payments quarterly with principle due in December 2005.

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

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, 2005 and 2004 were as follows:

	2005		2004
Audit Fees	$	45,000	$	26,000
Audit-Related Fees^(a)		—		—
Total Audit and Audit-Related Fees	$	45,000		26,000

Tax Fees		—		—
All Other Fees		—		—
Total	$	45,000	$	26,000

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: February 28, 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	Chairman of the Board of Directors,	February 28, 2006
Deloy Miller	and Chief Executive Officer

/s/ Lyle H. Cooper	Chief Financial Officer	February 28, 2006
Lyle H. Cooper

/s/ Charles M. Stivers	Director	February 28, 2006
Charles M. Stivers


Herbert J. White	Director	February 28, 2006

/s/ Herman E. Gettelfinger
Herman E. Gettelfinger	Director	February 28, 2006