U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

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FORM 10-KSB

 

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

For the fiscal year ended April 30, 2007

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

For the transition period from _______ to _______

Commission File No. 033-02249-FW

 

MILLER PETROLEUM, INC.

(Name of small business issuer in its charter)

  

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

 

3651 Baker Highway

Huntsville, Tennessee 37756

(Address of Principal Executive Offices)

 

(423) 663-9457

(Registrant’s Telephone Number, Including Area Code)

 

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

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

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

 

Check whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for past 90 days. Yes 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. x

Indicate by check mark whether the registrant is a shell company. Yes ¨ No x

 

The Registrant’s revenues for the fiscal year ended April 30, 2007 were $1,344,421.

 

The aggregate market value of the Common Stock held by non-affiliates, based on the average closing bid and asked price of the Common Stock on August 7, 2007 was $1,370,805.

 

There are approximately 4,031,779 shares of common voting stock of the Registrant held by non-affiliates. On August 7, 2007 the average bid and asked price was $0.34.

 

PART I

Item 1  Description of Business

 

Corporate History

 

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

 

Current Business

 

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

Principal Products or Services and Markets

 

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

 

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

 

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

 

Distribution Methods of Products or Services

 

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

 

Competitive Business Conditions

 

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

 

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

 

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

 

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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 oil and natural gas to the following purchasers:

·

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

 

·

Barrett Oil Purchasing purchases crude oil from the Koppers Field. Barrett’s purchase price is based on West Texas postings less $4.75.

 

·

Cumberland Valley 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. CV Resources purchases approximately 20% of total natural gas sales.

 

·

Nami Resources LLC purchases natural gas from the Jellico Field. The sales price varies each month, but will not be less than $6.00 per Mcf.

 

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 for 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, 2007.

 

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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.

 

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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

 

Item 2  Description of Property

 

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

 

Oil and Gas Leases

We are an exploration and production company that utilizes seismic data, and other technologies for geophysical exploration and development of oil and gas wells. In addition to our engineering and geological capabilities, we have work-over rigs, dozers, roustabout crews and equipment to set pumping units, tanks and lay flow lines, winch trucks and trailers for traveling support, backhoes, ditchers, fusion machines and welders for pipeline and compression installation, as well as other equipment necessary to take a drilling program from the development stage to completion. The company also sells rigs, oilfield trailers, compressors and other miscellaneous oil and gas production equipment.

As part of the creation of the Wind Mill Joint Venture, the following leases were transferred from us to the Joint Venture in December of 2005:

Koppers Acreage - 100% of the working interest in 27,000 acres in Campbell County, Tennessee, with the exception of the already existing oil wells, which were retained by us and other joint venture partners.

Lindsay Acreage - 40% of the working interest in 4,000 acres in Campbell County, Tennessee, with the exception of already existing gas wells retained by us and other joint venture partners.

Lake City Acreage - 100% of the working interest in 4,500 acres in Anderson County, Tennessee.

Harriman Acreage - 35% of the working interest in 3,500 acres in Roane County, Tennessee, with the exception of the Butler #1 gas well.

Since the Wind Mill Joint Venture was formed, eight successful gas wells have been drilled on the Koppers acreage, one successful gas well and one dry well have been drilled on the Lindsay acreage, one successful gas well and one dry well have been drilled on the Harriman acreage, and two dry wells have been drilled on the Lake City acreage. Our petroleum consultants, Lee Keeling and Associates, Inc., have estimated that these ten successful gas wells contain 1,965,775 Mcf of natural gas.

Under the terms of the Wind Mill agreement, when Wind City put back the 2,900,000 shares of common stock to us, the Wind Mill Agreement would terminate and all leases would be returned to us. At that point we would have no further ownership in Wind Mill, the ten successful gas wells would be retained by Wind Mill, and Wind Mill would be 100% owned by Wind City Oil & Gas, LLC.

On August 30, 2006 Wind City notified us of its intent to exercise the put provision of the stock purchase agreement. On November 7, 2006 Wind City filed a lawsuit in the United States District Court for the Southern District of New York (the “Court”) to force the exercise of the put provision. We do not believe the put was properly exercised and filed an application to stay the litigation and force arbitration as is required by the agreements. The litigation was stayed by the Court on December 21, 2006 on the condition that the parties promptly proceed with an arbitration for the purpose of determining if a threshold condition to exercise the put was met. Upon the decision reached in arbitration, the stay will be lifted by the Court and, depending upon the decision reached in arbitration, the Court will proceed to resolve the issues raised in the litigation. An initial arbitration administrative conference was held on March 12, 2007. As of the date of this report, the arbitration date has been mutually extended pending our efforts to raise additional capital in order to buy Wind City out and for additional drilling capital.

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Existing Production - We have partial ownership in eighteen producing oil wells and thirty-four producing gas wells. The total production and our ownership is as follows:

Oil Production (Bbls)

					Total All Wells			Miller’s %
Total			April 30, 2005			419,429			263,932
Produced			April 30, 2006			11,417			5,630
Total			April 30, 2006			430,846			269,562
Produced			April 30, 2007			9,613			4,898
Total			April 30, 2007			440,459			274,460

Gas Production (Mcf)

					Total All Wells			Miller’s %
Total			April 30, 2005			2,446,103			706,278
Produced			April 30, 2006			185,813			68,968
Total			April 30, 2006			2,631,916			775,246
Produced			April 30, 2007			213,111			54,766
Total			April 30, 2007			2,845,027			830,012

 

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 at April 30, 2007 by Lee Keeling and Associates, Inc., independent petroleum consultants, 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, 2005			93,825			1,249,566
Discoveries and extensions
[Revisions of previous estimates]			3,084			(207,922	)
Production			(5,630	)		(60,914	)
Balance April 30, 2006			91,279			980,730
Discoveries and extensions
[Revisions of previous estimates]			(24,977	)		(224,155	)
Production			(4,898	)		(54,765	)
Balance, April 30, 2007			61,044			701,810
Proved developed producing reserves at April 30, 2007			48,591			624,404
Proved developed producing reserves at April 30, 2006			58,188			686,580

Item 4  Submission of Matters to a Vote of Security Holders

 

No proposals were submitted for approval by our shareholders during the fiscal year ended April 30, 2007.

 

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PART II

Item 5  Market for Common Equity and Related Stockholder Matters

Market Information

 

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

		Bid Prices ($)
		High			Low
Quarter Ended:
July 31, 2006			0.95			0.80
October 31, 2006			0.41			0.40
January 31, 2007			0.35			0.35
April 30, 2007			0.32			0.32
July 31, 2005			1.45			1.20
October 31, 2005			1.24			1.10
January 31, 2006			1.30			1.30
April 30, 2006			1.02			1.00

 Holders

 

There were approximately 368 stockholders of record of our common stock as of April 30, 2007.

 

Dividends

 

Shares Issuable Under Equity Compensation Plans

 

The table below provides information, as of April 30, 2007, concerning securities authorized for issuance under equity compensation plans.

Plan Category		Number of securities to be issued upon exercise of outstanding options, warrants and rights			Weighted average exercise price of outstanding options, warrants and rights			Number of securities Remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
		(a)			(b)			(c)
Equity compensation plans
approved by shareholders			—			—			—
Equity compensation plans not
Approved by shareholders			150,000			0.8142			—
Total			150,000			0.8142			—

Recent Sales of Unregistered Securities

 

None.

 

Share Repurchases

 

None.

 

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

 

Introduction

 

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

Overview

We are actively engaged in the exploration, development, production and acquisition of crude oil and natural gas primarily in eastern Tennessee. In December 2005, we entered into an LLC agreement with Wind City Oil & Gas, LLC (“Wind City”) to form Wind Mill Oil & Gas, LLC (“Wind Mill”). We have a 49.9% interest in Wind Mill and Wind City’s interest is 50.1%. We contributed approximately 43,000 acres, which we held under lease in Tennessee, to Wind Mill for oil and gas exploration, development and exploitation of undeveloped wells. Wind City contributed $10,000,000. The LLC only encompasses new drilling projects. We retain our working interest in the developed and producing wells located on contributed leases. We also retained all additional producing properties. Under certain conditions, the agreement allows for the contributed acreage to return to us upon dissolution of Wind Mill. Relative to the development of wells by Wind Mill, we received reimbursement for certain salaried employees and revenue for providing labor and equipment.  Including the leases that were contributed to the Wind Mill, we have approximately 50,000 acres under lease. About 90% of these leases are held by production. Reimbursement for certain salaried employees and revenue for providing labor and equipment was stopped by Wind City in September 2006.

 

An additional “Stock Purchase” agreement was made with “Wind City” in December 2005, whereby Wind City purchased 2,900,000 shares of Miller stock at $1.50 per share or $4,350,000.00. With the condition of the Operating Agreement being timely terminated, “Wind City” could put the stock back to Miller at the same price. The agreement has a conditional 30 day notice prior to the resell.

 

The Wind Mill LLC drilled eight wells to prove the existence of the field. 4 ½” production casing was run in all of the wells and two wells were fraced to have an adequate production test before continued drilling and construction of the pipeline. The successful tests prompted additional drilling. Koppers South includes 22,000 contiguous acres that will be accessible to a sales line with the construction of a 6 mile pipeline. Koppers South has an 20% net royalty interest for the landowner, leaving an 80% working interest for Wind Mill LLC.

 

The Lindsay Field is located on a 3400 acres contiguous tract with a 40% working interest in an 87 ½% net royalty interest. The Lindsay #9 began producing in March 2002. Our eight wells have produced 580,000 mcf of natural gas, with our first well having produced for less than 1 year.

 

The following wells have been drilled in the Wind Mill, LLC:

 

Edwards - Fowler Unit #1 in Roane Co., Tennessee was drilled January 2006 to 4600 feet with a 37 ½% revenue interest. The well began producing from the Trenton formation into the Powell - Clinch Utility pipeline in August 2006 and in 8 months produced approximately 34,000 mcf of natural gas.

 

In April of 2006, the Hodnett #1 was drilled in Brazoria Co., Texas to 10,800 feet with a 50% working interest. The well was a “dry hole”.

 

In May 2006, the Koppers #34B was drilled to 3060 feet and the 38B to 3720 feet. Both wells are expected to produce commercial quantities of gas. For an accurate evaluation, the 34B was completed in the Devonian Shale only. It “open flow” tested 75 mcf of gas per day after stabilizing within 48 hours. The 38B was completed in both the “Big Lime” and Devonian Shale to “open flow” test 720 mcf of gas per day after 48 hours. These wells proved the economics of continued drilling as well as the construction of a pipeline.

 

In June 2006 the Koppers 36B was drilled to 3250 feet and is expected to be a commercial well. Production casing has been run but not completed pending pipeline completion. The Farmer #1 was drilled to 5660 feet on the Lake City Prospect and resulted in a “dry hole.” The Freeman #1 drilled to 5670 feet on the Lake City Prospect and resulted in a “dry hole.”

 

In July 2006 the Koppers #39B was drilled to 3680 feet and is expected to be a commercial well. Production casing has been run but not completed pending pipeline completion. The Lindsay #19 was drilled to 3960 feet and the Lindsay #20 drilled to 3990 feet. The Lindsay #19 began producing into the pipeline in September 2006 and produced 59,000 mcf of gas in 10 months. The Lindsay #20 was a “dry hole.”

 

In August 2006 the Edwards - Gann Unit #1 was drilled to 4320 feet with a 37 ½% revenue interest. The well had favorable shows of hydrocarbons without commercial quantities. The Koppers #41B was drilled to 3250 feet and #42B drilled to 3369 feet. Both wells are expected to have commercial quantities of gas. Production casing has been run but not completed pending pipeline completion.

 

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In September 2006 the Koppers #43B was drilled to 3780 feet and the Koppers #48B drilled to 3240 feet. Both wells are expected to have commercial quantities of gas. Production casing has been run but not completed pending pipeline construction.

 

The spacing of the Koppers wells defined the gas field with accurate geologic data for contouring. These wells have proven a gas field with additional wells to be drilled into the “Big Lime” with the Devonian Shale serving as a secondary horizon.

 

The Lindsay field has a pipeline in place and is continuing to be a success with production from the “Big Lime” as in the Koppers South. The Lindsay property will support many more wells.

 

The Edwards - Fowler Unit #1 has an upside to the Harriman Prospect with over 3200 acres. Adequate seismic data is available to hedge against dry holes. The Edwards - Fowler Unit #1 proved a reservoir and the Edwards - Gann Unit #1 gave insight as to well placement relative to faulting and structure. Here, a sales line is in place also.

 

Wind City put their 2,900,000 shares of stock in August, 2006. Reimbursement for certain salaried employees and revenue for providing labor and equipment was stopped by Wind City in September 2006. In October 2006, Wind City was advised that the stock repurchase request could not be effective because they had not timely exercised the right under the terms of the contract. As a result, in November 2006, Wind City filed a lawsuit against us in New York. On December 21, 2006 the proceedings were stayed to put the case before arbitration in Tennessee, to determine if the Operating Agreement was properly terminated, thus triggering an obligation on Miller’s part to repurchase the stock. It is expected that the arbitration will take place in December 2007 or January 2008. Miller has filed a counterclaim against Wind City for causing it damages in the amount of $13,000,000 due to its attempt to terminate the LLC without a proper basis and for breach of the contracts. Wind City has likewise filed a claim against Miller for breach of contract, asserting damages in the amount of $10,000,000.

 

Indicative of these proceedings, we recognize a continued opportunity to fully develop the mentioned properties. We have greatly benefited from drilling in the LLC for the continued development of producing properties and discovery of the Koppers South gas field.

 

Results of Operations

For the Fiscal Year Ended		April 30, 2007			April 30, 2006			In(Decrease) 2006 to 2007
REVENUES
Oil and gas revenue		$	509,742		$	810,607		$	(300,865	)
Service and drilling revenue			834,679			1,728,165			(893,486	)
Total Revenue			1,344,421			2,538,772			(1,194,351	)
COSTS AND EXPENSES
Cost of oil and gas revenue			56,072			89,167			(33,095	)
Cost of service and drilling revenue			815,535			1,523,376			(707,841	)
Selling, general and administrative			1,646,788			2,073,322			(426,534	)
Plugged and abandoned wells						624,255			(624,255	)
Depreciation, depletion and amortization			207,082			376,461			(169,379	)
Total Costs and Expenses			2,725,477			4,686,581			(1,961,104	)
INCOME (LOSS) FROM OPERATIONS			(1,381,056	)		(2,147,809	)		766,753
OTHER INCOME (EXPENSE)
Interest expense			1,256			959			297
Interest expense and financing cost			(163,950	)		(1,443,084	)		1,279,134
Total Other Income (Expense)			(162,694	)		(1,442,125	)		1,279,431
NET INCOME (LOSS)		$	(1,543,750	)	$	(3,589,934	)	$	2,046,184

14

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Revenue

 

Oil and gas revenue was $509,742 for the year ended April 30, 2007 as compared to $810,607 for the year ended April 30, 2006, a decrease of $300,865. This decrease resulted from changing oil vendors such that oil production was not picked up for two months and the normal well decline.

 

Service and drilling revenue was $834,679 for the year ended April 30, 2007 as compared to $1,728,165 for the year ended April 30, 2006, a decrease of $893,486. This decrease resulted from the fact that all of the drilling for 2007 was performed in the Wind Mill Joint Venture.  

 

Cost and Expense

 

The cost of oil and gas revenue was $56,072 for the year ended April 30, 2007 as compared to $89,167 for the year ended April 30, 2006, a decrease of $33,095. This decrease resulted from the decrease in oil and gas production.

 

The cost of service and drilling revenue was $815,535 for the year ended April 30, 2007 as compared to $1,523,376 for the year ended April 30, 2006, a decrease of $707,841. This increase is due to the fact that all of the drilling for 2007 was performed in the Wind Mill Joint Venture.

 

Selling, general and administrative expense was $1,646,788 for the year ended April 30, 2007 as compared to $2,073,322 for the year ended April 30, 2006, a decrease of $426,534. This decrease resulted from less stock compensation in 2007.

 

There was no plugged and abandoned wells expense for the year ended April 30, 2007, as compared to $624,255 for the year ended April 30, 2006, a decrease of $624,255. This decrease resulted from the fact that no wells were written off in 2007.

Depreciation, depletion and amortization expense was $207,082 for the year ended April 30, 2007 as compared to $376,461 for the year ended April 30, 2006, a decrease of $169,379. This decrease resulted from less oil and gas production.

 

There was no gain on the sale of equipment for the year ended April 30, 2007 as compared to a gain of $157,562 for the year ended April 30, 2006, a decrease of $157,562.

 

Interest expense and financing cost was $163,950 for the year ended April 30, 2007 as compared to $1,443,084 for the year ended April 30, 2006, a decrease of $1,279,134. This resulted from the fact that Wind City invested $4,350,000 in 2005, which was used to pay down the debt.

		Average Net Production			Sales Price /
Fiscal Year		Gas / MBTU			MBTU
2006			60,914		$	6.94
2007			54,766			5.65

		Average Net
Fiscal Year		Barrels of Oil			Sales Price / Bbl
2006			5,630		$	61.75
2007			4,898			47.88

 

		2005			2006			2007
Net Productive Wells			20.20			22.84			25.66
Developed Acreage			1,480			1,840			2,240
Undeveloped Acreage			41,120			46,920			3,100
Net Productive Exploratory Wells			0			0			0
Net Dry Exploratory Wells			0.30			1.20			0
Net Productive Developmental Wells			1.20			2.64			0
Net Dry Developmental Wells			0			0			0

 

15

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Liquidity

 

Cash used by operating activities was $276,430 for fiscal 2007, a reduction of $1,617,872 from cash provided by operating activities in fiscal 2006 of $1,894,302. Our principal source of liquidity has been oil and gas revenues, loans from related parties and directors, private placement transactions of our common stock, and participation with investors in various oil and gas wells. The increase in oil and gas prices and the fact that we have approximately 50,000 acres under lease in Tennessee enhances our ability to attract investors and to pursue joint ventures in oil and gas.

 

On December 23, 2005 we entered into the Wind Mill Oil & Gas LLC Agreement (“Wind Mill”) and also sold 2,900,000 shares of common stock to Wind City Oil & Gas, LLC (“Wind City”) for $4,350,000. These funds were used to pay off the $4,150,000 of loans and to provide some working capital. Wind City also contributed $10,000,000 to Wind Mill and we contributed oil and gas leases as part of the Wind Mill agreement. For the year ended April 30, 2006 we received $276,491 of administrative salary reimbursements and revenue of $153,096 for various labor, parts and use of equipment. For the year ended April 30, 2007 we received $353,640 in salary reimbursements and $534,944 for equipment, parts and labor.

 

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. We are presently seeking substantial financing to buy Wind City and Wind Mill out of the joint venture, but there can be no assurance that we will be successful in raising this financing. 

 

16

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Item 7 Financial Statements

INDEX TO FINANCIAL STATEMENTS

 

Report of Independent Certified Public Accountants			18
Consolidated Balance Sheets			19-20
Consolidated Statements of Operations			21
Consolidated Statements of Stockholders' Equity			22
Consolidated Statements of Cash Flows			23
Notes to the Consolidated Financial Statements			24-36

 

17

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MILLER PETROLEUM, INC.

CONSOLIDATED FINANCIAL STATEMENTS

    April 30, 2007 and 2006

 

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, 2007 and April 30, 2006 and the related consolidated statements of operations, changes in stockholders’ equity (deficit) and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company has determined that it is not required to have, nor was it engaged to perform, an audit of internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referenced above present fairly, in all material respects, the financial position of Miller Petroleum, Inc. and its Subsidiary as of April 30, 2007 and 2006, and the results of its operations and cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

 

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has suffered recurring losses from operations, and the Company is facing litigation which might require a put placed against the Company calling for the Company to redeem 2,900,000 shares of the Company’s common stock for approximately $4,350,000, which it currently does not have the capability of funding. This raises substantial doubt about the Company’s ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ Rodefer Moss & Co, PLLC

Knoxville, Tennessee

August 13, 2007

18

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Miller Petroleum, Inc.

Consolidated Balance Sheets

		April 30			April 30
		2007			2006
ASSETS
CURRENT ASSETS
Cash		$			$
Accounts receivable			67,276			311,286
Accounts receivable - related parties			180,699			347,060
Note Receivable			7,900			43,000
Inventory			114,691			97,388
Unbilled service and drilling cost			0			76,944
Total Current Assets			370,566			875,678
FIXED ASSETS
Machinery			912,592			880,904
Vehicles			344,427			321,895
Buildings			315,835			315,835
Office equipment			30,083			23,028
			1,602,937			1,541,662
Less: accumulated depreciation			(862,717	)		(782,971	)
Net Fixed Assets			740,220			758,691
OIL AND GAS PROPERTIES			1,462,439			1,576,950
On the basis of successful efforts accounting)
PIPELINE FACILITIES			181,597			193,948
OTHER ASSETS
Investment in joint venture at cost			801,319			801,319
Land			496,500			496,500
Investments			500			500
Well equipment and supplies			427,948			440,712
Cash - restricted			83,000			83,000
Total Other Assets			1,809,267			1,822,031
TOTAL ASSETS		$	4,564,089		$	5,227,298

See notes to consolidated financial statements.

 

19

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Miller Petroleum, Inc.

Consolidated Balance Sheets

		April 30			April 30
		2007			2006
LIABILITIES, TEMPORARY EQUITY
AND PERMANENT STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES
Bank overdraft		$	16,933		$	27,253
Accounts payable - trade			276,783			305,494
Accounts payable - related parties			88,809
Accrued expenses			93,874			43,189
Notes payable - related parties			114,500
Current portion of notes payable			202,234			16,636
Total Current Liabilities			793,133			392,572
LONG-TERM LIABILITIES
Notes payable
Other			326,880			323,898
Total Long-term Liabilities			326,880			323,898
Total Liabilities			1,120,013			716,470
TEMPORARY EQUITY
Common stock, subject to put rights, 2,900,000 shares			4,350,000			4,350,000
PERMANENT STOCKHOLDERS’ EQUITY
Common stock: 500,000,000 shares authorized
at $0.00001 par value, 11,466,856 shares issued
and outstanding			1,146			1,146
Additional paid-in capital			7,936,724			6,624,683
Unearned compensation			(1,587,033	)		(751,990	)
Accumulated deficit			(7,256,761	)		(5,713,011	)
Total Stockholders’ Equity (Deficit)			(905,924	)		160,828
TOTAL LIABILITIES, TEMPORARY EQUITY
AND PERMANENT STOCKHOLDERS’ EQUITY		$	4,564,089		$	5,227,298

 

See notes to consolidated financial statements.

20

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Miller Petroleum, Inc.

Consolidated Statements of Operations

		For the			For the
		Year Ended			Year ended
		April 30,			April 30,
		2007			2006
REVENUES
Oil and gas revenue		$	509,742		$	810,607
Service and drilling revenue			834,679			1,728,165
Total Revenue			1,344,421			2,538,772
COSTS AND EXPENSES
Oil and gas cost			56,072			89,167
Service and drilling cost			815,535			1,523,376
Selling, general and administrative			1,646,788			2,073,322
Impairment loss - plugged and abandoned wells						624,255
Depreciation, depletion and amortization			207,082			376,461
Total Costs and Expenses			2,725,477			4,686,581
INCOME (LOSS) FROM OPERATIONS			(1,381,056	)		(2,147,809	)
OTHER INCOME (EXPENSE)
Interest income			1,256			959
Interest expense and financing cost			(163,950	)		(1,443,084	)
Total Other Expense			(162,694	)		(1,442,125	)
INCOME TAXES
NET LOSS		$	(1,543,750	)	$	(3,589,934	)
BASIC AND DILUTED LOSS PER SHARE		$	(0.11	)	$	(0.33	)
BASIC WEIGHTED AVERAGE NUMBER
OF SHARE OUTSTANDING			14,366,856			10,812,774

 

See notes to consolidated financial statements.

 

21

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MILLER PETROLEUM, INC.

Consolidated Statements of Permanent Stockholders’ Equity

								Additional
		Common			Shares			Paid-in			Unearned			Accumulated
		Shares			Amount			Capital			Compensation			Deficit			Total
Balance, April 30, 2005			9,396,856		$	939		$	4,495,498		$	-		$	(2,123,077	)	$	(2,373,360	)
Issuance of warrants as
prepayment of financing
cost									370,392									370,392
Issuance of warrants for
financing cost penalty									66,000									66,000
Issuance of shares as
payment for services			1,650,000			165			1,682,835			(751,990	)					931,010
Issuance of shares for
sales commission			400,000			40			459,960									460,000
Cost of stock sales									(460,000	)								(460,000	)
Exercise of warrants			20,000			2			9,998									10,000
Net loss for the year
ended April 30, 2006															(3,589,934	)		(3,589,934	)
Balance, April 30, 2006			11,466,856			1,146			6,624,683			(751,990	)		(5,713,011	)		160,828
To reflect compensation
earned for the year ended
April 30, 2007												376,669						376,669
Issuance of warrants for
financing cost penalty									79,000									79,000
Issuance of warrants for
financing cost									40,453			(22,759	)					17,694
Stock options issued									3,635									3,635
Issue of warrants as payment
for services									1,188,953			(1,188,953	)
Net loss for the year ended
April 30, 2007															(1,543,750	)		(1,543,750	)
Balance, April 30, 2007			11,466,856			1,146			7,936,724			(1,587,033	)		(7,256,761	)		(905,924	)

 

See notes to consolidated financial statements.

 

22

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Miller Petroleum, Inc.

Consolidated Statements of Cash Flows

		April 30,			April 30,
		2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss		$	(1,543,750	)	$	(3,589,934	)
Adjustments to Reconcile Net Loss to
Net Cash from Operating Activities:
Depreciation, depletion and amortization			207,082			376,461
Impairment loss - plugged and abandoned wells						624,255
Options issued in exchange for services			100,329			436,392
Common stock issued in exchange for services			376,669			931,010
Write off offering cost						88,842
Changes in Operating Assets and Liabilities:
Accounts receivable			410,371			(475,395	)
Inventory			(4,539	)		(29,999	)
Unbilled service and drilling cost			76,944			(76,944	)
Bank overdraft			(10,320	)		27,253
Accounts payable			60,099			(25,126	)
Accrued expenses			50,695			(181,117	)
Net Cash from Operating Expenses			(276,420	)		(1,894,302	)
CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of equipment			(61,275	)		(139,106	)
Purchase of oil and gas properties			(475	)		(335,905	)
Increase in restricted cash						(12,000	)
Changes in note receivable			35,100			4,000
Net Cash from Investing Activities			(26,650	)		(483,011	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of stock						4,360,000
Adjustment on notes payable			3,580			(6,135,049	)
Proceeds from borrowings			299,500			4,150,000
Net Cash from Financing Activities			303,080			2,374,951
NET (INCREASE) DECREASE IN CASH			0			(2,362	)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR			0			2,362
CASH AND CASH EQUIVALENTS, END OF YEAR		$	0		$	0

 

See notes to consolidated financial statements.

 

23

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Notes to the Consolidated Financial Statements

April 30, 2007 and 2006

NOTE 1 - BASIS OF PRESENTATION, LIQUIDITY AND CONTINUING OPERATIONS

 

a.   Organization and Basis of Presentation

 

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

 

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

 

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

 

b.   Continuing Operations

 

The Company has incurred recurring losses over the past several years, and 2,900,000 shares of the Company’s common stock has been put back to the Company by a major stockholder and joint venture partner.

 

As discussed further in Note 2, Wind City Oil & Gas, LLC has exercised its option to put back its 2,900,000 shares for $4,350,000, and has filed suit in the United States District Court for the Southern District of New York to force the exercise of the put provision of the stock purchase agreement. At present, the Company does not have the resources to repurchase the stock. The Company has engaged financial advisors to obtain financing to repurchase the stock, which will result in the return of all leases transferred to Wind Mill and will allow for the continuation of drilling and development of the Koppers south and other properties.

On August 30, 2006 Wind City notified us of its intent to exercise the put provision of the stock purchase agreement. On November 7, 2006 Wind City filed a lawsuit in the United States District Court for the Southern District of New York (the “Court”) to force the exercise of the put provision. We do not believe the put was properly exercised and filed an application to stay the litigation and force arbitration as is required by the agreements. The litigation was stayed by the Court on December 21, 2006 on the condition that the parties promptly proceed with an arbitration for the purpose of determining if a threshold condition to exercise the put was met. Upon the decision reached in arbitration, the stay will be lifted by the Court and, depending upon the decision reached in arbitration, the Court will proceed to resolve the issues raised in the litigation. An initial arbitration administrative conference was held on March 12, 2007. As of the date of this report, the arbitration date has been mutually extended pending our efforts to raise additional capital in order to buy Wind City out and for additional drilling capital.

The ability of the Company to continue as a going concern is dependent upon the successful completion of the additional financing.

c.   Accounting Method

 

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

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

 

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

 

24

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MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2007 and 2006

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

 

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

 

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

e.   Net Earnings (Loss) per Share:

 

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

 

Since the Company had a net loss for the years ended April 30, 2007 and 2006, the assumed effects of the exercise of the options and warrants to purchase 7,055,000 and 1,550,000 shares of common stock that were outstanding at April 30, 2007 and 2006, respectively, and the application of the treasury stock method would have been anti-dilutive. Therefore, there are no diluted per share amounts in the 2007 and 2006 statements of operations.

 

f.   Cash Equivalents

 

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

 

 g.   Principles of Consolidation

 

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

 

 h.   Fixed Assets

 

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

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

 

Depreciation expense for the years ended April 30, 2007 and 2006 was $92,096 and $101,248 respectively.

25

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MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2007 and 2006

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

 

i.   Revenue Recognition

 

Oil and gas production revenue is recognized as income as production is extracted and sold. Service and drilling income is recognized at the time it is both earned and we have a contractual right to receive the revenue. Turnkey contracts not completed at year end are reported on the completed contract method of accounting. There were no uncompleted contracts at the end of fiscal 2007 and 2006. Retail sales of various parts and equipment is immaterial for the years ended April 30, 2007 and 2006 and has been combined with service and drilling revenue.

 

j.   Concentrations of Credit Risk

 

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

 

Accounts receivable arise from sales of gas and oil, equipment and services. Credit is extended based on the evaluation of the customer’s creditworthiness, and generally collateral is not required. Accounts receivable more than 45 days old are considered past due. The Company does not accrue late fees or interest income on past due accounts. Management uses the aging of accounts receivable to establish an allowance for doubtful accounts. Credit losses are written off to the allowance at the time they are deemed not to be collectible. Credit losses have historically been minimal and within management’s expectations. The allowance for doubtful accounts was $5,183 at April 30, 2007 and April 30, 2006. Accounts receivable more than 90 days old were $177,427 at April 30, 2007 and 58,503 at April 30, 2006. There was no bad debt expense for the year ended April 30, 2007.

 

k.   Inventory

 

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

 

 l.   Well Equipment and Supplies

 

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

 

m.   Estimates

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported on the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The most significant assumptions are for asset retirement obligation liabilities and estimated reserves of oil and gas. Oil and gas reserve estimates are developed from information provided by the Company’s management to Netherland Sewell and Associates, Inc., of Dallas Texas (“NSAI”) for the years ended April 30, 2007 and 2006, respectively.

26

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MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2007 and 2006

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

 

n.   Reclassifications

 

Certain amounts and balances pertaining to the April 30, 2006 financial statements have been reclassified to conform with the April 30, 2007 financial statement presentations.

 

o.   Stock Warrants

 

The Company measures its equity transactions with non-employees using the fair value based method of accounting prescribed by Statement of Financial Accounting Standards No. 123R.

 

p.   Income Taxes

 

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

 

q.   Recent Accounting Pronouncements

 

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

In June 2006, FIN 48, “Accounting for Uncertainty in Income Taxes,” an interpretation of SFAS No. 109, clarifies the accounting for uncertainties in income taxes recognized in an enterprise’s financial statements. The Interpretation requires that we determine whether it is more likely than not that a tax position will be sustained upon examination by the appropriate taxing authority. If a tax position meets the more likely than not recognition criteria, FIN 48 requires the tax position be measured at the largest amount of benefit greater than fifty percent (50%) likely of being realized upon ultimate settlement. This accounting standard is effective for fiscal years beginning after December 15, 2006. The effect, if any, of adopting FIN 48 is not expected to have a material affect on our financial position and results of operations.

 

In September 2006, the Staff of the SEC issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB No. 108”). SAB No. 108 provides guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of determining whether the current year’s financial statements are materially misstated. SAB 108 is effective for the Company’s fiscal year 2007 annual financial statements. The adoption of SAB 108 is not expected to have an impact on our financial position, results of operations or cash flows.

 

In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements” (“SFAS 157”). This standard defines fair value, establishes the framework for measuring fair value in accounting principles generally accepted in the United States and expands disclosure about fair value measurements. This pronouncement applies under other accounting standards that require or permit fair value measurements. Accordingly, this statement does not require any new fair value measurement. This statement is effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We are currently evaluating the requirements of SFAS No. 157 and have not yet determined the impact on our financial statements.

 

27

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MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2007 and 2006

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

 

q.   Recent Accounting Pronouncements (continued)

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FAS 115 (“SFAS No.159”). SFAS No. 159 allows companies to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. Unrealized gains and losses shall be reported on items for which the fair value option has been elected in earnings at each subsequent reporting date. SFAS No. 159 also establishes presentation and disclosure requirements. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007 and will be applied prospectively. We are currently evaluating the impact of adopting SFAS No. 159 on our financial position, results of operations or cash flows.

 

In December 2006, the FASB issued FASB Staff Position No. EITF 00-19-2, Accounting for Registration Payment Arrangements, (“FSP No. EITF 00-19-2”), which addresses an issuer’s accounting for registration payment arrangements. FSP No. EITF 00-19-2 specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB Statement No. 5, Accounting for Contingencies. The guidance in FSP No. EITF 00-19-2 amends FASB Statements No. 133, Accounting for Derivative Instruments and Hedging Activities, and No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, and FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, to include scope exceptions for registration payment arrangements. FSP No. EITF 00-19-2 further clarifies that a financial instrument subject to a registration payment arrangement should be accounted for in accordance with other applicable generally accepted accounting principles (GAAP) without regard to the contingent obligation to transfer consideration pursuant to the registration payment arrangement. FSP No. EITF 00-19-2 shall be effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to the date of issuance of FSP No. EITF 00-19-2. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to the issuance of FSP No. EITF 00-19-2, this guidance shall be effective for financial statements issued for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years. We adopted FSP No. EITF 00-19-2 effective January 1, 2007. We have not had any transactions subject to EITF 00-19-2 since its adoption, so there has been no material impact to the Company’s financial position, results of operations or cash flows.

 

 r.   Major Customers

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

 

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

 

Oil:	South Kentucky Purchasing Co. - South Kentucky purchases some of the Company’s crude oil. South Kentucky accounted for $124,454 of the Company’s total revenue, which was about 9% of the Company’s total revenue.

 

Barrett Oil Purchasing purchases oil from the Koppers Fields. Barrett accounted for $121,436 of the Company’s total revenue, which was about 9% of the Company’s total revenue.

 

Gas:	Cumberland Valley Resources purchases natural gas produced from the joint venture with Delta Producers, Inc. in the Jellico East Field. Delta Producers Inc. accounted for $328,788 of the Company’s total revenue, which was about 24% of the Company’s total revenue.

 

Nami Resources, LLC purchases natural gas from the Jellico Field. Nami Resources, LLC accounted for $94,614 of the Company’s total revenue, which was about 7% of the Company’s total revenue.

 

Other:

Wind Mill Oil & Gas, LLC - Wind Mill accounted for $534,944 of the Company’s drilling and service revenue, which was about 40% of the Company’s total revenue.

 

Daughtery Ptroleum Inc. - Daughtery accounted for $233,024 of the company’s drilling and service revenue, which was about 17% of the Company’s total revenue.

 

28

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MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2007 and 2006

 

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

 

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

 

Under the Wind Mill agreement the Company is reimbursed for administrative salaries and receives revenue for Wind Mill’s use of the Company’s production equipment and employees. For the period from December 23, 2005 to April 30, 2006 the Company received salary reimbursements of $276,491 and drilling and service revenue of $153,096. From May 1, 2006 to April 30, 2007 the Company received $353,640 of salary reimbursement and $534,944 of drilling and service revenue.

 

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

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

 

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

 

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

Litigation

Wind City put back their 2,900,000 shares of stock in August 2006. Reimbursement for certain salaried employees and revenue for providing labor and equipment was stopped by Wind City in September 2006. In October 2006 Wind City was advised that the stock repurchase request could not be effective because they had not timely exercised the right under the terms of the contract. As a result, in November 2006 Wind City filed a lawsuit against the Company in New York. On December 21, 2006 the proceedings were stayed to put the case before arbitration in Tennessee to determine if the operating agreement was properly terminated, thus triggering the obligation on Miller’s part to repurchase the stock. It is expected that arbitration will take place in December 2007 or January 2008. Miller has filed a counterclaim against Wind City for causing it damages in the amount of $13,000,000 due to its attempt to terminate the LLC without a proper basis and for breach of the contracts. Wind City has likewise filed a claim against Miller for breach of contract, asserting damages in the amount of $10,000,000.

As of this date there has been no discovery in the arbitration and at this early stage of the dispute Management is unable to assess the likelihood of an adverse outcome, or the likely range of damages that might be awarded in the event of an adverse verdict. Accordingly, no provision for loss, if any, is reflected in these consolidated financial statements.

NOTE 3 - STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURE

		2007			2006
CASH PAID FOR:
Interest		$	53,247		$	364,625
Loan fees and cost						553,524
NON-CASH FINANCING ACTIVITIES:
Financing costs from issuance of warrants			96,694			436,392
Common stock issued for services			380,304			2,143,000
Deferred Offering Cost						88,842

 

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MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2007 and 2006

 

NOTE 4 - 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 $475 and $335,905 of oil and gas properties for the years ended April 30, 2007 and 2006, respectively, and recorded $114,986 and $275,213 of amortization expense for the years ended April 30, 2007 and 2006, respectively.

NOTE 5 - LONG-TERM DEBT

 

The Company had the following debt obligations at   April 30, 2007 and April 30 2006

 

		2007			2006
Note payable to American Fidelity Bank secured by a trust deed on property, bearing interest at prime, due in monthly payments of $2,500, with the final payment due in August 2008		$	344,114		$	340,534
Note payable to Jade Special Strategy, LLC, unsecured, dated March 7, 2007, bearing interest based on a sliding scale approximating 120% and due September 4, 2007			110,000
Note payable to Jade Special Strategy, LLC, unsecured, dated April 17, 2007, bearing interest based on a sliding scale approximating 120% and due Oct. 15, 2007			40,000
Note payable to Herman Gettlefinger, unsecured, dated February 21, 2007, bearing interest at 11%, and due March 21, 2007			42,000
Note payable to Sharon Miller, unsecured, dated January 7, 2007 to April 11, 2007, bearing interest at 11%, due on demand			72,500
Note payable to Petro Capital Securities, unsecured, dated May 24, 2007 bearing interest at 10%, and due June 30, 2008			35,000
Total Notes Payable		$	643,614		$	340,534
Less current maturities			316,734			16,636
Notes Payable - Long-term		$	326,880		$	323,898

 NOTE 6 - RELATED PARTY TRANSACTIONS

 

At April 30, 2007 and 2006 the Company has an account receivable from Wind Mill in the amount of $177,023 and $294,038, respectively; and an account receivable from Herman Gettlefinger, a member of the board of directors, and his wife in the amount of $3,676 and $53,062, respectively. The Company also received salary reimbursement and compensation from Wind Mill as discussed in Note 2.

 

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

The Company had a note payable to Sharon Miller (wife of Deloy Miller, majority stockholder) for $72,500 and a note payable to Herman Gettlefinger for $42,000 at April 30, 2007. These notes are included in current liabilities.

30

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MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2007 and 2006

 

NOTE 7 - ASSET RETIREMENT OBLIGATION

 

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

 

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

Asset retirement obligation as of April 30, 2005		$	15,196
Accretion expense for 2006			2,353
Asset retirement obligation as of April 30, 2006			17,549
Accretion expense for 2007			16,000
Asset retirement obligation as of April 30, 2007		$	33,549

 

NOTE 8 - ASSET IMPAIRMENT - PLUGGED AND ABANDONED WELLS

 

In connection with the assignment of leases to Wind Mill as discussed in Note 2, management assessed the remaining oil and gas properties and determined that $624,222 of well and lease cost should be written off as impaired at June 30, 2006.

 

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:

		2007			2006
Current Year Addition:
Federal statutory rate		34		%	34		%
Federal tax benefit at statutory rate		$	520,000		$	1,220,000
State income tax, net of benefit			68,700			126,000
Stock compensation			(128,000	)		(93,000	)
Stock warrants			(34,100	)		(126,000	)
			426,600			1,127,000
Increase in valuation allowance			(426,600	)		(1,127,000	)
Increase in deferred tax asset and valuation allowance		$	0		$	0
Cumulative Tax Benefit:
Net operating loss carryforward		$	2,964,600		$	2,452,000
Stock warrants			40,000			125,000
Valuation allowance			(3,004,600	)		(2,578,000	)
Net deferred tax benefit		$	0		$	0

 

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MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2007 and 2006

 

 

		2007						2006
		Weighted Shares			Average Exercise Price			Weighted Shares			Average Exercise Price
Options outstanding,
beginning of year			1,550,000		$	0.81			540,000		$	1.30
Options canceled			200,000			2.00			170,000			1.01
Options exercised			-			-			20,000			0.50
Options granted			5,705,000			.53			1,200,000			0.61
Options outstanding,
end of year			7,055,000		$	.38			1,550,000		$	0.81
Options exercisable,
end of year			2,055,000		$	0.77			1,550,000		$	0.81
Option price range,
end of year					$$	0.21 to $1.15					$	0.50 to 1.12
Option price range,
exercised shares						n/a						n/a
Options available for grant
at end of year												n/a
Weighted average fair value of
options granted during the year					$	0.23						1.12

 

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MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2007 and 2006

NOTE 11 - CONTINGENCIES

 

In addition to the contingency discussed in note 2 regarding the Wind City litigation, the Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control in the United States. The company cannot predict what effect future regulations or legislation, enforcement policies, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities. Although no assurances can be made, the Company’s management believes that absent the occurrence of an extraordinary event, compliance with existing laws, rules and regulations regulating the release of materials in the environment or otherwise relating to the protection of the environment will not have a material effect upon the Company’s financial position.

 

NOTE 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 - SUBSEQUENT EVENTS

Notes Payable to Jade Special Strategies, LLC

On August 2, 2007 the Company borrowed an additional $65,000 from Special Strategies, LLC bearing interest based on a sliding scale approximating 120%, due October 30, 2007. As part of this borrowing, upon closing the Company issued 100,000 shares of restricted common stock to Jade Special Strategies, LLC.

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

(1) Capitalized Costs Relating to Oil and Gas Producing Activities at April 30, 2007 and 2006 are as follows:

		2007			2006
Proved oil and gas properties and related lease equipment
Developed		$	2,783,855		$	2,776,181
Non-developed						7,199
			2,783,855			2,783,380
Accumulated depreciation and depletion			(1,258,830	)		(1,206,430	)
Net Capitalized Costs		$	1,525,025		$	1,576,950

 

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MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2007 and 2006

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

 

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

		2007			2006
Acquisition of Properties Proved and Unproved		$	-		$	-
Exploration Costs			-			-
Development Costs			474			335,905
Total		$	474		$	335,905

 

(3)  Results of Operations for Producing Activities

		2007			2006
Production revenues		$	509,742		$	810,607
Production costs			56,072			89,167
Depreciation and amortization			144,496			275,313
Results of operations for producing activities
(excluding corporate overhead and interest costs)		$	309,174		$	446,127

 

(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.

 

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MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2007 and 2006

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

 

		Oil (Bbls)			Gas (Mcf)
Proved reserves
Balance, April 30, 2005			93,825			1,249,566
			-
Revisions of previous estimates			3,084			(207,922	)
Production			(5,630	)		(60,914	)
Balance, April 30, 2006			91,279			980,730
Discoveries and extensions
Revisions of previous estimates			(25,337	)		(224,155	)
Productions			(4,898	)		(54,765	)
Balance, April 30, 2007			61,044			701,810
Proved developed producing
reserves at April 30, 2007			48,591			624,404
Proved developed producing
reserves at April 30, 2006			58,188			686,580

 

In addition to the proved developed producing oil and gas reserves reported in the geological and engineering reports, the Company holds ownership interests in various proved undeveloped properties. The reserve and engineering reports performed for the Company were by Netherland Sewell and Associates, Inc. for the years ended April 30, 2007 and April 30, 2006. 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 as soon as possible. However, such timing as well as the actual financing arrangements that will be secured by the Company is uncertain at this time.

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, 2007 and 2006. Estimated future cash flows were based on independent reserves evaluation from Netherland Sewell & Associates, Inc. for the years ended April 30, 2007 and April 30, 2006. Because the standardized measure of future net cash flows was prepared using the prevailing economic conditions existing at April 30, 2007 and 2006, 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, 2007 and 2006 were $55.77 and $61.75 per barrel of oil and $7.15 and $6.94 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.

 

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MILLER PETROLEUM, INC.

Notes to the Consolidated Financial Statements

April 30, 2007 and 2006

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

 

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.

 

		2007			2006
Future cash flows		$	8,422,828		$	12,208,700
Future production costs and taxes			(2,402,638	)		(1,761,100	)
Future development costs			(13,900	)		(160,500	)
Future income tax expense			(1,861,950	)		(3,189,000	)
Future cash flows			4,144,340			7,098,100
Discount at 10% for timing of cash flows			(2,144,700	)		(3,965,360	)
Discounted future net cash flows
from proved reserves		$	1,999,640		$	3,132,740

Of the Company’s total proved reserves as of April 30, 2007 and 2006, approximately 83% and 57%, respectively, were classified as proved developed producing, 17% and 31%, respectively, were classified as proved developed non-producing and 0% and 12%, 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, 2007 and 2006.

 

		April 30,
		2007			2006
Balance, beginning of year		$	3,132,740		$	3,480,636
Sales, Net of production costs and taxes			(453,670	)		(721,440	)
Changes in prices and production costs			1,008,950			1,358,851
Revisions of quantity estimates			(3,015,904	)		(1,251,928	)
Development costs incurred			474			335,905
Net changes in income taxes			1,327,050			(69,284	)
Balances, end of year		$	1,999,640		$	3,132,740

 

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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, 2007, 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		60		Director and Chief Executive Officer
Ernest Payne		60		President
Lyle H. Cooper		64		Chief Financial Officer
Gary Bible		57		Vice President of Geology
Teresa Cotton		44		Secretary and Treasurer
Charles M. Stivers		45		Director
Herman E. Gettlefinger		74		Director

 

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Business Experience

 

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

  

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

 

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

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

 

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

 

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

 

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

 

Term of Office

 

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

 

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Audit Committee Financial Expert

 

We have an audit committee consisting of Deloy Miller, Herman Gettelfinger and Charles Stivers. Our board of directors has determined that Mr. Stivers is an “audit committee financial expert” based on his qualification as a certified public accountant and his prior experience. Mr. Stivers is a member of the Board and is not independent.

 

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. Copies of our Code of Conduct may be obtained without charge by written request to our Secretary, Teresa Cotton, at Miller Petroleum, Inc., 3651 Baker Highway, Huntsville, TN 37756.

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 2007.  

 

Name and Principal Position		Year			Salary			Bonus			Stock Awards			Option Awards			Non-Equity Incentive Plan Compensation			Non-Qualified Deferred Compensation Earnings			All Other Compensation			Total
Deloy Miller Chief Executive Officer			2007		$	200,000			0			0			0			0			0			0		$	200,000

 

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

 

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

 

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. No attendance fees were paid to directors for the fiscal year ended April 30, 2007.