TABLE OF CONTENTS

Various statements in this annual report contain or may contain forward-looking statements that are subject to known and unknown risks, uncertainties, and other factors which may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These forward-looking statements were based on various factors and were derived from utilizing numerous assumptions and other factors that could cause our actual results to differ materially from those in the forward-looking statements. These factors include, but are not limited to the following:

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the capital intensive nature of oil and gas development and exploration operations and our ability to raise adequate capital to fully develop our operations and assets,

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our ability to perform under the terms of the Assignment Oversight Agreement with the Alaska DNR, including meeting the funding commitments of that agreement,

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fluctuating oil and gas prices and the impact on our results of operations,

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our ability to secure an extension of the Susitna Basin Exploration License,

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the impact of the global economic crisis on our business,

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the impact of natural disasters on our Cook Inlet Basin operations,

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the imprecise nature of our reserve estimates,

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our ability to recover proved undeveloped reserves and convert probable and possible reserves to proved reserves,

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the possibility that present value of future net cash flows will not be the same as the market value,

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the costs and impact associated federal and state regulations,

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changes in existing federal and state regulations,

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our dependence on third party transportation facilities,

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insufficient insurance coverage,

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conflicts of interest related to our dealings with MEI,

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cashless exercise provisions of outstanding warrants,

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market overhang related to restricted securities and outstanding options, warrants and convertible notes,

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adverse impacts on the market price of our common stock from sales by the selling security holders.

Most of these factors are difficult to predict accurately and are generally beyond our control. You should consider the areas of risk described in connection with any forward-looking statements that may be made herein. Readers are cautioned not to place undue reliance on these forward-looking statements, and readers should carefully review this annual report in its entirety, including the risks described in Item 1A. Risk Factors. Except for our ongoing obligations to disclose material information under the Federal securities laws, we undertake no obligation to release publicly any revisions to any forward-looking statements, to report events or to report the occurrence of unanticipated events. These forward-looking statements speak only as of the date of this annual report, and you should not rely on these statements without also considering the risks and uncertainties associated with these statements and our business.

OTHER PERTINENT INFORMATION

We maintain our web site at www. millerenergyresources.com. Information on this web site is not a part of this prospectus.

Unless specifically set forth to the contrary, when used in this prospectus the terms “Miller," "we", "us", "our", and similar terms refer to Miller Petroleum, Inc., a Tennessee corporation doing business as Miller Energy Resources, and its subsidiaries.

Oil wells drilled in this area range from 9,000 vertical feet to 10,000 vertical feet in depth while gas wells have a vertical depth of 8,000 feet to 9,000 feet. Wells that are deviated (continue on from the vertical depth either diagonally or horizontally) will have a longer measured depth of approximately 5,000 feet giving total measured depth of 14,000 feet to 15,000 feet. Well spacing is quite variable, as there are large parts of Cook Inlet which are completely undeveloped, and others, that are more mature. Our fields have approximately 60 to 80 acre spacing. The Cook Inlet basin contains a thick section of terrestrial Tertiary rocks which includes shales, sandstones, and coals. The primary targets in the area are crude oil reserves.

Susitna Basin Exploration License

Included in the Alaskan assets we acquired is a 100% interest in an Exploration License granted by the State of Alaska in October 2005 covering approximately 471,474 acres in the Susitna basin area north of Anchorage, Alaska. Under the terms of the Exploration License, the licensee was granted a five year exclusive license to explore for oil and gas on the specified lands, and upon fulfillment of the work commitment, the license for all or any part of the land could be converted into oil and gas leases. The original work commitment of approximately $3.5 million was fulfilled, and we have the right at any time to covert the license for all or any portion of the acreage into oil and gas leases at any time. Once the exploration license is converted into oil and gas leases, we are required to pay a per acre fee to the state and commence drilling operations within specified timeframes. In an effort to control the timing of the development of this acreage, in April 2010 we requested a three year extension of the exploration license for a work commitment of $750,000. While we reasonably believe the state will grant our request for extension, there are no assurances we are correct, or that if granted, that the terms and conditions of the extension will be satisfactory to us. If we are unable to negotiate an extension, it is likely we will convert the license for only a portion of the land into oil and gas leases.

Osprey Platform

Included in the assets acquired from Pacific Energy was the Osprey platform which is located in the Redoubt Unit approximately 1.8 miles southeast of the West Foreland in central Cook Inlet at a water depth of approximately 45 feet. The Osprey platform, which produces from the Redoubt Unit is connected to our Kustatan Production Facility by two eight-inch and one six-inch pipeline and one power cable. It relies on our Kustatan Production Facility, which is currently inactive, and our West McArthur River Unit Production Facility to provide all of its electricity and gas, and the Kustatan Production Facility to process all of Osprey's produced fluids. The platform has 21 slots, eight of which are currently used, and an attached 40 man camp. The platform is currently inactive.

The Osprey platform was placed on site during June 2000 and it initially conducted exploration drilling operations between January 2001 and July 2002. Eight wells were drilled, which in their present configuration consist of one water flood well, one Class I injection well, and six oil wells. The oil wells were equipped with electrical submersible pumps which were necessary to bring the oil to surface. In 2005, the third-party drilling rig was removed from the platform after a contract dispute. The removal of the rig crippled the ability to maintain and repair the platform’s wells or to expand production. Shortly afterwards, a series of mechanical problems took much of the platform’s production offline and these problems could not be corrected without a rig present. Reduced production was temporarily restored by deploying jet pumps, which can provide artificial lift, but do not require a rig; however, production continued to fall, and the Osprey platform was shut-in in the spring of 2009.

In order to restore production from the Redoubt Unit, it will be necessary to mobilize a drilling rig to the Osprey platform and repair six wells. We believe that past experience suggests that a rig should be permanently located on the platform. Two of these wells require only the replacement of the electrical submersible pumps, and the other four wells require re-drilling in sections. We estimated that the total cost of restoring production, including the purchase of a drill rig, is approximately $35 million.

Assignment Oversight Agreement

On November 5, 2009, Cook Inlet Energy, LLC entered into an Assignment Oversight Agreement with the Alaska DNR which set out certain terms under which the Alaska DNR would approve the assignment of certain specified state oil and gas leases from Pacific Energy Resources to Cook Inlet Energy. This agreement remains in place following our acquisition of Cook Inlet Energy in December 2009. Generally, the agreement requires Cook Inlet Energy to provide the Alaska DNR with additional information and oversight authority to ensure that Cook Inlet Energy is acting diligently to develop the oil and gas from Redoubt Shoal, West McArthur River Field and West Foreland Field. Under the terms of the agreement, until the Alaska DNR determines, in its sole discretion, that Cook Inlet Energy has completed its development and operation obligations under the assigned leases, Cook Inlet Energy agreed to the following:

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file a monthly summary of expenditures by oil and gas filed, tied to objectives in Cook Inlet Energy’s business plan and plan of development previously presented to the Alaska DNR,

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meet monthly with the Alaska DNR to provide an update on operations and progress towards meeting these objectives,

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notify the Alaska DNR 10 days prior to commitment when Cook Inlet Energy is preparing to spend funds on a purchase, project or item of more than $100,000 during the first 12 months, more than $1 million during the second 12 months and more than $5 million thereafter, and

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submit a new plan of development and plan of operations for the Alaska DNR’s approval on or before December 15, 2009 and submit a plan of development annually thereafter on or before February 1, 2010. Cook Inlet Energy timely met both of these deadlines.

The agreement required Cook Inlet Energy to obtain financing in the minimum amount of $5,150,000 to provide funds to be used for expenditures approved by the Alaska DNR as part of Cook Inlet Energy’s plan of development. The funds are to be used for workover and repair of the wells, repair of the physical infrastructure, construction of a grind and inject plant at the West McArthur River facility, normal operating expenses associated with the leases and infrastructure and other capital project which are to be pre-approved by the Alaska DNR. The agreement also required Cook Inlet Energy to demonstrate funding commitments to support restoration of the base production at the Redoubt Unit, including bringing a number of the shut-in wells back on line, which was estimated at $31 million in the agreement but which we have internally increased to $35 million to accommodate the purchase of a drilling right. These funding commitments necessary under the agreement were provided to us under the terms of the Vulcan Capital Corporation, LLC letter agreement described earlier in this annual report. We have subsequently provided these funds through for the West McArthur River facility using a portion of the proceeds of our capital raising efforts described elsewhere herein, and intend to seek alternative sources of funding for the balance of the necessary capital.

Cook Inlet Energy is prohibited from using any of the approximate $36.15 million or any proceeds from the operations under the assigned leases of the funding commitments for non-core oil and gas activities under the assigned leases, or any activities outside the assigned leases, without the prior written approval of the Alaska DNR until the parties mutually agree that the full dismantlement obligation under the assigned leases is funded. The assigned leases will be subject to default and termination should Cook Inlet Energy fail to submit the information required under the agreement and expenditure of funds for items or activities do not support core oil and gas activities, as reasonably determined by the Alaska DNR.

Recent Developments

Cook Inlet Energy, LLC was one of nine successful bidders in State of Alaska’s Division of Oil & Gas Cook Inlet Areawide 2010 Competitive Oil and Gas Lease Sale. There were 38 bids for 36 tracts covering an estimated 144,640 acres of State of Alaska oil and gas acreage. Cook Inlet Energy bid on seven tracts and was the successful high bidder on each of those tracts which cover an estimated 27,520 acres. Cook Inlet Energy’s winning bid for these seven tracts was $908,800. Cook Inlet Energy paid a deposit of $181,767 at the time of the auction and the balance will be due once the title work is complete which we presently anticipate to be in January 2012. All of Cook Inlet Energy’s bids completed acreage positions covering prospects acquired in its purchase of a portfolio of Pacific Energy Alaska assets late last year.

Membership in Cook Inlet Spill Prevention and Response, Inc.

Cook Inlet Energy is a Class G member of the Cook Inlet Spill Prevention and Response, Inc., which we refer to as CISPRI. CISPRI is a non-profit corporation formed in 1990 to provide oil spill prevention and response capabilities in Cook Inlet. CISPRI has been designated as a Class "E" Oil Spill Removal Organization by the U.S. Coast Guard, which is the highest level of designation based on spill containment and removal equipment requirements for offshore/ocean response. CISPRI's response zone includes the entire Cook Inlet Region, stretching from Palmer to the Barren Islands and out into the Gulf of Alaska. At each annual meeting of CISPRI members adopt a budget for the coming year which includes funds for day to day operational activities of CISPRI, investments in capital equipment and materials to be used in connection with the cleanup activities and research and development and training. The budget is funded though payment of dues by the members and the amount of dues is calculated in accordance with a participation formula. Class G members pay an annual fee of $10,000 together with additional fees based upon the amount of oil we transport.

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Cook Inlet Energy may resign its membership in CISPRI upon 30 days written notice. At the effective date of the resignation, Cook Inlet Energy is obligated to pay all unpaid dues and assessments levied prior to the notice of resignation. Cook Inlet Energy’s membership may be terminated by the Board of Directors of CISPRI upon 60 days notice if its determined Cook Inlet Energy is no longer eligible for membership. Cook Inlet Energy would not be entitled to a refund of any monies paid to CISPRI.

Appalachian Region

We own approximately 54,506 gross acres of leasehold interests with 185 producing oil wells and 334 producing gas wells in which we own an interest. Wells drilled in this area range from 1,800 to 4,200 feet in depth and the well spacing is generally from 20 to 40 acres per well and are predominately in Fort Payne formation.

The following table provides information on our reserves at April 30, 2010.

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Under recent SEC rules we are now also permitted to provide information about probable and possible reserves. As set forth above, prior to 2010 our reserve reports did not contain any estimates on probable or possible reserves. “Probable reserves” are additional reserves that are less certain to be recovered than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered. “Possible reserves” are additional reserves that are less certain to be recovered than probable reserves. The various reserve categories have different risks associated with them. Proved reserves are more likely to be produced than probable reserves and probable reserves are more likely to be produced than possible reserves. Because of these risks, the different reserve categories should not be considered to be directly additive.

Our reserve estimates for oil and natural gas at April 30, 2010 for our Cook Inlet assets were prepared by Ralph E. Davis Associates, Inc., an independent engineering firm, and our reserve estimates for oil and gas at April 30, 2010 for our Appalachian region assets were prepared by Lee Keeling and Associates, Inc., an independent engineering firm. Both of these reserve reports which are filed as exhibits to this annual report, were prepared in accordance with the generally accepted petroleum engineering and evaluation principles and most recent definitions and guidelines established by the SEC. All reserve definitions comply with the applicable definitions of the rules of the SEC. The reserves were estimated using engineering and geological methods widely accepted in our industry. The accuracy of the reserve estimates is dependent upon the quality of available data and upon independent geological and engineering interpretation of that data. For proved developed producing, the estimates considered to be definitive, using performance methods that utilize extrapolations of various historical data including oil, gas and water production and pressure history. For other than proved producing, proved undeveloped reserves and probable and possible reserve estimates were made using volumetric methods.

Our policies regarding internal controls over reserve estimates require reserves to be in compliance with the SEC definitions and guidance and for reserves to be prepared by an independent engineering firm under the supervision of our Chief Financial Officer. We provide the engineering firm with estimate preparation material such as property interests, production, current operation costs, current production prices and other information. This information is reviewed by our Chief Executive Officer and our Chief Financial Officer to ensure accuracy and completeness of the data prior to submission to our third party engineering firm. A letter which identifies the professional qualifications of each of the independent engineering firms who prepared the reserve reports are included in those reserve reports which are filed as exhibits to this annual report. There was no conversion of undeveloped reserves to proved reserves during the fiscal year ended April 30, 2010.

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Each of the engineering reports also projected future net income (FNI) from our net reserves and the present value, discounted at 10% per annum, of that future net income FNI @ 10% as summarized in the following table. Future net income is based upon gross income from future production, less direct operating expenses and taxes. Estimated future capital for development costs was also deducted from gross income at the time it will be expended. No allowance was made for depletion, depreciation, income taxes or administrative expense. In the following table, the price per barrel of oil was $73.01 and the price per MMcf of natural gas was $4.84 for the Cook Inlet reserves and $71.85 per barrel of oil and $5.15 per MMcf of natural gas for the Appalachian region reserves. In each instance these prices are computed in accordance with the SEC’s rule and represent the average fiscal year prices.

At April 30, 2010 our standardized measure of discounted future net cash flows for proved reserves was $315,679,195. The present value of future net pre-tax cash flows attributable to estimated net proved reserves, discounted at 10% per annum, (“PV-10”) is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at April 30, 2010. PV-10 may be considered a non-GAAP financial measure under the SEC’s regulations. We believe PV-10 to be an important measure for evaluating the relative significance of our natural gas and oil properties. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. We further believe investors may utilize our PV-10 as a basis for comparison of the relative size and value of our reserves to other companies. However, PV-10 is not a substitute for the standardized measure. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our natural gas and oil reserves.

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^(a)

The number of gross wells is the total number of wells in which a working interest is owned.

^(b)

The number of net wells is the sum of fractional working interests we own in gross wells expressed as whole numbers and fractions thereof.

Our staff of professional geologists is responsible for identifying areas with potential for economic production of natural gas and oil. They utilize results from logs, seismic data and other tools to evaluate existing wells and to predict the location of economically attractive new natural gas and oil reserves. To further this process, we have collected and continue to collect logs, core data, production information and other raw data available from state and private agencies and other companies and individuals actively drilling in the regions being evaluated. From this information, the geologists develop models of the subsurface structures and formations that are used to predict areas for prospective economic development.

On the basis of these models, we obtain available natural gas and oil leaseholds, farm-outs and other development rights in these prospective areas. In most cases, to secure a lease, we pay a lease bonus and an annual rental payment, converting to a royalty upon initial production. In addition, overriding royalty payments may be granted to third parties in conjunction with the acquisition of drilling rights initially leased by others.

We believe that we hold good and defensible title to our developed properties, in accordance with standards generally accepted in the industry. As is customary in the industry, a preliminary title examination is conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial work is performed with respect to discovered defects which we deem to be significant. Title examinations have been performed with respect to substantially all of our producing properties.

Certain of the properties we own are subject to royalty, overriding royalty and other outstanding interests customary to the industry. The properties may also be subject to additional burdens, liens or encumbrances customary to the industry, including items such as operating agreements, current taxes, development obligations under natural gas and oil leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with the use of the properties.

The following table presents, by operating area, leased acres or acreage subject to the Susitna Basin Exploration License as of April 30, 2010.

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Our current efforts are focused on reworking certain of the wells in Cook Inlet and we do not currently have any ongoing drilling operations in either the Appalachian region or Cook Inlet, other than the workover of the wells in Alaska as described elsewhere herein. Much of the work associated with drilling, completing and connecting wells, including fracturing, logging and pipeline construction is performed by subcontractors, under our direction, specializing in those operations, as is common in the industry. When judged advantageous, we acquire materials and services used in the development process through competitive bidding by approved vendors. We also directly negotiate rates and costs for services and supplies when conditions indicate that such an approach is warranted.

Principal markets and principal customers

The existing markets for natural gas production in south central Alaska are the Tesoro Nikiski Refinery, utility companies, petrochemical manufacturing, the production of liquefied natural gas (LNG) for export to Alaskan or Asian markets, and the production of synthetic crude oil (“syncrude”). Presently, the sole market for our crude oil produced at our Alaskan operations is the Tesoro Nikiski Refinery. Crude oil is shipped by pipeline and tanker vessel to the Tesoro Nikiski refinery, operated by Tesoro Alaska Petroleum Company. The main export pipeline is operated by the Cook Inlet Pipeline Company, which is operated by Chevron Pipelines and tanker vessels operate under contract to Tesoro.

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As of July 25, 2010 all natural gas produced by Cook Inlet Energy was used by it to generate heat and power at its production facilities. At such time as gas production exceeds Cook Inlet Energy’s internal needs, it can sell the excess production as all of Cook Inlet Energy’s gas wells are connected to the south central Alaska Railbelt pipeline network through the Cook Inlet Gas Gathering System and/or the Beluga Pipeline, both of which are operated by Marathon Pipelines.

The principal markets for our crude oil and natural gas produced in the Appalachian region are refining companies, utility companies and private industry end users.  Crude oil is stored in tanks at the well site until the purchaser retrieves it by tank truck.  Direct purchases of our crude oil are made statewide at our well sites by 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 three companies in northeastern Tennessee, including Cumberland Valley Resources, NAMI Resources Company, and Tengasco. Local markets in Tennessee are served by Citizens Gas Utility District and the Powell Clinch Utility District.  Natural gas is delivered to the purchaser via gathering lines into the main gas transmission line. Surplus gas is placed in storage facilities or transported to East Tennessee Natural Gas which serves Tennessee and Virginia.  In 2010 and 2009, sales to Barrett Oil Purchasing and Sunoco, collectively, represented approximately 9% and approximately 24%, respectively, of our total revenues and sales to Cumberland Valley Resources, which purchases natural gas produced from a joint venture with Delta Producers, Inc., accounted for approximately 21% of our total revenue for 2009 and approximately4% of our total revenue in 2010.

The following table presents information regarding production volumes and revenues, average sales prices and costs, after deducting royalties and interests of others, with respect to oil and gas production attributable to our interest for the last three years. In the following table, average production cost are costs incurred to operate and maintain the wells and equipment and to pay the production costs, which does not include ad valoreum and severance taxes per unit of production, and is exclusive of work-over costs.

We must currently pay a $14.57 per barrel Cook Inlet Pipe Line tariff to the Drift River Terminal and a minimum of 5% in royalties to the State of Alaska from any oil or gas sold from the West McArthur River Unit and the Redoubt Unit, although with increased production at the West McArthur River Unit these escalate to a maximum of 12.5%. The Redoubt Unit is scheduled to have an increased royalty rate of 12.5% in 2012, unless we can negotiate a reduced rate. We are currently in royalty discussions with the State of Alaska, Division of Natural Resources and hope there will be a reduction. We have also protested the increase in the Cook Inlet Pipe Line tariff, that was increased from $4.06 per barrel to the current rate following the 2009 eruption of Mount Redoubt that

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Our contract drilling operations

We provide land drilling services on a contract basis in the domestic market to customers that are primarily engaged in oil and natural gas exploration and production. The market that we serve is primarily the Appalachian Basin, which has unconventional natural gas bearing formations. Natural gas production from unconventional formations, including tight sands, shales and coalbed methane, is both the largest and fastest growing component of U.S. natural gas production. In addition to vertical drilling, we anticipate the need for horizontal drilling, which increases exposure of the wellbore to gas-bearing formations and provides better drainage. The horizontal drilling rigs contemplated for this are specially equipped for this type of work, as they typically require air circulation systems for penetrating through hard rock and enhanced fluid circulation systems for drilling horizontally into natural gas bearing formations. We plan to contract out the horizontal drilling operations in order to be able to provide this service.

Our services range from contract drilling by the foot or day rate to offering turnkey services to our customers. Our services are typically limited to the drilling portion of oil and gas extraction. Thus, when offering turnkey solutions, we will contract out the non-drilling functions such as possibly horizontal drilling and fracturing to non-affiliated third parties. We are responsible for the costs of rig refurbishment.

During calendar year 2010, in addition to providing drilling services for our other subsidiaries, we expect our wholly owned subsidiary Miller Drilling TN, LLC to drill, as needed, under contract in connection with our agreement to satisfy the two year drilling contract that it has with Atlas Energy. In addition, through our relationship with Atlas Energy, Miller Drilling has the opportunity to bid on other drilling or service work that Atlas Energy bids on in the State of Tennessee.

We are dependent on local customers for drilling revenues. Five customers, Atlas Energy Resources, LLC, Tri-Global Holdings, LLC, Montello Resources, LLC, Delta Producers Inc. and Herman Gettelfinger, a member of our Board of Directors, accounted for approximately 35% and approximately 94%, respectively, of our service and drilling revenue for 2010 and 2009.

Competition

Our oil and gas exploration activities in Alaska and 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 doing business in Alaska, Tennessee and elsewhere, including large oil and gas companies and other independent operators, many with greater financial resources than we have.

At the local level, as we seek to expand our lease holdings, we compete with several companies who are also seeking to acquire leases in the areas of the acreage which we have under lease. In Alaska, we have eight significant competitors including Aurora Gas, Bucaneer Alaska, Chevron, ConocoPhillips, Escopeta Oil, XTO, Linc Energy, and Marathon. However, we believe we have a competitive edge because we already have existing oil and gas production, facilities, infrastructure, and pipelines that connect us to the oil and gas markets as well as some of the lowest operating cost in the area. We believe that our existing Alaska oil and gas reserves and current leases with large acreage positions, enhance our competitive position within the area and will enable us to effectively compete for additional lease acreage with our competitors. In the Appalachian region, we have six significant competitors including Atlas Energy Resources, LLC, Consol Energy, Inc., Can Argo Energy Corporation, 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. We believe we can effectively complete for leases, however, as in the Appalachian region we have name recognition over 40 years, we are the largest operator of oil and gas wells in Tennessee and we have a staff of experienced, proven petroleum geologists and engineers that allows us to exploit the potential the Appalachian region provides.

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Government Regulation

While the prices of oil and natural gas are set by the market, other aspects of our business and the industry in general are heavily regulated. The availability of a ready market for oil production and natural gas depends on several factors beyond our control. These factors include regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to protect consumers from unfair treatment and oppressive control, to reduce the risk to the public and workers from the drilling, completion, production and transportation of oil and natural gas, to prevent waste of oil and natural gas, to protect rights among owners in a common reservoir and to control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies.

Our exploration and production business is subject to various federal, state and local laws and regulations on the taxation of natural gas and oil, the development, production and marketing of natural gas and oil and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, water discharge, prevention of waste and other matters. Prior to commencing drilling activities for a well, we must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies in the state in which the area to be drilled is located. The permits and approvals include those for the drilling of wells. Additionally, other regulated matters include the following:

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bond requirements in order to drill or operate wells;

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the location of wells;

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the method of drilling and casing wells;

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the surface use and restoration of well properties;

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the plugging and abandoning of wells; and

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the disposal of fluids.

The Regulatory Commission of Alaska regulates the intrastate pipeline tariffs and encompasses all pipelines Cook Inlet Energy ships through including the CIPL, CIGGS, and Beluga lines. The Regulatory Commission of Alaska must also review and approve most major gas sales contracts, and through this mechanism plays the dominant role in determining gas pricing, since Alaska has no spot market for gas.

Alaska law requires that we obtain state permits for the drilling of wells and to post a $200,000 bond with the Alaska Oil and Gas Conservation Commission. Injection wells are regulated by the Alaska Oil and Gas Conservation Commission and the United States Environmental Protection Agency (“EPA”). A $490,000 abandonment escrow is established for two Class 1 non-hazardous injection wells for benefit of EPA. These funds are held by the First National Bank of Alaska in escrow accounts currently on deposit. There are also many additional obligations to landholders, which are the Alaska DNR, Cook Inlet Region, Inc. (“CIRI”), Salamatof Native Association and the United States Bureau of Land Management (“BLM”). The Alaska DNR requires $600,000 in bonding to operate of Alaskan oil and gas leases, and as a condition of the bankruptcy sale has bound Cook Inlet Energy to funding an abandonment escrow over time based on production, not to exceed $50 million, which includes abandonment expenses associated with onshore assets, principally the wells associated with the West McArthur River Unit, is not to exceed $10 million, and the escrow for the offshore assets, principally for the closure of wells on the Osprey platform and the physical removal of the platform, is not to exceed $40 million. We are presently negotiating the term and amount of these escrow accounts in an effort to significantly reduce the amounts to levels we believe are more reasonable with the actual costs. Cook Inlet Energy is also obligated to establish an abandonment escrow of $1.5 million to cover future abandonment expenses related to the three West Foreland gas wells for benefit of the BLM and CIRI, $500,000 of which has already been funded, and $750,000 to establish an abandonment escrow for future abandonment expenses related to surface facilities and pipelines for benefit of CIRI and Salamatof Native Association. The BLM requires a bond of $25,000. $500,000 is due to Cook Inlet Region, Inc. in each of December 2010 and 2011 and $250,000 is payable to Salamatof Native in May each of 2010, 2011 and 2012.

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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 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 Tennessee Gas and Oil Board.

Sales of natural gas in Tennessee 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 is 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.

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.

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”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act and the Federal Water Pollution Control Act of 1972 (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:

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

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

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impose substantial liabilities for pollution resulting from our operations.

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 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

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·

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

·

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

·

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

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

The 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

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Consultants

In February 2010, we entered into a one year consulting agreement with Tyler Energy Consulting Group to provide certain investor relation services to us. Under the terms of this agreement issued 250,000 shares of our common stock valued at $487,500 as compensation. The agreement also provided that at our discretion we could issue up to an additional 250,000 shares of our common stock to the firm as additional compensation. On March 29, 2010 we issued the consultant an additional 70,000 shares of our common stock valued at $462,000 and on April 5, 2010 we issued the consultant an additional 110,000 shares of our common stock valued at $660,000 under the terms of this agreement. We granted Tyler Energy Consulting Group piggy back registration rights covering these shares and agreed to reimburse the firm for business related expenses. The agreement contains customary indemnification provisions.

We have entered into two agreements with Bristol Capital, LLC, an affiliate of Bristol Capital Advisors, LLC which is the investment advisor to Bristol Investment Fund, Ltd., an investor in the 2010 Offering, including the following:

·

On March 12, 2010 we entered into a one year consulting agreement with Bristol Capital, LLC under which it agreed to assist us with strategic planning, management and business operations, introductions to further our business goals, advice and services regarding our growth initiative and other similar services we might request. As compensation for these services we granted Bristol Capital, LLC a five year warrant to purchase 300,000 shares of our common stock at an exercise price of $2.50 and five year options to purchase an additional 300,000 shares of our common stock at an exercise price of $2.50 per share. However, Bristol Capital, LLC will only be entitled to exercise the warrant or the option, not both, which will result in a total possible issuance of 300,000 shares of our common stock. These securities were valued at $1,169,293. In the event we issue securities at a price per share which is lower than $2.50 we are required to increase the number of shares underlying the warrant and option. Under the terms of this agreement, we agreed to include the shares underlying the warrant or option in the next registration statement we filed with the SEC, depending upon the form of registration statement is utilized. Upon the effectiveness of such registration statement, the option will automatically terminate. In the event we fail to file a registration statement covering the shares of common stock underlying the warrant by September 10, 2010, Bristol Capital, LLC may elect to terminate either security in its discretion. In any event, Bristol Capital, LLC shall only retain either the warrant or the option, but not both. Bristol Capital, LLC is contractually limited under the terms of this consulting agreement so that its beneficial ownership of our common stock cannot exceed 9.9% of our outstanding shares. It may waive this limitation upon 61 days notice to us.

We agreed to pay all out-of-pocket expenses incurred by Bristol Capital, LLC under this agreement, subject to our prior approval. The agreement also contains customary indemnification and confidentially provisions.

·

On April 26, 2010 we entered into a finder’s agreement with Bristol Capital, LLC pursuant to which on our behalf it has commenced preliminary discussions with two parties regarding our possible acquisition of certain specified assets. We agreed that if within two years from the date of the agreement we should enter into a definitive agreement with either named party or any of their affiliates for the acquisition of these assets, we will pay Bristol Capital, LLC a finder’s fee of either an assignment of 5% of the interest in the assets or shares of our common stock valued at 5% of the aggregate purchase price at its election. We also agreed to pay a fee equal to 5% of the transaction value. If the efforts by Bristol Capital, LLC on our behalf should result in a joint venture or similar partnership related to these assets, we agreed to pay it a finder’s fee of 5% of the anticipated economic value of such an agreement.

Employees

At July 25, 2010 we had 45 full time and two part-time employees.

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We were incorporated in the State of Delaware in November 1985 originally under the name Longhorn Development Company, Inc. for the purpose of searching out and acquiring or participating in a business or business opportunity. In August 1988 we changed our name to Single Chip Systems International, Inc. In August 1988 we acquired all of the issued and outstanding securities of Single Chip Systems, Inc., a California corporation, in exchange for shares of our common stock. Our then current officers and directors resigned and the officers and directors of Single Chip Systems, Inc. were appointed officers and directors of our company. Prior thereto, on July 1, 1988, Single Chip Systems, Inc. had entered into a technology utilization license agreement with Ramtron International Corporation which granted Single Chip Systems, Inc. the royalty-bearing, non-exclusive licenses to use the ferroelectric technologies and the certain trademarks in production, manufacture and sales of Single Chip Systems, Inc. products. We failed to receive any economic benefit related to the license agreement and we recorded a $100,000 loss on the license agreement in the period ended December 31, 1988.

Thereafter, we had no business or operations until the transaction in January 1997 as hereinafter described. In May 1996 we changed our name to Triple Chip Systems, Inc.

Mr. Deloy Miller formed Miller Petroleum, Inc. (“pre-merger Miller”), a company which is the basis of our current operations, in January 1978. In January 1997, we closed an Agreement and Plan of Reorganization with pre-merger Miller whereby we issued 5,582,535 shares of our common stock in exchange for all of the outstanding common stock of per-merger Miller. The acquisition was accounted for as a recapitalization of our company because the shareholders of pre-merger Miller controlled the company after the acquisition. Following the transaction, in January 1997, pre-merger Miller was merged into our company and we changed our name to Miller Petroleum, Inc. in conjunction with the redomestication of our company into the State of Tennessee.

Effective as of June 13, 2008 we entered into an agreement with Atlas Energy Resources, LLC under which we assigned it:

·

an unencumbered, undivided 100% working interest and an 80% net revenue interest in and to the oil and gas lease comprising 27,620 acres known as Koppers North and Koppers South and located in Campbell County, Tennessee; and an unencumbered, undivided 100% interest and an 82.5% net revenue interest (net of a 5% overriding royalty interest to us) in and to the oil and gas lease comprising 1,952 acres adjacent to Koppers North and Koppers South and located in Campbell County, Tennessee; and

·

an unencumbered, undivided 100% working interest and an 80% net revenue interest in eight gas wells on Koppers South. We have the option to repurchase the wells within one year form the closing date or within 30 days after the pipeline to be built by Atlas Energy has been completed and is ready to accept gas for transport.

The transaction was subject to unwinding pursuant to a pending litigation between our company and CNX Gas Company LLC as disclosed in Item 3. Legal Proceedings. Transferring any of the leases or any interest thereon was also subject to a 60-day standstill period which has since expired. The aggregate consideration for the assignment of the leases and wells to Atlas Energy was $19,625,000, $9,025,000 of which was paid us and the remaining $10,600,000 of which was paid directly to Wind City Oil & Gas, LLC in consideration of a settlement of claims between Wind City and our company described below.

As part of the transaction, we also agreed to contract with Atlas Energy for two rigs for two years to drill wells, commencing a significant commitment to contract drilling. To give Atlas Energy the level of service required, during the first quarter of fiscal 2009 we acquired a 2007 COPCO Model RD III drilling rig and related equipment drilling rig from Atlas to assist in drilling the wells. For two years after the closing date, Atlas Energy granted us the opportunity to bid on any other drilling or service work that Atlas Energy bids on in the State of Tennessee. In addition, we entered into:

·

a natural gas transportation agreement with Atlas Energy which provides us access to the Atlas Volunteer Pipeline, to the extent that capacity is available, on substantially the same terms as those offered to the producers delivering into the system; and

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a natural gas processing agreement pursuant to which Atlas Energy will provide gas processing services to us on substantially the same terms as those services are provided to other producers delivering gas into the Atlas Volunteer Pipeline and deliver back to us gas with a heating value of 1,100 BTUs per cubic foot.

Effective as of June 13, 2008, we also settled all issues and controversies with Wind City Oil & Gas, LLC, Wind Mill Oil & Gas, LLC and Wind City Oil & Gas Management, LLC. Under the terms of the settlement, we paid Wind City $10,600,000 for the re-purchase of 2,900,000 shares of our common stock and reacquisition of all leases previously assigned by us to Wind City or the related parties, all wells and equipment associated with these leases, all pipeline rights and rights of way, all contract rights, and all other equipment, property and real property rights. As set forth above, we used a portion of the proceeds from the Atlas Energy transaction to pay the settlement amounts.

On June 8, 2009 we acquired certain assets from Ky-Tenn Oil, Inc., a Kentucky corporation ("KTO"), an unrelated third party, including KTO's:

·

undivided interest in approximately 170 oil and gas wells in Morgan, Scott and Fentress counties in Tennessee, together with all property, fixtures and improvements, leasehold interest and contract rights related to these wells;

·

undivided interest in approximately 35,325 acres of oil and gas leases in Scott and Morgan counties, Tennessee;

·

interest in an operating agreement with the Tennessee State Energy Development Partnership;

·

interest in a gas gathering pipeline system; and

·

other rights related to these assets, including royalty and working interests, licenses, permits, and similar incidental rights.

As consideration for these assets we issued KTO 1,000,000 shares of our common stock valued at $320,000 and we granted the seller piggy-back registration rights covering these shares. Pursuant to this FASB guidance, we originally valued these assets at $252,455 and recorded a loss on the transaction of $67,545. Subsequently, we completed the determination of the value of all undeveloped reserves for this acreage during the quarter ended October 31, 2009 and accordingly we recorded an additional gain of $1,057,564 on this transaction.

On June 18, 2009 we acquired 100% of the stock of East Tennessee Consultants, Inc., a Tennessee corporation ("ETC") and 100% of the membership interests in East Tennessee Consultants II, LLC, a Tennessee limited liability company ("LLC") from the owners of these entities. Pursuant to FASB ASC 805-10, we have valued these companies at $1,862,369 and have recorded a gain on the transaction of $828,745. As consideration for these companies we issued the sellers, who were unrelated third parties, 1,000,000 shares of our common stock valued at $250,000. We granted the sellers registration rights covering these shares.

Under the terms of the stock purchase agreement, the sellers agreed not to engage in oil and gas operations for a period of three years following the closing date. We also agreed that each of the sellers, Messrs. Eugene D. Lockyear, Douglas G. Melton and Jerry G. Southwood, would continue their employment with the acquired companies for at least three years from the closing date of the transaction at their same compensation and benefit levels to which they were entitled in May 2009. In addition, Mr. Lockyear was appointed Vice President of Operations of our company. We also agreed that if any or all of the sellers incur any income tax liability as a result of the receipt of the above shares as consideration for the stock purchase, we agreed to pay a bonus to such seller equal to the amount of his tax liability within 30 days from the request of the sellers.

On December 10, 2009, Cook Inlet Energy acquired former Alaskan assets of Pacific Energy Resources valued at more than $479 million through a Delaware Chapter 11 bankruptcy proceeding, including oil and gas assets which include onshore and offshore production facilities, $215 million in proven energy reserves, $122 million in probable energy reserves and $31 million in possible energy reserves, providing total reserves of $368 million. The purchased assets included the West McArthur River oil field, the West Foreland natural gas field, and the Redoubt unit with the Osprey offshore platform, all located along the west side of the Cook Inlet. Also included in the asset purchased were 602,000 acres of oil and gas leases which includes 471,474 acres under the Susitna Basin Exploration License as well as completed 3D seismic geology and other production facilities, together with:

·

all easements, wells and tangible assets,

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all oil and gas or proceeds from the sale of oil and gas produced in connection with the acquired assets from the closing date,

·

all contracts, unitization, communization and pooling declarations, orders and agreements,

·

all permits, records, royalty interests, partnership and joint venture interests,

·

to the extent assignable, all rights to indemnities,

·

all leases for real property used by the seller in connection with the operation of the acquired assets,

·

escrow accounts and bonds deposited with government entities with respect to the acquired assets,

·

all surety bonds, plugging bonds, abandonment bonds, standby trust agreements, escrow accounts for plugging, abandonment, decommissioning, removal and restoration obligations, together with security deposits,

·

all imbalances owed to the sellers by a third party at the closing, as well as all oil and gas in pipelines and tanks or held by or for the account of the sellers related to the assets acquired, and

·

the portion of the seller’s Royalty Distributors Inc.’s account relating to post-petition suspended royalties.

In this transaction, Cook Inlet Energy assumed certain liabilities related to the acquired assets, including:

·

all liabilities associated with or arising out of the ownership of, or operation of, the assets after the closing date,

·

all environmental liabilities with respect to the acquired assets,

·

all accounts payable from the closing date,

·

all royalty obligations associated with or related to the acquired assets after the closing date,

·

all claims arising out of the ownership or operation of the acquired assets after the closing date,

·

all plugging, abandonment, decommissioning, removal and/or restoration liabilities associated with or arising from the acquired assets with respect to all periods prior to, on or after the closing date,

·

permitted encumbrances and imbalances owed by the sellers to third parties, and

·

post-petition suspended royalties maintained by Royalty Distributors Inc.

At closing we paid Pacific Energy Resources $2.25 million and provided $2.22 million for bonds, contract cure payments and other federal and State of Alaska requirements to operate the facilities. Under the terms of the purchase agreement, Donkel Oil & Gas, LLC was granted a one-half of 1% overriding royalty interest in the oil and gas leases acquired by Cook Inlet Energy, a 1% overriding royalty interest on Pacific Energy’s working interest in all exploration oil and gas leases acquired by Cook Inlet Energy in the transaction, and a 5/10th of 1% overriding royalty interest owned by Pacific Energy on the leases that comprise the Cosmopolitan Unit and Falls Creek. In addition, Donkel Oil & Gas, LLC received a 1% overriding royalty interest on Cook Inlet Energy’s working interest in any oil and gas lease which arises from certain properties included in an exploration license, which includes one lease, together with a 1% overriding royalty on our working interest in two additional oil and gas leases.

On December 10, 2009, we acquired 100% of the membership interests in Cook Inlet Energy, an Alaska limited liability company from the owners of this entity. As consideration for these companies we issued the sellers, who were unrelated third parties, four year stock warrants to purchase 3,500,000 shares of our common stock at exercise prices ranging from $0.01 to $2.00 per share. In addition, we are required to deliver $250,000 in cash to satisfy certain expenses as well as reimbursement for reasonable out of pocket expenses; such payment has not yet been made. Under the terms of the stock purchase agreement, the sellers agreed not to engage in non-company related oil and gas operations for a period of three years following the closing date. We also agreed that each of the sellers, Messrs. David M. Hall, Walter J. Wilcox II and Troy Stafford, would continue their employment with the acquired company for at least three years from the closing date of the transaction at their specifically defined compensation and benefit levels. In addition, Mr. Hall was appointed as a member of our Board of Directors and as Chief Executive Officer of Cook Inlet Energy. Subsequent to April 30, 2010, Mr. Stafford has left the employ of Cook Inlet Energy.

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In 2009 we formed both Miller Energy GP and MEI. MEI was organized to provide the capital required to invest in various types of oil and gas ventures including the acquisition of oil and gas leases, royalty interests, overriding royalty interests, working interests, mineral interests, real estate, producing and non-producing wells, reserves, oil and gas related equipment including transportation lines and potential investments in entities that invest in such assets except for other investment partnerships sponsored by affiliates of MEI.

Between August 2009 and April 2010 MEI sold 61.35 units of securities to 23 accredited investors in transactions exempt from registration under the Securities Act of 1933 in reliance on exemptions provided by Section 4(2) and Regulation D of that act. Each unit consisted of a $50,000 limited partnership interest in MEI, together with 25,000 shares of our common stock and a five year warrant to purchase an additional 25,000 shares of our common stock with an exercise price of $1.00 per share. In order to receive our securities as part of the offering, investors in the MEI were required to purchase at least one unit. We issued a total of 1,329,250 shares of our common stock and common stock purchase warrants to purchase an additional 1,329,250 shares of our common stock.

MEI received $3,067,500 in proceeds from this offering. It paid selling commissions of 7% on the sale of certain units (an aggregate of $115,780) and a non-accountable marketing and due diligence allowance of 1% of the proceeds received from certain units sold in the offering (an aggregate of $16,540), to Dimirak Securities Corporation, a related party, and Newbridge Securities Corporation, both broker-dealers and members of FINRA. Mr. Scott M. Boruff, our CEO, is a director and 49% owner of Dimirak Securities Corporation. MEI also paid a wholesaling commission based on 2% of the gross proceeds (an aggregate of $33,080) to several firms including Newbridge Securities Corporation, Empire Securities Corporation and Arque Capital Ltd. MEI paid a dealer management fee of 1% of the gross offering proceeds (an aggregate of $30,540) to several parties including Dimirak Securities Corporation, its affiliate Dimirak Financial Corporation and Empire Securities Corporation. Finally, Dimirak Securities Corporation received an additional $30,675 in other fees which was based on 1% of investor capital and two individuals received a total of $81,000 for referral fees. Purchasers of these securities have been granted piggy back registration rights covering the shares of our common stock.

Cook Inlet Energy’s operations are subject to oversight by the Alaska DNR and the Cook Inlet Energy oil and gas leases could be terminated if it fails to uphold the terms of the Assignment Oversight Agreement. If these leases were terminated, we would be unable to continue our operations as they are presently conducted and could be liable for significant additional costs associated with decommissioning the Osprey platform.

Cook Inlet Energy is a party to an Assignment Oversight Agreement with the Alaska DNR that was entered into in November 2009 as a condition of the sale of the oil and gas leases from Pacific Energy Resources to Cook Inlet Energy. The agreement states that its intent is to ensure that there were sufficient funds, and that those funds are only spent, to fulfill Cook Inlet Energy’s initial development, operation, and dismantlement obligations under the assigned leases, applicable statutes and regulations. Those commitments include approximately $5.15 million to be used by Cook Inlet Energy to restore base production at the West McArthur River Unit Facility and approximately $31 million to support restoration of base production at the Redoubt Unit. Internally we have increased that requirement to $35 million to accommodate the purchase of a drilling rig for the Osprey platform. During the interim period, Cook Inlet Energy has fulfilled its commitment to restore base production from the West McArthur River Unit. However, we remain obligated to restore base production from the Redoubt Unit. We will need to either close the funding commitment from Vulcan Capital Corporation or raise the necessary capital from third parties. As a result of the restrictive covenants of the March 2010 unit offering, our ability to raise additional capital is limited. If we are unable to raise the capital as necessary to fully fund the commitment made in connection with the Assignment Oversight Agreement, the State of Alaska could terminate all of the Cook Inlet leases which would be a material adverse event to our company. Our operations would be limited to the Appalachian region and it is unlikely we would be able to continue our operations as they are presently conducted. In addition, we would then be obligated to fund the decommissioning and abandonment of the Osprey platform, which could cost as much as $40 million, of which only approximately $6.6 million has been escrowed with Alaska.

Oil and gas prices fluctuate due to a number of uncontrollable factors, creating a component of uncertainty in our development plans and overall operations. Declines in prices adversely affect our financial results and rate of growth in proved reserves and production.

Oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production depend on numerous factors beyond our control. These factors include, but are not limited to, changes in global supply and demand for oil and gas, the actions of the Organization of Petroleum Exporting Countries, the level of global oil and gas exploration and production activity, weather conditions, technological advances affecting energy consumption, domestic and foreign governmental regulations and tax policies, proximity and capacity of oil and gas pipelines and other transportation facilities and transportation costs and the price and technological advancement of alternative fuels.

The downward pressure in oil and natural gas prices that began in the last half of 2008 continued in 2010. The average realized gas price per thousand standard cubic feet (Mscf) for 2010 decreased 40% from 2009 and the average realized oil price per barrel for 2010 decreased 9% from 2009. The decrease in prices significantly decreased the amount available to invest in exploration and development drilling and the present value of our proved reserves. Our proved oil and gas reserves and production volumes decrease in quantity unless we successfully replace the reserves we produce with new discoveries or acquisitions. For the foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves to replace the reserves we produce, to increase our daily production and to increase our total proved reserves. It will be necessary for us to raise additional capital to fund these expenditures. Low prices also reduce the amount of oil and gas that we can economically produce and may cause us to curtail, delay or defer certain exploration and development projects.

The continued credit crisis and related turmoil in the global financial system may have an impact on our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing, which could have an impact on our flexibility to react to changing economic and business conditions. The economic situation could have an impact on potential lenders, purchasers of our oil and gas production and working interest owners in properties we operate, causing them to fail to meet their obligations to us.

The present value of future net cash flows from our proved reserves will not necessarily be the same as the current market value of our estimated natural gas, crude oil and natural gas liquids reserves.

You should not assume that the present value of future net revenues from our proved reserves referred to in this annual report is the current market value of our estimated natural gas, crude oil and natural gas liquids reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from our proved reserves are based on prices and costs on the date of the estimate, held flat for the life of the properties. Actual future prices and costs may differ materially from those used in the present value estimate. Actual future net cash flows will also be affected by increases or decreases in consumption by oil and gas purchasers and changes in governmental regulations or taxation. The timing of both the production and the incurrence of expenses in connection with the development and production of oil and gas properties affects the timing of actual future net cash flows from proved reserves. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the accuracy of the 10% discount factor.

Our industry is subject to extensive environmental regulation that may limit our operations and negatively impact our production. As a result of increased enforcement of existing regulations and potential new regulations following the Gulf oil spill, the costs for complying with government regulation could increase.

Extensive Federal, state, and local environmental laws and regulations in the United States affect all of our operations. Environmental laws to which we are subject in the U.S. include, but are not limited to, the Clean Air Act and comparable state laws that impose obligations related to air emissions, the Resource Conservation and Recovery Act of 1976 (RCRA), and comparable state laws that impose requirements for the handling, storage, treatment or disposal of solid and hazardous waste from our facilities, the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which our hazardous substances have been transported for disposal, and the Clean Water Act, and comparable state laws that regulate discharges of wastewater from our facilities to state and federal waters. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental laws, including CERCLA and analogous state laws, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Environmental legislation may require that we do the following:

·

acquire permits before commencing drilling;

·

restrict spills, releases or emissions of various substances produced in association with our operations;

·

limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas;

·

take reclamation measures to prevent pollution from former operations;

·

take remedial measures to mitigate pollution from former operations, such as plugging abandoned wells and remedying contaminated soil and groundwater; and

·

take remedial measures with respect to property designated as a contaminated site.

There is inherent risk of incurring environmental costs and liabilities in connection with our operations due to our handling of natural gas and other petroleum products, air emissions and water discharges related to our operations, and historical industry operations and waste disposal practices. The costs of any of these liabilities are presently unknown but could be significant. We may not be able to recover all or any of these costs from insurance. In addition, we are unable to predict what impact the Gulf oil spill will have on independent oil and gas companies

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The effects of future environmental legislation on our business are unknown but could be substantial.

Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. Changes in, or enforcement of, environmental laws may result in a curtailment of our production activities, or a material increase in the costs of production, development drilling or exploration, any of which could have a material adverse effect on our financial condition and results of operations or prospects. In addition, many countries, as well as several states in the United States have agreed to regulate emissions of “greenhouse gases.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning natural gas, are greenhouse gases. Regulation of greenhouse gases could adversely impact some of our operations and demand for products in the future.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005, the Federal Energy Regulatory Commission, or FERC, has authority to impose penalties for violations of the Natural Gas Act, up to $1 million per day for each violation and disgorgement of profits associated with any violation. FERC has recently proposed and adopted regulations that may subject our facilities to reporting and posting requirements. Additional rules and legislation pertaining to these and other matters may be considered or adopted by FERC from time to time. Failure to comply with FERC regulations could subject us to civil penalties.

The marketability of our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems owned by third parties. The lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. The lack of availability of these facilities for an extended period of time could negatively affect our revenues. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

We may be subject to certain conflicts of interest related to Miller Energy Income 2009 -A, LP which may not be resolved in a manner favorable to our company.

A wholly owned subsidiary of our company is the general partner of Miller Energy Income 2009-A, LP ("MEI") and Messrs. Miller, Boruff and Boyd are officers of MEI. In November and December 2009 we borrowed an aggregate of approximately $2.7 million from MEI under the terms of four year secured notes. In the event there should be a dispute under this loan, there are no assurances that it will be resolved in our favor. We asked a third party to hold in escrow titles to substantial company drilling equipment to serve as collateral for these loans. In the event of a dispute under this loan, we could lose ownership of this equipment which we need to perform drilling and drilling services. In that event, we would be unable to continue our operations as they are presently conducted which would have a material adverse impact on our results of operations in future periods. There are no assurances that decisions Messrs. Miller, Boruff and/or Boyd make in matters related to MEI will be beneficial to us.

Certain of our outstanding warrants contain cashless exercise provisions which means we will not receive any cash proceeds upon their exercise.

At July 22, 2010 we have common stock warrants outstanding to purchase an aggregate of 2,910,000 shares of our common stock with an average exercise price of $1.21 per share which are exercisable on a cashless basis. This means that the holders, rather than paying the exercise price in cash, may surrender a number of warrants equal to the exercise price of the warrants being exercised. It is possible that the warrant holders will utilize the cashless exercise feature which will deprive us of additional capital which might otherwise be obtained if the warrants did not contain a cashless feature.

A large portion of our outstanding common shares are “restricted securities” and we have outstanding options, warrants and purchase rights to purchase approximately 47% of our currently outstanding common stock.

At July 22, 2010 we had 33,389,383 shares of common stock outstanding together with outstanding options and warrants to purchase an aggregate of 11,976,955 shares of common stock at exercise prices of between $0.01 and $6.53 per share and $1,285,000 principal amount of convertible notes which are convertible into 2,336,364 shares of common stock at a conversion price of $0.55 per share. Of our outstanding shares of common stock at July 22, 2010, approximately 16,426,863 shares are "restricted securities." Future sales of restricted common stock under Rule 144 or otherwise could negatively impact the market price of our common stock. In addition, in the event of the exercise of the warrants and options and the conversion of the notes, the number of our outstanding common stock will increase by approximately 32%, which will have a dilutive effect on our existing shareholders.

The impacts of non-cash gains and losses from derivative liability accounting in future periods could materially impact our financial results.

As a result of the terms of the March 2010 unit offering, as well as the terms of other recent financing transactions we have entered into in 2010, our financial statements for the year ended April 30, 2010 were impacted by the accounting effect of the application of derivative accounting. We anticipate that our financial statements in future periods will also be impacted. The application of EITF 07-05 “ Determining Whether an Instrument (or Embedded Feature) is Indexed to a Company's Own Stock, ” which was effective on January 1, 2009 will significantly affect the application of ASC Topic 815 and ASC Topic 815-40 for both freestanding and embedded derivative financial instruments in our financial statements. Generally, warrants, conversion features in debt, and similar terms that include “full-ratchet” or reset provisions, which mean that the exercise or conversion price adjusts to pricing in subsequent sales or issuances, no longer meet the definition of indexed to a company's own stock and are not exemption for equity classification provided in ASC Topic 815-15. This means that instruments that were previously classified in equity will require reclassification to liabilities and ongoing measurement under ASC Topic 815. As a result of the application of this accounting principle, we recorded a current derivative liability of $720,840

25

None.

Information on our oil and gas properties appears earlier in this annual report.

On October 8, 2009 we filed an action styled Miller Petroleum, Inc. v. Maynard, Civil Action No. 9992 in the Chancery Court for Scott County, Tennessee, seeking a declaratory judgment that there has been continuing commercial production of oil, and oil and gas lease owned by us is still in full force and effect. The defendant filed an Answer and Counterclaim, seeking in the Counterclaim a declaration that the oil and gas lease has expired. Although no compensatory monetary damages have been sought against us, the Counterclaim does seek attorney fees, expenses and costs. There has been no discovery to date and a trial date has not been assigned. Plaintiff’s attorney left his firm, and the case has been delayed as Plaintiff’s new counsel (with the same firm) becomes familiar with the case.