Edgar Filing: MILLER ENERGY RESOURCES, INC.

Annual Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10-K

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(Mark One)


ü	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
	ACT OF 1934
For the fiscal year ended: April 30, 2011
OR
	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
	ACT OF 1934
For the transition period from: _____________ to _____________

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MILLER ENERGY RESOURCES, INC.

(Exact name of registrant as specified in its charter)

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Tennessee	001-34732	62-1028629
(State or Other Jurisdiction	(Commission	(I.R.S. Employer
of Incorporation or Organization)	File Number)	Identification No.)

3651 Baker Highway, Huntsville, TN 37756

(Address of Principal Executive Office) (Zip Code)

(423) 663-9457

(Registrant’s telephone number, including area code)

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Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common Stock, par value $0.0001 per share		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None
	(Title of Class)

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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
		Yes	ü	No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
		Yes	ü	No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 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 the past 90 days.	ü	Yes		No

Indicate by check mark whether the registrant has submitted electronically and posted on its Corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
		Yes		No


Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not 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-K or any amendment to this
Form 10-K.			ü

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.

Large accelerated filer	Accelerated filer		ü
Non-accelerated filer	Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).		Yes	ü	No

The aggregate market value of the outstanding common stock, other than shares held by persons who may be deemed affiliates of the registrant, computed by reference to the closing sales price for the registrant’s common stock on October 29, 2010 (the last business day of the registrant’s most recently completed second quarter), as reported on the NASDAQ Global Market, was approximately $147,621,755. As of July 15, 2011, there were 40,559,251 shares of common stock of the registrant outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

List hereunder the following documents if incorporated by reference and the Part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: (1) Any annual report to security holders; (2) Any proxy or information statement; and (3) Any prospectus filed pursuant to Rule 424(b) or (c) under the Securities Act of 1933. The listed documents should be clearly described for identification purposes (e.g., annual report to security holders for fiscal year ended December 24, 1980). None.

MILLER ENERGY RESOURCES, INC.

TABLE OF CONTENTS

Page No.

PART I

Unresolved Staff Comments

(Removed And Reserved)

PART II

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of

Equity Securities

Item 6.

Selected Financial Data

Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

Item 8.

Financial Statements and Supplementary Data

Item 9.

Changes In and Disagreements With Accountants on Accounting and Financial Disclosure

Item 9A.

Controls and Procedures

Item 9b.

Other Information

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

Item 11.

Executive Compensation

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related

Stockholder Matters.

Item 13.

Certain Relationships And Related Transactions, And Director Independence

Item 14.

Principal Accounting Fees And Services

PART IV

Item 15.

Exhibits, Financial Statement Schedules

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

The Company has made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with Company management, forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company’s operations, economic performance and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include those statements preceded by, followed by or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should” or similar expressions or variations on such expressions. For such statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. The Company undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise. These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the following risks and uncertainties:

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,

the Company’s assumptions about the energy market;

production levels;

reserve levels;

operating results;

competitive conditions;

technology;

the availability of capital resources, capital expenditures and other contractual obligations;

the supply and demand for and the price of natural gas, oil, natural gas liquids (NGLs) and other products or services;

volatility in the commodity-futures market;

the weather;

inflation;

the availability of goods and services;

drilling risks;

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

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

the impact of the global economic crisis on our business,

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

the imprecise nature of our reserve estimates,

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

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

the costs and impact associated with federal and state regulations,

changes in existing federal and state regulations,

our dependence on third party transportation facilities,

insufficient insurance coverage,

conflicts of interest related to our dealings with MEI,

cashless exercise provisions of outstanding warrants,

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

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.

An investment in our common stock involves a significant degree of risk. You should not invest in our common stock unless you can afford to lose your entire investment. You should consider carefully the following risk factors and other information in this annual report before deciding to invest in our common stock.

OTHER PERTINENT INFORMATION

We maintain our web site at www.millerenergyresources.com. On our website, you will find detailed information regarding our company, our locations and our leadership team, as well as information for shareholders and investors on our media and investor pages. Information on this web site is not a part of this annual report.

Unless specifically set forth to the contrary, when used in this report, the terms “Miller Energy Resources, Inc.,” the "Company," "we," "us," "ours," and similar terms refers to our Tennessee corporation Miller Energy Resources, Inc., formerly known as Miller Petroleum, Inc., and our subsidiaries, Miller Rig & Equipment, LLC, Miller Drilling TN, LLC and Miller Energy Services, LLC, East Tennessee Consultants, Inc., East Tennessee Consultants II, LLC, Miller Energy GP, LLC, and Cook Inlet Energy, LLC ("CIE" or "Cook Inlet Energy").

Our fiscal year end is April 30. The year ended April 30, 2011 is referred to as “fiscal 2011”, the year ended April 30, 2010 is referred to as “fiscal 2010” and the year ending April 30, 2012 is referred to as “fiscal 2012.”

GLOSSARY OF TERMS

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

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

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

“MMBbls” means million barrels of oil.

“MMcf” means million cubic feet.

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

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

“Proved developed reserves” are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved reserves” are the quantities of oil and gas that, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible. We provide information on two types of proved reserves - developed and undeveloped.

“Proved undeveloped reserves” are reasonably certain reserves in drilling units immediately adjacent to the drilling unit containing a producing well as well as areas beyond one offsetting drilling unit from a producing well.

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

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

PART I

ITEM 1.

BUSINESS.

Overview

increasing our overall oil and gas production through maintenance and repairs of nonperforming or underperforming wells located in Alaska, and

organically growing production through drilling for our own benefit on existing leases and acreage in the exploration licenses with a view towards retaining the majority of working interest in the new wells.

Our exploration and production activities

Historically, we focused our exploration, development, and production efforts in the Appalachian region of eastern Tennessee. During fiscal 2011, we continued to benefit from the increase in our operations through the June 2009 acquisitions of the businesses of Ky-Tenn Oil, Inc., a Kentucky corporation (“KTO”), East Tennessee Consultants, Inc., a Tennessee corporation ("ETC”) and East Tennessee Consultants II, LLC, a Tennessee limited liability company ("LLC”) in our Appalachian region and business in Alaska, which comprise our Cook Inlet operations. As of April 30, 2011, we had approximately 699,965 acres of gross oil and gas leases and exploration license rights (679,045 net acres), which includes 534,383 gross acres under our two Susitna Basin Exploration Licenses.

Cook Inlet Basin

Cook Inlet stretches 180 miles from the Gulf of Alaska to Anchorage in south-central Alaska. The Cook Inlet Basin contains large oil and gas deposits including several offshore fields. There are also numerous oil and gas pipelines running around and under the Cook Inlet.

As of April 30, 2011, we own approximately 115,124 gross acres of leasehold interests, the exploration license rights to an additional 534,383 acres and interests in 10 crude oil and five natural gas wells. The increased acreage from April 30, 2010 is a result of Cook Inlet Energy’s successful bids in State of Alaska’s Division of Oil & Gas Cook Inlet Areawide 2010 Competitive Oil and Gas Lease Sale, and the award of Susitna Basin Exploration License No. 4, consisting of 62,909 acres. The leases, consisting of 17,027 acres, were awarded to CIE on March 1, 2011. All of Cook Inlet Energy’s bids completed acreage positions covering prospects acquired in its purchase of Pacific Energy Alaska operations in December 2009. The Susitna Basin Exploration License No. 4 was awarded on April 1, 2011. We also sold leases of 8,829 acres to an Alaska limited liability company, but retained overriding royalty interests.

At the time we acquired the Alaskan operations, all ten oil wells, three gas wells and four injection wells except for one gas were shut-in. By June 30, 2010, four of the oil wells had been returned to production. In addition, Cook Inlet Energy owns a 30% working interest in two gas wells operated by Aurora Gas, which have been operated continuously.

Oil wells drilled in this area range from 9,000 vertical feet to 10,000 feet in vertical 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 shale, sandstone, and coal. The primary targets in the area are crude oil reserves.

In January 2010 we entered into a Master Services Agreement with Fairweather E&P Services, Inc. (now SolstenXP), a company based in Anchorage, Alaska which provides a wide range of support services for the oil and gas industries, whereby it acts as an independent contractor for us in the development and/or refurbishment of the wells in Cook Inlet Basin. The agreement provides us with engineering, logistics, field and project management support for the well and facility work in Cook Inlet Basin which are anticipated to be completed on or before December 31, 2012. We pay the contractor for all costs associated with these services, including any services that Fairweather E&P may subcontract to third party providers, at its cost plus 15%. Fairweather is required to maintain certain minimum levels of insurance coverage and the agreement contains customary cross-indemnification provisions. We may terminate the agreement at any time without reason.

Susitna Basin Exploration License

Included in the Alaskan operations 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. 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. The State granted the extension in October 2010. We will have the right to convert the license for all or any portion of the acreage into oil and gas leases upon completion of the new work commitment. If the exploration license is converted into oil and gas leases, we are required to pay an annual rental to the State of Alaska.

On April 1, 2011, we were awarded Susitna Basin Exploration License No. 4, which consists of 62,909 acres. Under the terms of the Exploration License, CIE was granted a ten-year exclusive license to explore for oil and gas on the specified lands, and upon fulfillment of the work commitment of $2,250,000, the license for all or any part of the land can be converted into oil and gas leases. If no work is carried out, CIE will post $225,000 in additional funding each year.

Osprey Platform

Also, included in the operations 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. It relies on our Kustatan Production Facility 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. After a period of inactivity, we started work to re-commission Osprey in February 2011 and restored production in May 2011.

The Osprey platform was placed on site in June 2000 and initially it was used to conduct 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 delayed the ability to maintain and repair the platform’s wells or to expand production, 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 it is cost effective to permanently locate a drilling rig on the platform. Two of the Osprey wells required only the replacement of the electrical submersible pumps (“ESPs”), but the other four wells will require re-drilling in sections. We estimated that the total cost of restoring full production, including the purchase and construction of a drilling rig, is approximately $45 million. We began bringing the Osprey platform out of lighthouse mode in March 2011. In May, we successfully repaired the first of the two wells needing ESP replacement. In June, we secured financing in the form of a $100 million credit facility with Guggenheim Corporate Funding, LLC, Citibank, N.A., and Bristol Investment Fund, Ltd. The credit facility has an initial availability of $35 million and will be used to purchase the platform drilling rig and to finance the further development of our Alaskan and Tennessee assets. In June 2011, we contracted with Voorhees Equipment and

Consulting, Inc. for the custom construction and purchase of a drilling rig for the Osprey platform for $17.9 million. We expect the rig to ship and arrive in Alaska in September 2011 and be operational in November 2011. We have also brought the second well requiring ESP replacement online since closing on our credit facility.

Assignment Oversight Agreement

On November 5, 2009, Cook Inlet Energy entered into an Assignment Oversight Agreement with the Alaska Department of Natural Resources (“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:

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

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

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

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 $5.15 million 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 $45 million primarily to accommodate the contractual purchase price of a drilling rig. We have provided these funds for the West McArthur River facility using a portion of the proceeds of our capital raising efforts described elsewhere herein.

Cook Inlet Energy is prohibited from using any of the 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.

On March 11, 2011, CIE entered into a Performance Bond Agreement with the Alaska DNR that applies to the offshore obligations under the Assignment Oversight Agreement. Under the Performance Bond Agreement, CIE is required to post a total bond of $18 million; however, the Performance Bond Agreement makes clear that approximately $6.8 million held by the state will apply to the total bond required. The first payment of $1.0 million toward the bonding requirement is due in July 2013.

Membership in Cook Inlet Spill Prevention and Response, Inc.

Cook Inlet Energy is a 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. We pay an annual fee of $10,000 together with additional fees based upon the amount of oil we transport.

If a spill is identified as originating from facilities owned or operations conducted by one or more of the members, CISPRI will act to control and clean up the spill of crude oil/synthetic crude oil or refined petroleum products arising from those operations without any further action by the members. Any member that utilizes or receives the benefit of these activities must reimburse CISPRI for all expenses of control and clean up, including costs of equipment, materials and personnel. Each member is required to execute a response action contract providing terms and conditions under which response and cleanup activities will be undertaken. Cook Inlet Energy is a party to such an agreement which, in part, requires Cook Inlet Energy to maintain worker’s compensation insurance, employers’ liability insurance, comprehensive general and automotive liability insurance covering injury or death or persons and property damage of at least $10 million. Cook Inlet Energy is in compliance with this insurance requirement. All members accept responsibility for spills which result from their operations or facilities and have indemnified CISPRI and all other members for all liabilities arising for a spill. This indemnification is not limited by the amount of insurance coverage.

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 50,458 gross acres of leasehold interests with 195 producing oil wells and 193 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 the Fort Payne formation.

Our oil and gas properties

The following table provides information on our proved reserves at April 30, 2011, 2010 and 2009.


	Net Reserves at April 30,
	2011		2010		2009
Reserves category	Oil (MMBbls)	Natural Gas (MMcf)	Oil (MMBbls)	Natural Gas (MMcf)	Oil (MMBbls)	Natural Gas (MMcf)
PROVED
Developed
Cook Inlet	2.371	1.739	2.551	1.085	—	—
Appalachian region	0.090	1.672	0.114	652	0.053	0.593

Undeveloped
Cook Inlet	7.536	584	7.679	3.722	—	—
Appalachian region	—	497	—	—	—	1.271

Total Proved	9.997	4.492	10.344	5.459	0.053	1.864

When used in this table, MMBbls means million barrels of oil and MMcf means million cubic feet. We also use a number of terms when describing our reserves. “Proved reserves” are the quantities of oil and gas that, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible. We provide information on two types of proved reserves - developed and undeveloped. “Proved developed reserves” are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods and “proved undeveloped reserves” are reasonably certain reserves in drilling

units immediately adjacent to the drilling unit containing a producing well as well as areas beyond one offsetting drilling unit from a producing well. “Unproved reserves” are based on geological and/or engineering data similar to that used in estimates of proved reserves, but technical, contractual, or regulatory uncertainties preclude such reserves being classified as proved. They are sub-classified as probable and possible. Probable reserves are attributed to known accumulations and usually claim a 50% confidence level of recovery. Possible reserves are attributed to known accumulations that have a less likely chance of being recovered than probable reserves. This term is often used for reserves which are claimed to have at least a 10% certainty of being produced. Reasons for classifying reserves as possible include varying interpretations of geology, reserves not producible at commercial rates, uncertainty due to reserve infill (seepage from adjacent areas) and projected reserves based on future recovery methods.

Our reserve estimates for oil and natural gas at April 30, 2011 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, 2011 for our Appalachian region assets were prepared by Lee Keeling and Associates, Inc., an independent engineering firm. Our reserve reports, which are filed as exhibits to this annual report, were prepared using engineering and geological methods widely accepted in the industry. All reserve definitions comply with the applicable definitions of the rules of the SEC. 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 the proved developed producing reserves, the estimates were made when considered to be definitive, using performance methods that utilize extrapolations of various historical data including, but not limited to, oil, gas and water production and pressure history. For the other proved producing, proved behind pipe reserves, proved undeveloped reserves, and probable and possible reserves 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. Our Chief Financial Officer and the Chief Executive Officer of our CIE subsidiary are primarily responsible for the engagement and oversight of our independent engineering firm. 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 the Chief Executive Officer of CIE and our Chief Financial Officer 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 unproved reserves to proved reserves during the fiscal year ended April 30, 2011.

The following table presents our producing wells by operating area at April 30, 2011.


	Producing Wells
	Gross (a)			Net (b)
Location	Oil	Gas	Total	Oil	Gas	Total
Cook Inlet	3	5	8	3	4	7
Appalachian region	195	193	388	120	130	250
Total	198	198	396	123	134	257

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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. Our head geologist is our Vice President of Geology, Gary Bible, Ph.D. Dr. Bible was appointed Vice President of Geology in September 1997. Dr. Bible came from Alamco Inc., where he had served since May 1991 as manager of geology and senior geologist. Dr. Bible earned his BS in geology from Kent State University and his MS 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 over 30 years of experience as a petroleum geologist. In addition, Dr. Bible has spent more than 17 years in the Appalachian Basin in the exploration and development of reserves in the “Big Lime” zone, in 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. In addition to Dr. Bible, for our assets in Alaska, we also utilize the consulting services of Mr. Gregory L. Kirkland. Mr. Kirkland is also a professional geologist and has extensive knowledge of the Cook Inlet region of Alaska. Mr.

Kirkland has over thirty five years with majors and large independent oil and gas companies in numerous domestic and international provinces, extensive geological, geophysical, reserves estimation and petrophysical background with broad technical and supervisory experience covering Gulf Coast, Mid Continent, Rockies, Alaska, Canada and International areas.

Dr. Bible, Mr. Kirkland and their teams 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 Licenses as of April 30, 2011.


	Developed Acres		Undeveloped Acres		Total Acres
Project	Gross	Net	Gross	Net	Gross	Net
Cook Inlet	34,996	32,800	614,511	597,662	649,507	630,462
Appalachian region	13,760	9,468	43,817	30,159	57,577	39,627
Total acreage	48,756	42,268	658,328	627,821	707,084	670,089

The following table presents the net undeveloped acres that we control under fee leases and the Susitna Basin Exploration License and the period the leases and exploration license are scheduled to expire, absent pre-expiration drilling and production which extends the term of the lease(s) or the fulfillment of the exploration license terms which permits us to convert all or any portion of the exploration license into oil and gas leases. The expiration dates of the leases are subject to one year automatic renewals so long as we are producing oil and/or gas on the lease. The term of the Susitna Basin #2 Exploration License and the two MHT – Olson Creek leases were extended, the Susitna Basin #4 Exploration License was issued, the seven leases from the State of Alaska Cook Inlet Areawide 2010 Lease Sale were issued, and the leases covering the parcel known as the Raptor Prospect were sold with the Company retaining a 3% overriding royalty interest.


	Net Undeveloped Acres
Lease/Exploration License	Year of Expiration	Total Acres
Cook Inlet
MHT 9300062 - Olson Creek	2012	5,483
MHT 9300063 - Olson Creek	2012	3,906
ADL 391613 - Olson Creek	2018	107
ADL 391614 - Olson Creek	2018	35
ADL 391615 - Olson Creek	2018	570
ADL 390551 - Stingray	2012	520
ADL 390578 - N Alexander	2012	5,705
ADL 390585 - N Alexander	2012	5,689
ADL 391628 - N Alexander	2018	5,513
ADL 390749 - Otter	2013	2,522
ADL 390579 - Otter	2012	5,760
ADL 391621 - Otter	2018	2,528
ADL 391624 - Otter	2018	2,514
ADL 390078 - Susitna Basin #2 Exploration License	2013	471,474
ADL 391628 - Susitna Basin #4 Exploration License	2021	62,909
ADL 390555 - Tutna	2012	1,280
ADL 390556 - Tutna	2012	2,522
ADL 390557 - Tazlina	2012	2,529
ADL 391608 - Tazlina	2018	5,760
ADL 17602 – Sabre	1967, Held by Unit	896
ADL 18758 - Sabre	1967, Held by Unit	280
ADL 17594	1967, Held by Unit	80
ADL 17597	1967, Held by Unit	2,280
ADL 18730	1967, Held by Unit	480
ADL 18777	1967, Held by Unit	553
Total		591,895
Appalachian region
Lindsay	Held by production	1,535
Edwards-Fowler, Gann	Held by production	81
Butler et al	Held by production	24
Gunsight	Held by production	1,335
Phillips et al from Gunsight acreage	Held by production	901
KTO acreage and wells	Held by production	19,128
ETC acreage and wells	Held by production	3,507
Baker-Senior lease farm out	Held by production	1,020
Other Undeveloped, net	2011 to 2013	2,628
Total		30,159

Total acreage		622,054

The following table presents our development and exploratory drilling activities during the past three fiscal years ended April 30. There is no correlation between the number of productive wells completed during any period

and the aggregate reserves to those wells. Productive wells consist of producing wells capable of commercial production.


	Drilling Activities
	2011				2010				2009
	Gross		Net		Gross		Net		Gross		Net
Development:
Producing
Cook Inlet		—		—		—		—		—		—
Appalachian region		—		—		—		—		—		—
Total producing		—		—		—		—		—		—
Non-Producing
Cook Inlet		—		—		—		—		—		—
Appalachian region		—		—		—		—		—		—
Total non-producing		—		—		—		—		—		—
Injection
Cook Inlet		—		—		—		—		—		—
Appalachian region		—		—		—		—		—		—
Total injection		—		—		—		—		—		—
Dry
Cook Inlet		—		—		—		—		—		—
Appalachian region		—		—		—		—		—		—
Total dry		—		—		—		—		—		—

Total development		—		—		—		—		—		—

Exploratory:
Productive
Cook Inlet		—		—		—		—		—		—
Appalachian region		3		3		—		—		—		—
Total productive		3		3		—		—		—		—
Dry
Cook Inlet		—		—		—		—		—		—
Appalachian region		—		—		—		—		—		—
Total dry		—		—		—		—		—		—
Pending determination		—		—		—		—		—		—
Total exploratory		3		3		—		—		—		—

Total drilling activity		3		3		—		—		—		—

Our current efforts are focused on reworking certain of the wells in Cook Inlet and ongoing drilling operations in the Appalachian region. The Company incurred $8.3 million and $5.8 million of development cost in the Cook Inlet region in fiscal years 2011 and 2010, respectively. These costs were primarily related to recompletion and repair of wells that were shut in by Pacific Energy, as well as repair of the physical infrastructure. Three oil wells and four gas wells were producing in Cook Inlet by April 30, 2010 and three oil wells and five gas wells were producing in Cook Inlet during the year ended April 30, 2011. We do not currently have any ongoing drilling operations in 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.

As a result of the acquisition of the Alaskan operations in December 2009, Cook Inlet Energy is a successor to the September 2003 contract with Tesoro Refining and Marketing Company. Under the terms of this agreement, Tesoro has agreed to purchase at the Drift River Terminal all of the Alaskan Cook Inlet crude oil which is produced from leases on the west side of Cook Inlet for the maximum annual capacity of the lesser of the average proportionate share of the Alaskan Cook Inlet crude oil produced or 40,000 barrels per day. The per barrel pricing is based upon the simple arithmetic average of the published daily New York Mercantile Exchange (“NYMEX”) settlement prices for light sweet crude oil less certain adjustments and deductions. This pricing may be modified upon the mutual agreement of the parties if the volume falls below 9,000 barrels per day or exceeds 24,000 barrels per day. The initial term of the agreement was to December 31, 2008 and thereafter it has automatically renewed in additional one year terms. The agreement may be terminated by either party upon notice 60 days prior to the automatic renewal. All of our present and planned future oil production is from the west side of Cook Inlet, and would be covered by this contract. Sales to Tesoro Refining and Marketing Company under this agreement represented approximately 87% of our total revenue in fiscal 2011.

Currently, all natural gas produced by Cook Inlet Energy is 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, 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 fiscal years 2011 and 2010, sales to Barrett Oil Purchasing and Sunoco, collectively, represented approximately 2% and approximately 9%, 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 4% of our total revenue for fiscal 2010 and approximately 12% of our total revenue in fiscal 2011.

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 valorem and severance taxes per unit of production, and is exclusive of work-over costs.


	Year Ended April 30,
	2011		2010		2009
Oil production (Bbls)
Cook Inlet
Production (Gross)		312,583		46,445		—
Average sales price	$	83.43	$	78.76		—
Average production cost	$	23.03	$	56.64		—
Appalachian region
Production (Gross)		28,502		2,945		4,580
Average sales price	$	76.25	$	71.33	$	68.77
Average production cost	$	29.68	$	28.29	$	52.49

On November 19, 2010, the Regulatory Commission of Alaska accepted a settlement agreement between CIE and the Cook Inlet Pipe Line Company ("CIPL"). CIPL, a subsidiary of Chevron Pipeline Co., operates a 42-mile pipeline on the west side of Cook Inlet, and is the sole means by which CIE can export its oil production. This settlement reduced transportation costs for all CIE production by $6.57 per barrel to a rate of $8.00 per barrel for the remainder of 2010. The settlement lays out a methodology for determining CIE's future pipeline transportation rates. The rates to be paid by CIE to CIPL during calendar years 2011 through 2014 shall be determined by dividing the agreed annual CIPL revenue requirement of $17.28 million for each year of the term of the Settlement Agreement by the forecasted total annual CIPL throughput. CIE paid for transportation of 260,063 barrels of production in fiscal 2010 and has committed to pay for a minimum of 346,750 barrels in each of the fiscal years 2011 through 2014. Each February, a true-up adjustment for the previous year will be made by dividing the $17.28 million revenue requirement of the pipeline by the actual number of barrels put through the line by all shippers to determine the rate due to CIPL.

We currently pay 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 a royalty rate of 5% until December 2012 when it will increase to 12.5%. We are also obligated to pay Cook Inlet Region, Inc. a 12.5% royalty on any gas sold from the portion of the West Foreland Gas Field located outside of the West McArthur River Unit. Finally, there are overriding royalty interests totaling approximately 12.4% for West McArthur River Unit, 4% for Redoubt Unit, and 5% for the portion of the West Foreland Gas Field located outside the West McArthur River Unit.

Other ancillary services

The Company also generates ancillary revenue from drilling activities. While the equipment and personnel on hand are for the benefit of drilling on our own properties, from time to time we optimize unused capacity to perform drilling and related services on behalf of third parties. In fiscal 2011, 34% of our other revenue related to a cleanup project for the U.S. Department of Interior. Drilling wells for Atlas Energy Resources, LLC accounted for approximately 43% of our other revenue for fiscal 2010.

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 nine significant competitors consisting of Apache Corporation, Aurora Gas, Buccaneer 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 compete effectively for additional lease acreage with our competitors. In the Appalachian region, we have six significant competitors consisting of 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 compete for leases, however, as in the Appalachian region we have name recognition of 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.

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:

bond requirements in order to drill or operate wells;

the location of wells;

the method of drilling and casing wells;

the surface use and restoration of well properties;

the plugging and abandoning of wells; and

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.

CIE has posted $825,000 in state and federal bonds. The Alaska DNR requires $600,000 in bonding to operate of oil and gas leases on state lands, the Alaska Oil and Gas Conservation Commission (“AOGCC”) requires a $200,000 bond to drill wells in the state, and the U.S. Bureau of Land Management (“BLM”) requires a bond of $25,000 to operate on federal lands. These bonds are fully funded and are held by the First National Bank of Alaska in certificates of deposit for benefit of the various beneficiates.

CIE has a total of $1,490,000 in designated accounts to satisfy future abandonment obligations. An additional $14,740,000 will need to be placed into escrow over the next eight years to fund various future abandonment liabilities. A $490,000 letter of credit is established for two Class 1 non-hazardous injection wells for benefit of the United States Environmental Protection Agency (“EPA”). This letter of credit is backed by an account which must maintain a minimum value of $490,000. Under the terms of the bankruptcy sale of the Pacific Energy assets CIE was obligated to establish accounts to cover abandonment obligations to Cook Inlet Region, Inc. (“CIRI”), Salamatof Native Association (“Salamatof”), and the State of Alaska; $1.5 million was required to cover future abandonment expenses related to the three West Foreland gas wells for benefit of CIRI, of which $1,000,000 has already been funded, and $500,000 will be due December 10, 2011. An additional $750,000 is for future abandonment expenses associated with surface facilities and pipelines for benefit of CIRI and Salamatof, none of which has yet been funded. The account is owed $500,000 pending the resolution between CIRI and Salamatof over who will be the named party for the account. The final $250,000 is payable in May 2012.

In March 2011, CIE entered into a Performance Bond Agreement that set the bond for the Osprey platform at an inflation-adjusted $18 million. The agreement sets a payment schedule totaling $12 million in annual payments between July 2013 and July 2019. An existing interest bearing account containing approximately $6.8 million is to be credited against the inflation-adjusted $18 million liability. Annual payments will be made after 2019 as necessary to the degree that inflation has caused the liability to increase over the amount contained in the funded accounts.

Under the Oil Pollution Act of 1990, Cook Inlet Energy is required to fund a citizens advisory group, the Cook Inlet Regional Citizen’s Advisory Council, under which its commitment is approximately $55,000 per year.

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:

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.

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 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 do the following:

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 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.

Consultants

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. (“Bristol”), both an investor in a securities offering we undertook in fiscal 2010 and one of the lenders in our recent debt financing, including the following:

On March 12, 2010, we entered into a one year consulting agreement with Bristol 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 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 will be entitled only 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. 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 may elect to terminate either security in its discretion. In any event, Bristol shall only retain either the warrant or the option, but not both. Bristol 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. This agreement was renewed and extended for an additional one year term by an amendment with an effective date of April 29, 2011. The amendment revised the compensation issuable to Bristol by making it clear that a warrant for the purchase of 300,000 shares of stock with an exercise price of $2.50 was issuable under the original agreement, and eliminated the anti-dilution clause in the agreement. We agreed to issue a second warrant as consideration for the second year of the agreement in the same 300,000 share amount, but the exercise price of that warrant is set as of the execution date of the amendment, which was May 22, 2011. Additional consideration was provided in the form of a finder’s fee of three percent (3%) for any mezzanine debt financing secured by us during the term of the agreement, including 3% of the initial borrowing base of $35 million in the Loan Agreement with Guggenheim. See exhibit 10.49 filed with the current report on June 17, 2011.

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

On April 26, 2010, we entered into a finder’s agreement with Bristol 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 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 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 15, 2011, we had 70 full-time and one part-time employee.

Our history

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 pre-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 Energy Resources, Inc. in conjunction with the re-domestication of our company into the State of Tennessee.

Effective 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 from 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 therein 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

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 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 oil and gas properties from 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 FASB guidance, we valued these oil and gas properties at $$1,310,019 and recorded a gain on the transaction of $990,019.

On June 18, 2009, we acquired 100% of the stock of ETC and 100% of the membership interests in LLC from the owners of these entities. Pursuant to FASB ASC 805-10, we have valued the assets for these companies at $1,862,369 and have recorded an after-tax 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, we would 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, through a Delaware Chapter 11 bankruptcy proceeding, former Alaskan operations of Pacific Energy Resources. The acquisition included onshore and offshore oil and gas production facilities. We acquired total reserves of over 13.2 million barrels of oil and 15.5 BCF of natural gas, including total proved reserves of 5.6 million barrels of oil and 3.7 BCF of natural gas as reported by the Pacific Energy in their most recent reserve report of January 1, 2009. The fair value of the Alaska reserves that we acquired is over $327 million dollars, including $119 million dollars of proven reserves, $185 million of probable reserves and $23 million of possible reserves, as stated in its reserve report as of January 1, 2009. The purchased operations 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. We also acquired 602,000 acres of oil and gas leases, including 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,

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

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 0.5% 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 0.5% 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. As consideration, 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. Under the terms of the stock purchase agreement, the sellers agreed not to engage in competing 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.

In March 2009, we formed Miller Energy GP and in April 2009 we formed Miller Energy Income 2009-A, LP (“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. Through a subsidiary we own 1% of MEI, however due to the shared management of our company and MEI, we consolidate this entity.

On June 24, 2011, we acquired a 48% minority interest in each of two limited liability companies, Pellissippi Pointe, LLC and Pellissippi Pointe II, LLC for a total cash consideration of $384,000. We have also agreed to indemnify the sellers of the membership interests with respect to their guaranties of the construction loans held by the Pellissippi Pointe entities, but have not become direct guarantors of the loans ourselves. The gross outstanding amount under the loans is $5,193,699. The Pellissippi Pointe entities own two office buildings in West Knoxville, Tennessee. We will be moving our corporate headquarters into the building located at 9721 Cogdill Road, Knoxville, TN as soon as the space is ready for our occupancy. We have executed a five year lease for the space, and with the addition of us, the building will be fully occupied by tenants. The forms of assignment of membership interest, and the lease are filed as exhibits to this annual report.

ITEM 1A.

RISK FACTORS.

Risks Related to Our Business

We have a history of operating losses; we incurred a net loss in fiscal 2011 and our net income in fiscal 2010 was the result of one-time acquisition gains. Our revenues are not currently sufficient to fund our operating expenses and there are no assurances we will develop profitable operations.

We reported an operating loss of approximately $15.1 million in fiscal 2011 and approximately $11.3 million in 2010. Our net loss of approximately $4.4 million in 2011 is primarily attributable to the operating loss, partially offset by an approximate $4.9 million in other income and a $5.7 million benefit from income taxes. Our net income of approximately $250.9 million in fiscal 2010 is attributable to $461.1 million in gains on the acquisitions of the Alaska and Tennessee businesses. As a result of the continued expansion of our business during fiscal 2011, our operating expenses presently exceed our revenues. We anticipate that our operating expenses will continue to increase as we fully develop our operations following the acquisition of the Alaskan assets. Although we expect an increase in our revenues to come from these development activities, we will continue depleting our cash resources to fund operating expenses until such time as we are able to significantly increase our revenues. We may have to reduce our expansion efforts if we have not seen an increase in revenues in the next few months. While we believe that our revenue will increase and exceed our operating expenses, there are no assurances that we will develop profitable operations.

We will be subject to new debt costs under the terms of our Credit Facility with Guggenheim, Citibank N.A., and Bristol Investment Fund, Ltd. Monies borrowed are subject to an interest rate of the higher of 9.5% or the prime rate plus 4.5% per annum. In addition, we are required to pay an additional make-whole payment upon termination or payment in full of the credit facility, bringing the effective interest rate to 25% to 35%, depending on the timing of repayment. In January 2012, we will be required to devote 90% of our consolidated monthly net revenues toward paying back outstanding amounts under the credit facility.

As described later in this report, in June 2011 we entered into a Loan Agreement with Guggenheim Corporate Funding, LLC, Citibank N.A., and Bristol Investment Fund, Ltd., under which a credit facility of up to $100 million has been made available to us. At July 15, 2011 we had drawn approximately $10.875 million under the Credit Facility. Any monies borrowed by us will bear interest at mezzanine rates and will be subject to a make whole premium that could amount to as much as 35%, depending on the date we repay the Credit Facility. These debt costs may be substantial, and will adversely impact our results until such time as the facility has been repaid. In addition, beginning in January 2012 we are required to use 90% of our consolidated monthly net revenues (after deducting general and administrative expenses up to certain limitations) to repay the amounts outstanding under the Credit Facility. If we have not repaid the facility in full prior to January 2012, we could be forced to reduce our general and administrative expenses. This could mean that we would need to make reductions in salaries and/or staffing, which could impact our ability to operate our business and achieve our aggressive plan for development. Depending on our success in increasing revenue and/or raising equity, the facility may not be repaid prior to January 2012.

The restatement of our historical financial statements has already consumed, and may continue to consume, a significant amount of our time and resources and may have a material adverse effect on our business and stock price.

As described elsewhere in this report, we have restated our unaudited consolidated financial statements for our first three quarters of fiscal year 2011. The restatement process was highly time and resource-intensive and involved substantial attention from management and significant accounting costs. Furthermore, we cannot guarantee that we will have no inquiries from the SEC or the NYSE regarding our restated financial statements or matters relating thereto. Any future inquiries from the SEC as a result of the restatement of our historical financial statements will, regardless of the outcome, likely consume a significant additional amount of our resources in addition to those resources already consumed in connection with the restatement itself. Further, many companies that have been required to restate their historical financial statements have experienced a decline in stock price and stockholder lawsuits related thereto.

The staff of the SEC has determined that certain of our Forms 8-K related to acquisitions we made in fiscal year 2010 are materially deficient which will adversely impact our ability to raise additional capital.

In connection with a review of our Annual Report on Form 10-K for the year ended April 30, 2010, the staff of the SEC has concluded that we omitted required audited financial statements of three acquired businesses, including ETC, KTO and CIE, from our Forms 8-K reporting these acquisitions. Until such time as we file audited financial statements, the staff has advised us it considers those Forms 8-K to be materially deficient and that it will not waive these financial statement requirements. As a result, we are unable to utilize a “short-form” registration statement on SEC Form S-3. In addition, until such time as the audited financial statements of the acquired businesses are filed, the staff of the SEC has advised us it will not declare effective any registration statements or post-effective registration statements. We believe that the acquisitions of ETC and KTO were not material and did not rise to the level which required audited financial statements. Further, the CIE assets and liabilities were acquired through bankruptcy and via the newly formed CIE. These oil and gas producing assets were not operational for several months prior to the acquisition, were consolidated in, as they were part of a larger enterprise, and as accounting records were not adequately maintained by Pacific Energy Alaska Operating LLC and Pacific Energy Alaska Holdings, we were unable to carve out historical operational results on these specified assets. At the time of acquisition of these assets, we determined that the resulting assets and liabilities were not a separate business for purposes of preparing pro forma financials with historical results for the past year and / or related stub period and our Current Report on Form 8-K/A as filed included only a pro forma balance sheet to reflect the acquisition. We do not believe we will be able to obtain audited financial statements on this acquisition for the periods provided in Regulation S-X.

In addition, under the terms of the registration rights agreement for our 2010 offering, we are required to keep the registration statement current which registered the resale of the shares sold in that private offering effective until either all of the shares have been sold or Rule 144 is available to the holders without our compliance with the current public information requirements of Rule 144. As a result of our current inability to file a post-effective amendment to that registration statement, we will begin accruing registration rights penalties which will adversely impact our results in future periods.

We expect to continue our discussions with the staff of the SEC regarding this matter in an effort to obtain waivers to the financial statement requirements of Form 8-K for these acquisitions. There are no assurances we will be successful in our efforts. Until such time, if ever, that we are able to obtain a waiver from the SEC on the requirement to include audited financial statements in these Forms 8-K, our ability to register additional capital will be materially impacted.

We are party to several lawsuits seeking millions of dollars in damages against us. An adverse decision in any of these lawsuits could result in our being forced to pay the prevailing plaintiff substantial amounts of money that would adversely impact our ability to continue with our development plans and/or operate our business.

As described later in this report, we are subject to lawsuits seeking millions of dollars in damages against us. Litigation is inherently unpredictable, and any damages that could ultimately be paid by us in relation to any of these lawsuits are subject to significant uncertainty. The timing and progression of each case is also unpredictable; it may take years for the case to make its way to trial and through various appeals. The total amounts that will ultimately be paid by us in relation to all obligations relating to these lawsuits are subject to significant uncertainty and the ultimate exposure and cost to us will be dependent on many factors, including the time spent litigating each case and the attorneys’ fees incurred by us in defending the cases. Our financial statements contained herein do not contain any reserves for any potential damages associated with this pending litigation. If we should not be successful in our defense of this pending litigation, our results of operations in future periods could be materially adversely impacted.

Our ability to draw under the Credit Facility is subject to a 15 business day waiting period and subject to the Lenders’ approval in their sole discretion.

When we wish to make a draw under the Credit Facility, we are required to file a borrowing request in a particular form outlining the monies requested and their intended use. The lenders have 15 business days during which to assemble the funds requested. We may not be able to identify our need for capital three weeks in advance, and the timing requirement under the loan may hinder our ability to operate at the pace we are used to. There is no

guarantee that the request will be approved at all as the required lenders may approve or deny the borrowing request in their sole and absolute discretion.

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.

On March 11, 2011, CIE entered into a Performance Bond Agreement with the DNR concerning certain bonding requirements initially established by the Assignment Oversight Agreement between these two parties dated November 5, 2009. The performance bond is intended to ensure that CIE has sufficient funds to meet its dismantlement, removal and restoration obligations under the applicable agreements, leases, and state laws and regulations. The Performance Bond Agreement applies only to the Redoubt Unit and Redoubt Shoal Field, and sets forth an amount of $18.0 million for the bond. The Agreement includes a funding schedule, which requires payments annually on July 1, beginning in 2013, of amounts ranging from $1.0 million to $2.5 million per year, and totaling $12.0 million. The Agreement also clarifies that approximately $6.8 million as of April 30, 2011 from a bond funded by the previous owner and held in a State Trust Account since the sale of the assets is included in the account holding the performance bond for our dismantlement, restoration, and rehabilitation obligations under the Agreement. The monies deposited under the Agreement may be held in the State Trust Account or in private bank or surety company accounts. Until the performance bond is fully funded, all interest on either account will be retained in the account.

If the State Trust Account, which is currently an interest-bearing account, becomes a non-interest bearing account, CIE may transfer the funds to a private account with the DNR Commissioner’s consent. If CIE is more than 10 days late with a payment to the State Trust Account or more than 10 days late providing proof of a payment into a private account, the State will assess a late payment fee of $50,000. Our obligation to pay one or more late payment fees will further reduce the cash resources we have available to devote to the expansion of our operations and could adversely impact our ability to increase our revenues in future periods.

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.

Estimates of oil and natural gas reserves are inherently imprecise. Any material inaccuracies in these reserve estimates or underlying assumptions will affect materially the quantities and present value of our reserves.

Estimates of proved oil and natural gas reserves and the future net cash flows attributable to those reserves are prepared by independent petroleum engineers and geologists. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and cash flows attributable to such reserves, including factors beyond our control and that of our engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Different reserve engineers may make different estimates of reserves and cash flows based on the same available data. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future oil and natural gas prices and expenditures for future development drilling and exploration activities, and of engineering and geological interpretation and judgment. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based upon production history, development drilling and exploration activities and prices of oil and natural gas. Actual future production, revenue, taxes, development drilling expenditures, operating expenses, underlying information, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and underlying information set forth herein.

Approximately 75% of our total estimated proved reserves at April 30, 2011 were proved undeveloped reserves. In addition, there are no assurances that probable and possible reserves will be converted to proved reserves.

Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve engineer reports assumes that substantial capital expenditures are required to develop such reserves. Although cost and reserve estimates attributable to our natural gas and crude oil reserves have been prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate, that development will occur as scheduled or that the results of such development will be as estimated. We also have a significant amount of unproved reserves at April 30, 2011. There is significant uncertainty attached to unproved reserve estimates, which include probable and possible reserves. Proved reserves are more likely to be produced than probable reserves and probable reserves are more likely to be produced than possible reserves. There are no assurances that we can develop probable or possible reserves into proved reserves, or that if developed, probable reserves will become producing reserves to the level of the estimates.

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 constant 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 an appropriate discount factor for determining a market valuation. 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 relevance 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 such as our company. For instance, companies such as ours currently pay an $0.08 per barrel tax on all oil produced in the U.S. which is contributed to the Oil Spill Liability Trust Fund. There are pending proposals to raise this tax to $0.18 to $0.25 per barrel. It is also probable that there will be increased enforcement of existing regulations and adoption of new regulations which will also increase our cost of doing business which would reduce our operating profits in future periods.

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.

Our business depends on oil and natural gas transportation facilities, most of which are owned by others.

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.

Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate.

Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, formations with abnormal pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures or cement failures, and environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases. Any of these risks can cause substantial losses resulting from injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution and other environmental damages, regulatory investigations and penalties, suspension of our operations and repair and remediation costs. In addition, our liability for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease. We maintain insurance coverage against some, but not all,

potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operation.

Our Cook Inlet Basin leases and our Osprey Platform are located in a region of active volcanoes and we could be subject to the adverse impacts of natural disasters.

The Cook Inlet region contains active volcanoes, including Augustine Volcano, Mount Spurr and Mount Redoubt, and volcanic eruptions in this region have been associated with earthquakes and tsunamis and debris avalanches have also resulted in tsunamis. In 2009 the Cook Inlet Pipeline Co. suspended operations on several occasions as a result of the spring 2009 major eruption of Mount Redoubt which also resulted in a shutdown of the Drift River Oil Terminal. Our operations in this area are subject to all of the inherent risks associated with operations in a geographical region which is subject to natural disasters and we are susceptible to the risk of damage to our operations and assets located in the Cook Inlet Basin. While our facilities are engineered to withstand seismic activity, and the current tight line configuration should allow us to continue shipments through an active volcanic period without much interruption, we do not maintain business interruption insurance which could adversely impact our results of operations as the result of lost revenues in future periods.

Risks Related to the Ownership of Our Securities

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

At April 30, 2011 we have common stock warrants outstanding to purchase an aggregate of 85,400 shares of our common stock with an average exercise price of $1.74 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 35% of our currently outstanding common stock. The exercise of these options, warrants and purchase rights would be dilutive to our current shareholders.

At July 15, 2011 we had 40,559,251 shares of common stock outstanding together with outstanding options and warrants to purchase an aggregate of 13,975,955 shares of common stock at exercise prices of between $0.01 and $6.94 per share. Of our outstanding shares of common stock at July 15, 2011, approximately 11,135,338 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, the number of our outstanding common stock will increase by approximately 34%, 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, our financial statements for the years ended April 30, 2011 and 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 became effective for us on May 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 exempt for equity classification provided in ASC Topic 815-15. This means that instruments that were previously classified in equity required reclassification to liabilities and require ongoing measurement under ASC Topic 815. As a result of the application of this accounting principle, we recorded a current derivative liability of $2,305,118 for oil hedging instruments remaining until December 2011 and a long-term derivative liability of $2,732,659 at April 30, 2011. In addition, we recognized a non-cash loss on

derivative securities of $1,007,574 in fiscal 2011, as compared to a non-cash loss of $13,299,430 in fiscal 2010. Beginning in the first quarter of fiscal 2012, we expect to record either a gain or loss based upon the market price of our common stock. The amount of quarterly non-cash gains or losses we will record in future periods is unknown at this time as the measurement is based upon the fair market value of our common stock on the measurement date. It is likely, however, that these non-cash gains or losses will continue to have a material impact on our financial results in future periods.

ITEM 1B.

UNRESOLVED STAFF COMMENTS.

Not applicable to a smaller reporting company.

ITEM 2.

PROPERTIES.

Our executive offices presently comprise approximately 4,968 square feet and 6,600 square feet for the shop building, both located on 14.05 acres of land that we own in Huntsville, Tennessee. We own or rent facilities in the following locations:

Knoxville, Huntsville and Sunbright, Tennessee

Anchorage, Alaska

We also own a membership interest in each of two limited liability companies that own two office buildings in West Knoxville. Once the space is ready for our occupancy, we intend to move our corporate headquarters into one of those buildings in order to accommodate the growth of our company and additional employees.

Production facilities

Cook Inlet Energy operates two onshore production facilities and one offshore platform located on or near the West Foreland field, which is a small peninsula located in a remote area on the west side of Cook Inlet. The West Foreland is accessible by barge and fixed wing aircraft, and is not tied in with the Alaskan road system or electrical grid. Cook Inlet Energy maintains its own 10-mile road system and local electrical system.

The West McArthur River Unit Production Facility is one of our two onshore production facilities. It is located 3.5 miles south of Chevron's Trading Bay Production Facility, which is near the site of the local airstrip and barge landing. The West McArthur River Unit Production Facility can process 5,000 barrels of oil and seven MMcf of natural gas per day, generate three megawatts of electricity and contains 10,000 barrels of on-site tankage. The West McArthur River Unit Production Facility also includes our onshore camp, which provides housing and life support facilities sufficient for 65 people.

The Kustatan Production Facility is our other onshore production facility. This facility can process 30,000 barrels of oil a day, generate 16 megawatts of electricity, treat up to 20 MMcf of natural gas and contains 50,000 barrels of on-site tankage. The facility, which is located five miles south of The West McArthur River Unit Facility, is currently supporting our off-shore activity.

Oil and gas properties

Information on our oil and gas properties appears earlier in this report and in Notes 1, 2, 5 and 17 of “Notes to Consolidated Financial Statements” in this annual report.

ITEM 3.

LEGAL PROCEEDINGS.

On May 11, 2011, the Court of Appeals of Tennessee at Knoxville returned its opinion in the case styled CNX Gas Company, LLC v. Miller Petroleum, Inc., et al. As previously reported CNX Gas Company, LLC commenced litigation on June 11, 2008 in the Chancery Court of Campbell County, State of Tennessee to enjoin us from assigning or conveying certain leases described in the Letter of Intent signed by CNX and our company on May 30, 2008, to compel us to specifically perform the assignments as described in the Letter of Intent, and for damages. After the trial court granted the motion for summary judgment of the company and other party defendants and dismissed the case, finding that there were no genuine issues of material fact and we were entitled to judgment as a matter of law, CNX appealed. All parties filed briefs and the Court of Appeals heard oral arguments on May

18, 2010. In its May 11, 2011 opinion, the Court of Appeals reversed the trial court’s grant of summary judgment in favor of our company and the other party defendants, and remanded the case back to the trial court for further proceedings. On July 28, 2011, the case was dismissed without prejudice on the motion of CNX.

On May 17, 2011 we were served with a lawsuit filed in the United States District Court for the Eastern District of Tennessee at Knoxville by Troy D. Stafford, the former Chief Financial Officer of our wholly owned subsidiary, Cook Inlet Energy, LLC (“CIE”). The suit, styled Troy D. Stafford v. Miller Petroleum, Inc., Civil Action No. 3-11CV-206, claims that we terminated Mr. Stafford’s employment without cause in contravention of the terms of the Purchase and Sale Agreement between us and the sellers of CIE (“PSA”), failed or refused to pay his salary, severance, percentage of purchase price, expenses or stock warrant and violated a duty of good faith and fair dealing. The suit seeks damages in excess of $3,000,000, which includes $2,686,700 of damages for loss of vested warrants. We believe the all of the asserted claims are baseless, particularly in view of the fact that we issued the warrants in accordance with the terms of the PSA. We believe that we had appropriate cause to fire Mr. Stafford after discovering that he had breached certain representations and warranties in the PSA, and had acted in violation of our Code of Conduct. We intend to vigorously defend this action.

On June 15, 2011, a breach of contract lawsuit was filed against us and CIE in the United States District Court for the Eastern District of Pennsylvania styled VAI, Inc. v. Miller Energy Resources, Inc., f/k/a Miller Petroleum, Inc. and Cook Inlet Energy, LLC. The Plaintiff alleges three causes of action against the Defendants: (1) breach of contract, (2) unfair enrichment, and (3) breach of the implied covenant of good faith and fair dealing. The case seeks damages in warrants to purchase our common stock and monetary damages for certain fees and expenses. The Sale Agreement with David Hall, Walter “JR” Wilcox, and Troy Stafford dated December 10, 2009 contains indemnification provisions relevant to this claim. We have retained counsel and are currently drafting a responsive pleading.

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. On October 27, 2010, a temporary injunction was granted allowing us access to the property at issue in this case. We are presently conducting discovery.

We are also party to various routine legal proceedings arising in the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations.

ITEM 4.

(REMOVED AND RESERVED).

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

On April 12, 2011 our common stock was listed on the NYSE under the symbol “MILL”. From May 6, 2010 to April 11, 2011 our common stock was listed on the NASDAQ Global Market. Previously, our common stock was quoted on the OTC Bulletin Board and in the over the counter market on the Pink Sheets. The reported high and low sales prices for the common stock as reported on the various markets on which our stock was quoted during the periods indicated are shown below. The quotations reflect inter-dealer prices, without retail mark-up, markdown or commission, and may not represent actual transactions.


	High		Low

2010
First quarter ended July 31, 2009	$	0.38	$	0.22
Second quarter ended October 31, 2009	$	0.70	$	0.28
Third quarter ended January 31, 2010	$	2.95	$	0.60
Fourth quarter ended April 30, 2010	$	6.60	$	1.95

2011
First quarter ended July 31, 2010	$	7.48	$	4.40
Second quarter ended October 31, 2010	$	6.31	$	4.05
Third quarter ended January 31, 2011	$	5.69	$	4.20
Fourth quarter ended April 30, 2011	$	6.11	$	4.80

On July 15, 2011, the last sale price of our common stock as reported on the NYSE was $8.02. As of July 15, 2011, there were approximately 355 record owners of our common stock.

Dividend Policy

We have never paid cash dividends on our common stock and we do not anticipate that we will declare or pay dividends in the foreseeable future. Payment of dividends, if any, is within the sole discretion of our Board of Directors and will depend, among other factors, upon our earnings, capital requirements and our operating and financial condition. In addition under Tennessee law, we may not pay a dividend if, after giving effect, we would be unable to pay our debts as they become due in the usual course of business or if our total assets would be less than the sum of our total liabilities plus the amount that would be needed if we were to be dissolved at the time of the payment of the dividend to satisfy the preferential rights upon dissolution of shareholders whose preferential rights were superior to those receiving the dividend.

ITEM 6.

SELECTED FINANCIAL DATA.

Not applicable to a smaller reporting company.

ITEM 7.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

We are an independent exploration and production company that utilizes seismic data, and other technologies for geophysical exploration and development of oil and gas wells in the Cook Inlet Basin in south-central Alaska and the Appalachian region of eastern Tennessee. Occasionally, during times of excess capacity, we offer these services, on a contract basis, to third-party customers primarily engaged in our core competency - natural gas exploration and production.

Currently, we are continuing to develop the acreage we acquired during fiscal 2010 and 2011. These acquisitions have grown our Alaskan acreage position to approximately 649,507 acres of gross oil and gas leases and exploration license rights (630,462 net acres), which includes 471,474 acres under the Susitna Basin Exploration License No. 2 and 62,909 acres under the Susitna Basin Exploration License No. 4 (also referred to as our North Susitna Exploration License). We are continuing to assess and add strategic acreage to our Alaska leases and licenses. Our Tennessee leases consist of 37,916 acres, making our total gross acreage 687,423 acres.

During the year ended April 30, 2011, we began completion work on three Alaska wells that were previously shut in, and we have completed work on two of these wells. We capitalized approximately $8.6 million of costs associated with those efforts. In addition, we plan to recomplete eight previously shut in wells in the next three to six months.

Our management is focusing the majority of its efforts on growing our company. In addition to raising capital we are continuing to focus our short-term efforts on two distinct areas:

increasing our overall oil and gas production through maintenance and repairs of nonperforming or underperforming oil and gas wells, and

organically growing production through drilling for our own benefit on existing leases and under license rights, leveraging our 100,000 plus well log database and approximately 700,000 acres which are either under lease or part of the Susitna Basin Exploration License, with a view towards retaining the majority of working interest in the new wells.

Our ability to implement one or more of these goals in a timely manner has been greatly increased by our securing of a $100 million credit facility with an initial borrowing base of $35 million. These funds will be used to rework certain wells, to drill new wells, and to purchase a custom drilling rig that we expect will allow us to bring our Osprey offshore platform into full production. As of June 30, 2011, two wells have been reworked on the platform by replacing their electronic submersible pumps. The wells, RU-1 and RU-7, are producing above the expected rates of 200 bbls/day. As of June 30, 2011, the wells have averaged 335 bbls/day (RU-1) and 245 bbls/day (RU-7).

During fiscal 2011 and the first quarter of fiscal 2012 we had a number of significant accomplishments:

FINANCING:

On December 27, 2010, we obtained a $5,000,000 line of credit from PlainsCapital Bank that provided financial flexibility to us while we continued to seek longer-term financing.

On June 13, 2011, we closed on a $100 million credit facility with an initial availability of $35 million with Guggenheim Corporate Funding, LLC, Citibank, N.A., and Bristol Investment Fund, Ltd. The PlainsCapital facility allowed us to stay on track with our development plans as we sought the larger, longer-term facility. We used a portion of the proceeds from the Credit Facility to satisfy the PlainsCapital line of credit in June 2011.

LAND AND DEVELOPMENT:

We entered into our Performance Bond Agreement regarding the Redoubt Offshore assets with the Alaska DNR, and received approval of CIE’s Amended Redoubt Unit Plan of Development, which was approved on February 17, 2011, as well as approval of the Redoubt Redevelopment Plan, which was approved March 16, 2011. This agreement and these approvals allowed us to restart the

operation of our Osprey offshore Platform in March 2011. Since the platform has come back online, we have successfully reworked two wells on it, substantially adding to our production in Alaska.

In June 2011 we contracted with Voorhees Equipment and Consulting, Inc. for the custom construction and purchase of a drilling rig for the Osprey platform for $17.9 million. We expect the rig to be moved to arrive in Alaska in September 2011 and become operational in November 2011.

In June 2011, we signed a five year lease for new office space for our corporate headquarters, and acquired a minority ownership interest in the entities that own the building that will be our new home. This lease and acquisition should allow us to meet our demands for increased space for our growing team of employees.

We were the successful bidder on additional acreage in Alaska that complements our current acreage, adding another 17,027 acres. This acreage was awarded with an effective date of April 1, 2011.

We were awarded our North Susitna exploration license (No. 4), and along with leases won at auction, these new properties result in an increase of 79,936 acres in our gross acreage to 687,423 acres

We secured a three-year extension of the Susitna Basin Exploration License No. 2, which is comprised of 471,474 acres. The terms of the extension require us to spend an aggregate of $750,000 over the next three years under a new work commitment. This extension will allow us to identify the most valuable acres covered by the license and convert only the most promising prospects to leases at the expiration of the license.

We strategically assigned four leases with a total gross acreage of 8,828.5 acres to Buccaneer Alaska for total consideration of $12,500, as of June 1, 2010. We retained the overriding royalty interests in each lease including 2% in the ADL-391108 and ADL-17595-2 leases and 4% in the ADL-390379 and ADL-390370 leases. If Buccaneer Alaska fails to drill at least one well on the leased acreage by 2013, we will be entitled to a payment of $303,613, and may choose to cause Buccaneer Alaska to assign any of the leases to us that remain active.

SETTLEMENT OF DISPUTES:

We settled two of our significant lawsuits, entering into a settlement agreement with Petro Capital III, LP and Petro Capital Advisors, LLC and with Prospect Capital Corporation; which resolved litigation that had been pending in federal court in Texas. The settlement agreement resulted in our issuing a total of 518,510 shares of our common stock to Petro Capital III, LP and Petro Capital Advisors, LLC. We also settled similar claims with Prospect Capital Corporation. We issued a total of 2,013,814 shares of our common stock to Prospect Capital Corporation upon the cashless exercise of certain warrants. In addition to the attorney fee savings and certainty that comes from the settlement and dismissal of the Petro lawsuit and Prospect claims, we have eliminated a substantial amount of the derivative liability that we had booked as a result of the anti-dilution clause in the warrants at issue in this matter. These warrants accounted for the majority of our long-term derivative liability, and their elimination has contributed in a decrease in our total derivative liability from $16,897,275 at April 30, 2010 to $5,037,777 at April 30, 2011. On January 28, 2011, we entered into a settlement agreement with Gunsight Holdings, LLC. The lease in dispute in the lawsuit was declared to be in full force and effect, and we agreed to drill at least one well on the property subject to the lease each year for the next four years.

We reduced our transportation costs in Alaska substantially by settling a tariff dispute. On November 19, 2010, the Regulatory Commission of Alaska accepted a settlement agreement between CIE and the Cook Inlet Pipe Line Company ("CIPL"). CIPL, a subsidiary of Chevron Pipeline Co., operates a 42-mile pipeline on the west side of Cook Inlet, and is the sole means by which CIE can export its oil production. This settlement reduced transportation costs for all CIE production by $6.57 per barrel to a rate of $8.00 per barrel for the remainder of 2010. On February 15, 2011, we received a cash payment of approximately $1,500,000 pursuant to the true-up mechanism in the settlement agreement. CIPL retained another $250,000 that was credited toward the costs of our future shipments.

CORPORATE GOVERNANCE and LEADERSHIP:

We moved the primary listing of our common stock from the NASDAQ Global Market to the New York Stock Exchange on April 12, 2011.

On January 17, 2011 we added to our Board of Directors an experienced oil and gas accounting executive who has over 35 years of accounting and financial experience with an emphasis in the oil and gas business, and we appointed him as chairman of our Audit Committee on March 11, 2011.

We held our annual shareholders’ meeting for fiscal 2010 on March 11, 2011. At that meeting the current members of our Board were re-elected, we adopted a stock plan compliant with Section 162(m) of the Internal Revenue Code to allow us to deduct certain compensation under the exemption in that section, changed our name officially to Miller Energy Resources, Inc., and adjusted the quorum required for shareholders’ meetings going forward.

We entered into a revised employment agreement with our CEO, Scott Boruff, and a new employment agreement with our CFO, Paul Boyd, ensuring continuity in our management. In early fiscal 2012, we hired Director David Voyticky as our President. Along with Founder, Chairman of the Board, and Chief Operating Officer Deloy Miller and CIE CEO David Hall, we have assembled and retained a management team to lead us into our next phase of development.

Results of Operations

Fiscal 2011 as compared to fiscal 2010.

Fiscal 2011 as compared to fiscal 2010 was a year of growth and development. We recorded a loss of $4,439,749, for fiscal 2011 which compares to net income of $250,930,568 for fiscal 2010. As seen below, if you exclude interest income and expense, income tax expense and depletion, depreciation and amortization (“DD&A”) from the numbers, fiscal 2011 shows this adjusted earnings before interest, income taxes, depreciation, depletion and amortization (“EBITDA”) to be a positive $3,142,532 as compared to an EBITDA of $439,162,943 for fiscal 2010. Revenues increased $16,974,865 between the years while costs and expenses increased $20,734,220. Other income dropped significantly from $446,930,429 in fiscal 2010 to $4,921,656 in fiscal 2011 as fiscal 2010 had large one-time acquisition gains driving this total as compared to fiscal 2011. The major components of our Consolidated Statement of Income for fiscal 2011 and 2010 are as follows:


	For the Year Ended April 30,
	2001			2010			% Change

Revenues	$	22,841,869		$	5,867,004		289	%
Costs and expenses		(37,924,325	)		(17,190,105	)	113	%
Other income		(4,921,656	)		446,930,429		(101	)%
Income tax benefit (expense)		5,721,051			(184,676,760	)	(103	)%
Net income (loss)	$	(4,439,749	)	$	250,930,568		(97	)%

EBITDA

To assess the operating results of the Company, the chief operating decision maker analyzes income (loss) before income taxes, interest income and expense, and depreciation, depletion and amortization (“DD&A”). EBITDA is not a GAAP measure. DD&A and impairments are excluded from EBITDA as a measure of operating performance because capital expenditures are evaluated at the time capital costs are incurred. Management believes that the presentation of EBITDA provides information useful in assessing the Company’s financial condition and results of operations and that EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions to stockholders.

EBITDA, as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, our EBITDA should be considered in conjunction with net income (loss) and other performance measures prepared in accordance with GAAP, such as operating income or cash flow from operating activities. EBITDA has important limitations as an analytical tool because it excludes certain items that affect net

income (loss) and net cash provided by operating activities. EBITDA should not be considered in isolation or as a substitute for an analysis of the Company’s results as reported under GAAP.

Reconciliation of EBITDA for fiscal 2011 and 2010 is as follows:


	For the Year Ended April 30,
	2001			2010

Net income (loss)	$	(4,439,749	)	$	250,930,568
Add (deduct):
Interest income		(546,274	)		(25,616	)
Interest expense		990,235			156,617
Income tax expense (benefits)		(5,721,051	)		184,676,760
Depreciation, depletion and amortization		12,859,371			3,424,614
EBITDA	$	3,142,532		$	439,162,943

The following table shows the components of our revenues for fiscal 2011 and 2010, together with their percentages of total revenue in each year and percentage change on a year-over-year basis.


	For the Year Ended April 30,
	2011		2010		% Change
Revenues
Oil sales	$	19,999,423	$	4,064,909	351	%
Natural gas sales		525,694		372,306	41	%
Other revenue		2,316,752		1,429,789	62	%
Total revenues	$	22,841,869	$	5,867,004	289	%

Oil and gas revenue represents revenues generated from the sale of oil and natural gas produced from the wells in which we have an ownership interest. Oil and gas revenue is recognized as income as production is extracted and sold. We reported a 351% increase in oil revenues for fiscal 2011 over 2010. The increase was primarily due to the addition of the Alaskan oil well production during fiscal 2011 which accounted for revenues of approximately $19.4 million for the year then ended. In addition, we produced 397,113 Mcf of gas in fiscal 2011 in Alaska but we did not sell this as substantially all was used in our Alaska oil production.

The increase in our oil and gas revenue from fiscal 2010 to 2011 was primarily due to increased production from the Alaska acquisition as well as increased oil and gas prices. For fiscal 2011 we sold 312,583 barrels of oil and sold at an average price of $83.43 per barrel in Alaska and we sold 27,807 barrels of oil at an average price of $76.25 per barrel in Tennessee. We also produced 397,113 Mcf of natural gas in Alaska which we converted 208,954 Mcf to electricity and used internally and banked 188,159 Mcf for future use, and produced and sold 288,983 Mcf in Tennessee at an average of $2.67 per Mcf. In 2010 we produced 63,002 barrels of oil and sold at an average price of $78.76 per barrel in Alaska and $71.33 in Tennessee. We also produced 154,291 Mcf of natural gas in Alaska which we primarily converted to electricity and used internally and produced 202,283 and sold Mcf and sold at $3.96 per Mcf in Tennessee during fiscal 2010.

Other revenue represents revenues generated from contracts for plugging, drilling, maintenance and repair of third party wells as well as rental income we received for use of our Alaska facility. Service and drilling income is recognized at the time it is both earned and we have a contractual right to receive the revenue. Our other revenue increased 62% for fiscal 2011 as compared to fiscal 2010.

The increase was impacted by a $0.4 million increase in rental income.

In summary, our total revenues increased 289% to $22,841,869 in fiscal 2011 as compared to fiscal 2010. If our efforts to turn non-productive wells into productive wells and drill new wells reach our expectations, and the price of oil and gas does not drop significantly, we expect revenue to continue to increase in fiscal 2012.

Costs and Expenses

The following table shows the components of our direct costs and expenses for fiscal 2011 and 2010. Percentages listed in the table reflect margins for each component of direct expenses and percentage change on a year-over-year basis for each component of other expenses.


	For the Year Ended April 30,
	2011		2010		% Change
Costs and Expenses
Oil and gas operating	$	9,702,548	$	2,737,774	254	%
Cost of other revenue		807,739		754,559	7	%
General and administrative		14,554,667		11,380,158	28	%
Depletion, depreciation and amortization		12,859,371		3,424,614	276	%
Total costs and expenses	$	37,924,325	$	18,297,105	103	%

Oil and gas operating expenses increased approximately $7.0 million or 254% from fiscal 2010 to 2011 primarily due to costs associated with the Alaska business we acquired in December 2009. Expenses associated with the work on the Alaska operation to return non-productive wells to producing status increased approximately $2.1 million between fiscal 2010 and fiscal 2011 and direct labor and contract services increased $1.0 million and $0.3 million, respectively, surface materials increased approximately $0.4 million and pipeline expenses contributed another approximately $0.6 million to this variance as well. During fiscal 2012, we expect to continue to turn more non-productive wells to producing status and if that occurs, we expect these expenses will continue to rise; however, we are not able at this time to quantify the amount of any anticipated increase in expenses.

Our central business activity is exploration and production and the cost of other revenue represents costs of services to third parties as a result of excess capacity, and are primarily derived from the direct labor costs of employees associated with these services, as well as costs associated with equipment, parts and repairs. Fiscal 2011 showed $807,739 for this component, up 7% from $754,559 in fiscal 2010. During fiscal 2011, we drilled three wells for ourselves and also entered into a contract with the U.S. Department of Interior for plugging non-company related abandoned wells located in the Big South Fork area in Tennessee and Kentucky. During fiscal 2010, we drilled 10 wells for Atlas Energy, and in preparation for the Atlas Energy drilling contract we spent significant time and expense maintaining and repairing our drilling equipment in fiscal 2010 which contributed to the costs for that year

General and administrative expense includes salaries, general overhead expenses, insurance costs, professional fees and consulting fees. Salaries were $2,580,444 for fiscal 2011, which was an increase of $1,263,251, as compared to fiscal 2010, and was primarily due to the increased staff in Alaska. Professional fees were $3,203,782 for fiscal 2011, which is an increase of $180,902 or 6% due primarily to increased costs associated with the new acquisitions and onetime costs associated with a registration statement filed with the SEC, as well as increases in investor relations and public relations expenses. In addition, we incurred expenses of $5,161,751 in non-cash items, which were recorded as compensation expense during fiscal 2011, an increase of $3,141,875, or 156%, from the non-cash compensation amount recorded for fiscal 2010 of $2,019,876. These expenses were associated primarily with director and employee equity awards granted or vesting during the year. This new layer of expense will continue in future periods and may increase as further development in Alaska occurs. As we continue to grow our business, particularly in Alaska, we expect these general and administrative expenses will continue to rise in fiscal 2012, however, we are unable at this time to quantify the amount of these expected increases.

Depletion, depreciation and amortization expense increased 276% to $12,859,371 in fiscal 2011 from fiscal 2010. We capitalize costs of proved oil and gas properties and record depreciation, depletion and amortization provide on a pooled basis using the units-of-production method based upon proved reserves. During fiscal 2011, depletion, depreciation and amortization expense was 56% of total revenue, as compared to $3,424,614 or 58% of total revenue for fiscal 2010. The primary reason for the increase in expense for fiscal 2011 was the addition of wells and equipment as a result of the Alaska business combination. These non-cash expenses will continue at this higher level as the Alaska assets are being depleted over a range of 30 to 40 years.

As a result of these components, total costs and expenses were $37,924,325, which reflected an operating loss of $15,082,456 for fiscal 2011. This compares to an operating loss of $11,323,101 for fiscal 2010.

Other Income (Expense)

The following table shows the components of certain of our other income and expenses for fiscal 2011 and 2010. Percentages listed in the table reflect percentages of total revenue for each component of other expenses.


	For the Year Ended April 30,
	2011			% of Revenue	2010			% of Revenue
Interest expense, net of interest income	$	(443,961	)	(2)%	$	(131,001	)	(2)%
Loss on derivative securities		(1,007,574	)	<1%		(13,299,430	)	227%
Other income (expense), net		(537,157	)	2%		(751,064	)	NM
Gain on acquisitions		6,910,348		30%		461,111,924		NM
Total	$	4,921,656		22%	$	446,930,429		NM

NM = not meaningful

Interest expense, net of interest income decreased $312,960 or 239% in fiscal 2011 compared to fiscal 2010. This was primarily due to non-cash expenses in fiscal 2010 related to the fair value of warrants issued in connection with a prior financing transaction. This was partially offset by fiscal 2011 interest expense associated with our 6% convertible note program as these notes were issued during fiscal 2010, but converted into equity during the fiscal year 2011, as described more fully in Other Recent Financing Transactions further in this report.

Our derivative liability fluctuates from period to period based on changes in the price of oil for our commodity derivative pricing as well as for changes in components of the Black-Scholes pricing model including the Company's ending stock price, risk free rates, expected life terms, expected volatility and expected dividend rates for our outstanding warrants that have reset provisions. During fiscal 2010 and fiscal 2011, the Company recorded a non-cash losses of $13,299,430 and $1,007,574, respectively, relating to the change in fair value of these derivative instruments. The loss in fiscal 2010 was comprised of three transactions, 3,000,000 warrants issued in the current and past years, 817,055 warrants issued in an equity financing in March 2010 and 300,000 warrants issued pursuant to a consulting arrangement in March 2010. Two of these transactions are no longer applicable at April 30, 2011, as we made a settlement on the 3,000,000 warrants, and the derivative language was removed from a consultant agreement related to the 300,000 warrants, so we only need value the 817,055 warrants program as of April 30, 2011. The application of this accounting treatment on our financial statements in future periods could likewise result in non-cash gains or losses, which could be significant.

During fiscal 2010, we recorded a gain on acquisitions of $461,111,924. This was primarily due from the Alaskan acquisition as previously discussed. During fiscal 2011, we recorded a gain of $6,910,348 primarily related to approximately $6.8 million of restricted cash, which we could not verify was ours until we entered into the Performance Bond Agreement with the state of Alaska on February 17, 2011. On March 11, 2011, CIE entered into a Performance Bond Agreement with the Alaska DNR that applies to the offshore obligations under the Assignment Oversight Agreement. Under the Performance Bond Agreement, CIE is required to post a total bond of $18 million; however, the Performance Bond Agreement also makes clear that approximately $6.8 million held by the state will apply to the total bond required. Therefore, we recorded this event as a gain on acquisition for our Alaska subsidiary. We do not anticipate recording similar gains on acquisitions in future periods.

Liquidity and capital resources

Liquidity is the ability of a company to generate sufficient cash to satisfy its needs for cash. We experienced operating losses for fiscal year 2011 and 2010 and had a working capital deficit as of April 30, 2011. We anticipate that our operating expenses will continue to increase as we fully develop our operations following the acquisition of the Alaskan assets. Although we expect an increase in our revenues to come from these development activities, we will continue depleting our cash resources to fund operating expenses until such time as we are able to significantly increase our revenues. We may have to reduce our expansion efforts if we have not seen an increase in revenues over the next few months.

Subsequent to year-end we secured a $100 million credit facility which we will utilize to further develop our Alaskan subsidiary for off-shore and on-shore oil and gas wells. We do not have any other external sources of working capital. Management believes that the credit facility, along with projected cash flow, are adequate to meet our funding needs for fiscal 2012. See Loan Commitment from Financial Institutions and Guggenheim Corporate Funding, LLC.

At April 30, 2011 we had a working capital deficit of $7,691,517 as compared to a working capital surplus of $229,384 at April 30, 2010. This decrease in capital surplus is primarily due to an increase in trade payables of $3,917,674, an increase in accrued expenses of $3,453,480 and an increase in notes payable of $2,000,000, partially offset by an increase in state tax credits receivable of $2,513,336.

From April 30, 2010 to April 30, 2011, cash decreased from $2,994,634 to $1,558,933. This decrease was primarily due from an increase in cash used in investment activities of $11,177,090, partially offset by increases in cash provided by operations of $3,776,581 and cash provided by financing activities of $6,208,601.

We presently have internal plans for capital expenditures of approximately $66 million for fiscal 2012; $45 million of this earmarked to restore production from our Redoubt Unit, including the purchase and construction of a drilling rig. We anticipate we will draw on our $100 million credit facility to access these cash needs. We also believe we will have increased cash flow from our planned increased production. However, if those avenues are not sufficient, we may be required to raise additional capital or change our capital expenditure plans.

As previously discussed, 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. 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. We have subsequently provided these funds for the West McArthur River facility using a portion of the proceeds of our capital raising efforts described elsewhere herein.

Cash flows

Net cash provided by operating activities for fiscal 2011 was $962,052. This primarily reflects a gain on acquisitions of $6,910,348, and gains on derivative securities of $2,427,485, along with increases in accounts payable and accrued liabilities of $7,398,430, which were partially offset by operating losses of $16,523,864 for fiscal 2011.

Net cash used by operating activities for fiscal 2010 was $1,744,837. This primarily reflects the cash paid for the operating expenses and selling, general and administrative expense in excess of revenues received for the period, which included the gain from the Alaska transaction, but partially offset by the issuance of equity for services, compensation and financing costs of $3,892,886.

Net cash used in investing activities for fiscal 2011 of $15,048,098 is primarily due to additions to property and improvements of $1,056,979 and capital expenditures for oil and gas properties of $14,011,119.

Net cash used by investing activities for fiscal 2010 of $10,476,830 is primarily due to the cash we paid for the Alaska assets of $4,541,252 and the purchase of oil and gas properties of $5,600,843, which were primarily costs associated with well startups.

Net cash provided by financing activities of $12,894,138 for fiscal 2011 primarily reflects the exercise of equity rights for $12,354,450 and proceeds from borrowings of $5,500,000, which were partially offset payments on notes payable of $3,500,000.

Net cash provided by financing activities of $14,925,942 for fiscal 2010 primarily reflects the net cash received from the sale of stock of $9,646,478, proceeds received from borrowings of $5,926,444, a $1,856,488 decrease in restricted cash due to payoff of a bank financing, and cash acquired through acquisitions of $203,993, which was partially offset by payments on notes payable of $2,309,205.

Loan Commitment from Financial Institutions and Guggenheim Corporate Funding, LLC

On June 13, 2011, we entered into a Loan Agreement (the “Loan Agreement”) with Guggenheim Corporate Funding, LLC (“Guggenheim”), as Administrative Agent, Arranger and Lender and Citibank, N.A. and Bristol Investment Fund as Lenders.

The Loan Agreement provides for a credit facility of up to $100 million with an initial borrowing base of $35 million. The credit facility matures on June 13, 2013 and is secured by substantially all of our assets and those of our subsidiaries. Amounts outstanding under the credit facility bear interest at a rate per annum equal to the higher of 9.5% or the prime rate plus 4.5%. In addition, we are required to pay an additional make-whole payment upon

termination or payment in full of the credit facility, bringing the effective interest rate to 25% to 35%, depending on the timing of repayment. Beginning on January 1, 2012, or earlier under certain circumstances, we are required to use 90% of our consolidated monthly net revenues (after deducting general and administrative expenses to the extent permitted under the Loan Agreement) to repay the loans outstanding under the Credit Facility. Proceeds of certain asset sales and indebtedness and other proceeds received outside the ordinary course of business are required to be used to repay loans outstanding under the Credit Facility.

Draws under the credit facility are subject to the discretion of the administrative agent and the lenders. The borrowing base is determined on a scheduled basis twice per year, and more often our or the required lender’s request. The redetermination of the borrowing base is at the discretion of the lenders. The Loan Agreement contains interest coverage, asset coverage and minimum gross production covenants, as well as other affirmative and negative covenants. In connection with the Loan Agreement, we granted Guggenheim a right of first refusal to provide financing for the acquisition, development, exploration or operation of any oil and gas related properties including wells during the term of the Credit Facility and one year thereafter.

Upon an event of default under the Loan Agreement, all amounts outstanding accelerate and become immediately due and payable, the Lenders may stop making advances under the credit facility and may terminate the agreement. An “event of default” includes, among other things, our failure to pay any amounts when due, our failure to perform under or observe any term, covenant or provision of the Loan Agreement, the occurrence of a Material Adverse Change (as that term is defined in the Loan Agreement), the seizure of or levy upon our assets or properties, our insolvency or bankruptcy, judgments against us in excess of certain amounts, defaults under certain other agreements, the limitation or termination of the any of the guarantors, which include us and all of our subsidiaries, under the Guarantee and Collateral Agreement described below, the death or incapacitation of either Mr. Scott Boruff or Mr. David Hall, or if either of them cease to be substantially involved in our operations or the breach or termination of the Shareholders Agreement described below.

On the closing date of the Loan Agreement we paid the administrative agent, ratably for the benefit of the Lenders a non-refundable facility fee of $700,000. We also agreed to pay a non-refundable fee of 2% on increase in the borrowing base from the borrowing base limit then in effect. At closing we paid the administrative agent a non-refundable fee of $30,000 and agreed to pay annual additional fees in this amount so long as the Loan Agreement remains in effect. A finder’s fee of 3% of the initial borrowing base of $35 million to Bristol Capital, LLC, a consultant to us and an affiliate of Bristol Investment Fund, Ltd., was also due.

In connection with the credit facility, certain of our executive officers and directors entered into a Shareholders’ Agreement which is described later in this report.

We expect to use the proceeds of the loans made under the Credit Facility to increase oil production both onshore and offshore in Alaska through the drilling of new wells and the reworking of previously producing oil wells and for the purchase of a new drilling rig. The first draws, totaling $10,874,612, have been used to pay fees associated with the transaction, such as attorney’s fees, to pay off our line of credit with PlainsCapital Bank, to make the first progress payment under the Rig contract, and for working capital.

Other Recent Financing Transactions

In order to finance the expansion of our operations into Alaska and to provide capital for our other operations, we entered into the following financing transactions:

In December 2009 we issued $2,855,000 principal amount 6% convertible secured promissory notes to provide funds for the Alaskan asset transaction. Included in the sales of these notes was an aggregate of $500,000 purchased by Mr. Scott Boruff, our Chief Executive Officer and a member of our Board of Directors, and Mr. Deloy Miller, member of our Board of Directors. We paid a finder’s fee of $20,000. Interest on the notes is paid quarterly and the principal is due December 4, 2016. The holders of all of these notes, including Messrs. Boruff and Miller, have subsequently converted the notes into shares of our common stock. As of April 30, 2011, none of the notes remain outstanding.

Between December 2009 and January 2010 we sold 6,015,000 shares of our common stock in private transactions to accredited investors for $1.00 per share. This was a discount of 16.67% from market value on the date of determination. The $5,657,000 in net cash proceeds from this offering, after payment of offering costs, commissions and finder’s fees, was used for general corporate purposes,

including reducing debt and partially financing the Alaska asset acquisition. We paid Sutter Securities Incorporated, a FINRA member firm, cash compensation of $200,000 as well as a non-accountable sum of $10,000 for its legal fees and expenses and issued it five-year warrants to purchase an aggregate of 280,000 shares of our common stock at exercise prices ranging from $1.35 to $1.815 per share. We also paid finder’s fees of $123,000 and issued five-year warrants to purchase an aggregate of 52,500 shares of our common stock at exercise price of $1.35 per share. In addition, we paid Seaside 88 Advisors, LLC, the general partner of one of the purchasers of the shares, a non-accountable sum of $25,000. The warrants are exercisable on a cashless basis. If we make any subsequent sales of our securities within one year to any purchaser introduced to us by Sutter Securities Incorporated, we are obligated to pay that firm a finder’s fee on those sales. Under the terms of the Securities Purchase Agreements we agreed that until 12 months from the closing date, if in connection with a Subsequent Financing (as defined in the Securities Purchase Agreement), either our company or any of our subsidiaries should issue any common stock or common stock equivalents entitling any person or entity to acquire shares of common stock at an effective price per share less than the per share purchase price of $1.00 (subject to reverse and forward stock splits and the like), that we will issue to the purchaser of this current stock sale, a number of additional shares of common stock to the aforementioned purchasers to prevent the follow-on investment from being a dilutive issuance. If shares are issued for a consideration other than cash, the per share selling price shall be the fair value of such consideration as determined in good faith by the Board of Directors. We also granted the purchasers of stock certain piggy back registration rights until such time as the purchasers are able to resell the shares of common stock purchased in the offering pursuant to Rule 144 of the Securities Act until the requirement for adequate public information on our company is no longer applicable.

On March 26, 2010, we executed a Securities Purchase Agreement pursuant to which at closing we agreed to sell units of our securities, including 1,433,432 shares of our common stock at a purchase price of $3.50 per share and five year warrants to purchase an additional 716,716 shares of common stock with an exercise price of $5.28 per share to 14 accredited and/or institutional purchasers. This offering closed on April 1, 2010. We received gross proceeds $5,017,002. Sutter Securities Incorporated, a broker-dealer and member of FINRA, acted as finder for us in this unit offering. Under the terms of a Finder’s Agreement with the firm, we paid Sutter Securities Incorporated a fee of $346,190 and issued the firm five-year common stock purchase warrants to purchase an aggregate of 100,339 shares of our common stock at an exercise price of $5.28 per share. In addition, we paid a finder’s fee of $5,000 to Viriathus Capital LLC and paid the attorney for Sutter Securities Incorporated legal expenses totaling $10,000 incurred in the preparation of the various transactional documents. We used the net proceeds of this offering for general corporate purposes.

The Securities Purchase Agreement for the March 2010 unit offering provided that until September 26, 2010 any securities sold in the offering are subject to a per share price protection. In the event we were to issue any shares of common stock, or securities convertible into or exercisable for shares of common stock, to any third party purchaser at a purchase price or exercise price per share which is less than $3.50 per share, or less than the exercise price of $5.28 per warrant share (collectively, the “Discounted Per Share Purchase Price”), we would automatically issue additional shares of our common stock to the purchasers in the March 2010 unit offering without the payment of any additional consideration by those purchasers. We did not issue any shares lower than $3.50 or issue any exercisable shares at less than $5.28.

Under the terms of the Registration Rights Agreement entered into with the purchasers in the March 2010 unit offering, we were obligated to file a registration statement with the SEC covering the shares of common stock issued and sold in the offering, as well as the shares of common stock underlying the warrants, on or before April 15, 2010 so as to permit the public resale thereof. We filed the registration statement on August 13, 2010, and it was declared effective on August 25, 2010. Because we did not timely file the registration statement, we have recorded liquidated damages during the fourth quarter of fiscal 2010.

Off Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that we are required to disclose pursuant to these regulations. In the ordinary course of business, we enter into operating lease commitments, purchase commitments and other contractual obligations. These transactions are recognized in our financial statements in accordance with generally accepted accounting principles in the United States.

Critical Accounting

General

The preparation of financial statements requires management to utilize estimates and make judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. These estimates are based on historical experience and on various other assumptions that management believes to be reasonable under the circumstances. The estimates are evaluated by management on an ongoing basis, and the results of these evaluations form a basis for making decisions about the carrying value of assets and liabilities that are not readily apparent from other sources. Although actual results may differ from these estimates under different assumptions or conditions, management believes that the estimates used in the preparation of our financial statements are reasonable. The critical accounting policies affecting our financial reporting are summarized in Note 1 to the consolidated financial statements included in this annual report. Policies involving the most significant judgments and estimates are summarized below.

Impact of Derivative Accounting

As a result of recent financing transactions we have entered into, our financial statements are impacted by the accounting effect of the application of derivative accounting. The application of EITF 07-05 “Determining Whether an Instrument (or Embedded Feature) is Indexed to a Company's Own Stock,” which was effective for our company in May 2009, significantly affects 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 are reclassified to liabilities and ongoing measurement under ASC Topic 815. The amount of non-cash gains or losses we record is based upon the fair market value of our common stock on the measurement date.

Estimates of Proved Reserves and Future Net Cash Flows

Estimates of our proved oil and gas reserves and related future net cash flows are used in impairment tests of goodwill and other long-lived assets. These estimates are prepared as of year-end by independent petroleum engineers and are updated internally at mid-year. There are many uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The accuracy of any reserve estimate is dependent on the quality of available data and is subject to engineering and geological interpretation and judgment. Results of our drilling, testing and production after the date of these estimates may require future revisions, and actual results could differ materially from the estimates.

Impairment of Long-Lived Assets

Our long-lived assets include property, equipment and goodwill. Long-lived assets with an indefinite life are reviewed at least annually for impairment, and all long-lived assets are reviewed whenever events or changes in circumstances indicate that their carrying values may not be recoverable.

Oil and Gas Activities

We follow the successful efforts method of accounting for our 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

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.

Fair Value of Financial Instruments

Effective May 1, 2008, we adopted guidance issued by the FASB on "Fair Value Measurements" for assets and liabilities measured at fair value on a recurring basis. This guidance establishes a common definition for fair value to be applied to existing generally accepted accounting principles that require the use of fair value measurements, establishes a framework for measuring fair value, and expands disclosure about such fair value measurements. The adoption of this guidance did not have an impact on our financial position or operating results, but did expand certain disclosures.

The FASB defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Additionally, the FASB requires the use of valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

These inputs are prioritized below:


	Level 1:		Observable inputs such as quoted market prices in active markets for identical assets or liabilities.
	Level 2:		Observable market-based inputs or unobservable inputs that are corroborated by market data
	Level 3:		Unobservable inputs for which there is little or no market data, which require the use of the reporting entity's own assumptions.

Cash and cash equivalents include money market securities and commercial paper and marketable securities representing certificates of deposits maturing in less than one year that are considered to be highly liquid and easily tradable. These securities are valued using inputs observable in active markets for identical securities and are therefore classified as Level 1 within the fair value hierarchy.

In addition, the FASB issued, "The Fair Value Option for Financial Assets and Financial Liabilities," effective for May 1, 2008. This guidance expands opportunities to use fair value measurements in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. We did not elect the fair value option for any of our qualifying financial instruments.

Equity-Based Compensation

The computation of the expense associated with stock-based compensation requires the use of a valuation model. The FASB issued accounting guidance requires significant judgment and the use of estimates, particularly surrounding Black-Scholes assumptions such as stock price volatility, expected option lives, and expected option forfeiture rates, to value equity-based compensation. We currently use a Black-Scholes option pricing model to calculate the fair value of our stock options. We primarily use historical data to determine the assumptions to be used in the Black-Scholes model. However, changes in the assumptions to reflect future stock price volatility and future stock award exercise experience could result in a change in the assumptions used to value awards in the future and may result in a material change to the fair value calculation of stock-based awards. This accounting guidance requires the recognition of the fair value of stock compensation in net income. Although every effort is made to ensure the accuracy of our estimates and assumptions, significant unanticipated changes in those estimates, interpretations and assumptions may result in recording stock option expense that may materially impact our financial statements for each respective reporting period.

Recent Accounting Pronouncements

On January 1, 2009, we adopted the FASB guidance for Business Combinations, which replaces SFAS No. 141, Business Combinations ("SFAS 141R" FASB ASC 805-10), and requires an acquirer to recognize the assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions. This Statement also requires the acquirer in a business combination achieved in stages to recognize the identifiable assets and liabilities, as well as the non-

controlling interest in the acquiree, at the full amounts of their fair values. Additionally, this Statement requires acquisition-related costs to be expensed in the period in which the costs were incurred and the services are received instead of including such costs as part of the acquisition price. This guidance makes various other amendments to authoritative literature intended to provide additional guidance or to conform the guidance in that literature to that provided in this Statement. Our acquisition of the Ky-Tenn Oil, Inc and Cook Inlet assets and the stock and membership interests of East Tennessee Consultants, Inc. and East Tennessee Consultants II, LLC were recorded in accordance with this guidance.

In December 2009, the FASB issued guidance for Consolidations - Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities (Topic 810). The amendments in this update are a result of incorporating the provisions of SFAS No. 167, Amendments to FASB Interpretation No. 46(R). The provisions of such Statements are effective for fiscal years, and interim periods within those fiscal years, beginning on or after November 15, 2009. Earlier adoption is not permitted. The presentation and disclosure requirements shall be applied prospectively for all periods after the effective date. Management believes this Statement will not have a material impact on our financial statements.

We determined that all other issued, but not yet effective accounting pronouncements are inapplicable or insignificant to us and once adopted are not expected to have a material impact on our financial position.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Not applicable to a smaller reporting company.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Our financial statements are contained in pages F-1 through F-36, which appear at the end of this annual report.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

On February 1, 2011, Miller Petroleum, Inc. dismissed Sherb & Co. LLP as our independent registered public accounting firm and engaged KPMG LLP as our independent registered public accounting firm. Sherb & Co. LLP audited our financial statements for our fiscal years ended April 30, 2010 and 2009. The dismissal of Sherb & Co. LLP was approved by our Board of Directors. Sherb & Co. LLP did not resign or decline to stand for re-election.

Sherb & Co., LLP had served as our independent registered public accounting firm since August 2008. Neither the report of Sherb & Co. LLP dated July 25, 2010 on our consolidated balance sheets as of April 30, 2010 and 2009 and the related consolidated statements of operations, changes in stockholders' equity (deficit), and cash flows for the years then ended, nor the report of Sherb & Co. LLP dated July 30, 2009 on our consolidated balance sheet as of April 30, 2009 and the related consolidated statements of operations, changes in stockholders' equity (deficit), and cash flows for the year then ended, contained an adverse opinion or a disclaimer of opinion, nor was either such report qualified or modified as to uncertainty, audit scope, or accounting principles.

During our two most recent fiscal years and the subsequent interim period preceding our decision to dismiss Sherb & Co. LLP we had no disagreements with the firm on any matter of accounting principles or practices, financial statement disclosure, or auditing scope of procedure which disagreement if not resolved to the satisfaction of Sherb & Co. LLP would have caused it to make reference to the subject matter of the disagreement in connection with its report.

During our two most recent fiscal years and the subsequent interim period prior to retaining KPMG LLP (1) neither we nor anyone on our behalf consulted KPMG LLP regarding (a) either the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on our financial statements or (b) any matter that was the subject of a disagreement or a reportable event as set forth in Item 304(a)(1)(iv) and (v), respectively, of Regulation S-K, and (2) KPMG LLP did not provide us with a written report or oral advice that they concluded was an important factor considered by us in reaching a decision as to accounting, auditing or financial reporting issue.

ITEM 9A.

CONTROLS AND PROCEDURES.

Disclosure Controls and Procedures.

Under the supervision and with the participation of our management, including our Chief Executive Officer and our 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) under the Securities Exchange Act of 1934, as amended, at the end of the period covered by our report for the quarter ended July 31, 2011 filed on Form 10-Q (the " Q3 Evaluation Date"). Prior to the filing of such report with the Securities and Exchange Commission, on March 17, 2011 the Audit Committee of the Board of Directors determined that our unaudited consolidated balance sheet at July 31, 2010, and our unaudited consolidated statements of operations and cash flows for the three-month period ended July 31, 2010, as well as our unaudited consolidated balance sheet at October 31, 2010, and our unaudited consolidated statements of operations and cash flows for the three and six month periods ended October 31, 2010 could no longer be relied upon as a result of misstatements in those financial statements. We failed to properly accrete our asset retirement obligations in each of the first two quarters of fiscal 2011. In these periods we also failed to properly record depletion, depreciation and amortization expenses related to leasehold costs, wells and equipment, fixed assets and asset retirement obligations and did not properly record the state tax credits expected from our Alaska operations. We have corrected these accounting misstatements in our financial statements contained in this report.

As a result of these accounting misstatements, which are deemed to result from material weaknesses in our internal controls over financial reporting, our Chief Executive Officer and Chief Financial Officer have concluded that as of the Evaluation Date we did not maintain disclosure controls and procedures that were effective in providing reasonable assurances that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 was recorded, processed, summarized and reported within the time periods prescribed by SEC rules and regulations, and that such information was accumulated and communicated to our management to allow timely decisions regarding required disclosure.

In addition, under the supervision and with the participation of our management, including our Chief Executive Officer and our 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) under the Securities Exchange Act of 1934, as amended, at the end of the period covered by this report (the “Evaluation Date”). Subsequent to the Evaluation Date, but prior to the filing of this report with the Securities and Exchange Commission, on July 28, 2011 the Audit Committee of the Board of Directors determined that that our unaudited consolidated balance sheets at July 31, 2010, October 31, 2010 and January 31, 2011 and our unaudited consolidated statements of operations and cash flows for the quarterly and year to date periods then ended, could no longer be relied upon as a result of errors in those financial statements. In these periods we failed to properly classify royalty expense, did not properly record depletion, depreciation and amortization expenses related to leasehold costs, wells and equipment, fixed assets and asset retirement obligations, failed to properly calculate and record sufficient compensation expense on equity rewards, and did not properly calculate the liability for our derivative securities. We also failed to properly record income taxes.

Accordingly, our unaudited consolidated balance sheets at July 31, 2010, October 31, 2010 and January 31, 2011 and the unaudited consolidated statements of operations and cash flows for the quarterly and year to date periods then ended contained in the respective Form 10-Q will be restated. As described in note 15, the Company has reflected an immaterial correction of an error in the accompanying April 30, 2010 consolidated balance sheet and in the accompanying consolidated statements of operations, stockholders’ equity and cash flows for the year ended April 30, 2010.

Our management, including the Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures will prevent all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system's objectives will be met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. Our management assessed the effectiveness of our internal control over financial reporting as of April 30, 2011. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in Internal Control-Integrated Framework. There are five control components to the COSO integrated framework: Control Environment, Risk Assessment, Control Activities, Information and Communication, and Monitoring. Based on the assessment using those criteria, our management concluded that the internal control over financial reporting was not effective at April 30, 2011 as a result of material weaknesses in our internal control over financial reporting. These material weaknesses in internal controls have led to the restatement of our financial statements for the quarterly periods ended July 30, 2010, October 31, 2010 and January 31, 2011 as described earlier in this section.

While we have designed a system of internal controls to supplement our existing controls during our ongoing implementation of Section 404 of the Sarbanes-Oxley Act of 2002 ("SOX 404"), we have been unable to complete testing of these controls and accordingly lack the documented evidence that we believe is necessary to support an assessment that our internal control over financial reporting is effective. Without such testing, we cannot conclude that there are any additional significant deficiencies or additional material weaknesses, nor can we appropriately remediate any such deficiencies that might have been detected. In addition, during the analysis of our internal controls in connection with our implementation of SOX 404, we did identify a number of control weaknesses, the remediation of which is material to our internal control environment and critical to providing reasonable assurance that any potential errors could be detected. Those identified control weaknesses include:

We do not maintain a sufficient complement of personnel with an appropriate level of accounting knowledge, experience and training in the selection and application of U.S. GAAP and SEC reporting requirements commensurate with our financial reporting requirements.

We do not maintain sufficient policies and procedures to prevent and/or detect material misstatements over cut-off of accruals.

KPMG LLP has not issued a report on the Company’s internal control over financial reporting.

Due to the nature of these material weaknesses in our internal control over financial reporting, there is more than a remote likelihood that misstatements which could be material to our annual or interim financial statements could occur and would not be prevented or detected. To remediate these weaknesses, during fiscal year 2012, we will:

Implement changes to our internal control over financial reporting to ensure that we properly record depletion, depreciation and amortization expenses related to leasehold costs, wells and equipment, fixed assets and asset retirement obligations, and properly calculate and record sufficient compensation expense on equity rewards, and properly record the state tax credits expected from our Alaska operations and recognize our full liability on derivative securities. Our plan is to:

Hire additional accounting personnel, who are sufficiently experienced in the application of GAAP and SEC reporting requirements; and

Employ recently engaged third party consultants to assess our current deficiencies and to formulate recommendations to remediate them, with respect to Sarbanes Oxley compliance, compliance with the rules and regulations of the New York Stock Exchange and overall financial reporting controls to assure compliance with GAAP and SEC requirements.

We anticipate that we will be able to complete these remediation efforts by the end our next fiscal year-end of April 30, 2012.

Changes in Internal Control over Financial Reporting. There have been no changes in our internal control over financial reporting during our fourth fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting with the exception of engaging a local CPA firm to access and recommend controls and procedures.

ITEM 9B.

OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Directors and Executive Officers


Name	Age	Position
Deloy Miller	64	Chairman of the Board of Directors and Chief Operating Officer
Scott M. Boruff	48	Chief Executive Officer and Director
David J. Voyticky	42	President, Director
Paul W. Boyd	53	Chief Financial Officer
David M. Hall	42	Chief Executive Officer of Cook Inlet Energy and Director
Herman E. Gettelfinger ³	78	Director
Jonathan S. Gross^2,3	52	Director
General Merrill A. McPeak ^{1, 2}	75	Lead Outside Director
Charles M. Stivers ^{1, 2}	49	Director
Don A. Turkleson^{1, 3}	56	Director

———————

Member of the Audit Committee.

Member of the Compensation Committee.

Member of the Nominating and Corporate Governance Committee.

Deloy Miller. Mr. Miller has been Chairman of the Board of Directors since December 1996, and was Chief Executive Officer from December 1997 to August 2008. Since then, Mr. Miller has been our Chief Operating Officer. From 1967 to 1997, Mr. Miller was the founder and Chief Executive Officer of our company. He is a seasoned gas and oil professional with more than 40 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. Mr. Miller served two terms as president of the Tennessee Oil & Gas Association and in 1978 the organization named him the Tennessee Oil Man of the Year. He continues to serve on the board of that organization. Mr. Miller was appointed in 1978 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. Mr. Miller is the father-in-law of Mr. Boruff.

Scott M. Boruff. Mr. Boruff has served as a director and our Chief Executive Officer since August 2008 and as our President from June 26, 2010 to June 8, 2011. Prior to joining our company, Mr. Boruff has been a licensed investment banker and was a director from 2006 to 2007 with Cresta Capital Strategies, LLC a New York investment banking firm that was responsible for closing transactions in the $150 to $200 million category. Mr. Boruff specialized in investment banking consulting services that included structuring of direct financings, recapitalizations, mergers and acquisitions and strategic planning with an emphasis in the gas and oil field. As a commercial real estate broker for over 20 years Mr. Boruff developed condominium projects, hotels, convention centers, golf courses, apartments and residential subdivisions. As a consultant to us, Mr. Boruff led the last three major financial transactions completed by the company. Since April 2009, Mr. Boruff has also been a director and 49% owner of Dimirak Securities Corporation, a broker-dealer and member of FINRA. See Item 13. Certain Relationships and Related Transactions and Director Independence appearing later in this annual report. Mr. Boruff holds a Bachelor of Science in Business Administration from East Tennessee State University. Mr. Boruff is the son-in-law of Mr. Miller.

David J. Voyticky. Mr. Voyticky has been a member of our Board of Directors since April 2010, and our President since June 9, 2011. Mr. Voyticky is has over 15 years of domestic and international mergers and acquisitions, restructuring and financing experience. Since August 2005, Mr. Voyticky has been an independent consultant to companies in the middle market on value maximization strategies. As part of this focus, Mr. Voyticky provides strategic and capital markets advice to high growth businesses He served as a vice president with Goldman, Sachs & Co. from June 2000 to May 2002, a vice president of Houlihan Lokey Howard & Zukin Capital, Inc. in Los Angeles from July 2002 to January 2005, and an associate with J.P. Morgan in London and New York from June 1996 to May 2000. During that period, he advised public and private domestic and multinational corporations and financial sponsors on mergers, acquisitions, divestitures, joint ventures, cross-border transactions, anti-raid (defense) preparation and capital-raising activities. Mr. Voyticky designed and was a founding partner of Red Mountain Capital Partners. From December 2005 through June 2006, Mr. Voyticky was a partner in the

$300 million re-launch of Chapman Capital L.L.C., an activist hedge fund focused on the publicly traded middle market companies. Since January 2010 he has been a member of the Board of Directors of Best Energy Services, Inc. In July 2011, Mr. Voyticky was named to the board of a biotechnology company, Genesis Biopharma, Inc. Mr. Voyticky received a J.D. and a M.B.A degree from the University of Michigan and a Masters in International Policy and Economics from the Ford School at the University of Michigan. He also received a Bachelor of Arts in Philosophy from Pomona College.

Paul W. Boyd. Mr. Boyd has served as our Chief Financial Officer since September 2008. Prior to joining our company, from 2001 until August 2008 Mr. Boyd was Chief Financial Officer and Treasurer of IdleAire Technologies Corporation, a Knoxville, Tennessee company which provides a patented system that enables long haul truck drivers to park their trucks for extended periods of time while still using the heat, air conditioning and many other amenities. From 1999 to 2000 Mr. Boyd was Chief Financial Officer of United States Internet, Inc., a Knoxville, Tennessee company which was a subsidiary of Earthlink Company. From 1996 to 1999 he was Treasurer of Clayton Homes, Inc., a manufacturer of manufactured housing which is a subsidiary of Berkshire Hathaway, Inc. Mr. Boyd received a B.B.A. in Accounting from the University of Houston and is a certified public accountant.

David M. Hall. Mr. Hall has served as Chief Executive Officer of our Cook Inlet Energy subsidiary and member of our Board of Directors since December 2009. Mr. Hall was the former Vice President and General Manager of Alaska Operations, Pacific Energy Resources Ltd. from January 2008 to December 2009. Before that time, from 2000 to 2008, he served as the Production Foreman and Lead Operator in Alaska for Forest Oil Corp, rising to Production Manager for all of Alaska operation for Forest Oil.

Herman E. Gettelfinger. Mr. Gettelfinger has been a member of our Board of Directors since 1997. Mr. Gettelfinger, who has been active in the gas and oil drilling and exploration business for more than 35 years, is a co-owner and President of Kelso Oil Company, Knoxville Tennessee. Kelso is one of eastern Tennessee’s largest distributors of motor oils, fuels and lubricants to the industrial and commercial market.

Jonathan S. Gross. Mr. Gross has been a member of our Board of Directors since April 2010. Mr. Gross has 30 years of experience oil and gas exploration and is currently President of Jexco LLC which provides geological and geophysical consulting services. During his career, Mr. Gross has served as the Chief Operating Officer of Houston Exploration Services, Inc., a Houston, Texas based subsidiary of Kuwait Energy Company from 2008 to 2009, Senior Vice President of Exploration and Technology Manager of Cheniere Energy, Inc. from 1999 to 2008. During his nine years at Cheniere he oversaw the company’s exploration program both onshore and offshore, served in the capacity of chief geophysicist, oversaw the expansion of the company’s information technology infrastructure, coordinated Sarbanes-Oxley Act of 2002 (SOX) compliance of information technology (IT) controls, and served in the company’s LNG marketing group to evaluate upstream opportunities for liquid natural gas (LNG) supply. From 1981 to 1998, Mr. Gross served in a variety of technical positions within Amoco Production Company, and he has domestic and international experience in both onshore and offshore basins in several parts of the world including the U.S., Trinidad, West Africa, North Africa, the Middle East and Eurasia. Mr. Gross received his B.A. in Geophysical Sciences from the University of Chicago in 1981 and is a member of the American Association of Petroleum Geologists, the Society of Exploration Geophysicists and the Houston Geological Society.

General Merrill A. McPeak (USAF, retired). General McPeak is our Lead Outside Director. He has been a member of our Board of Directors since April 2010. General McPeak has served as President of McPeak and Associates, a 15-year old management consulting firm, since its founding in 1995. From October 1990 until October 1994, he was Chief of Staff of the U.S. Air Force and a member of the Joint Chiefs of Staff. During this period, he was the senior officer responsible for organization, training and equipage of a combined active duty, National Guard, Reserve and civilian work force of over 850,000 people serving at 1,300 locations in the United States and abroad. As a member of the Joint Chiefs of Staff, he and the other service chiefs were military advisors to the Secretary of Defense, the National Security Council and the President of the United States. Following retirement from active service, General McPeak began a second career in business. He is Chairman of Ethicspoint, a privately-held, Portland-based provider of risk management and compliance software-as-a-service, including secure, anonymous reporting of ethical violations in the workplace. General McPeak has also served as a member of the Board of Director for Del Global Technologies Corp. (since 2005), Tektronix, Inc. (1995 to 2006); TWA (1997 to 2002) and ECC International (1997 to 2003), where he was for many years chairman of the board. In July 2011, General McPeak was appointed to the board of Genesis Biopharma, Inc., a biotechnology company. In 1992, San Diego State University honored General McPeak with its first ever Lifetime Achievement Award. In 1995, George Washington University gave him its Distinguished Alumni Award, the “George.” He was among the initial seven

inductees to the Oregon Aviation Hall of Honor. He is a member of the Council on Foreign Relations, New York City. In 2011, General McPeak became Chairman of the American Battle Monuments Commission, the federal agency that oversees care and maintenance of 24 cemeteries abroad that constitute the final resting place for almost 125,000 American war dead.

Charles M. Stivers. Mr. Stivers has been a member of our Board of Directors 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. Mr. Stivers served as Treasurer and Chief Financial Officer 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.

Don A. Turkleson. Mr. Turkleson has been a member of our Board of Directors since January, 2011. Mr. Turkleson has over 35 years of accounting and financial experience with emphasis in the oil and gas business. He is currently the Chief Financial Officer at Laurus Energy, Inc., a privately held company located in Houston, a position he has held since January 2010. Prior to joining Laurus Energy, he was Senior Vice President and CFO for Cheniere Energy, Inc. where he worked from 1997 to June, 2009. During his 11 years at Cheniere, he oversaw the company's establishing an internal control environment compliant with Sarbanes-Oxley requirements and a financial reporting system for three publicly traded companies. As CFO, Mr. Turkleson helped lead Cheniere's completion of more than $6 billion in financings and re-financings, including project financing for a $1.5 billion Liquefied Natural Gas (LNG) receiving terminal, $2.2 billion in publicly traded senior notes, term loans, convertible debt, and equity offerings including the IPO of a master limited partnership. Mr. Turkleson also served as Vice President – Finance for PetroCorp Incorporated, an oil and gas exploration and production company where he worked from 1983 to 1996. At PetroCorp he assisted in the negotiation for management of 700 oil and gas properties, the merger of $50 million in properties for equity, the formation of joint ventures to acquire $175 million in oil and gas properties, and the completion of the company's initial public offering. He began his career at Arthur Andersen & Co. in 1975 where he worked as a certified public accountant for eight years, principally with oil and gas industry clients. While at Arthur Andersen, he assisted in various client equity offerings, including the coordination of financial reporting for a $600 million exchange offering initial public offering which combined over 200 limited partnerships. Mr. Turkleson received a Bachelor of Science in Accounting from Louisiana State University, and is a Certified Public Accountant. He also serves on the board of directors of the general partner of Cheniere Energy Partners, L.P., a publicly traded master limited partnership and on the board of managers of privately-held Stone Horn Ridge, LLC.

There are no family relationships between any of the executive officers and directors, except as set forth above. Each director is elected at our annual meeting of shareholders and holds office until the next annual meeting of shareholders, or until his successor is elected and qualified. As a term of the acquisition of Cook Inlet, we agreed Cook Inlet’s owners would be represented by a seat on our Board of Directors for a period of three years from December 11, 2009. Mr. Hall has initially been designated as the director representing Cook Inlet’s prior owners. In the event Mr. Hall should die or otherwise become incapacitated or unavailable to act as director, Mr. Wilcox will be designated as the successor director.

Director Qualification

The following is a discussion for each director of the specific experience, qualifications, attributes or skills that led to our conclusion that such person should be serving as a member of our Board of Directors as of the date of this annual report in light of our business and structure. In addition to their individual skills and backgrounds which are focused on our industry as well as financial and managerial experience, we believe that the collectively skills and experience of our Board members are well suited to guide us as we continue to grow our company.

Deloy Miller – Mr. Miller has extensive experience as a seasoned gas and oil professional for our company. Mr. Miller has more than 40 years of experience in the drilling and production business in the Appalachian basin, extensive geological knowledge of Tennessee and Kentucky, training in the reading of well logs, and particular familiarity with our operations as our founder, former Chief Executive Officer, and current Chief Operating Officer.

Scott M. Boruff – Mr. Boruff has experience in the financial industry, specializing in investment banking consulting services that included structuring of direct financings, recapitalizations, mergers and acquisitions and strategic planning with an emphasis in the gas and oil field.

David J. Voyticky – Mr. Voyticky has over 15 years of domestic and international mergers and acquisitions, restructuring and financing experience. He provides strategic and capital markets advice for our Company.

David M. Hall – Mr. Hall has a comprehensive knowledge of our Alaskan operations, with nearly 20 years of experience with our Alaskan assets, together with engineering expertise in which he trained as both an electrical engineer and industrial engineer.

Herman E. Gettelfinger – Mr. Gettelfinger has over 35 years of experience in the gas and oil drilling and exploration business including as co-owner and President of Kelso Oil Company, one of East Tennessee’s largest distributors of motor oils, fuels and lubricants to the industrial and commercial market.

Jonathan S. Gross – Mr. Gross has 29 years of experience in domestic and international oil and gas exploration and education and is trained as a geologist. Mr. Gross has experience in both onshore and offshore basins in several parts of the world, has held various positions in several energy companies and is a geologist. He serves as chair of our Nominating and Corporate Governance Committee.

Merrill A. McPeak – General McPeak has extensive experience in management consulting and a successful military career, including his position as Chief of Staff of the U.S. Air Force and a member of the Joint Chiefs of Staff, during which time he was the senior officer responsible for organization, training and equipage of a combined active duty, National Guard, Reserve and civilian work force of over 850,000 people serving at 1,300 locations in the United States and abroad and advised the Secretary of Defense, the National Security Council and the President of the United States. General McPeak currently serves or has served in the past on the Board of Directors of a number of publicly traded companies. He serves as our Lead Outside Director and as chair of our Compensation Committee.

Charles M. Stivers – Mr. Stivers, a certified public accountant, has over 18 years of experience in accounting and over 12 years of experience within the energy industry. Mr. Stivers owns and operates an accounting firm that specializes in the oil and gas industry with clients in eight different states.

Don A. Turkleson. Mr. Turkleson has over 35 years of accounting and financial experience with emphasis in the oil and gas business. As a current and previous CFO, he has overseen internal control environments, compliance with Sarbanes-Oxley requirements and a financial reporting system for three publicly traded companies. He serves as chair of our Audit Committee.

Director Compensation

We had not established standard compensation arrangements for our directors by the end of fiscal 2011, and the compensation payable to each individual for their service on our Board is determined from time to time by our Board of Directors based upon the amount of time expended by each of the directors on our behalf. Currently, executive officers of our company or its subsidiaries who are also members of the Board of Directors do not receive any compensation specifically for their services as directors.

On May 27, 2011 the Board adopted a compensation policy for its outside directors, consisting of certain cash payments and an annual grant of an option to purchase 40,000 shares of our common stock at a price equal to the price at the close of business on the date of award, vesting in one year. The cash compensation is comprised of an annual retainer of $20,000, and a per board meeting payment of $1,000. An outside director is also paid $500 for attendance at a committee meeting, and $500 for telephonic attendance of a board or committee meeting. Instead of the $20,000 retainer, our lead independent director receives a $30,000 annual retainer. The chairman of our each of our committees will receive an additional retainer as follows: Audit, $7,500; Compensation, $5,000; and Nominating and Corporate Governance, $2,500.

The following table provides information about compensation paid to our non-employee directors during fiscal 2011 for their services as directors. The value of the securities issued reflects the aggregate grant date fair value computed in accordance with ASC Topic 718. While options were granted to these individuals as described below, because none of these options have vested and the grant is subject to continued Board service, under generally accepted accounting principles, we recognize compensation expense for these grants over the vesting period.


Name (a)	Fees Paid or Earned in Cash ($) (b)	Stock Awards ($) (c)	Option Awards ($) (d)	Non-Equity Incentive Plan Compensation ($) (e)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) (f)	All Other Compensation ($) (g)	Total ($) (h)

David J. Voyticky ¹	$0	$0	$78,536	$0	$0	$0	$78,536
Herman E. Gettelfinger	0	0	0	0	0	0	0
Jonathan S. Gross²	0	0	78,536	0	0	0	78,536
Merrill A. McPeak³	0	0	78,536	0	0	0	78,536
Charles M. Stivers	0	0	0	0	0	0	0
Don A. Turkleson⁴	0	0	11,198	0	0	0	11,198

———————

Mr. Voyticky was granted options to purchase an aggregate of 100,000 shares of our common stock at an exercise price of $4.98 per share, of which options to purchase 33,333 shares vest on July 29, 2011, options to purchase an additional 33,333 shares vest on July 29, 2012 and options to purchase the remaining 33,334 shares vest on July 29, 2013.

Mr. Gross was granted options to purchase an aggregate of 100,000 shares of our common stock at an exercise price of $4.98 per share, of which options to purchase 33,333 shares vest on July 29, 2011, options to purchase an additional 33,333 shares vest on July 29, 2012 and options to purchase the remaining 33,334 shares vest on July 29, 2013.

General McPeak was granted options to purchase an aggregate of 100,000 shares of our common stock at an exercise price of $4.98 per share, of which options to purchase 33,333 shares vest on July 29, 2011, options to purchase an additional 33,333 shares vest on July 29, 2012 and options to purchase the remaining 33,334 shares vest on July 29, 2013.

⁴

Mr. Turkleson was granted options to purchase an aggregate of 100,000 shares of our common stock at an exercise price of $5.25 per share, of which options to purchase 33,333 shares vest on January 18, 2012, options to purchase an additional 33,333 shares vest on January 18, 2013 and options to purchase the remaining 33,334 shares vest on January 18, 2014.

Code of Business Conduct and Ethics

We have adopted a Code of Business Conduct and Ethics that applies to our President, Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and Controller, and any other persons performing similar functions. In July 2011, we adopted a new Code of Business Conduct and Ethics policy which applies to all of our employees, officers and directors as well as all employees and officers of our subsidiaries. This Code provides written standards that we believe are reasonably designed to deter wrongdoing and promote honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships, and full, fair, accurate, timely and understandable disclosure in reports we file with the Securities Exchange Commission. A copy of our Code of Business Conduct and Ethics is available on our website. It has also been filed with the Securities and Exchange Commission as an exhibit to this annual report.

Committees of the Board of Directors

Our Board of Directors has established an Audit Committee, a Compensation Committee and a Nominating and Corporate Governance Committee. While our Board of Directors established the Audit Committee in 2004, the Compensation Committee and Nominating and Corporate Governance Committee were only recently established.

Audit Committee. The Audit Committee assists the Board in fulfilling its oversight responsibility relating to the integrity of our financial statements, our compliance with legal and regulatory requirements and the qualifications and independence of our independent registered public accountants. The Audit Committee is composed of three directors, Messrs. Turkleson (Chairman) and Stivers and General McPeak, all of whom have been determined by the Board of Directors to be “independent,” as defined by the NYSE Corporate Governance Standards. The Board has determined that each of Mr. Turkleson, the Chairman of the Audit Committee, and Mr. Stivers qualify as an “audit committee financial expert” as defined by the SEC. Each of our Audit Committee members is financially literate.

Compensation Committee. The Compensation Committee is responsible for overseeing our compensation programs and practices, including our executive compensation plans and incentive compensation plans. The Chief Executive Officer will provide input to the Compensation Committee with respect to the individual performance and compensation recommendations for the other executive officers. The Compensation Committee is composed of three directors, General McPeak (Chairman), Stivers and Gross, all of whom have been determined by the Board of Directors to be “independent,” as defined by the NYSE Corporate Governance Standards.

Nominating and Corporate Governance Committee. The Nominating and Corporate Governance Committee will recommend the slate of director nominees for election to our Board of Directors, identify and recommend candidates to fill vacancies occurring between annual stockholder meetings, review the composition of Board committees and monitor compliance with, review, and recommend changes to our various corporate governance policies and guidelines. The committee will also prepare and supervise the Board’s annual review of director independence and the Board’s annual self-evaluation. The Nominating and Corporate Governance Committee is composed of three directors, Messrs. Gross (Chairman), Gettelfinger and Turkleson, all of which have been determined by the Board of Directors to be “independent,” as defined by the NYSE Corporate Governance Standards.

The Nominating and Corporate Governance Committee will consider all qualified candidates for our Board of Directors identified by members of the committee, by other members of the Board of Directors, by senior management and by our stockholders. The committee will review each candidate, including each candidate’s independence, skills and expertise based on a variety of factors, including the person’s experience or background in management, finance, regulatory matters and corporate governance. Further, when identifying nominees to serve as director, the Nominating and Corporate Governance Committee will seek to create a Board that is strong in its collective knowledge and has a diversity of skills and experience with respect to accounting and finance, management and leadership, vision and strategy, business operations, business judgment, industry knowledge and corporate governance. In addition, prior to nominating an existing director for re-election to the Board of Directors, the Nominating and Corporate Governance Committee will consider and review an existing director’s Board and committee attendance and performance, length of Board service, experience, skills and contributions that the existing director brings to the Board, equity ownership in our company and independence.

The Nominating and Corporate Governance Committee will follow the same process and use the same criteria for evaluating candidates proposed by stockholders, members of the Board of Directors and members of senior management. Based on its assessment of each candidate, the committee will recommend candidates to the Board. However, there is no assurance that there will be any vacancy on the Board at the time of any submission or that the committee will recommend any candidate for the Board.

ITEM 11.

EXECUTIVE COMPENSATION.

The following table summarizes all compensation recorded by us in fiscal 2011 for the following:

our principal executive officer or other individual serving in a similar capacity,

our two most highly compensated executive officers other than our principal executive officer who were serving as executive officers at April 30, 2011 as that term is defined under Rule 3b-7 of the Securities Exchange Act of 1934, and

up to two additional individuals for whom disclosure would have been required but for the fact that the individual was not serving as an executive officer at April 30, 2011.

For definitional purposes, these individuals are sometimes referred to as the “named executive officers.” The value attributable to any option awards in the following table is computed in accordance with ASC Topic 718. The value of the securities issued reflects the aggregate grant date fair value computed in accordance with ASC Topic 718 assuming the following weighted averages:


Expected life (in years)	5.6
Volatility	65-216%
Discount rate - bond equivalent rate	2.44	%
Annual rate of quarterly dividends	0.00

Summary Compensation Table


NAME AND PRINCIPAL POSITION (A)	YEAR (B)	SALARY ($) (C)	BONUS ($) (D)	STOCK AWARDS ($) (E)	OPTION AWARDS ($) (F)	NON-EQUITY INCENTIVE PLAN COMPENSATION ($) (G)	NONQUALIFIED DEFERRED COMPENSATION EARNINGS ($) (H)	ALL OTHER COMPENSATION ($) (I)	TOTAL ($) (J)

Scott M. Boruff ¹	2011	341,146	1,084,047	311,875	359,178	0	0	12,704	2,108,950
	2010	260,228	576,547	0	0	0	0	12,640	849,415

Paul W. Boyd ²	2011	177,346	91,000	0	93,351	0	0	6,000	367,697
	2010	133,943	0	0	506,621	0	0	6,000	646,564

Deloy Miller³	2011	200,000	60,000	0	79,797	0	0	1,277	341,074
	2010	203,846	0	0	0	0	0	1,161	205,007

———————

Mr. Boruff has served as our Chief Executive Officer since August 2008 and the terms of his compensation are set forth in his employment agreement which is described later in this section. Mr. Boruff is entitled to a bonus each year equal to 100% of his base salary and 100,000 shares of our common stock for continued employment and if we meet certain revenue and earnings before income taxes, depreciation and amortization, or EBITDA, milestones. These milestones were met in each of 2011and 2010. Mr. Boruff’s bonus in 2011 and 2010 included $888,875 and $319,500, respectively, attributable to the value of 100,000 shares of our common stock issued to him. The value of stock awards and option awards in each of 2011 and 2010 represents the value of restricted stock awards and option grants made to him in each of those years under the terms of his employment agreement. All other compensation for both 2011 and 2010 included an auto allowance of $1,000 per month plus $704 and $640, respectively, of compensation derived from personal use of a company vehicle. The amount of Mr. Boruff’s compensation excludes fees paid to Dimirak Securities Corporation, a broker-dealer and member of FINRA, and its related parties under the terms of a Marketing Agreement. Mr. Boruff is a director and owns 49% of Dimirak Securities Corporation. See Item 14. Certain Relationships and Related Transactions and Director Independence appearing later in this annual report. Mr. Boruff’s compensation for 2010 excludes the value of options granted to him in April 2010 which had not yet vested.

Mr. Boyd served as our Chief Financial Officer since September 2009 and the terms of his compensation are set forth in his employment agreement which is described later in this section. All other compensation for both 2011 and 2010 included an auto allowance of $500 per month.

Mr. Miller served as our Chief Executive Officer from December 1997 to August 2008 and is currently our Chief Operating Officer. All other compensation included $1,277 and $1,161 of compensation derived from personal use of a company vehicle in 2011 and 2010, respectively. Mr. Miller’s compensation for 2010 excludes the value of options granted to him in April 2010 which had not yet vested.

Employment Agreement with Mr. Boruff

Effective August 1, 2008, we entered into an employment agreement, as amended in September 2008, with Mr. Boruff pursuant to which Mr. Boruff will serve as our Chief Executive Officer for an initial term of five years, subject to additional one-year renewal periods. On December 23, 2010, we entered into a second amendment to the Employment Agreement with Mr. Boruff. The changes in the agreement reflect our uplisting to the NASDAQ Stock Market, and the increases in Mr. Boruff’s responsibilities associated with the oversight of new employees hired and the several subsidiaries we acquired in 2009.

The employment agreement as amended and restated on December 23, 2010 provides for:


	·	an increase in Mr. Boruff’s base salary,
	·	certain payments upon signing, and
	·	changes to the structure of Mr. Boruff’s incentive compensation, The new incentive compensation structure, instead of providing certain pre-set benchmarks, tasks the Compensation Committee of the Board of Directors with setting benchmarks annually during the first quarter of the fiscal year. These benchmarks will be based on performance that is significantly related to our business performance. An annual incentive opportunity must be provided each year, and should range between 100% to 300% of Mr. Boruff’s base salary.

Upon execution of the December 2010 amendment, Mr. Boruff was awarded a bonus of $500,000, payable in four quarterly installments. If he should voluntarily terminate his employment with us, he forfeits the right to receive any unpaid installments. If we should terminate his employment, he is entitled to receive any unpaid installments within 15 days of termination.

Under the terms of the agreement, as amended, Mr. Boruff’s compensation consists of the following:


	·	a base salary of $500,000 per annum, effective December 23, 2010. Previously, his base salary was $250,000 per annum, with provision for cost-of-living increases.
	·	10 year options to purchase 250,000 shares of our common stock at an exercise price per share of $0.33, with vesting in equal annual installments over a period of four years from the grant date, or immediately upon a change of control of our company as described in the agreement,
	·	a restricted stock grant of 250,000 shares of common stock, with vesting in equal annual installments over a period of four years from the issuance date, or on an accelerated basis in the event of a change of control of our company also as described in the agreement, and
	·	an option to purchase 2,500,000 shares of our common stock exercisable at $6.00 per share, vesting over four years and expiring five years after the date of grant, was granted to Mr. Boruff at signing

Mr. Boruff is also entitled to receive certain incentive compensation in the form of cash and shares of our common stock based upon, and subject to, two performance benchmarks, gross revenue and earnings before income taxes, depreciation and amortization (EBITDA), as follows:


	·	100% of his base salary and 100,000 shares of our common stock in the event that our gross revenues for fiscal 2009 (annualized beginning on the date of the agreement) were not less than $2,000,000 and EBITDA for such period was not less than $200,000,
	·	100% of his base salary and 100,000 shares of our common stock in the event that our gross revenues for fiscal 2010 are not less than $4,000,000 and EBITDA for such period was not less than $400,000,
	·	100% of his base salary and 100,000 shares of our common stock in the event that our gross revenues for fiscal 2011 are not less than $8,000,000 and EBITDA for such period was not less than $800,000,
	·	100% of his base salary and 100,000 shares of our common stock in the event that our gross revenues for fiscal 2012 are not less than $16,000,000 and EBITDA for such period was not less than $1,600,000, and
	·	100% of his base salary and 100,000 shares of our common stock in the event that our gross revenues for fiscal 2013 are not less than $30,000,000 and EBITDA for such period was not less than $3,000,000.

One half of each element of incentive compensation is earned if the gross revenue benchmark is achieved, and the other half of each element is earned if the EBITDA benchmark is achieved. Mr. Boruff earned the incentive compensation for each of fiscal 2009 and fiscal 2010. The equity portion of the incentive awards earnable by Mr. Boruff for fiscal 2011, 2012 and 2013 were not changed by the December 2010 amendment to his employment agreement. For fiscal 2011, the present value of the cash portion of the annual incentive award earnable as set forth above was estimated to be approximately $260,000 and was when he entered into the December 2010 amendment to his employment agreement. The cash portion of the annual incentive award earnable for fiscal 2012 and fiscal 2013 was amended as part of the December 2010 amendment to his employment agreement. The new cash incentive structure will take effect in the first quarter of fiscal 2012, which began on May 1, 2011, is as follows:

The target annual incentive opportunity will not be less than 100% of base salary (the "Target Annual Incentive") as in effect at the beginning of the fiscal year (or, if higher, as in effect at the time the Board of Directors or Compensation Committee establishes the annual incentive opportunity), with a maximum annual incentive opportunity of not less than 300% of his base salary, with the Board of Directors or Compensation Committee retaining discretion to specify a threshold annual incentive opportunity and other payout levels for performance ranging between the threshold and target levels of performance or between the target and maximum levels of performance;

The Board of Directors or Compensation Committee will specify the performance goals to be achieved as a condition to earning and payout of the Target Annual Incentive and maximum annual incentive, and for other specified levels of payout of the annual incentive opportunity; provided, however that:


	·	the performance goals will be based on performance determined by the Board of Directors or Compensation Committee to be significantly related to our business performance (which may include EBITDA (earnings before provision for income taxes, depreciation and amortization), revenues, operating income, stock price or total shareholder return, measures of production, return on capital, or other measures specified by the Board of Directors or Compensation Committee, and


	·	the performance goal corresponding to the Target Annual Incentive will be at a level determined by the Board of Directors or Compensation Committee to have at least an approximately even chance of being achieved for the fiscal year;

The nature of the performance and the levels of performance triggering payments of the annual incentive compensation for each fiscal year will be established by the Board of Directors or Compensation Committee after consultation with Mr. Boruff, and will be established by the Board of Directors or Compensation Committee and communicated to him not later than the end of the first quarter of such fiscal year;

Any annual incentive compensation payable to Mr. Boruff will be paid at times specified under any applicable plan and the Board of Directors or Compensation Committee retains negative discretion with regard to the final payout amount of the annual incentive to the extent specified in any incentive plan governing annual incentive awards for senior executives;

For fiscal years beginning in 2011 and thereafter, the annual incentive award will be structured and administered so as to qualify as “performance-based compensation” under Internal Revenue Code Section 162(m), if we then have in effect a shareholder approved compensation plan providing for such performance-based compensation; and

The Board of Directors or Compensation Committee may provide for payment of a portion or all of an annual incentive award in the form of shares of our common stock. With respect to any payout of an annual incentive award in excess of the Target Annual Incentive Award, the common stock may be granted in the form of restricted stock or restricted stock units subject to vesting in annual installments over four years, subject to accelerated vesting in the event of Mr. Boruff’s termination due to death or disability or by us not for cause or upon a change in control. In addition, the Board of Directors or Compensation Committee may provide Mr. Boruff with an opportunity to elect to receive shares or share units (deferred shares) in lieu of portions of the annual incentive award otherwise payable in cash.

Mr. Boruff is also entitled to a $1,000 per month automobile allowance. The employment agreement, as amended, also provides that Mr. Boruff is entitled to participate in the employee benefit plans, programs and arrangements we have in effect during the employment term which are generally available to our senior executives. The agreement, as amended, also contains indemnification, confidentiality and non-solicitation clauses.

We did not consult with any experts or other third parties in determining the terms of Mr. Boruff’s employment agreement. The Compensation Committee, however, recommended the terms of the December 2010 amendment to our Board of Directors, after engaging and being advised by a third party executive compensation attorney. The agreement with Mr. Boruff may be terminated by us for cause, as defined in the agreement, or upon

his death or disability, or for no cause. In the event the agreement is terminated for either reason, if Mr. Boruff should terminate the agreement for any reason or if the agreement is not renewed, he is only entitled to receive his base salary through the date of termination. We may also terminate the agreement without cause, in which event Mr. Boruff will be entitled to his base salary through the date of termination and, should we terminate the agreement during the initial term, as severance, his base salary for one year. If we should terminate the agreement as a result of a change of control as defined in the agreement, he is entitled to a lump sum payment equal to 2.99 times Mr. Boruff’s then base salary.

In addition to the compensation payable to him under the terms of his employment agreement, in April 2010 the Compensation Committee of the Board of Directors granted Mr. Boruff options under our stock option plan to purchase 450,000 shares of our common stock with an exercise price of $5.94 per share and 50,000 shares of our common stock with an exercise price of $6.53 as additional compensation. These options vest over three years in arrears commencing on April 27, 2011, and are subject to continued employment.

Also, in May 2011 the Compensation Committee of the Board of Directors granted Mr. Boruff options under our stock option plan to purchase 250,000 shares of our common stock with an exercise price of $5.89 per share as additional compensation. These options vest over three years in arrears commencing May 27, 2011, and are subject to continued employment. The Compensation Committee determined to make these awards of additional compensation to Mr. Boruff in recognition of his past performance and a desire to retain him throughout the three year vesting period.

How Mr. Miller's Compensation was Determined

Mr. Miller, who served as our principal executive officer from December 1997 to August 1, 2008, is not a party to an employment agreement with our company. His compensation is determined by the Compensation Committee. The Committee considered a number of factors in determining Mr. Miller's compensation including the scope of his duties and responsibilities to our company and the time he devotes to our business. The Board of Directors did not consult with any experts or other third parties in fixing the amount of Mr. Miller's compensation. During each of fiscal 2011 and 2010, Mr. Miller's compensation package included a base salary of $200,000. The Compensation Committee increased his base salary to $205,000 on May 1, 2011. We also provide him with a company vehicle. In addition, in April 2010 the Compensation Committee of the Board of Directors granted Mr. Miller options under our stock option plan to purchase 350,000 shares of our common stock, 300,000 of these have an exercise price of $5.94 per share and 50,000 of these options have an exercise price of $6.54. These options were recorded as additional compensation. These options vest over three years in arrears commencing April 27, 2011, and are subject to continued employment. Also, in May 2011 the Compensation Committee of the Board of Directors granted Mr. Miller options under our stock option plan to purchase 175,000 shares of our common stock with an exercise price of $5.89 per share as additional compensation. These options vest over three years in arrears commencing May 27, 2011, and are subject to continued employment. The Compensation Committee determined to make these awards of additional compensation to Mr. Miller in recognition of his past performance and a desire to retain him throughout the three year vesting period.

How Mr. Boyd’s Compensation was Determined

Mr. Boyd’s Compensation is determined by our Compensation Committee who considered a number of factors in determining Mr. Boyd's compensation including the scope of his duties and responsibilities to our company and the time he devotes to our business. We did not consult with any experts or other third parties in fixing the amount of Mr. Boyd's compensation. We entered into an employment agreement with our Chief Financial Officer, Mr. Paul W. Boyd, on March 11, 2011. The employment agreement has a one year term and will automatically renew for successive one year periods unless either party delivers a notice of non-renewal 60 days prior to the termination date. Mr. Boyd’s base salary is $185,000, which is consistent with the terms of his hire. Mr. Boyd also receives a $500 per month automobile allowance and he is eligible for an annual performance bonus to be determined each year by the Compensation Committee of the Board of Directors. The agreement contains a maximum severance amount of one year’s salary, which is only payable in the case of termination without cause, and a one-year non-compete clause. Upon a termination of employment because of a change in control, Mr. Boyd will be paid an amount equal to 2.99 multiplied by his annualized salary that he is then earning, payable in a lump-sum payment upon the closing of the change in control. Mr. Boyd may also terminate the agreement without cause upon 90 days notice to us. We will pay for all of Mr. Boyd’s expenses incurred in maintaining his professional license as a Certified Public Accountant. Mr. Boyd is entitled to receive the same benefits that all of our employees receive with respect to health and life.

At the time he joined our company we granted Mr. Boyd two year options to purchase 250,000 shares of our common stock at an exercise price of $0.40 per share, of which options to purchase 125,000 shares vested on the date of grant and the remaining options vested on March 31, 2010. In addition, in February 2010 our Board granted Mr. Boyd five year options to purchase 25,000 shares of our common stock at an exercise price of $2.52 per share which options vested on May 19, 2010. In addition, in April 2010 the Compensation Committee of the Board of Directors granted Mr. Boyd options under our stock option plan to purchase 350,000 shares of our common stock with an exercise price of $5.94 per share as additional compensation. These options vest over three years in arrears commencing April 27, 2011, and are subject to continued employment. Also, in May 2011 the Compensation Committee of the Board of Directors granted Mr. Boyd options under our stock option plan to purchase 175,000 shares of our common stock with an exercise price of $5.89 per share as additional compensation. These options vest over three years commencing May 27, 2011, and are subject to continued employment. The Compensation Committee determined to make this award of additional compensation to Mr. Boyd in recognition of his past performance and a desire to retain him throughout the three year vesting period. Mr. Boyd’s total cash and equity compensation for 2011 was $367,697.

Outstanding Equity Awards at Fiscal Year-End

The following table provides information concerning unexercised options, stock that has not vested and equity incentive plan awards for each named executive officer outstanding as of April 30, 2011:


OPTION AWARDS						STOCK AWARDS
Name (a)	Number of securities underlying unexercised Options (#) exercisable (b)	Number of Securities Underlying Unexercised options (#) unexercisable (c)	Equity Incentive plan awards: Number of Securities Underlying Unexercised Unearned options (#) (d)	Option Exercise price ($) (e)	Option Expiration date (f)	Number of shares or units of stock that have not vested (#) (g)	Market value of shares or units of stock that have not vested ($)¹ (h)	Equity incentive plan awards: Number of unearned shares, units or other rights that have not vested (#) (i)	Equity incentive plan awards: Market or payout value of unearned shares, units or other rights that have not vested ($)¹ (j)

Scott M. Boruff	125,000	125,000	—	0.33	8/1/18	—	—	—	—
	150,000	300,000	—	5.94	4/27/20	—	—	—	—
	16,667	33,333	—	6.53	4/27/20	—	—	—	—
	—	2,500,000	—	6.00	12/22/15	—	—	—	—
	—	250,000	—	5.89	5/27/21	—	—	—	—
	—	—	—	—	—	387,500	2,235,875	—	—

Paul W. Boyd	250,000	—	—	0.40	9/23/11	—	—	—	—
	25,000	—	—	2.52	2/18/15	—	—	—	—
	116,667	233,333	—	5.94	4/27/20	—	—	—	—
	—	175,000	—	5.89	5/27/21	—	—	—	—

Deloy Miller	25,000	—	—	2.52	2/18/15	—	—	—	—
	100,000	200,000	—	5.94	4/27/20	—	—	—	—
	16,667	33,333	—	6.53	4/27/20	—	—	—	—
	—	175,000	—	5.89	5/27/21	—	—	—	—

———————

Based upon the closing price of our common stock of $5.77 on April 30, 2011.

Compliance with Section 16(a) of the Exchange Act

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our executive officers and directors, and persons who beneficially own more than 10% of a registered class of our equity securities to file with the Securities and Exchange Commission initial statements of beneficial ownership, reports of changes in ownership and annual reports concerning their ownership of our common shares and other equity securities, on Forms 3, 4 and 5 respectively. Executive officers, directors and greater than 10% stockholders are required by the Securities and Exchange Commission regulations to furnish us with copies of all Section 16(a) reports they file. Based on our review of the copies of such forms received by us, and to the best of our knowledge, all executive officers, directors and persons holding greater than 10% of our issued and outstanding stock have filed the required reports in a timely manner during fiscal 2011.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

At June 30, 2011 we had 40,030,251 shares of our common stock issued and outstanding. The following table sets forth information regarding the beneficial ownership of our common stock as of June 30, 2011, by:

each person known by us to be the beneficial owner of more than 5% of our common stock;

each of our directors;

each of our named executive officers; and

our named executive officers, directors and director nominees as a group.

Unless otherwise indicated, the business address of each person listed is in care of 3651 Baker Highway, Huntsville, TN 37756. The percentages in the table have been calculated on the basis of treating as outstanding for a particular person, all shares of our common stock outstanding on that date and all shares of our common stock issuable to that holder in the event of exercise of outstanding options, warrants, rights or conversion privileges owned by that person at that date which are exercisable within 60 days of that date. Except as otherwise indicated, the persons listed below have sole voting and investment power with respect to all shares of our common stock owned by them, except to the extent that power may be shared with a spouse.


	Amount and Nature of Beneficial Ownership ¹
Name	# of Shares	% of Class
Deloy Miller ²	4,646,555	11.6	%
Scott M. Boruff ³	4,028,641	10.0	%
David M. Hall ⁴	1,546,784	3.8	%
Paul W. Boyd ⁵	391,667	<1	%
Charles Stivers ⁶	33,333	<1	%
Herman E. Gettelfinger ⁷	763,234	1.9	%
General Merrill A. McPeak ⁸	130,000	<1	%
Jonathan S. Gross ⁹	100,000	<1	%
David J. Voyticky ¹⁰	100,000	<1	%
Don A. Turkleson ¹¹	—	—
All named executive officers and directors as a group (10 persons) ^{2,3,4,5,6,7,8,9, and 10 and 11}	11,740,214	27.7	%
Seaside 88, LP ¹²	2,936,486	7.4	%

———————

The inclusion of any shares as deemed beneficially owned does not constitute an admission of beneficial ownership by the named shareholder.

The number of shares owned by Mr. Miller includes options to purchase an additional 100,000 shares of our common stock exercisable at $5.94 expiring in April 2020 and 16,667 shares of our common stock exercisable at $6.534 expiring in April 2015 but excludes options to purchase an additional 200,000 shares of our common stock exercisable at $5.94 which have not yet vested and expire in April 2020, 33,333 shares of our common stock exercisable at $6.534 which have not yet vested and expire in April 2020 and 175,000 shares of our common stock exercisable at $5.89 which have not yet vested and expire in May 2021.

The number of shares owned by Mr. Boruff includes 8,000 shares owned for the benefit of his minor children, options to purchase an additional 187,500 shares of our common stock which are exercisable at $0.33 per share expiring in August, 2018 and options to purchase an additional 150,000 shares of our common stock exercisable at $5.94 and 16,667 shares of our common stock exercisable at $6.534 and expire in April 2015. The number of shares owned by Mr. Boruff excludes options to purchase an additional 62,500 shares of our common stock exercisable at $0.33 per share which have not yet vested and expire in August 2018, restricted stock awards totaling 487,500 shares which have not yet vested, options to purchase an additional 300,000 shares of our common stock exercisable at $5.94 which have not yet vested and expire in April 2020, options to purchase an additional 33,333 shares of our common stock exercisable at $6.534 which have not yet vested and expire in April 2015, options to purchase an additional 2,500,000 shares of our common stock exercisable at $6.00 which have not yet vested and expire in April 2015 and options to purchase an additional 250,000 shares of our common stock exercisable at $5.89 which have not yet vested and expire in May 2021.

⁴

The number of shares owned by Mr. Hall includes a warrant to purchase an additional 711,000 shares of our common stock exercisable at $1.00 expiring in December 2013, a warrant to purchase an additional 480,000 shares of our common stock exercisable at $2.00 expiring in December 2013, options to purchase an additional 33,334 shares of our common stock exercisable at $5.94 expiring in April 2020 but excludes options to purchase an additional 66,666 shares of our common stock exercisable at $5.94 which have not yet vested and expire in April 2020 and options to purchase an additional 175,000 shares of our common stock exercisable at $5.89 which have not yet vested and expire in May 2021.

⁵

The number of shares owned by Mr. Boyd includes options to purchase 250,000 shares of our common stock exercisable at $0.40 per share expiring in September 2011, options to purchase 25,000 shares of common stock at $2.52 per share expiring in February 2015 and options to purchase 116,667 shares of common stock at $5.94 per share expiring in April 2020 but excludes options to purchase an additional 250,000 shares of our common stock exercisable at $5.94 which have not yet vested and expire in April 2020 and options to purchase an additional 175,000 shares of our common stock exercisable at $5.89 which have not yet vested and expire in April 2021.

⁶

The number of shares owned by Mr. Stivers includes options to purchase 33,333 shares of common stock at $5.94 per share expiring in April 2020 but excludes options to purchase an additional 66,667 shares of our common stock exercisable at $5.94 which have not yet vested and expire in April 2020 and options to purchase 40,000 shares of common stock at an exercise price of $5.89 which have not yet vested and expire in May 2021.

⁷

The number of shares owned by Mr. Gettelfinger includes options to purchase 33,333 shares of common stock at $5.94 per share expiring in April 2020 but excludes options to purchase an additional 66,667 shares of our common stock exercisable at $5.94 which have not yet vested and expire in April 2020 and options to purchase 40,000 shares of common stock at an exercise price of $5.89 which have not yet vested and expire in May 2021.

⁸

The number of shares owned by General McPeak includes 30,000 shares held in a family trust over which he has voting and dispositive control, options to purchase 66,667 shares of common stock at $5.94 per share expiring in April 2020 and options to purchase 33,333 shares of common stock at $4.98 per share expiring in July 2020 but excludes options to purchase an additional 133,333 shares of our common stock exercisable at $5.94 which have not yet vested and expire in April 2020, options to purchase an additional 66,667 shares of our common stock exercisable at $4.98 which have not yet vested and expire in July 2020 and 40,000 shares of common stock at an exercise price of $5.89 which have not yet vested and expire in May 2021.

⁹

The number of shares owned by Mr. Gross includes options to purchase 66,667 shares of common stock at $5.94 per share expiring in April 2020 and options to purchase 33,333 shares of common stock at $4.98 per share expiring in July 2020 but excludes options to purchase an additional 133,333 shares of our common stock exercisable at $5.94 which have not yet vested and expire in April 2020, options to purchase an additional 66,667 shares of our common stock exercisable at $4.98 which have not yet vested and expire in July 2020 and 40,000 shares of common stock at an exercise price of $5.89 which have not yet vested and expire in May 2021.

¹⁰

The number of shares owned by Mr. Voyticky includes options to purchase 66,667 shares of common stock at $5.94 per share expiring in April 2020 and options to purchase 33,333 shares of common stock at $4.98 per share expiring in July 2020 but excludes options to purchase an additional 133,333 shares of our common stock exercisable at $5.94 which have not yet vested and expire in April 2020, options to purchase an additional 66,667 shares of our common stock exercisable at $4.98 which have not yet vested and expire in July 2020, options to purchase an additional 150,000 shares of our common stock exercisable at $5.89 which have not yet vested and expire in May 2021 and options to purchase an additional 2,300,000 shares of common stock at an exercise price of $5.35 which have not yet vested and expire in June 2016.

¹¹

The number of shares owned by Mr. Turkleson excludes options to purchase 100,000 shares of common stock at an exercise price of $5.25 which have not yet vested and expire in January 2021 and options to purchase 40,000 shares of common stock at an exercise price of $5.89 which have not yet vested and expire in May 2021.

¹²

The number of shares owned by Seaside 88, LP includes warrants to purchase 70,000 shares of common stock at an exercise price of $5.28 expiring in March 2015. Seaside 88, LP’s address is 750 Ocean Royale Way, Suite 805, Juno Beach. FL 33408.

Shareholders Agreement

In connection with the Loan Agreement described previously, Miller also entered into a certain Shareholders’ Agreement (the “Shareholders’ Agreement”), dated June 13, 2011, with Scott M. Boruff, Paul W. Boyd, David Hall, Deloy Miller and David Voyticky (the “Shareholders”). The Shareholders’ Agreement provides that the Shareholders may not transfer their shares of common stock of Miller while the loans under the Credit Facility are outstanding, subject to certain exceptions for Messrs. Deloy Miller and Paul W. Boyd. Specifically, Mr. Miller is permitted to transfer a number of shares of our common stock beneficially owned by him which does not exceed the lesser of (a) 2,500,000 shares of common stock, and (b) a number of shares necessary for him to receive net proceeds equal to $10 million, provided that simultaneous with such transfer Miller receives net proceeds from a new issuance of its securities equal to two times the net proceeds received by Mr. Miller and Mr. Miller transfers the shares at the same price and for the same consideration as received by Miller from such new issuance. Mr. Boyd is permitted to exercise outstanding options to purchase 250,000 shares of Miller’s common stock which expire in September 2011 and to transfer the shares of common stock obtained upon such exercise. There are no permitted exceptions for the transfer of shares by either Messrs. Boruff, Hall or Voyticky.

Securities Authorized For Issuance Under Equity Compensation Plans

The following table sets forth securities authorized for issuance under any equity compensation plans approved by our shareholders as well as any equity compensation plans not approved by our shareholders as of April 30, 2011.


	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted average exercise price of outstanding options, warrants and rights (b)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Plan category

Plans approved by our shareholders:
Miller Petroleum, Inc. Stock Plan	3,000,000	$5.86	0
Miller Petroleum, Inc. 2011 Equity Compensation Plan	2,850,000	$5.91	5,400,000
Warrants granted to employee in January 2010	100,000	$2.00	0
Options granted to employees in February 2010	150,000	$2.52	0
Employment agreement with Scott M. Boruff	125,000	$0.33	125,000
Option agreement with Paul W. Boyd	250,000	$0.40	0

Miller Petroleum, Inc. Stock Plan

In April 2010 our Board of Directors authorized the Miller Petroleum, Inc. Stock Plan which was subsequently approved by our shareholders at a special meeting held on April 27, 1010. The purpose of this plan, which is administered by the Compensation Committee of the Board of Directors, is to further the success of our company by making our common stock available to our employees through grants of incentive stock options, non-qualified stock options and restricted stock. We believe that the plan provides an incentive to such persons to continue in our service, to perform at and above targeted levels, and to give them a greater interest as shareholders in our success. We have reserved 3,000,000 shares of our common stock for issuance under this plan. Options and restricted stock awards may be granted under the plan only to our employees, officers or directors, or to members of any advisory panel or board established at the direction of the Board. In determining the persons to whom options or restricted stock awards will be granted and the number of shares to be covered by each option or award, the Compensation Committee may take into account the nature of the services rendered by the respective persons, their present and potential contributions to our and such other factors as the Compensation Committee in its discretion may believe relevant. The term of options granted under the stock option plan may not exceed 10 years or five years for an incentive stock option granted to an optionee owning more than 10% of our voting stock. The exercise price for stock options cannot be less than fair market value on the date of grant. However, the incentive stock options granted to a 10% holder of our voting stock are exercisable at a price equal to or greater than 110% of the fair

market value of the common stock on the date of the grant. As of April 30, 2011, we have granted options or awarded shares in the amount of 2,970,000 shares of our common stock under the plan.

Miller Petroleum, Inc. 2011 Equity Compensation Plan

In December 2010 our Board of Directors authorized the Miller Petroleum, Inc. 2011 Equity Compensation Plan which was subsequently approved by our shareholders at our fiscal 2010 annual meeting held on March 11, 2011. The purpose of this plan, which is administered by the Compensation Committee of the Board of Directors, is to further the success of our company by making our common stock available to our employees through grants of incentive stock options, non-qualified stock options and restricted stock. We believe that the plan provides an incentive to such persons to continue in our service, to perform at and above targeted levels, and to give them a greater interest as shareholders in our success. We have reserved 8,250,000 shares of our common stock for issuance under this plan. Options and restricted stock awards may be granted under the plan only to our employees, officers or directors, or consultants. In determining the persons to whom options or restricted stock awards will be granted and the number of shares to be covered by each option or award, the Compensation Committee may take into account the nature of the services rendered by the respective persons, their present and potential contributions to our and such other factors as the Compensation Committee in its discretion may believe relevant. The term of options granted under the stock option plan may not exceed 10 years or five years for an incentive stock option granted to an optionee owning more than 10% of our voting stock. The exercise price for stock options cannot be less than fair market value on the date of grant. However, the incentive stock options granted to a 10% holder of our voting stock are exercisable at a price equal to or greater than 110% of the fair market value of the common stock on the date of the grant. As of April 30, 2011, we have granted options or awarded shares in the amount of 2,850,000 shares of our common stock under the plan.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

From time to time our company provides service work on oil and gas wells owned by Mr. Gettelfinger, a member of the Board of Directors, and his wife. The terms and pricing are the same as to third parties. At each of April 30, 2011 and 2010 Mr. and Mrs. Gettelfinger owed us $17,505 and $29,950, respectively.

On August 1, 2009 we entered into a Marketing Agreement with The Dimirak Companies, an affiliate of Dimirak Financial Corp. and Dimirak Securities Corporation, a broker-dealer and member of FINRA. Mr. Boruff, our CEO, is a director and 49% owner of Dimirak Securities Corporation. Under the terms of this agreement, we engaged The Dimirak Companies to serve as our exclusive marketing agent in a $20 million of income fund and a $25.5 million drilling offering, which included the MEI offering described earlier in this annual report. The term of the agreement will expire upon the termination of the offerings. We agreed to pay The Dimirak Companies a monthly consulting fee of $5,000, a marketing fee of 2% of the gross proceeds received in the offerings or within 24 months from the expiration of the term of the agreement, a wholesaling fee of 2% of the proceeds and a reimbursement of pre-approved expenses. The agreement contains customary indemnification, non-circumvention and confidentiality clauses. During 2011 and 2010 we paid The Dimirak Companies and their affiliates a total of $69,932 and $25,468 under the terms of this agreement.

On December 22, 2010, in connection with the line of credit made available to us by PlainsCapital Bank, our Founder, Chief Operating Officer and Chairman of the Board, Deloy Miller, and our Chief Executive Officer and member of the Board of Directors, Scott Boruff, personally guaranteed the repayment of the line of credit. Mr. Miller and Mr. Boruff also each pledged a portion of their shares of our common stock owned by them as security for the loan. The line of credit was repaid on or about June 15, 2011, in connection with the closing of our Credit Facility.

On June 13, 2011, in connection with the Credit Facility (as discussed previously in this report), we, along with all of our subsidiaries, entered into a Guarantee and Collateral Agreement (the “Guarantee”) with the Lenders. We granted a security interest in substantially all of our and our subsidiaries’ assets to secure the performance of our obligations under the Loan Agreement and the Guarantee.

Director Independence

Messrs. Stivers, Gettelfinger, Gross, McPeak and Turkleson are considered independent within The New York Stock Exchange’s director independence standards pursuant to Corporate Governance Standard 303A.02

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES.

The following table shows the fees that were billed for the audit and other services provided by KPMG LLP and Sherb & Co., LLP for 2011 and 2010.


	2011		2010

Audit Fees	$	298,044	$	128,500
All Other Fees		17,033		0
Total	$	315,077	$	128,500

Audit Fees — This category includes the audit of our annual financial statements, review of financial statements included in our Quarterly Reports on Form 10-Q and services that are normally provided by the independent registered public accounting firm in connection with engagements for those fiscal years. This category also includes advice on audit and accounting matters that arose during, or as a result of, the audit or the review of interim financial statements.

All Other Fees — This category consists of fees for other miscellaneous items.

Our Board of Directors has adopted a procedure for pre-approval of all fees charged by our independent registered public accounting firm. Under the procedure, the Board approves the engagement letter with respect to audit, tax and review services. Other fees are subject to pre-approval by the Board, or, in the period between meetings, by a designated member of Board. Any such approval by the designated member is disclosed to the entire Board at the next meeting. The audit and tax fees paid to the auditors with respect to 2011 were pre-approved by the entire Board of Directors.

PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

The following documents are filed as a part of this report or are incorporated by reference to previous filings, if so indicated:


Exhibit No.		Description of Exhibit
2.1		Agreement and Plan of Reorganization dated December 20, 1996 between Triple Chip Systems, Inc. and Miller Petroleum, Inc. (1)
3.1		Certificate of Incorporation (2)
3.2		Certificate of Amendment of Certificate of Incorporation (2)
3.3		Certificate of Amendment of Certificate of Incorporation (2)
3.4		Certificate of Ownership and Merger and Articles of Merger between Triple Chip Systems, Inc. and Miller Petroleum, Inc. (3)
3.5		Amended and Restated Charter of Miller Petroleum, Inc. (18)
3.6		Amended and Restated Bylaws of Miller Petroleum, Inc. (18)
3.7		Articles of Amendment to the Bylaws of Miller Petroleum, Inc. (29)
3.8		Articles of Amendment to the Charter of Miller Petroleum, Inc. (30)
4.1		Form of Stock Purchase Warrant issued May 4, 2005 to Prospect Energy Corporation (4)
4.2		Form of Stock Purchase Warrant issued May 4, 2005 to Petro Capital III, L.P. (4)
4.3		Form of Stock Purchase Warrant issued May 4, 2005 to Petrol Capital Advisors, LLC (4)
4.4		Form of Stock Purchase Warrant issued December 31, 2005 to Petro Capital III, L.P. (5)
4.5		Form of Stock Purchase Warrant issued December 31, 2005 to Prospect Energy Corporation (5)
4.6		Form of Stock Purchase Warrant issued December 31, 2005 to Petro Capital Advisors, LLC (5)
4.7		Form of warrant issued to Cresta Capital Corporation (12)
4.8		Form of option granted to Paul W. Boyd (12)
4.9		Form of warrant issued to David M. Hall, Walter J. Wilcox, II and Troy Stafford (15)
4.10		6% Convertible Secured Promissory Note (15)
4.11		Form of common stock purchase warrant for March 2010 private placement (21)
4.12		Form of common stock purchase warrant issued to purchasers in the Miller Energy Income Fund 2009-A, LP offering (21)
4.13		Form of common stock purchase warrant issued to Sutter Securities Incorporated (21)
10.1		Purchase and Sale Agreement dated December 16, 1997 between AKS Energy Corporation and Miller Petroleum, Inc. (6)
10.2		Assumption Agreement dated December 16, 1997 between AKS Energy Corporation and Miller Petroleum, Inc. (6)
10.3		Purchase and Sale Agreement dated September 6, 2000 between NAMI Resources Company, LLC and Miller Petroleum, Inc. (7)
10.4		Employment Agreement as of August 1, 2008 with Scott M. Boruff (8)
10.5		Amendment to Employment Agreement with Scott M. Boruff dated September 9, 2008 (9)
10.6		Form of Registration Rights Agreement dated May 4, 2005 by and among Miller Petroleum, Inc., Petro Energy Corporation, Petrol Capital III, L.P. and Petro Capital Advisors, LLC. (4)
10.7		Farmout Agreement dated September 3, 1999 between Tengasco, Inc. and Miller Petroleum, Inc. (3)
10.8		Registration Rights Agreement dated May 4, 2005 (4)
10.9		Purchase and Sale Agreement dated June 13, 2008 between Atlas Energy Resources, LLC and Miller Petroleum, Inc. (8)
10.10		Termination Agreement, General Release and Covenant No To Sue Dated June 13, 2008 with Cresta Capital Strategies, LLC (12)
10.11		Agreement dated June 8, 2009 between Ky-Tenn Oil, Inc. and Miller Petroleum, Inc. (13)
10.12		Agreement dated June 18, 2009 for Sale of Capital Stock of East Tennessee Consultants, Inc. and Sale of Membership Interests of East Tennessee Consultants II, LLC (14)
10.13		Agreement for Sale of Membership Interest in Cook Inlet Energy, LLC (15)
10.14		Form of Securities Purchase Agreement for December 2009 private placement (16)
10.15		First Secured Promissory Note from Miller Petroleum, Inc. to Miller Energy Income 2009-A, LP (17)
10.16		Second Secured Promissory Note from Miller Petroleum, Inc. to Miller Energy Income 2009-A, LP (17)


10.17		Loan and Security Agreement between Miller Petroleum, Inc and Miller Energy Income 2009-A, LP (17)
10.18		Escrow Agreement (17)
10.19		Form of Securities Purchase Agreement for March 2010 private placement (21)
10.20		Form of Registration Rights Agreement for March 2010 private placement (21)
10.21		Finder’s Agreement with Sutter Securities Incorporated dated December 28, 2009 (21)
10.22		Finder’s Agreement with Sutter Securities Incorporated dated March 18, 2010 (21)
10.23		Miller Petroleum, Inc. Stock Plan (18)
10.24		Consulting Agreement dated March 12, 2010 with Bristol Capital, LLC (21)
10.25		Marketing Agreement dated August 1, 2009 with The Dimirak Companies (21)
10.26		Consulting Agreement dated February 1, 2010 with Tyler Energy Consulting Group (21)
10.27		Letter Agreement dated November 5, 2009 between Vulcan Capital Corporation, LLC and Miller Petroleum, Inc. (21)
10.28		Assignment Oversight Agreement dated November 5, 2009 between Cook Inlet Energy, LLC and The State of Alaska Department of Natural Resources (21)
10.29		Cook Inlet Energy, LLC Master Services Agreement with Fairweather E&P Services, Inc. dated January 1, 2010 (21)
10.30		Purchase and Sale Agreement by and between Cook Inlet Energy, LLC and Pacific Energy Alaska Operating LLC and Pacific Energy Alaska Holdings, LLC dated as of November 24, 2009 (20)
10.31		Cook Inlet Spill Prevention and Response, Inc. Bylaws and Response Action Contract (21)
10.32		Separation Agreement and General Release with Ford F. Graham (19)
10.33		Third Secured Promissory Note from Miller Petroleum, Inc. to Miller Energy Income 2009-A, LP (22)
10.34		Letter from the State of Alaska to Cook Inlet Energy, LLC announcing acceptance of terms for the extension of Susitna Exploration License #2 (23)
10.35		Settlement Agreement between Petro Capital III, LP, Petro Capital Advisors, LLC, and Miller Petroleum, Inc. (24)
10.36		Settlement Agreement between Cook Inlet Pipe Line Company and Cook Inlet Energy, LLC (25)
10.37		Settlement Agreement between Prospect Capital Corporation and Miller Petroleum, Inc. (26)
10.38		Aircraft Purchase Agreement between The Heavener Company Leasing, LLC, Bristol Capital Advisors, LLC, Bristol Capital, LLC and Miller Petroleum, Inc. (27)
10.39		Promissory Note from Miller Petroleum, Inc. to PlainsCapital Bank (28)
10.40		Guaranty from Deloy Miller to PlainsCapital Bank (28)
10.41		Guaranty from Scott Boruff to Plains Capital Bank (28)
10.42		Amended and Restated Employment Agreement with Scott M. Boruff (28)
10.43		Performance Bond Agreement between the State of Alaska and Cook Inlet Energy, LLC (29)
10.44		2011 Equity Compensation Plan (29)
10.45		Employment Agreement with Paul W. Boyd (29)
10.46		Employment Agreement with David J. Voyticky (31)
10.47		Contract of Construction and Sale between Miller Energy Resources, Inc. and Voorhees Equipment and Consulting, Inc. (32)
10.48		Collateral Assignment of Rig Contract between Miller Energy Resources, Inc. and Guggenheim Corporate Funding, LLC (32)
10.49		Loan Agreement between Miller Energy Resources, Inc. and Guggenheim Corporate Funding, LLC, Citibank, N.A. and Bristol Investment Fund, Ltd. (33)
10.50		Shareholders’ Agreement between Deloy Miller, Scott M. Boruff, David J. Voyticky, David M. Hall, Paul W. Boyd and Miller Energy Resources, Inc. (33)
10.51		Guarantee and Collateral Agreement between Miller Energy Resources, Inc. and its subsidiaries, and Guggenheim Corporate Funding, LLC (33)
10.52		First Amendment to Consulting Agreement between Miller Energy Resources, Inc. and Bristol Capital, LLC (33)
10.53		Lease between Miller Energy Resources, Inc. and Pellissippi Pointe II, LLC*
10.54		Form of Assignment of Membership Interest in Pellissippi Pointe, LLC*
10.55		Form of Assignment of Membership Interest in Pellissippi Pointe II, LLC*
14.1		Amended and Restated Code of Business Conduct and Ethics *
21.1		Subsidiaries of the registrant *
23.1		Consent of Ralph E. Davis Associates, Inc.*
23.2		Consent of Lee Keeling and Associates, Inc. *


31.1		Rule 13a-14(a)/15d-14(a) certification of Chief Executive Officer *
31.2		Rule 13a-14(a)/15d-14(a) certification of Chief Financial Officer *
32.1		Section 1350 certification of Chief Executive Officer *
32.2		Section 1350 certification of Chief Financial Officer *
99.1		Reserve Report of Ralph E. Davis Associates, Inc. at April 30, 2011 on Cook Inlet assets *
99.2		Reserve Reports of Lee Keeling and Associates, Inc. at April 30, 2011 on Appalachian region assets *

———————

filed herewith

(1)

Incorporated by reference to the Current Report on Form 8-K dated January 15, 1997.

(2)

Incorporated by reference to the Annual Report on Form 10-KSB for the year ended December 31, 1995.

(3)

Incorporated by reference to the exhibits filed with the registration statement on Form SB-2, SEC File No. 333-53856, as amended.

(4)

Incorporated by reference to the Current Report on Form 8-K dated May 9, 2005.

(5)

Incorporated by reference to the Quarterly Report on Form 10-QSB for the period ended January 31, 2006.

(6)

Incorporated by reference to the Current Report on Form 8-K dated March 17, 1998.

(7)

Incorporated by reference to the Current Report on Form 8-K dated September 21, 2000.

(8)

Incorporated by reference to the Annual Report on Form 10-KSB for the year ended April 30, 2008.

(9)

Incorporated by reference to the Current Report on Form 8-K dated September 12, 2008

(10)

Incorporated by reference to the Annual Report on Form 10-KSB for the year ended April 30, 2007.

(11)

Incorporated by reference to the Current Report on Form 8-K dated August 21, 2008.

(12)

Incorporated by reference to the Annual Report on Form 10-K for the year ended April 30, 2009.

(13)

Incorporated by reference to the Current Report on Form 8-K filed on June 12, 2009.

(14)

Incorporated by reference to the Current Report on Form 8-K filed on June 24, 2009.

(15)

Incorporated by reference to the Current Report on Form 8-K filed on December 23, 2009.

(16)

Incorporated by reference to the Current Report on Form 8-K filed on January 4, 2010.

(17)

Incorporated by reference to the Quarterly Report on Form 10-Q for the period ended January 31, 2010.

(18)

Incorporated by reference to the Current Report on Form 8-K filed on April 29, 2010.

(19)

Incorporated by reference to the Current Report on Form 8-K filed on June 28, 2010.

(20)

Incorporated by reference to the Current Report on Form 8-K/A filed on July 27, 2010.

(21)

Incorporated by reference to the Annual Report on Form 10-K for the year ended April 30, 2010.

(22)

Incorporated by reference to the Registration Statement on Form S-1 filed on August 13, 2010.

(23)

Incorporated by reference to the Current Report on Form 8-K filed on November 2, 2010.

(24)

Incorporated by reference to the Current Report on Form 8-K filed on November 4, 2010.

(25)

Incorporated by reference to the Current Report on Form 8-K filed on November 26, 2010.

(26)

Incorporated by reference to the Current Report on Form 8-K filed on December 9, 2010.

(27)

Incorporated by reference to the Quarterly Report on Form 10-Q filed on December 10, 2010.

(28)

Incorporated by reference to the Current Report on Form 8-K filed on December 29, 2010.

(29)

Incorporated by reference to the Current Report on Form 8-K filed on March 17, 2011.

(30)

Incorporated by reference to the Current Report on Form 8-K filed on April 15, 2011.

(31)

Incorporated by reference to the Current Report on Form 8-K filed on June 14, 2011.

(32)

Incorporated by reference to the Current Report on Form 8-K filed on June 16, 2011.

(33)

Incorporated by reference to the Current Report on Form 8-K filed on June 17, 2011.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: July 28, 2011


	MILLER ENERGY RESOURCES, INC.


	By:	/s/ SCOTT BORUFF
		Chief Executive Officer

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


Signature	Title	Date

/s/ DELOY MILLER	Chairman of the Board, Chief Operating Officer	July 28, 2011
Deloy Miller

/s/ SCOTT M. BORUFF	Chief Executive Officer, director, principal
Scott M. Boruff	executive officer	July 28, 2011

/s/ PAUL W. BOYD	Chief Financial Officer, principal financial and
Paul W. Boyd	accounting officer	July 28, 2011

/s/ DAVID J. VOYTICKY	President, Director	July 28, 2011
David J. Voyticky

/s/ HERMAN GETTLEFINGER	Director	July 28, 2011
Herman Gettlefinger

/s/ JONATHAN S. GROSS	Director	July 28, 2011
Jonathan S. Gross

/s/ DAVID M. HALL	Director	July 28, 2011
David M. Hall

/s/ MERRILL A. MCPEAK	Director	July 28, 2011
Merrill A. McPeak

/s/ CHARLES STIVERS	Director	July 28, 2011
Charles Stivers

/s/ Don A. Turkleson	Director	July 28, 2011
Don A. Turkleson

MILLER ENERGY RESOURCES, INC.

FORM 10-K

INDEX TO FINANCIAL STATEMENTS


	Pages
Reports of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets	F-4
Consolidated Statements of Operations	F-5
Consolidated Statements of Stockholders' Equity	F-6
Consolidated Statements of Cash Flows	F-7
Notes to the Consolidated Financial Statements	F-8

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors

Miller Energy Resources, Inc.:

We have audited the accompanying consolidated balance sheet of Miller Energy Resources, Inc. and subsidiaries (the Company) as of April 30, 2011, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of April 30, 2011, and the results of their operations and cash flows for the year ended April 30, 2011, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Knoxville, Tennessee

July 29, 2011

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Miller Energy Resources, Inc. f/k/a Miller Petroleum, Inc.

We have audited the accompanying consolidated balance sheets of Miller Energy Resources, Inc. as of April 30, 2010 and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for the year ended April 30, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of April 30, 2010, and the results of its operations and cash flows for the year ended April 30, 2010, in conformity with generally accepted accounting principles in the United States.


	/s/ Sherb & Co., LLP
	SHERB & CO, LLP
	Certified Public Accountants

	New York, New York
	July 25, 2010

F-3

MILLER ENERGY RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS


	April 30, 2011			April 30, 2010
ASSETS
Current Assets
Cash and cash equivalents	$	1,558,933		$	2,994,634
Cash – restricted		202,980			126,064
Accounts receivable, net
Related parties		27,822			47,446
Customers and other		1,619,720			1,444,844
State production credits receivable		3,620,336			1,107,000
Inventory		1,043,960			275,610
Prepaid expenses		231,724			1,503,755
Total		8,305,475			7,499,353
Oil and Gas Properties Cost		496,308,182			485,925,420
Less: accumulated depletion		(14,439,233	)		(3,156,420	)
Net oil and gas properties		481,868,949			482,769,000
Equipment Cost		10,292,514			9,196,979
Less: accumulated depreciation and amortization		(2,003,053	)		(1,961,756	)
Total		8,289,461			7,235,223
Other Assets
Land		526,500			526,500
Cash - restricted long-term		10,026,516			2,071,839
Other assets		63,907			240,056
Total other assets		10,616,923			2,838,395
Total Assets	$	509,080,808		$	500,341,971

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	7,496,786		$	3,579,112
Accrued expenses		4,175,088			806,608
Current derivative liability		2,281,332			2,884,249
Current portion of notes payable		2,000,000			—
Total		15,973,206			7,269,969

Long-term Liabilities
Deferred income taxes		178,876,064			184,607,116
Asset retirement liability		17,293,718			16,017,572
Long-term derivative liability		2,732,659			14,013,026
Notes payable					1,239,399
Total		198,926,227			215,877,113
Total Liabilities		214,909,433			223,147,082

Equity
Common stock, par value $0.0001 per share (500,000,000 shares authorized, 39,880,251 and 32,224,894 shares issued as of April 30, 2011 and 2010, respectively)		3,988			3,223
Additional paid-in capital		49,012,755			27,597,285
Retained earnings		245,164,632			249,604,381
Total Stockholders' Equity		294,181,375			277,204,889
Total Liabilities and Equity	$	509,080,808		$	500,341,971

See accompanying Notes to Consolidated Financial Statements.

F-4

MILLER ENERGY RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended
	April 30, 2011			April 30, 2010
Revenues
Oil sales	$	19,999,423		$	4,064,909
Natural gas sales		525,694			372,306
Other revenue		2,316,752			1,429,789
Total		22,841,869			5,867,004

Costs and Expenses
Oil and gas operating		9,702,548			2,737,774
Cost of other revenue		807,739			754,559
General and administrative		14,554,667			10,273,158
Depreciation, depletion and amortization		12,859,371			3,424,614
Total		37,924,325			17,190,105
Operating Loss		(15,082,456	)		(11,323,101	)

Other Income (Expense)
Interest income		546,274			25,616
Interest expense		(990,235	)		(156,617	)
Loss on derivative securities		(1,007,574)			(13,299,430	)
Other expense, net		(537,157	)		(751,064	)
Gain on acquisitions		6,910,348			461,111,924
Total		4,921,656			446,930,429

Income (Loss) Before Income Taxes		(10,160,800	)		435,607,328
Income Tax Expense (Benefit)		(5,721,051	)		184,676,760
Net Income (Loss)	$	(4,439,749	)	$	250,930,568

Income (Loss) per Share
Basic	$	(0.12	)	$	11.65
Diluted	$	(0.12	)	$	8.34

Average Number of Common Shares Outstanding
Basic		36,112,286			21,537,677
Diluted		36,112,286			30,092,017

See accompanying Notes to Consolidated Financial Statements.

F-5

MILLER ENERGY RESOURCES, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY


	Common Shares		Shares Amount		Additional Paid-in Capital		Accumulated Earnings (Deficit)			Total
Balance at April 30, 2009		15,974,356	$	1,597	$	8,555,324	$	(1,336,187	)	$	7,220,734
Net income		—		—		—		250,940,568			250,940,568
Sale of equity for cash		7,893,432		790		7,799,826		—			7,800,616
Issuance of equity for acquisitions		2,000,000		200		2,641,455		—			2,641,655
Issuance of equity for compensation		100,000		10		1,662,210		—			1,662,220
Issuance of equity for financing cost		1,679,250		168		2,961,757		—			2,961,925
Exercise of equity rights		2,017,847		202		281,798		—			282,000
Issuance of equity for services		469,100		47		1,735,861		—			1,735,908
Beneficial conversion features		—		—		809,263		—			809,263
Conversion of notes		2,090,909		209		1,149,791		—			1,150,000
Balance at April 30, 2010		32,224,894		3,223		27,597,285		249,604,381			277,204,889

Net loss		—		—		—		(4,439,749)			(4,439,749)
Issuance of equity for services		30,000		3		609,556		—			759,165
Issuance of equity for equipment		100,000		10		452,990		—			453,000
Issuance of equity for compensation		162,500		16		4,516,088		—			4,740,654
Exercise of equity rights		4,262,858		426		14,132,146		—			12,354,450
Conversion of notes		3,099,999		310		1,704,690		—			1,705,000
Balance at April 30, 2011		39,880,251	$	3,988	$	49,012,755	$	245,164,632		$	294,181,375

See accompanying Notes to Consolidated Financial Statements.

F-6

MILLER ENERGY RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended April 30,
	2011			2010
Cash Flows from Operating Activities
Net Income (Loss)	$	(4,439,749	)	$	250,930,568
Adjustments to reconcile net income (loss) to net cash provided (used) by operating activities:
Depreciation, depletion and amortization		(12,859,371	)		3,424,614
Gain on acquisitions and other		6,910,348			(461,102,169	)
Write off of prepaid offering cost		—			666,476
Issuance of equity for services		609,556			1,735,908
Issuance of equity for compensation		(4,516,088	)		1,638,900
Issuance of equity for financing cost		—			1,139,382
Deferred income taxes		(5,721,052	)		184,596,339
Loss (gain) on derivative instruments		(1,007,574	)		13,299,430
Changes in Operating Assets and Liabilities:
Receivables, net		(2,668,588	)		(2,428,816	)
Inventory		(768,350	)		(222,291	)
Prepaid expense		1,272,031			(1,257,726	)
Accounts payable and accrual expenses		10,420,544			2,454,708
Asset retirement liability		1,276,146			270,890
Other assets		176,149			4,022,447
Cash provided (used) by operating activities		(15,472,640	)		(821,340	)

Cash Flows from Investing Activities
Purchase of equipment and improvements		(642,535	)		(824,179	)
Proceeds from sale of properties and equipment		—			75,000
Capital expenditures for oil and gas properties		(12,515,649	)		(4,153,222	)
Purchase of Alaska business		—			(4,541,252	)
Net cash used by investing activities		(13,158,184	)		(9,443,653	)

(continued)

See accompanying Notes to Consolidated Financial Statements.

F-7

MILLER ENERGY RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)


	Year Ended
	April 30, 2011			April 30, 2010
Cash Flows from Financing Activities
Payments on notes payable		(3,500,000	)		(3,762,980	)
Debt acquisition costs		—			(619,359	)
Proceeds from borrowing		5,500,000			5,576,444
Proceeds from sale of stock, net		—			9,646,478
Cash acquired through acquisition		—			203,993
Exercise of equity rights		—			282,000
Restricted cash		(1,121,245	)		1,856,488
Restricted cash non-current		—			(60,897	)
Net cash provided by financing activities		878,755			13,183,063
Net Increase (Decrease) in Cash		(1,435,701	)		2,948,068

Cash and Cash Equivalents at Beginning of Period		2,994,634			46,566
Cash and Cash Equivalents at End of Period	$	1,558,933		$	2,994,634

Cash paid for interest	$	824,055		$	603,034

Supplemental Disclosure of Non-Cash Investing and Financing Activities:
Portion of Alaska acquisition financed by equity	$	—		$	2,071,655
Beneficial conversion right of debt issues	$	—		$	809,263
Fair value of equity rights issued with debt	$	—		$	1,048,765
Cash acquired from issuance of stock	$	—		$	203,993
Restricted cash acquired from issuance of stock	$	—		$	196,682
Net assets acquired from issuance of stock	$	(453,000	)	$	(5,111,252	)
Conversion of debt for equity	$	—		$	1,150,000

See accompanying Notes to Consolidated Financial Statements.

F-8

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

(1)

Summary of Significant Accounting Policies

General

Miller Energy Resources, Inc. (the “Company”) is an independent exploration and production company that utilizes seismic data and other technologies for the geophysical exploration, development and production of oil and natural gas wells in the Cook Inlet Basin of south-central Alaska and in the Appalachian region of eastern Tennessee.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company, and its wholly-owned subsidiaries Miller Drilling TN, LLC, Miller Rig & Equipment, LLC, Miller Energy Services, LLC, East Tennessee Consultants II, LLC, East Tennessee Consultants, Inc., Miller Energy GP, LLC, and Cook Inlet Energy, LLC. The consolidated financial statements also include the accounts of Miller Energy Income 2009-A, LP as a result of the Company maintaining control of such entity. All significant intercompany transactions have been eliminated.

Use of Estimates

The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Our management believes the major estimates and assumptions impacting our financial statements are the following:

estimates of oil and gas reserve quantities, which affect the calculations of gains from acquisitions and amortization and impairment of capitalized costs of oil and gas properties;

estimates of the fair value of oil and gas properties we own, particularly properties that we have not yet explored, or fully explored, by drilling and completing wells;

estimates of asset retirement obligation liabilities;

estimates of the fair value of stock options and warrants at date of grant;

estimates of the fair value of derivative liabilities; and

estimates as to the future realization of deferred income tax assets.

Oil and gas reserve estimates for our Tennessee operations are developed from information provided by the Company's management to Lee Keeling & Associates, Inc. of Tulsa, Oklahoma for the years ended April 30, 2011 and 2010. Oil and gas reserve estimates for Alaska operations are developed from information provided by the Company's management to Ralph E. Davis Associates, Inc. of Houston, Texas for the years ended April 30, 2011 and 2010.

The fair value of stock options and warrants at the date of grant to employees and members of our Board of Directors is estimated on the date of grant based on the Black-Scholes options-pricing model utilizing certain assumptions for a risk free interest rate; volatility; and expected remaining lives of the awards. The assumptions used in calculating the fair value of share-based payment awards represent management's best estimates, but these estimates involve inherent uncertainties and the application of management judgment.

As a result, if factors change and the Company uses different assumptions, the Company's stock-based compensation expense could be materially different in the future. In addition, the Company is required to estimate the expected forfeiture rate and only recognize expense for those shares expected to vest. In estimating the Company's forfeiture rate, the Company analyzed its historical forfeiture rate, the remaining lives of unvested options, and the amount of vested options as a percentage of total options outstanding.

If the Company's actual forfeiture rate is materially different from its estimate, or if the Company reevaluates the forfeiture rate in the future, the stock-based compensation expense could be significantly different from what we have recorded in the current period.

F-9

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

The fair value of certain warrants outstanding which have “full-ratchet” or reset provisions (whereby the exercise or conversion price adjusts to pricing in subsequent sales or issuances in certain instances) is based on judgment as to expected future volatility of our common stock.

Actual results may differ from estimates and assumptions of future events. Future production may vary materially from estimated oil and gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting.

Reclassifications

Certain amounts and balances pertaining to the April 30, 2010 financial statements have been reclassified to conform to the April 30, 2011 financial statement presentations. As described in note 15, the Company has reflected an immaterial correction of an error in the accompanying April 30, 2010 consolidated balance sheet and in the accompanying consolidated statements of operations, stockholders’ equity and cash flows for the year ended April 30, 2010.

Cash Equivalents

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

Allowance for Doubtful Accounts

We routinely assess the recoverability of all material trade and other receivables to determine their collectability. The Company charges uncollectible accounts receivable against the allowance for uncollectible accounts when it determines collection will no longer be pursued. The Company deems all accounts receivable collectible at April 30, 2011 and 2010 and therefore has no allowance for doubtful accounts established for its accounts receivable.

Inventory

Inventory consists primarily of crude oil in tanks and is carried at the lower of cost or market. The cost of crude oil inventory includes production costs and Depreciation, Depletion and Amortization (“DD&A”) expense.

Oil and Gas Properties

The Company follows the successful efforts method of accounting for oil and gas properties. Exploration costs such as exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Acquisition costs and costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are charged to exploration expense. Acquisition costs of unproved properties are assessed for impairment during the holding period and transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment, based on the Company’s current exploration plans, and a valuation allowance is provided if impairment is indicated. Costs of expired or abandoned leases are charged to expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties and impairment of unsuccessful leases, are included in oil and gas operating expense.

Impairment

Properties and equipment, net of salvage value, are reviewed for impairment at the lowest level for which identifiable cash flows are independent of cash flows from other assets, and when facts and circumstances indicate that net book values may not be recoverable. In performing this review, an undiscounted cash flow test is performed on the impairment unit. If the sum of the undiscounted estimated future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property’s net book value over its estimated fair value.

F-10

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

Other Properties

Other property includes automobiles, trucks, airplanes, office furniture, computer equipment and buildings. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets or group of assets, which range from five to forty years.

Capitalized Interest

Interest is capitalized as part of the historical cost of developing and constructing assets for significant projects. Significant investments in unproved oil and gas properties, significant exploration and development projects for which DD&A is not currently recognized, and exploration or development activities that are in progress qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined based upon the Company’s weighted-average borrowing cost on debt for the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment, along with other capitalized costs related to that asset.

Asset Retirement Obligations

Asset retirement obligations (“AROs”) associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of AROs change, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.

Depreciation, Depletion and Amortization

Costs of drilling and equipping successful wells, costs to construct or acquire facilities and associated asset retirement costs are depreciated using the unit-of-production method based on estimated proved developed oil and gas reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties and costs to construct or acquire offshore platforms and associated asset retirement costs, are depleted using the unit of production method based on estimated proved developed and undeveloped reserves. Mineral properties are also depleted using the unit of production method.

Derivative Instruments

The Company uses derivative instruments to manage its exposure to cash-flow variability resulting from commodity price risk. All derivatives that do not satisfy the normal purchases and sales exception criteria are carried on the balance sheet at fair value and are included in other current assets, other assets, accrued expenses or other long-term liabilities, depending on the derivative position and the expected timing of settlement. Where the Company has the contractual right and intends to net settle, derivative assets and liabilities are reported on a net basis.

Revenues

Oil and gas revenue is recognized as production is extracted and sold. Service and drilling revenue is recognized at the time it is both earned and we have a contractual right to receive the revenue. The Company follows the sales method of accounting for natural-gas production imbalances. If the Company’s sales volumes for a well exceed the estimated remaining recoverable reserves of the well, a liability is recognized. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production. 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 2011 and 2010.

F-11

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

Share-Based Compensation

We record share-based payments at fair value and record compensation expense for all share-based awards granted, modified, repurchased or cancelled after the effective date, in accord to the FASB guidance. We record compensation expense for outstanding awards for which the requisite service had not been rendered as of the effective date over the remaining service period.

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The Company records a valuation allowance if it is deemed more likely than not that its deferred tax assets will not be realized.

Earnings Per Share

The Company presents "basic" earnings per share and, if applicable, "diluted" earnings per share pursuant to the accounting guidance, "Earnings Per Share." Basic earnings per share are calculated by dividing net income 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, if net income is positive, 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. There were no dilutive shares during fiscal year 2011 and 8,554,340 during fiscal year 2010.

Statement of Comprehensive Income

No statement of comprehensive income is presented since net income (loss) and comprehensive income (loss) would be the same.

Changes in Accounting Principles

Effective July 1, 2010, the Company adopted revised oil and gas reserve estimation standards. This standard allows the use of reliable technology in determining estimates of proved reserve quantities and requires the use of a 12- month first-day-of-the-month average price to estimate proved reserves. Adoption of this standard did not have a material impact on depreciation, depletion and amortization expense.

(2)

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. Bad debt expense was $0 for the years ended April 30, 2011 and 2010.

Financial instruments which potentially subject us to concentration of credit risk consist principally of oil derivative instruments that fluctuate with the price of a barrel of oil. The Company does not apply hedge accounting and recognizes all gains and losses on such instruments in earnings in the period in which they occur.

As of April 30, 2011, we had $11,538,492 in restricted and unrestricted cash balances in excess of the $250,000 limit insured by the Federal Deposit Insurance Corporation. As of April 30, 2010, we had $4,942,537 in

F-12

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

restricted and unrestricted cash balances in excess of the $250,000 limit insured by the Federal Deposit Insurance Corporation.

(3)

Major Customers

The Company depends upon local purchasers of hydrocarbons to purchase our products in the areas where its properties are located. Currently, we sell oil and natural gas to the following purchasers:

Tesoro Corporation purchases all oil from our Alaska production facilities and accounts for $19,378,730 or 94.4% of the Company’s total revenue and $1,143,667 or 70.6% of all accounts receivable for fiscal 2011.

The U.S. Department of Interior has contracted with us to perform clean up on certain wells in National Parks. The Department of Interior accounted for $817,643, which was 48.5% of the other revenue.

(4)

Related Party Transactions

The Company had an account receivable from a member of the Board of Directors, and his wife, at April 30, 2011 and April 30, 2010 in the amount of $17,822 and $29,950, respectively, for work performed on oil and gas wells. This board member and his wife own partial interests in the oil and gas wells the Company also owns.

Our Chairman and CEO pledged personal Company stock to secure our 6% short-term PlainsCapital Bank notes, due July 5, 2011. As of April 30, 2011, the principal balance of the note was $2,000,000.

In 2009 we formed both Miller Energy GP and Miller Energy Income 2009-A, LP (“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. The Company, through a subsidiary, owns 1% of MEI, however due to the shared management of the Company and MEI, we consolidate this entity.

On August 1, 2009, we entered into a marketing agreement with The Dimirak Companies, an affiliate of Dimirak Financial Corp. and Dimirak Securities Corporation, a broker-dealer and member of FINRA. Mr. Boruff, our CEO, is a director and 49% owner of Dimirak Securities Corporation. Under the terms of this agreement, we engaged The Dimirak Companies to serve as our exclusive marketing agent in $20 million income fund and a $25 million drilling offering, which included the MEI offering described above. The term of the agreement will expire upon the termination of the offerings. We agreed to pay The Dimirak Companies a monthly consulting fee of $5,000, a marketing fee of 2% of the gross proceeds received in the offerings or within 24 months from the expiration of the term of the agreement, a wholesaling fee of 2% of the proceeds and a reimbursement of pre-approved expenses. The agreement contains customary indemnification, non-circumvention and confidentiality clauses. During 2010 we paid The Dimirak Companies and their affiliates a total of $25,468 under the terms of this agreement.

(5)

Equipment

Summary of equipment as of April 30 is as follows:


	April 30, 2011		April 30, 2010
Machinery and equipment	$	5,454,923	$	5,034,663
Vehicles		2,071,322		1,402,095
Buildings		2,682,810		2,682,810
Office equipment		83,459		77,411
		10,292,514		9,196,979
Less: accumulated depreciation		(2,003,053)		(1,961,756	)
Total Equipment	$	8,289,461	$	7,235,223

F-13

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

Machinery and equipment includes oil and gas related equipment we use to drill for new wells and related activities as well as to maintain or improve existing wells.

(6)

Derivative Instruments

At April 30, 2011, the Company had two derivative instruments; warrants with exercise reset provisions and an oil derivative financial instrument.

During the year ended April 30, 2011, the Company entered into commodity derivative financial instruments for 300 barrels of oil per day from January 1, 2011 to December 31, 2011 and from May 1, 2011 to April 30, 2012, respectively. These instruments are used to manage the inherent uncertainty of future revenues due to oil price volatility and to manage the Company’s exposure to oil pricing volatility. The hedges are priced at $92.13 and $108.25, respectively, per barrel of oil. The Company has elected not to designate any of its derivative instruments for hedge accounting treatment. As a result, both realized and unrealized gains and losses are recognized in earnings. The liabilities recorded for these instruments as of April 30, 2011 is $2,305,118, which is also the unrealized loss included in earnings for the year ended April 30, 2011.

Effective May 1, 2009, the Company adopted the provisions of EITF 07-05 “Determining Whether an Instrument (or Embedded Feature) is Indexed to a Company's Own Stock,” which was codified into ASC Topic 815 – Derivatives and Hedging. ASC 815 applies to any freestanding financial instruments or embedded features that have characteristics of a derivative and to any freestanding financial instruments that are potentially settled in an entity’s own common stock. The Company had potentially almost 4million of warrants with exercise reset provisions, which are considered freestanding derivative instruments. ASC 815 requires these warrants to be recorded as liabilities as they are no longer afforded equity treatment. The derivative liability as of April 30, 2010 of $16,897,275 is comprised three transactions, warrants issued in connection with a debt financing arrangement in the current and past years, which are subject to an ongoing litigation matter, 716,715 warrants issued in an equity financing in March 2010 and 300,000 warrants issued pursuant to a consulting arrangement in March 2010. The terms of the exercise reset provision on the 716,715 warrants expire in September 2010, hence the related fair value of this derivative of $2,884,249 has been recorded as a current liability. The Company utilized the Black-Scholes pricing model to record a fair value of these derivative security instruments . The fair value of the warrants issued and outstanding at May 1, 2009, attributed to this derivative liability has been determined to be immaterial due to the low stock price in comparison to the exercise price, hence there was no adjustment to make upon adoption of this accounting standard. During fiscal year 2010, the Company has recorded non-cash losses of $13,299,430 relating to the change in fair value of these derivative instruments.

Predominately all of the above derivative securities either expired, were exercised or settled as part of the Petro / Prosepct litigation during fiscal 2011. There remains as of April 30, 2011 $2,756,445 of derivative liabilities.

(7)

Long-Term Debt, Warrants, Loan Fees and Restricted Cash

The Company had the following debt obligations at April 30, 2011 and 2010:


	April 30, 2011		April 30, 2010

6% convertible secured promissory notes, secured by 35,235 leased acres, bearing interest at 6.00%, due December 4, 2016	$	—	$	1,705,000

6% short-term PlainsCapital Bank notes, secured by Company stock owned by the CEO and Chairman of the Company, due July 5, 2011		2,000,000		—

		2,000,000		1,705,000

Less: current maturities		(2,000,000)		—
Less: debt discount		—		(465,601	)

Notes Payable - Long-term	$	—	$	1,239,399

F-14

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

On December 27, 2010, we obtained a $5,000,000 line of credit from PlainsCapital Bank that provided financial flexibility to us while we continued to seek longer-term financing. Our Chairman and CEO pledged personally owned Company stock to secure this 6% short-term bank note, due July 5, 2011. As of April 30, 2011, the principal balance of the note was $2,000,000. The note was paid in full subsequent to year end.

In December 2009, the Company issued $2,855,000 as 6% convertible secured promissory notes. These convertible secured notes bear interest at 6% per annum with an original maturity in December 2016. The convertible secured notes, including any accrued and unpaid interest are convertible into common stock at $0.55 per share, at the option of the holder. During the year ended April 30, 2010, notes for $1,150,000 were converted into 2,090,909 shares of common stock. The conversion price was below market at the time of this debt raise, as a result the fair value of beneficial conversion feature was computed to be $809,263. This beneficial conversion feature was recorded as a debt discount and was amortized over the term of the debt. The amortization expense recorded for the years ended April 30, 2011 and 2010 were $465,601 and $363,662, respectively. During the year ended April 30, 2011, the remaining notes were exchanged into 3,099,999 shares of the Company’s common stock.

(8)

Asset Retirement Obligations

The changes in the Company's asset retirement obligations are as follows:


	April 30, 2011			April 30, 2010
	April 30, 2011			April 30, 2010
Asset retirement obligation, beginning of period	$	16,017,572		$	57,246
Asset retirement obligation acquired through acquisitions		—			15,645,565
Accretion expense		1,406,906			314,761
Revisions		(130,760	)		—

Asset retirement obligation, end of period	$	17,293,718		$	16,017,572

(9)

Equity

During the year ended April 30, 2011, we issued the following securities: 7,655,357 shares, which included four warrant holders who exercised warrants for 194,600 shares in a cashless exercise that netted the holders 153,784 shares and ten other warrant holders exercised warrants for 1,576,750 shares for exercise prices ranging from $0.01 to $2.00 per share.

During fiscal 2011, the Company issued 3,175,000 employee and director options between February 18, 2010 and April 30, 2011 and 100,000 options to an advisor to the Company’s Board of Directors on October 1, 2010 which is included in non-cash compensation expense of $4,740,638 for the year ended April 30, 2011.

In addition, between June 3, 2010 and October 18, 2010, fifteen note holders converted $1,705,000 of their 6% secured convertible notes at a conversion rate of $0.55 and we issued 3,099,999 shares. We also issued 30,000 shares to an advisor to the Company’s Board of Directors for services rendered. During the year ended April 30, 2011, we also issued 162,500 shares to an employee for compensation in accords with an employment contract and expensed $888,875 in non-cash compensation expense.

On October 29, 2010, we entered into a settlement agreement with Petro Capital III, LP and Petro Capital Advisors, LLC (collectively, “Petro”) and resolved litigation that had been pending in federal court in Texas. The settlement agreement resulted in our issuing a total of 518,510 shares of our common stock to Petro.

On November 17, 2010, we issued 100,000 shares of stock in a to acquire a jet from three sellers, one of which is a consultant to the Company and another of which is affiliated with that consultant. The Company valued the transaction at $453,000 based on the fair value of the shares.

F-15

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

On December 3, 2010, we entered into a settlement agreement with Prospect Capital Corporation (“Prospect”) whereby we issued 2,013,814 shares of our common stock in exchange for Prospect forfeiting warrants to purchase 2,148,050 shares of our common stock. There was no gain or loss recognized as a result of this settlement.

During the year ended April 30, 2010, we issued 16,250,538 shares of common stock as well as warrants and options for various reasons.

Acquisitions

We issued 2,000,000 shares of common stock for the acquisition of KTO and ETC, which were valued at the then fair market value of the shares issued of $570,000.

We issued 3,500,000 of warrants to the sellers of CIE at exercise prices varying from $0.01 to $2.00 a share, and the fair value of these warrants was recorded at $2,071,655.

Equity and Debt Financings

In June 2009, the Company sold in a private transaction to accredited investors 350,000 shares of common stock, which resulted in gross proceeds to the Company of $119,000.

In November 2009, the Company borrowed $350,000, with a term of sixty days. The Company also issued 350,000 shares of common stock as an inducement for such loan. The fair value of such shares issued of $245,000 was expensed as a cost of debt issuance.

In December 2009, the Company raised $2,855,000 of convertible debt, discussed earlier. The Company recorded a beneficial conversion feature attributed to the conversion feature of $809,263, which was recorded as a debt discount and was amortized completely during fiscal 2011 as all of the remaining notes were converted to equity during fiscal 2011.

In December 2009 and January 2010, we sold 6,015,000 shares of common stock for $1.00 a share, and $326,000 was incurred as costs to raise such equity, including the issuance of 332,500 warrants to consultants related to this sale of common stock.

In March 2010, we sold for $5,017,002, 1,433,432 shares of common stock and 716,716 warrants exercisable at $2.50 a share. The fair value of this derivative amounted to $542,094 at inception; hence such value was allocated to a derivative liability. In addition these equities sold have registration rights penalties, which if the Company had not filed a registration statement to register such shares to be freely tradable within 30 days then the Company was subject to a 2% percent a month penalty for a total penalty of 12% of this equity raise. As a result of the untimely registration of such shares, the Company accrued the registration penalty of $616,727 as of April 30, 2011. The Company also incurred $361,190 of direct costs related to this equity raise and issued 100,339 of warrants to consultants for this sale of equity. The terms of the exercise reset provision on the 817,055 warrants expire in March, 2015, hence the related fair value of this derivative of $2,732,659 has been recorded as a non-current liability. The Company utilized the Black-Scholes pricing model with the following weighted average assumptions: risk free rate of 1.4%, expected life terms of one year, an expected volatility of 76% and a dividend rate of 0.0%.

In March 2010, the Company sold 95,000 shares of common stock in a private transaction resulting in $326,800 of gross proceeds to the Company.

In April 2010, $1,150,000 of the 6% Convertible debt holders converted their debt for 2,090,909 shares of common stock.

Shares and Options Issued for Services and Compensation

During the fiscal year 2011, we issued 192,500 shares of restricted common stock and 3,275,000 qualified and non-qualified stock options to our employees, directors and consultants, pursuant to employment arrangements or discretionary issues at the directive of the board of directors. The five to ten year stock options issued had exercise prices ranging from $4.98 to $6.94 and vesting terms ranging from an immediate vesting to vesting over

F-16

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

four years. These common shares and stock options issued had a fair value of $5,233,136, which $3,628,906 was expensed in fiscal 2011. The balance of $1,604,230 will be expensed over the next four years as such equities vest.

During the fiscal year 2010, we issued 469,100 shares of common stock and 450,000 five year warrants with exercise prices ranging from $0.01 to $2.50, which all vested immediately. These common shares and warrants had a fair value of $2,372,743, which has been expensed. There was one batch of 300,000 warrants issued which had an exercise price reset provision. The value of these warrants of $636,835 has been classified to be a derivative liability.

Exercise of Warrants

During the fiscal year 2011, there were 4,401,350 warrants converted for cash or on a cashless basis resulting in 4,360,334 shares of common stock being issued with net proceeds of $1,318,750.

During the fiscal year 2010, there were 2,397,500 warrants converted for cash or on a cashless basis resulting in 2,017,847 of common shares being issued with net proceeds of $282,000.

(10)

Share-Based Compensation

We estimated the fair value of options granted during the years ended April 30, 2011 and 2010 on the date of grant, using the Black-Scholes pricing model with the following assumptions:


	2011	2010
Weighted average of expected risk-free interest rates	1.6%	1.56%
Expected years from vest date to exercise date	4.29	2.9
Expected stock volatility	74-82%	50-216%
Expected dividend yield	0%	0%

The Company recorded $5,161,757 and $2,019,876 of compensation expense, net of related tax effects, relative to stock options for the years ended April 30, 2011 and 2010. Net loss per share basic and diluted for this expense is $0.12 and $0.12.

The aggregate intrinsic value is calculated as the difference between the exercise price of the underlying awards and the quoted price of our common stock for those awards that have an exercise price currently below the closing price. During the year ended April 30, 2011 and 2010, the aggregate intrinsic value of stock options and warrants exercised was $20,430,348 and $3,752,093, respectively, determined as of the date of exercise.

A summary of the stock options and warrants as of April 30, 2011 and 2010 and changes during the periods is presented below:


	2011				2010
	Number of Options and Warrants		Weighted Average Exercise Price		Number of Options and Warrants		Weighted Average Exercise Price
Balance at beginning of year		12,306,305	$	2.44		4,090,000	$	0.88
Granted		3,275,000		5.82		10,688,805		2.62
Exercised		4,360,534		0.58		2,397,500		0.03
Expired		-		-		75,000		5.67
Cancelled		140,816		4.59		0		0.96
Balance at end of year		11,079,955		3.98		12,306,305		2.44

Options exercisable at April 30		5,146,625	$	2.67		6,843,805	$	1.50

F-17

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

The following table summarizes information concerning stock options and warrants outstanding and exercisable at April 30, 2011:


Options and Warrants Outstanding				Options and Warrants Exercisable
Range of Exercise Price	Number Outstanding	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price	Number Exercisable	Weighted Average Exercise Price
$0.01 to $0.40	850,000	3.3	$0.22	725,000	$0.20
$1.00 to $1.82	2,062,900	3.0	1.03	2,062,900	1.03
$2.00 to $2.52	1,550,000	3.0	2.15	550,000	2.41
$4.98 to $5.53	1,567,055	6.6	5.23	967,055	5.30
$5.94 to $6.94	5,050,000	6.8	5.99	841,670	5.96
	11,079,955	5.3	3.98	5,146,625	$2.67

All options and warrants were issued at the fair market of common stock on the date of grant.

(11)

INCOME TAX

The components of the provision for income taxes for income from operations are as follows:


	April 30, 2011			April 30 2010
Federal:
Current	$	—		$	—
Deferred		(1,547,811	)		143,512,841
Total Federal		(1,547,811	)		143,512,841
State
Current		—			—
Deferred		(4,173,240	)		41,163,919
Total State		(4,173,240	)		41,163,919
Total income tax expense (benefit)	$	(5,721,051	)	$	184,676,760

A reconciliation of the provision for income taxes as reported and the amount computed by multiplying the income before taxes and extraordinary item by the U.S. federal statutory rate of 35% was as follows:


	April 30, 2011			April 30 2010

Provision calculated at federal statutory income tax rate	$	(3,071,488	)	$	152,169,910
State and local income taxes, net of federal benefit		(494,303	)		26,756,546
Change in effective state tax rate		(2,247,185	)		—
Change in valuation allowance		—			5,750,304
Other		91,925			—
Total expense (benefit)	$	(5,721,051	)	$	184,676,760

F-18

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

Significant components of the Company’s net deferred tax asset consisted of the following:


	April 30, 2011			April 30 2010
Deferred tax assets:
Unrealized derivative loss	$	889,956		$	115,626
Asset Retirement Obligation		7,243,811			6,550,632
Net operating loss carryforwards		7,136,072			5,924,403
Stock options and warrants		2,555,108			762,914
Other		9,098			5,504
Total deferred tax assets, net of valuation allowance	$	17,834,046		$	13,359,079

Deferred tax liabilities:
Book basis of oil and gas properties and other PP&E in excess of tax basis	$	(196,616,917	)	$	(197,513,472	)
Other		(103,194	)		(452,725	)
Total deferred tax liabilities		(196,720,111	)		(197,966,197	)
Net deferred tax liability	$	(178,886,065	)	$	(184,607,116	)

At April 30, 2011, the Company had net operating loss carryforwards for federal income tax purposes of approximately $19 million with expiration through 2023.

In assessing the realizable value of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which these temporary differences become deductible. As management believes, based on assessment of both positive and negative evidence and objective and subjective evidence, that it is more likely than not that all of the deferred tax assets will be realized, the Company does not maintain a valuation allowance against deferred tax assets at April 30, 2011 or April 30, 2010.

(12)

COMMITMENTS

In August 2008 we engaged a broker-dealer and member of FINRA to assist us in raising capital by means of a private placement of securities. As initial compensation for their services, we paid a $25,000 retainer and issued 250,000 shares of our common stock, valued at $115,000 and agreed to pay a monthly consulting fee of $5,000. Upon the successful completion of the private offering we will be obligated to pay the firm certain cash compensation and issue them up to an additional 150,000 shares of our common stock in amounts to be determined based upon the gross proceeds received by us from the financing.

As of April 30, 2011, we have $475,000 in exploration work commitments arising out of two leases over 534,383 acres located in the Susitna River Basin in Alaska. These commitments require the Company to invest in exploration efforts on those leases.

On November 5, 2009, Cook Inlet Energy, LLC entered into an Assignment Oversight Agreement with the Alaska DNR which set our 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:

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,

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

F-19

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

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. We have subsequently provided these funds 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.

(13)

ALASKA STATE TAX CREDITS

The Company operates several oil and gas wells in Alaska and has leased properties for other oil and gas exploration purposes. Alaska has investment tax incentives whereby through June 30, 2010, up to 20% of certain qualified expenditures are reimbursable via a tax credit which can be sold to other oil and gas companies at a discount to obtain an immediate realization of such benefits or such tax credits could be utilized by the Company to offset taxes due or obtain a refund based on certain future reinvestment criteria. Effective July 1, 2010, the state of Alaska has increased the tax incentive rate from 20% to 40% and relaxed the criteria for a refund requirement to be obtained from the state of Alaska. The Company has recorded $3,620,336 as an other asset for an estimate of an investment tax credit incentive refund due from the state of Alaska, as of April 30, 2011.

(14)

ACQUISITIONS

KTO Acquisition

On June 8, 2009, we closed on the purchase of privately owned Ky-Tenn Oil, Inc., ("KTO") which includes approximately 35,325 leased acres located on the Chattanooga Shale and 153 natural gas and oil producing wells. For this acquisition we issued 1,000,000 shares of our common stock, which was valued at $320,000 on the date of acquisition. The acquisition included the aforementioned 35,325 leased acres with 153 producing oil and gas wells as well as $194,400 in restricted bond certificates for well reclamation with a related liability. No cash or receivables were acquired from KTO. A third-party analysis was performed to determine the fair value of the assets acquired. The report was prepared utilizing methods and procedures regularly used by petroleum engineers to estimate oil and gas reserves for properties of this type and character. The value as determined by this evaluation was $252,455. The value of the restricted bond certificates had an offsetting retirement liability, therefore, under the guidance of SFAS 141(R)(FASB ASC 805-10) the difference between the value of the oil and gas properties less the value of the common stock resulted in a loss of $67,545 and was recorded in the Consolidated Statements of Operations as a net to Gain on Acquisitions.

F-20

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

Pursuant to this FASB guidance, we originally valued the acquisition 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.

We determined that pro-forma information related to this acquisition was not required (or useful to investors) due to the fact that this business combination was not material in relation to our consolidated financial statements. As 92 of the 153 wells acquired were shut in, and approximately 81% of the value of the well interests acquired were for undeveloped locations, pro-forma results would not have differed materially from actual results.

ETC Acquisition

On June 18, 2009 the Company 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. The acquisition included 221 producing oil and gas wells and consisted of approximately 4,442 acres. The Company issued 1,000,000 shares for all of ETC and LLC membership interest. Our common shares were valued at $250,000 on the date of acquisition. The acquisition included the following balance sheet items:


Assets			Liabilities and equity
Cash	$	203,993	Accounts payable	$	202,760
Receivables		24,904	Deferred tax		580,864
Fixed assets, net		313,458	Value of shares issued		250,000
Oil and gas properties		1,319,140	Bargain Purchase Gain		828,745
Other assets		874
Total assets	$	1,862,369	Total liabilities and equity	$	1,862,369

We valued this acquisition under the FASB guidance and, accordingly, a Bargain purchase of $828,745 was recorded as of the acquisition date. For the twelve months ended April 30, 2010 the consolidation of this entity increased the Company revenues by $808,159 and increased costs of revenues by $381,674. The impacts of consolidation on all other line items within our Consolidated Statements of Operations were not significant.

Alaska Acquisition

On December 10, 2009, the Company acquired the Alaskan business of Pacific Energy Resources (“Pacific Energy”) valued at more than $479 million through a Delaware Chapter 11 Bankruptcy proceeding. The Company acquired the Alaskan business, 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 operations include 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 purchase are 602,000 acres of oil and gas leases and licenses as well as completed 3D seismic geology and other production facilities. At closing Miller paid Pacific Energy a purchase price of $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. The Company will operate the facilities through its recently acquired wholly-owned subsidiary, Cook Inlet Energy LLC ("Cook"), which has been approved by the State of Alaska as the long-term operator for the Alaskan oil and gas wells.

On December 10, 2009, the Company acquired 100% of the membership interests in Cook Inlet Energy, LLC, an Alaska limited liability company from the owners of this entity. As consideration for this company we issued the sellers, who were unrelated third parties, stock warrants to purchase three million five hundred thousand (3,500,000) shares of our common stock. The Warrants were issued in three tranches with vesting features ranging from immediate to four years and with exercise prices ranging from $0.01 to $2.00, the fair value of the warrants issued were determined to be $2,071,655 and were expensed as a cost of the transaction. In addition, the Company was obligated to deliver $250,000 in cash by March 10, 2010 to satisfy certain expenses as well as reimbursement for reasonable out of pocket expenses. As of the date of this filing, this obligation is still outstanding. 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. David M. Hall, Walter J. Wilcox II

F-21

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

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. However, subsequent to the balance sheet date, Mr. Stafford left the Company. In addition, Mr. Hall was appointed as a member of the Company's Board of Directors and as Chief Executive Officer of Cook Inlet Energy, LLC., Mr. Hall will receive an annual salary of $195,000.

The business combination included the following balance sheet items:

Calculation of the bargain purchase gain is as follows:


Inventory	$	212,228
Fixed Assets		2,516,500
Oil & Gas Properties		476,035,281
Restricted Cash		1,789,995
Asset Retirement Liability		(15,289,994	)
Accounts Payable		(2,230,057	)
Cash paid at closing		(2,250,000	)
FV of Equity Issued		(2,071,657	)
Pre-tax Gain	$	458,712,296
Deferred taxes		(184,703,207	)
Net Gain	$	274,009,089

(15)

LITIGATION

On May 11, 2011, the Court of Appeals of Tennessee at Knoxville returned its opinion in the case styled CNX Gas Company, LLC v. Miller Petroleum, Inc., et al. As previously reported, CNX Gas Company, LLC commenced litigation on June 11, 2008 in the Chancery Court of Campbell County, State of Tennessee to enjoin us from assigning or conveying certain leases described in the Letter of Intent signed by CNX and our company on May 30, 2008, to compel us to specifically perform the assignments as described in the Letter of Intent, and for damages. After the trial court granted the motion for summary judgment of the company and other party defendants and dismissed the case, finding that there were no genuine issues of material fact and we were entitled to judgment as a matter of law, CNX appealed. All parties filed briefs and the Court of Appeals heard oral arguments on May 18, 2010. In its May 11, 2011 opinion, the Court of Appeals reversed the trial court’s grant of summary judgment in favor of our company and the other party defendants, and remanded the case back to the trial court for further proceedings. On July 28, 2011, the case was dismissed without prejudice on the motion of CNX.

On May 17, 2011, we were served with a lawsuit filed in the United States District Court for the Eastern District of Tennessee at Knoxville by Troy D. Stafford, the former Chief Financial Officer of our wholly owned subsidiary, Cook Inlet Energy, LLC (“CIE”). The suit, styled Troy D. Stafford v. Miller Petroleum, Inc., Civil Action No. 3-11CV-206, claims that we terminated Mr. Stafford’s employment without cause in contravention of the terms of the Purchase and Sale Agreement between us and the sellers of CIE (“PSA”), failed or refused to pay his salary, severance, percentage of purchase price, expenses or stock warrant and violated a duty of good faith and fair dealing. The suit seeks damages in excess of $3,000,000, which includes $2,686,700 of damages for loss of vested warrants. We believe the all of the asserted claims are baseless, particularly in view of the fact that we issued the warrants in accordance with the terms of the PSA. We believe that we had appropriate cause to fire Mr. Stafford after discovering that he had breached certain representations and warranties in the PSA, and had acted in violation of our Code of Conduct. We intend to vigorously defend this action.

F-22

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

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. On October 27, 2010, a temporary injunction was granted allowing us access to the property at issue in this case. We are presently conducting discovery.

F-23

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

(16)

RESTATEMENT

The Company has restated its unaudited consolidated balance sheets as of July 31, 2010, October 31, 2010 and January 31, 2011 and our unaudited consolidated statements of operations and cash flows for the quarterly and year to date periods then ended. We failed to properly accrete our asset retirement obligations in each of the first two quarters of fiscal 2011. In these periods we also failed to properly record depletion, depreciation and amortization expenses related to leasehold costs, wells and equipment, fixed assets and asset retirement obligations and did not properly record the state tax credits expected from our Alaska operations. In the third quarter of fiscal 2011 it was determined that we failed to properly classify royalty expense, failed to properly record sufficient compensation expenses on equity awards, did not properly calculate the liability for our derivative liability, and did not properly consolidate an entity we control.

In addition, the Company made an immaterial correction of an error in its consolidated financial statements as of for the year April 30 2010.

The following is a summary presentation of corrections made to the Company’s consolidated balance sheet as of April 30, 2010, previously filed on Form 10-K for the year ended April 30, 2010:


	April 30, 2010					April 30, 2010
	As Reported		Corrections			As Restated
ASSETS

Cash and cash equivalents	$	2,750,841	$	243,793		$	2,994,634
Cash - restricted		126,064		—			126,064
Accounts receivable, net		1,492,290		—			1,492,290
State production tax credits receivables		—		1,107,000			1,107,000
Inventory		275,610		—			275,610
Prepaid expenses		521,639		982,116			1,503,755
Net oil and gas properties		376,216,621		106,552,379			482,769,000
Net equipment		114,820,779		(107,585,556	)		7,235,223
Land		526,500		—			526,500
Cash – restricted long-term		2,071,839		—			2,071,839
Other assets		1,649,972		(1,409,916	)		240,056

TOTAL ASSETS	$	500,452,155	$	(110,184	)	$	500,341,971

LIABILITIES AND EQUITY

Accounts payable	$	3,579,112	$	—		$	3,579,112
Accrued expenses		421,938		278.227			700,165
Derivative liability		17,429,787		(532,511	)		16,897,275
Unearned revenue		106,443		—			106,443
Notes payable		3.043,174		(1,803,775	)		1,239,399
Deferred income tax payable		184,468,878		(138,238	)		184,607,116
Asset retirement liability		15,662,002		355,570			16,017,572
Total Liabilities		224,711,334		(1,562,252	)		223,147,082

STOCKHOLDERS’ EQUITY
Common stock		3,223		—			3,223
Additional paid-in capital		27,620,605		23,320			27,597,285
Retained earnings		248,116,993		1,477,388			249,594,381
Total Stockholders’ Equity		275,740,821		1,454,068			277,194,889

TOTAL LIAB. AND STOCKHOLDERS’ EQUITY	$	500,452,155	$	(110,184	)	$	500,341,971

F-24

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

The following is a summary presentation of corrections made to the Company’s consolidated statement of operations for the year ended April 30, 2010, previously filed on Form 10-K for the year ended April 30, 2010:


	For the Year Ended April 30, 2010 As Reported			Corrections			For the Year Ended April 30, 2010 As Restated
Revenues
Oil sales	$	4,437,215		$	—		$	4,437,215
Service and other revenue		1,429,789			—			1,429,789
Total		5,867,004			—			5,867,004

Costs and Expenses
Oil and gas operating		2,583,383			154,391			2,737,774
Cost of other revenue		1,342,509			(587,950	)		754,559
General and administrative		10,345,216			(72,058	)		10,273,158
Depreciation, depletion and amortization		2,709,308			715,306			3,424,614
Total		16,980,416			209,689			17,190,105

Operating Loss		(11,113,412	)		(209,689	)		(11,323,101		)

Other Income (Expense)
Interest income		25,616			—			25,616
Interest expense		(527,355	)		370,738			(156,617	)
Loss on derivative instruments		(15,861,007	)		2,561,577			(13,299,430	)
Other, net		(751,064	)		—			(751,064	)

Gain on acquisitions		461,111,924			—			461,111,924
Income tax expense		(183,431,522	)		1,245,238			(184,676,760	)
Net Income	$	249,453,180		$	1,477,388		$	250,930,568
Income per Share
Basic	$	11.58					$	11.65
Diluted	$	8.29					$	8.34

Average Number of Common Shares Outstanding
Basic		21,537,677						21,537,677
Diluted		30,092,017						30,092,017

F-25

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

The following is a summary presentation of corrections made to the Company’s unaudited consolidated balance sheet as of July 31, 2010, previously filed on Form 10-Q for the quarter ended July 31, 2010:


	July 31, 2010					July 31, 2010
	As Reported		Corrections			As Restated
ASSETS

CURRENT ASSETS
Cash	$	472,543	$	243,793		$	716,336
Cash, restricted		126,379		—			126,379
Accounts receivable, net		1,489,620		—			1,489,620
State production tax credits receivable		1,603,358		—			1,603,358
Inventory		767,678		—			767,678
Prepaid expenses		177,556		698,813			876,369
Total Current Assets		4,637,134		942,606			5,579,740

PROPERTY PLANT AND EQUIPMENT
Oil and gas properties, net (On the basis of successful efforts accounting)		483,238,369		(239,865	)		482,998,504
Fixed assets, net		7,243,536		37,259			7,281,065
Land		526,500		—			526,500
Total Property, Plant and Equipment		491,008,405		(202,336	)		490,806,069

OTHER ASSETS
Cash – restricted, long-term		2,070,445		—			2,070,445
Other assets		599,550		(302,916	)		296,634
Total Other Assets		2,669,995		(302,916	)		2,367,079

TOTAL ASSETS	$	498,315,534	$	437,354		$	498,752,888

LIABILITIES AND STOCKHOLDERS’ EQUITY

Accounts payable	$	5,244,203	$	—		$	5,244,203
Accrued expenses		440,570		278,227			718,797
Derivative liability		14,523,830		(531,412)			13,992,418
Unearned revenue		41,442		—			41,442
Deferred income tax liability		184,367,963		(707,372	)		183,670,590
Asset retirement liability		16,301,020		(39,9Z62	)		16,261,058
Notes payable		3,104,744		(2,219,323	)		885,421
Total Liabilities		224,023,772		(3,219,842)			220,813,929

STOCKHOLDERS’ EQUITY
Common stock		3,339		—			3,339
Additional paid-in capital		28,733,128		756,947			29,490,075
Retained earnings		245,555,295		2,900,249			248,445,545
Total Stockholders’ Equity		274,291,762		3,657,196			277,938,959

TOTAL LIAB. AND STOCKHOLDERS’ EQUITY	$	498,315,534	$	437,354		$	498,752,888

F-26

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

The following is a summary presentation of corrections made to the Company’s unaudited consolidated statement of operations for the three month period ended July 31, 2010, previously filed on Form 10-Q for the quarter ended July 31, 2010:


	For the Three Months Ended July 31, 2010 As Reported			Corrections			For the Three Months Ended July 31, 2010 As Restated
REVENUES
Oil and gas revenue	$	4,791,179		$	(824,746	)	$	3,966,433
Other revenue		409,068			—			409,068
Total Revenue		5,200,247			(824,746	)		4,375,501

COSTS AND EXPENSES
Cost of oil and gas revenue		2,304,107			(579,194	)		1,724,913
Cost of other revenue		495,747			(245,552	)		250,195
General and administrative		3,769,415			(458,978	)		3,310,437
Depreciation, depletion and amortization		3,736,177			(757,821	)		2,978,356
Total Costs and Expenses		10,305,446			(2,041,545	)		8,263,901

LOSS FROM OPERATIONS		(5,105,199	)		1,216,799		$	(3,888,400	)

OTHER INCOME(EXPENSE)
Interest income		4,553			—			4,533
Interest expense		(219,338	)		—			(219,338	)
Gain (loss) on derivative instruments		2,905,957			(1,100	)		2,904,857

Other, net		77,800			638,448			716,328
Total		2,613,292			639,548			1,973,724

INCOME (LOSS) BEFORE INCOME TAXES		(2,491,907	)		1,856,347			(1,914,676	)
INCOME TAX BENEFIT (EXPENSE)		(69,791	)		835,611			765,820
NET LOSS	$	(2,561,718	)	$	1,412,862		$	1,148,856
LOSS PER SHARE
Basic	$	(0.08	)				$	0.03
Diluted	$	(0.08	)				$	0.03

WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		32,835,722						32,835,722
Diluted		32,835,722						32,835,722

F-27

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

The following is a summary presentation of corrections made to the Company’s unaudited consolidated balance sheet as of October 31, 2010, previously filed on Form 10-Q for the quarter ended October 31, 2010:


	October 31, 2010 As Reported		Corrections			October 31, 2010 As Restated
ASSETS

CURRENT ASSETS
Cash	$	986,547	$	243,793		$	1,230,340
Cash, restricted		126,697		—			126,697
Accounts receivable, net		1,726,215		—			1,726,215
State production tax credits receivable		2,167,044		—			2,167,044
Inventory		627,746		—			627,746
Prepaid expenses		1,487,444		415,510			1,902,954
Total Current Assets		7,121,693		659,303			7,780,996

Net oil and gas properties		481,630,866		(257,899	)		481,372,967
Net equipment		7,087,429		73,688			7,161,117
Land		526,500		—			526,500
Cash – restricted long-term		2,314,517		—			2,314,517
Other assets		476,050		(302,916	)		173,134
Total		492,035,362		(172,176	)		491,548,235

TOTAL ASSETS	$	499,157,055	$	172,176		$	499,329,231

LIABILITIES AND STOCKHOLDERS’ EQUITY

LIABILITIES
Accounts payable	$	8,604,077	$	—		$	8,604,077
Accrued expenses		399,517		278,227			677,744
Derivative liability		13,741,892		(271,928	)		13,469,964
Unearned revenue		108,473		—			108,473
Deferred income tax liability		184,468,878		(3,421,479	)		181,047,399
Asset retirement liability		16,544,505		(39,962	)		16,504,543
Notes payable		2,284,871		(2,284,871	)		—
Total		226,152,213		(5,750,012	)		220,402,201

STOCKHOLDERS’ EQUITY
Common stock		3,617		—			3,617
Additional paid-in capital		30,939,449		3,614,577			34,554,026
Retained earnings		242,061,776		2,297,612			244,369,388
Total		273,004,842		5,922,188			278,927,030

TOTAL LIAB. AND STOCKHOLDERS’ EQUITY	$	499,157,055	$	172,176		$	499,329,231

F-28

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

The following is a summary presentation of corrections made to the Company’s unaudited consolidated statement of operations for the three month period ended October 31, 2010, previously filed on Form 10-Q for the quarter ended October 31, 2010:


	For the Three Months Ended Oct. 31, 2010 As Reported			Corrections			For the Three Months Ended Oct. 31, 2010 As Restated
REVENUES
Oil and gas revenue	$	6,081,793		$	(1,036,987	)	$	5,044,806
Other revenue		593,869			—			593,869
Total		6,675,662			(1,036,987	)		5,638,675

COSTS AND EXPENSES
Cost of oil and gas revenue		3,611,582			(893,150	)		2,718,432
Cost of other revenue		341,408			(143,837	)		197,571
General and administrative		3,078,951			791,779			3,870,730
Depreciation, depletion and amortization		3,517,056			(18,125	)		3,498,931
Total		10,548,997			(263,333	)		10,285,664

LOSS FROM OPERATIONS		(3,873,335	)		(625,912	)		(4,499,247	)

OTHER INCOME (EXPENSE)
Interest income		1,174			—			1,174
Interest expense		(410,422	)		—			(410,422	)
Gain on derivatives		781,938			(2,543,090	)		(1,761,152	)
Other, net		7,125			—			7,125

Total		379,815			(2,543,090	)		(2,163,275	)

LOSS BEFORE INCOME TAXES		(3,493,520	)		(3,169,002	)		(6,662,522	)
INCOME TAX BENEFIT (EXPENSE)		—			2,724,106			2,724,106
NET LOSS	$	(3,493,520	)	$	(592,638	)	$	(4,086,158	)

LOSS PER SHARE
Basic	$	(0.10	)				$	(0.12	)
Diluted	$	(0.10	)				$	(0.12	)

WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		34,314,794						34,314,794
Diluted		34,314,794						34,314,794

F-29

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

The following is a summary presentation of corrections made to the Company’s unaudited consolidated balance sheet as of January 31, 2011, previously filed on Form 10-Q for the quarter ended January 31, 2011:


	January 31, 2011 As Reported		Corrections			January 31, 2011 As Restated
ASSETS

CURRENT ASSETS
Cash	$	3,158,946	$	243,793		$	3,402,739
Cash, restricted		290,531		—			290,531
Accounts receivable, net		1,487,669		—			1,487,669
State production tax credits receivable		5,417,126		—			5,417,126
Inventory		528,573		—			528,573
Prepaid expenses		1,926,357		132,207			2,058,564
Total		12,809,202		376,000			13,185,202

Net oil and gas properties		480,387,148		(287,058	)		480,100,090
Net equipment		8,016,302		105,719			8,122,021
Land		526,500		—			526,500
Cash – restricted long-term		2,299,538		—			2,299,538
Other assets		289,009		(289,009	)		—
Total		491,518,497		(470,348	)		491,048,149

TOTAL ASSETS	$	504,327,699	$	(94,348	)	$	504,233,351

LIABILITIES AND STOCKHOLDERS’ EQUITY

LIABILITIES
Accounts payable	$	9,183,616	$	—		$	9,183,616
Accrued expenses		766,507		278,227			1,044,734
Derivative liability		1,261,291		1,960,274			3,221,565
Unearned revenue		41,443		—			41,443
Deferred income tax liability		184,468,878		(3,479,592	)		180,989,236
Asset retirement liability		16,913,376		(39,962	)		16,873,414
Notes payable		4,850,419		(2,350,419	)		2,500,000
Total		217,485,530		(3,641,471	)		204,660,443

STOCKHOLDERS’ EQUITY
Common stock		3,941		—			3,941
Additional paid-in capital		43,866,501		2,236,633			46,103,134
Retained earnings		242,971,727		1,300,491			244,282,218
Total		286,842,169		3,547,123			290,389,292

TOTAL LIAB. AND STOCKHOLDERS’ EQUITY	$	504,327,699	$	(94,348	)	$	504,233,351

F-30

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

The following is a summary presentation of corrections made to the Company’s unaudited consolidated statement of operations for the three month period ended January 31, 2011, previously filed on Form 10-Q for the quarter ended January 31, 2011:


	For the Three Months Ended Jan. 31, 2011 As Reported			Corrections			For the Three Months Ended Jan. 31, 2011 As Restated
REVENUES
Oil and gas revenue	$	7,039,457		$	(1,429,499	)	$	5,609,958
Other revenue		775,664			—			775,664
Total Revenue		7,815,121			(1,429,499	)		6,385,622

COSTS AND EXPENSES
Cost of oil and gas revenue		2,994,888			(1,163,822	)		1,831,066
Cost of other revenue		691,504			(265,677	)		425,827
General and administrative		1,204,116			549,135			1,753,251
Depreciation, depletion and amortization		3,357,654			(2,872	)		3,354,782
Total Costs and Expenses		8,248,162			(883,236	)		7,364,926

LOSS FROM OPERATIONS		(433,041	)		(546,263	)		(979,304	)

OTHER INCOME (EXPENSE)
Interest income		9,253			—			9,253
Interest expense		(111,162	)		—			(111,162	)
Gain on derivatives		1,444,900			(508,971	)		935,929
Total		1,342,991			(508,971	)		834,020

LOSS BEFORE INCOME TAXES		909,950			(1,055,234	)		(145,284	)
INCOME TAX BENEFIT (EXPENSE)		—			58,113			58,113
NET INCOME (LOSS)	$	909,950		$	(997,121	)	$	87,171

INCOME (LOSS) PER SHARE
Basic	$	0.03					$	(0.00	)
Diluted	$	0.03					$	(0.00	)

WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		34,314,794						34,314,794
Diluted		34,314,794						34,314,794

F-31

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

(17)

SUBSEQUENT EVENTS

On June 13, 2011, the Company entered into a loan agreement (the “Loan Agreement”) with Guggenheim Corporate Funding, LLC (“Guggenheim”), as Administrative Agent, Arranger and Lender and Citibank, N.A. and Bristol Investment Fund as Lenders. The loan agreement provides for a credit facility of up to $100 million (the “Credit Facility”) with an initial borrowing base of $35 million. The Credit Facility matures on June 13, 2013 and is secured by substantially all the assets of the Company and its subsidiaries. Amounts outstanding under the credit facility bear interest at a rate per annum equal to the higher of 9.5% or the prime rate plus 4.5%. In addition, the Company is required to pay an additional make-whole payment upon termination or payment in full of the Credit Facility, bringing the effective interest rate to 25% to 35%, depending on the payment date. Beginning on January 1, 2012, or earlier under certain circumstances, the Company is required to use 90% of its consolidated monthly net revenues (after deducting general and administrative expenses to the extent permitted under the Loan Agreement) to repay the loans outstanding under the Credit Facility. Proceeds of certain asset sales and indebtedness and other proceeds received outside the ordinary course of business are required to be used to repay loans outstanding under the Credit Facility.

Draws under the Credit Facility are subject to the discretion of the Agent and the Lenders. The borrowing base is redetermined on a scheduled basis twice per year, and more often at the request of the Borrower or the required lenders. The redetermination of the borrowing base is at the discretion of the lenders. The Loan Agreement contains interest coverage, asset coverage and minimum gross production covenants, as well as other affirmative and negative covenants. In connection with the Loan Agreement, the Company has granted Guggenheim a right of first refusal to provide financing for the acquisition, development, exploration or operation of any oil and gas related properties including wells during the term of the Credit Facility and one year thereafter.

Upon an event of default under the Loan Agreement, all amounts outstanding become immediately due and payable, the Lenders may stop making advances under the Credit Facility and may terminate the agreement. An “event of default” includes, among other things, our failure to pay any amounts when due, our failure to perform under or observe any term, covenant or provision of the Loan Agreement, the occurrence of a Material Adverse Change (as that term is defined in the Loan Agreement), the seizure of or levy upon our assets or properties, our insolvency or bankruptcy, judgments against us in excess of certain amounts, defaults under certain other agreements, the limitation or termination of the any of the guarantors, which include Miller and all of our subsidiaries, under the Guarantee and Collateral Agreement described below, the death or incapacitation of either Mr. Scott Boruff or Mr. David Hall, or if either of them cease to be substantially involved in our operations or the breach or termination of the Shareholders Agreement described below.

On the closing date of the Loan Agreement, we paid the Administrative Agent, ratably for the benefit of the Lenders a non-refundable facility fee of $700,000. We also agreed to pay a non-refundable fee of 2% on increase in the borrowing base from the borrowing base limit then in effect. At closing we paid the Administrative Agent a non-refundable fee of $30,000 and agreed to pay annual additional fees in this amount so long as the Loan Agreement remains in effect. A finder’s fee of 3% of the initial borrowing base of $35 million to Bristol Capital, LLC, a consultant to us and an affiliate of Bristol Investment Fund, Ltd., was also due.

In connection with the Loan Agreement, the Company also entered into a certain Shareholders’ Agreement (the “Shareholders’ Agreement”), dated June 13, 2011, with Scott M. Boruff, Paul W. Boyd, David Hall, Deloy Miller and David Voyticky (the “Shareholders”). The Shareholders’ Agreement provides that the Shareholders may not transfer their shares of common stock of the Company while the loans under the Credit Facility are outstanding, subject to certain exceptions for Messrs. Deloy Miller and Paul W. Boyd. Specifically, Mr. Miller is permitted to transfer a number of shares of our common stock beneficially owned by him which does not exceed the lesser of (a) 2,500,000 shares of common stock, and (b) a number of shares necessary for him to receive net proceeds equal to $10 million, provided that simultaneous with such transfer the Company receives net proceeds from a new issuance of its securities equal to two times the net proceeds received by Mr. Miller and Mr. Miller transfers the shares at the same price and for the same consideration as received by the Company from such new issuance. Mr. Boyd is permitted to exercise outstanding options to purchase 250,000 shares of the Company’s common stock which expire in September 2011 and to transfer the shares of common stock obtained upon such exercise. There are no permitted exceptions for the transfer of shares by either Messrs. Boruff, Hall or Voyticky.

F-32

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

The Company expects to use the proceeds of the loans made under the Credit Facility to increase oil production both onshore and offshore in Alaska through the drilling of new wells and the reworking of previously producing oil wells and for the purchase of a new drilling rig. The first draws, totaling $10,874,612, have been used to pay fees associated with the transaction, such as attorney’s fees, to pay off our line of credit with PlainsCapital Bank, to make the first progress payment under the rig contract, and for working capital.

(18)

Fair Value of Financial Instruments

The accounting guidance establishes a fair value hierarchy based on whether the market participant assumptions used in determining fair value are obtained from independent sources (observable inputs) or reflect the Company's own assumptions of market participant valuation (unobservable inputs). A financial instrument's categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The accounting guidance establishes three levels of inputs that may be used to measure fair value:

Level 1—Quoted prices in active markets that are unadjusted and accessible at the measurement date for identical, unrestricted assets or liabilities;

Level 2—Quoted prices for identical assets and liabilities in markets that are inactive; quoted prices for similar assets and liabilities in active markets or financial instruments for which significant inputs are observable, either directly or indirectly; or

Level 3—Prices or valuations that require inputs that are both unobservable and significant to the fair value measurement.

The Company considers an active market to be one in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis, and views an inactive market as one in which there are few transactions for the asset or liability, the prices are not current, or price quotations vary substantially either over time or among market makers. Where appropriate the Company's or the counterparty's non-performance risk is considered in determining the fair values of liabilities and assets, respectively.

F-33

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

The fair value of our financial instruments at April 30, 2011 and 2010 follows:


	Fair Value Measurements at Reporting Date Using
Description	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivative securities –
April 30, 2010	$	—	$	—	$	16,897,275

Warrant derivatives	$	—	$	16,897,275	$	—
Commodity derivatives		—		—		—
April 30, 2010	$	—	$	16,897,275	$	—

Warrant derivatives	$	—	$	2,732,659	$	—
Commodity derivatives		—		2,305,118		—
April 30, 2001	$	—	$	5,037,777	$	—

Derivative securities –
April 30, 2011	$	—	$	2,732,659	$	2,305,118

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

We are an independent exploration and production company that utilizes seismic data and other technologies for geophysical exploration and development of oil and gas wells in the Appalachian region of eastern Tennessee and the Cook Inlet Basin in south-central Alaska. The Company follows the successful efforts method of accounting for oil and gas properties. Exploration costs such as exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Acquisition costs and costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are charged to exploration expense. Acquisition costs of unproved properties are assessed for impairment during the holding period and transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment, based on the Company’s current exploration plans, and a valuation allowance is provided if impairment is indicated. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis (thereby establishing a valuation allowance) over the average terms of the leases, at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged against the valuation allowance, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration expense.

F-34

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

The following tables show our capital and operational costs for fiscal years 2011 and 2010:

a. Capitalized Costs Relating to Oil and Gas Producing Activities at April 30, 2011 and 2010 are as follows:


	2011		2010
Natural gas and oil properties:
Proved properties	$	344,249,686	$	225,128,384
Unproved properties		153,443,617		154,244,658
		497,693,303		379,373,042
Accumulated depletion		(15,119,811)		(3,156,421	)
Net capitalized costs	$	482,573,493	$	376,216,621

b. Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities:


	2011		2010
Property Acquisition Costs
Proved properties	$	—	$	216,559,484
Unproved properties		—		154,244,658
Acquisition Costs		—		370,804,142
Exploration costs		129,382		—
Development costs		9,624,701		5,822,391
Total	$	9,454,083	$	376,626,533

c. Results of Operations for Producing Activities:


	2011		2010
Production revenues	$	20,525,117	$	4,437,215
Oil and gas operating costs		(9,573,166)		(96,240	)
Depreciation and amortization		(13,105,586)		(1,741,150	)
Results of operations for producing activities (excluding corporate overhead and interest costs)	$	(2,153,635)	$	2,599,825

F-35

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

d. Reserve Quantity Information (Unaudited)

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


	Oil (Bbls)		Gas (Mcf)
Proved reserves
Balance, April 30, 2009	53,443		1,863,537
Discoveries and extensions	—		—
Revisions of previous estimates	89,516		(912,402	)
Acquisitions	10,288,075		4,831,879
Production	(86,611	)	(324,298	)
Balance, April 30, 2010	10,344,423		5,458,716
Discoveries and extensions	—		1,309,700
Revisions of previous estimates	(160,422	)	(3,370,671	)
Acquisitions	—		—
Production	(86,611	)	(324,298	)
Balance, April 30, 2011	10,097,390		3,072,817

Proved developed producing reserves at April 30, 2011	1,684,990		1,150,017
Proved developed producing reserves at April 30, 2010	1,803,272		1,704,552

Acquisitions, as noted above, were comprised of several entities. ("KTO") which includes approximately 35,325 leased acres located on the Chattanooga Shale and 153 natural gas and oil producing wells. On June 18, 2009 the Company 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. The acquisition included 221 producing oil and gas wells and consisted of approximately 4,442 acres. On December 10, 2009, the Company acquired 100% of the membership interests in Cook Inlet Energy, LLC, an Alaska limited liability company from the owners of this entity and simultaneously acquired former Alaskan operations of Pacific Energy Resources ("Pacific Energy") valued at more than $479 million through a Delaware Chapter 11 Bankruptcy proceeding. The Company acquired the Alaskan 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 include 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 purchase are 602,000 acres of oil and gas leases, which includes 471,474 acres under the Susitna Basin Exploration License

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 Lee Keeling and Associates, Inc. for the years ended April 30, 2011 and April 30, 2010 for all of the Tennessee reserves and by Ralph E. Davis Associates, Inc. for the years ended April 30, 2011 and April 30, 2010 for all of the Alaska reserves.

F-36

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

With the closing of these acquisitions, our management is now able to focus the majority of its efforts on growing our company. We are continuing to focus our short-term efforts on three distinct areas, including:

Increase our overall oil and gas production through maintenance and repairs of nonperforming or underperforming wells,

Organically growing production through drilling for our own benefit on existing leases and under license rights, leveraging our 100,000 plus well log database and over 660,000 acres which are either under lease or part of the Susitna Basin Exploration License, with a view towards retaining the majority of working interest in the new wells, and

Expanding our contract drilling and service capabilities and revenues, including drilling and service contracts with third parties.

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, 2011 and 2010. Estimated future cash flows were based on independent reserves evaluation from Lee Keeling and Associates, Inc. for the years ended April 30, 2011 and April 30, 2010 for all Tennessee reserves and by Ralph E. Davis Associates, Inc. for the years ended April 30, 2011 and April 30, 2010 for all of the Alaska reserves. Because the standardized measure of future net cash flows was prepared using the prevailing economic conditions existing at April 30, 2011 and 2010, 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.

Each of the engineering reports also projected future cash flows from our net reserves and the present value, discounted at 10% per annum. Future cash flows are 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.

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

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

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

F-37

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED APRIL 30, 2011 AND 2010

Standardized measures of discounted future net cash flows at April 30, 2011 and 2010 are as follows:


	2011			2010
Future cash flows	$	732,001,880		$	662,317,776
Future production costs and taxes		(126,059,693	)		(123,537,182	)
Future development costs		(93,248,900	)		(50,232,400	)
Future income tax expense		(144,363,683	)		(132,463,555	)
Future cash flows		368,329,604			356,084,639
Discount at 10% for timing of cash flows		(124,236,521	)		(126,410,047	)
Discounted future net cash flows from proved reserves	$	244,093,083		$	229,674,592

Of the Company's total proved reserves as of April 30, 2011 and 2010, approximately 18% and 18%, respectively, were classified as proved developed producing, 10% and 8%, respectively, were classified as proved developed non-producing and 72% and 74%, 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, 2011 and 2010.


	April 30,
	2011			2010
Balance, beginning of year	$	229,674,592		$	1,534,809
Sales, Net of production costs and taxes		(10,822,569	)		(4,340,975	)
Changes in prices and production costs		75,590,109			(16,027,414	)
Extensions, discoveries and improved recovery, less related costs		4,591,800			—
Purchase of reserves in place		—			366,479,122
Changes in estimated future development costs		(42,398,062	)		66,269,898
Development costs incurred		9,624,701			(50,232,400	)
Revisions of previous quantity estimates		(19,034,046	)		—
Net changes in income taxes		41,540,875			(134,008,448	)
Sales of reserves in place		(1,470,797	)		—
Accretion of discount		36,213,815			—
Changes in timing and other		(79,417,335	)		—
	$	244,093,083		$	229,674,592

F-38