Edgar Filing: MILLER ENERGY RESOURCES, INC.

mill_10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended October 31, 2011

o TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _________________ to _________________

Commission file number: 001-34732

Miller Energy Resources, Inc.

(Name of registrant as specified in its charter)

Tennessee		62-1028629
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

9721 Cogdill Road, Suite 302, Knoxville, TN		37932
(Address of principal executive offices)		(Zip Code)

(865) 223-6575

(Registrant's telephone number, including area code)

3651 Baker Highway, Huntsville, tn 37756

(Former name, former address and former fiscal year, if changed since last report)

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.

Yes o No þ

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 (§232.405 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 þ Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer	o	Accelerated filer	þ
Non-accelerated filer	o	Smaller reporting company	o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)

Yes o No þ

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. 40,911,751 shares of common stock are issued and outstanding as of November 30, 2011.

TABLE OF CONTENTS

		Page
PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited):		1

	Consolidated Balance Sheets as of October 31, 2011 and April 30, 2011		1

	Consolidated Statements of Operations for the Three and Six Months Ended October 31, 2011 and 2010		2

	Consolidated Statements of Cash Flows for the Six Months Ended October 31, 2011 and 2010		3

	Notes to Consolidated Financial Statements		4

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		22

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		36

Item 4.	Controls and Procedures		37

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings		39

Item 1A.	Risk Factors		39

Item 6.	Exhibits		39

SIGNATURES			43

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

MILLER ENERGY RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	October 31, 2011			April 30, 2011

ASSETS

Current Assets
Cash and cash equivalents	$	2,543,429		$	1,558,933
Restricted cash		264,826			202,980
Accounts receivable
Related parties		27,142			27,822
Customers and other		1,628,403			1,619,720
State production credits receivable		7,457,816			3,620,336
Inventory		1,014,856			1,043,960
Prepaid expenses		201,397			231,724
Derivative asset		810,379			—
Total current assets		13,948,248			8,305,475

Oil and Gas Properties (Successful Efforts Method)
Cost		501,445,094			496,308,182
Less accumulated depletion		(22,145,666	)		(14,439,233	)
Oil and gas properties, net		479,299,428			481,868,949

Equipment
Cost		31,672,769			10,292,514
Less accumulated depreciation and amortization		(2,521,022	)		(2,003,053	)
Equipment, net		29,151,747			8,289,461

Other Long-Term Assets
Land		526,500			526,500
Restricted cash, non-current		9,936,660			10,026,516
Deferred financing costs, net of accumulated amortization		2,318,468			63,907
Other assets		382,308			—
Total other long-term assets		13,163,936			10,616,923
Total Assets	$	535,563,359		$	509,080,808

LIABILITIES AND EQUITY

Current Liabilities
Accounts payable	$	9,790,418		$	7,496,786
Accrued expenses		4,172,065			4,185,087
Derivative liability		—			2,305,118
Borrowings under credit facility		28,894,615			2,000,000
Total current liabilities		42,857,098			15,986,991

Long-term Liabilities
Deferred income taxes		175,492,494			178,326,065
Asset retirement obligation		17,830,428			17,293,718
Non-current portion of derivative liability		1,207,846			2,732,659
Total long-term liabilities		194,530,768			198,352,442
Total Liabilities		237,387,866			214,339,433
Commitments and Contingencies (Note 5, 7, 12 and 14)
Equity
Common stock, par value $0.0001 per share (500,000,000 shares authorized, 40,911,751 and 39,880,251 shares issued as of October 31, 2011 and April 30, 2011, respectively)		4,091			3,988
Additional paid-in capital		57,113,759			49,012,755
Retained earnings		241,057,643			245,724,632
Total Stockholders' Equity		298,175,493			294,741,375
Total Liabilities and Stockholders’ Equity	$	535,563,359		$	509,080,808

The accompanying notes are an integral part of these unaudited consolidated financial statements.

MILLER ENERGY RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	For the Three Months Ended						For the Six Months Ended
	October 31, 2011			October 31, 2010			October 31, 2011			October 31, 2010
				(as restated)						(as restated)
Revenues
Oil and natural gas sales	$	8,440,857		$	5,044,806		$	16,760,220		$	9,011,239
Other revenue		763,905			593,869			1,300,316			1,002,937
Total revenues		9,204,762			5,638,675			18,060,536			10,014,176

Costs and Expenses
Oil and gas operating		4,374,869			2,718,432			8,171,121			4,443,345
Cost of other revenue		145,782			197,571			372,426			447,766
General and administrative		7,948,985			3,870,730			13,721,175			7,181,167
Exploration expense		148,264			—			179,792			—
Depreciation, depletion, amortization and accretion		4,317,869			3,290,415			7,960,109			6,268,771
Other operating expense (income), net		(4,818	)		—			(897,278	)		638,468
Total costs and expenses		16,930,951			10,077,148			29,507,345			18,979,517
Operating Loss		(7,726,189	)		(4,438,473	)		(11,446,809	)		(8,965,341	)

Other Income (Expense)
Interest income		3,835			1,174			5,067			5,727
Interest expense, net of interest capitalized		(883,197	)		(618,938	)		(1,380,559	)		(838,276	)
Gain (loss) on derivatives, net		1,506,189			(1,761,152	)		5,261,845			1,143,705
Other income (expense), net		28,636			7,125			59,894			(70,755	)
Total other income (expense)		655,463			(2,371,791	)		3,946,247			240,401

Loss Before Income Taxes		(7,070,726	)		(6,810,264	)		(7,500,562	)		(8,724,940	)
Income tax benefit		2,586,416			2,724,106			2,833,571			3,489,926
Net Loss	$	(4,484,310	)	$	(4,086,158	)	$	(4,666,991	)	$	(5,235,014	)

Loss per Share:
Basic	$	(0.11	)	$	(0.12	)	$	(0.11	)	$	(0.16	)
Diluted	$	(0.11	)	$	(0.12	)	$	(0.11	)	$	(0.16	)

Average Number of Common Shares Outstanding:
Basic		40,908,490			34,314,794			40,624,050			33,575,258
Diluted		40,908,490			34,314,794			40,624,050			33,575,258

The accompanying notes are an integral part of these unaudited consolidated financial statements.

MILLER ENERGY RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	For the Six Months Ended October 31,
	2011			2010
				(as restated)
Cash Flows from Operating Activities
Net loss	$	(4,666,991	)	$	(5,235,014	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		7,423,399			5,781,800
Amortization of deferred financing fees		544,538			208,516
Loss on equity method investment		17,629			—
Issuance of equity for compensation		5,974,213			3,271,189
Issuance of equity for services		843,894			2,831,758
Deferred income taxes		(2,833,572	)		(3,559,717	)
Unrealized gain on derivative instruments, net		(4,640,310	)		(3,427,311	)
Accretion of asset retirement obligation		536,710			486,971
Changes in operating assets and liabilities:
Receivables, net		(8,003	)		(233,925	)
State production credits receivable		(3,837,480	)		(1,060,043	)
Inventory		29,104			(352,136	)
Prepaid expenses		30,327			(399,200	)
Other assets		—			66,308
Accounts payable, accrued expenses and other		2,280,610			5,004,575
Net cash provided by operating activities		1,694,068			3,383,771

Cash Flows from Investing Activities
Purchase of equipment and improvements		(21,197,327	)		(732,087	)
Capital expenditures for oil and gas properties		(4,518,837	)		(4,666,838	)
Investment in affiliate		(399,934	)		—
Net cash used by investing activities		(26,116,098	)		(5,398,925	)

Cash Flows from Financing Activities
Payments on notes payable		(2,000,000	)		(1,239,401	)
Deferred financing costs		(2,799,099	)		—
Proceeds from borrowings		28,894,615			—
Exercise of equity rights		1,283,000			1,732,939
Restricted cash		28,010			(242,678	)
Net cash provided by financing activities		25,406,526			250,860
Net Increase (Decrease) in Cash and Cash Equivalents		984,496			(1,764,294	)

Cash and Cash Equivalents at Beginning of Period		1,558,933			2,994,634
Cash and Cash Equivalents at End of Period	$	2,543,429		$	1,230,340

Cash paid for interest	$	679,948		$	327,715

The accompanying notes are an integral part of these unaudited consolidated financial statements.

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(1) Summary of Significant Accounting Policies

General

The accompanying unaudited interim consolidated financial statements of Miller Energy Resources, Inc. (the “Company” or “Miller”) have been prepared in accordance with accounting principles generally accepted in the United States of America and the rules of the Securities and Exchange Commission (“SEC”), and should be read in conjunction with the audited consolidated financial statements and notes thereto contained in the Company’s annual report on Form 10-K, as amended, for the year ended April 30, 2011. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of the financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. Notes to the consolidated financial statements which would substantially duplicate the disclosure contained in the audited consolidated financial statements as reported in the 2011 annual report on Form 10-K, as amended, have been omitted.

Investments

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 total cash consideration of $399,934. 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 $5,139,394. The Pellissippi Pointe entities own two office buildings in West Knoxville, Tennessee. We moved our corporate offices into the building on November 7, 2011. We have executed a five year lease for the space for $7,446 per month, and the building is fully occupied by tenants. As the Company is in a position to exercise significant influence, but not control the financial and operating policy decisions of the investee, we account for these investments using the equity method. These investments are included in our unaudited interim consolidated financial statements in “other assets.”

Reclassifications

Certain reclassifications have been made to the prior period amounts presented to conform to the current period presentation.

(2) Concentrations of Credit Risk

Financial instruments which potentially subject the Company to concentrations of credit risk are primarily cash and cash equivalents, accounts receivable and commodity derivative contracts. 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 oil, natural gas and 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. There were no bad debt expenses for the three and six months ended October 31, 2011 and 2010.

The Company periodically enters into 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 October 31, 2011 and April 30, 2011, we had $12,494,915 and $11,538,429, respectively, in 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 its products in the areas where its properties are located. Tesoro Corporation currently purchases all oil from our Alaska production facilities and accounted for $7,553,667 or 82% and $15,448,796 or 86% of the Company’s total revenue for the three and six months ended October 31, 2011, respectively. Tesoro Corporation also accounted for $940,458 or 58%, and $1,143,667 or 71% of accounts receivable as of October 31, 2011 and April 30, 2011, respectively.

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

(4) Related Party Transactions

The Company had an account receivable from a member of the Board of Directors, and his wife, at October 31, 2011 and April 30, 2011 in the amount of $16,796 and $17,822, respectively, for work performed on oil and gas wells. This board member and his wife own working interests in oil and gas wells in which the Company has an ownership interest and oparates.

The Company uses a number of contract labor companies to provide on demand labor at our Alaska operations. One of these companies, H & H Industrial, Inc., is wholly-owned by the sister and father of David Hall, the CEO of our Alaskan subsidiary and a member of our Board of Directors. For the three and six months ended October 31, 2011, H & H had invoiced us for $206,678.78 and $339,881.08, respectively.

In 2009, we formed both Miller Energy GP, LLC 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. Scott M. 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 income fund and a $25.5 million drilling offering, which included the MEI offering. 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 the six months ended October 31, 2011 and 2010, we paid The Dimirak Companies and their affiliates a total of $36,000 and $41,932, respectively, under the terms of this agreement.

On August 27, 2010, we entered into a consulting arrangement with Matrix Group, LLC (“Matrix”), an entity through which one of our directors at the time, David J. Voyticky, provides consulting services to us, including assisting us in locating strategic investments and business opportunities. In the first quarter of fiscal 2012, and prior to his appointment as our President (and later, Acting Chief Financial Officer), we paid Matrix $70,000 for consulting services rendered under this arrangement, together with a $250,000 bonus for the successful closing of the Credit Facility (as described in Note 7). We also reimbursed Matrix $10,000 of related expenses. Following Mr. Voyticky’s appointment as our President, we have terminated the consulting arrangement.

On July 13, 2011, Cook Inlet Energy, LLC (“CIE”) entered into a consulting agreement with Jexco LLC, an entity owned by Jonathan S. Gross, a member of our Board of Directors. Under the terms of this agreement, Jexco LLC provides advice to us in areas related to seismic processing services with contractors located in Houston. The agreement terminates on December 31, 2011 and can be extended upon the consent of the parties. As compensation for the services, we agreed to pay a flat fee of $15,000 for work performed in the Houston metropolitan area and a fee of $2,500 per day for work performed outside of the Houston metropolitan area. We agreed to reimburse Jexco LLC for out of pocket expenses incurred in rendering the services to us. As of October 31, 2011, Jexco LLC commenced work and billed $5,000 under this agreement.

(5) Equipment

Equipment is summarized as follows:

	October 31, 2011			April 30, 2011
Machinery and equipment	$	26,107,999		$	5,454,923
Vehicles		1,641,043			1,618,322
Aircraft		459,698			453,000
Buildings		3,221,105			2,682,810
Office equipment		242,924			83,459
		31,672,769			10,292,514
Less accumulated depreciation		(2,521,022	)		(2,003,053	)
Total equipment	$	29,151,747		$	8,289,461

On June 12, 2011, MER entered into a contract with Voorhees Equipment and Consulting, Inc. for the construction and purchase of a custom drilling rig to be used on our Osprey offshore platform located in the Cook Inlet of Alaska. The contract sets a total purchase price of $17,927,770. The addition of the rig will greatly enhance our drilling opportunities and capabilities on the Osprey platform. Commonly referred to as Rig 35, the new rig arrived in Alaska during October 2011 and is expected to be assembled and operational in January 2012.

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

(6) 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.

The fair value of our financial instruments at October 31, 2011 and April 30, 2011 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)


Warrant derivatives	$	—	$	(2,732,659	)	$	—
Commodity derivatives		—		(2,305,118	)		—
April 30, 2011	$	—	$	(5,037,777	)	$	—

Warrant derivatives	$	—	$	(1,207,846	)	$	—
Commodity derivatives		—		810,379			—
October 31, 2011	$	—	$	(397,467	)	$	—

The Company participated in fixed price swap commodity derivatives for 300 barrels of oil per day from January 1, 2011 to December 31, 2011 and for 300 barrels of oil per day from May 1, 2011 to April 30, 2012. These instruments are used to manage the inherent uncertainty of future revenues due to oil price 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 the statement of operations. The asset recorded for these instruments as of October 31, 2011 was $810,379 as the price for a barrel of oil was below the average hedging price of $100.19. The liability recorded for these instruments as of April 30, 2011 was $2,305,118 as the price for a barrel of oil was above the average hedging price of $100.19.

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

As of October 31, 2011 and April 30, 2011, the Company had 817,055 warrants with exercise price reset provisions, which are considered freestanding derivative instruments that are required to be recorded at fair value as liabilities each reporting period, as they are not afforded equity treatment.

The non-current portion of the derivative liability related to the 817,055 warrants as of April 30, 2011 and October 31, 2011 was $2,732,659 and $1,207,846, respectively. The warrants expire in March 2015, and accordingly, the fair value of these derivatives are recorded as a non-current liability. The Company utilized the Black-Scholes pricing model with the following weighted average assumptions as of April 30, 2011 and October 31, 2011: risk-free rate of 1.45% and 0.53%, an expected term of 3.91 years and 3.40 years, expected volatility of 77.0% and 91.4% and a dividend rate of 0.0%.

During the three months ended October 31, 2011 and 2010, the Company recorded gains on derivatives, net, as follows:

	October 31, 2011		October 31, 2010
			(as restated)
Warrant derivatives	$	854,986	$	(1,761,152	)
Commodity derivatives		651,203		—
	$	1,506,189	$	(1,761,152	)

During the six months ended October 31, 2011 and 2010, the Company recorded gains on derivatives, net, as follows:

	October 31, 2011		October 31, 2010
			(as restated)
Warrant derivatives	$	1,524,814	$	1,143,705
Commodity derivatives		3,737,031		—
	$	5,261,845	$	1,143,705

At October 31, 2011, the estimated fair value of accounts receivable, prepaid expenses, accounts payables and accrued liabilities approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s short-term debt at October 31, 2011 approximates the respective carrying value because the interest rate approximates the current market rate.

(7) Debt Obligations

Debt obligations consist of the following:

	October 31, 2011			April 30, 2011

$100 million secured line of credit	$	28,894,615		$	—
6% PlainsCapital Bank notes, due July 5, 2011		—			2,000,000
		28,894,615			2,000,000
Less: current maturities		(28,894,615	)		(2,000,000	)
Borrowings, less current portion	$	—		$	—

On December 27, 2010, we obtained a $5,000,000 line of credit from PlainsCapital Bank. 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 on June 16, 2011.

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 is secured by substantially all the assets of the Company and its subsidiaries.

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

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 redevelopment or recompletion of previously producing oil wells and for the purchase of a new drilling rig. The first four draws, totaling $28,894,615, have been used to make progress payments under the rig 35 contract, to pay off our line of credit with PlainsCapital Bank, and to pay fees associated with the transaction, such as attorney’s fees.

Interest related to the Credit Facility is capitalized on construction-in-progress at the weighted average cost of debt outstanding during the period of construction. Capitalized interest was $1,641,145 and $1,950,483 for the three and six months ended October 31, 2011, respectively, as compared to zero for the three and six months ended October 31, 2010, respectively.

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 interest rate to 25% in the event the amounts are paid by June 30, 2012, 30% in the event repayment is made between July 1 and December 31, 2012, and 35% if payment is made on or after January 1, 2013. The Company is recording interest expense, using the effective interest method, assuming an interest rate of 35%.

Although the Loan Agreement does not mature until June 13, 2013, the Company is required to make monthly repayments based on 90% of its consolidated monthly net revenues (after deducting general and administrative expenses to the extent permitted by the Loan Agreement) beginning on October 10, 2011. In addition, proceeds of certain asset sales and indebtedness and other proceeds received outside the ordinary course of business are required to be used to repay amounts outstanding under the Credit Facility. As a result, the Company has classified amounts outstanding under the Loan Agreement as of October 31, 2011 as a current liability in the accompanying consolidated balance sheet.

Draws under the Credit Facility are subject to the discretion of Guggenheim and the other lenders. The borrowing base is redetermined on a scheduled basis twice per year (October 31 and April 30), and more often at the request of the Company or the required lenders. The borrowing base did not change from $35 million at the October 31, 2011 redetermination. 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 includes the Company and all of its subsidiaries, under the Guarantee and Collateral Agreement, 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 Guggenheim, 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 the increase in the borrowing base from the borrowing base limit then in effect. At closing we paid Guggenheim 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. To honor this obligation, we issued 100,000 shares of the Company’s restricted stock to Bristol Capital, LLC and agreed to a cash payment of $750,000. Deferred financing fees, net of accumulated amortization total $2,318,468 and will be amortized into interest expense over the term of the Loan Agreement.

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 J. 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. Miller and 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 and to transfer the shares of common stock obtained upon such exercise. There are no permitted exceptions for the transfer of shares by Messrs. Boruff, Hall or Voyticky.

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

On August 26, 2011, we entered into the First Amendment to Loan Agreement and Limited Waiver (the “Amendment”) with our lenders under the Credit Facility. We were previously required under the terms of the Loan Agreement to deliver audited financial statements for our fiscal year ended April 30, 2011 to the lenders within 75 days of the end of our fiscal year, together with certain additional compliance certificates and reports. We did not deliver the required documents within the timeframes required under the Loan Agreement. Subsequent thereto, upon our satisfaction of certain conditions in the Amendment, including the delivery of our audited financial statements together with certain additional compliance certificates and reports to the lenders, these limited events of default under the Loan Agreement were waived. As described below, the Amendment revises certain timelines in the Loan Agreement with respect to repayment, imposes additional reporting requirements on us, provides for an increase of 2% in the applicable margin in certain circumstances, waives certain events of default, lengthens certain reporting deadlines, and revises the make-whole premium. The Amendment also makes delisting from the New York Stock Exchange an event of default.

Beginning October 10, 2011, we are required to use 90% of our Consolidated Net Revenues (as defined in the Loan Agreement) to pay certain fees and expenses, interest, and finally, the outstanding principal under the loan. Consolidated Net Revenues do not include certain operating costs, such as royalty interests and lease operating costs, and up to $750,000 will be allocated to our general and administrative expenses. Should a default exist, this amount would be 100% of our Consolidated Net Revenues. Should we fail to satisfy certain requirements related to compliance with Section 404 of the Sarbanes-Oxley Act of 2002 by April 30, 2012, our interest rate will increase by 2%.

The deadlines for delivery of our next two quarterly financial statements to the Lenders has been extended to 60 days, and the deadline for delivery of our audited financial statements at our fiscal year end has been extended to 90 days. The make-whole premium has been revised so as not to include the waiver fee of $115,593 payable in connection with the Amendment or any payments of increased interest due to a default.

On October 11, 2011, the Lenders granted us an extension of time to pay certain registration rights penalties incurred by us in connection with the March 26, 2010 private placement and required registration statement related thereto. Under section 6.19(c) of the Loan Agreement, we were required to pay these penalties within 120 days of closing. That date has now been extended to 180 days from the date of the extension.

(8) Asset Retirement Obligation

The following table summarizes the Company’s asset retirement obligation during the six months ended October 31, 2011 and October 31, 2010:

	Six Months Ended October 31, 2011		Six Months Ended October 31, 2010
			(as restated)
Asset retirement obligation, as of April 30	$	17,293,718	$	16,017,572
Accretion expense		536,710		486,971

Asset retirement obligation, as of October 31	$	17,830,428	$	16,504,543

(9) Equity

During the six months ended October 31, 2011, we issued 1,031,500 shares as follows: 869,000 shares from the exercise of equity rights, 100,000 shares to a consultant as part of a finder’s fee for the Guggenheim Loan Agreement and 62,500 shares to an employee as part of an employment agreement.

During the six months ended October 31, 2010, we issued shares to four warrant holders who exercised warrants for 177,600 shares in a cashless exercise of 142,286 shares and five other warrant holders who exercised an equal number of warrants for 151,750 shares for an exercise price of $1.00. In addition, fifteen note holders were issued 3,099,999 shares upon conversion of $1,705,000 of their 6% secured convertible notes at a conversion rate of $0.55 per share. We also issued 30,000 shares to an advisor to the Board for services rendered. And on October 29, 2010, we entered into a settlement agreement with Petro Capital III, LP and Petro Capital Advisors, LLC 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 Capital III, LP and Petro Capital Advisors, LLC.

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

(10) Share-Based Compensation

The Company’s equity compensation plans (collectively, the “Plans”) enables the Company to offer its employees, officers, directors and consultants an opportunity to acquire a proprietary interest in the Company, and to enable the Company to attract, retain, motivate and reward such persons in order to promote the success of the Company. The 2010 and 2011 Plans, respectively, authorized 3,000,000 and 8,250,000 shares of common stock. The Plan allows for the issuance of incentive stock options, nonqualified stock options and restricted stock. Stock options may not be granted with an exercise price less than the fair market value on the grant date. For stockholders that own more than 10% of the Company’s common stock, incentive stock options granted must have an exercise price that is at least 10% higher than the fair market value on the grant date. Stock options granted under the Plan have a term of 10 years except for incentive stock options granted to stockholders that own more than 10% of the Company’s common stock. Such options have a term of 5 years. Vesting provisions are determined by the Compensation Committee of the Board of Directors (the “Compensation Committee”). All awards issued under the Plan must be approved by the Compensation Committee. At April 30, 2011 and October 31, 2011, there were 5,400,000 and 1,615,000 additional shares available for the Company to grant under the 2011 Plan.

The Company recorded $3,476,277 and $5,974,213 of employee non-cash compensation expense related to stock options and vested restricted stock for the three and six month periods ended October 31, 2011 and $845,506 and $1,690,040 related to the three and six month periods ended October 31, 2010, respectively. Employee share-based non-cash compensation expense is included in our consolidated statement of operations in “general and administrative” which is the same financial statement caption where we recognize cash compensation paid to these employees.

The Company also recorded $280,627 and $498,894 of non-employee non-cash equity related expense for services related to warrants for the three and six month periods ended October 31, 2011 and zero and $443,669 related to the three and six month periods ended October 31, 2010, respectively. These expenses are included in our consolidated statement of operations in “general and administrative” and are recognized over the requisite service period.

A summary of the stock options and warrants as of October 31, 2011 and 2010 and changes during the periods is presented below:

	Six Months Ended October 31, 2011					Six Months Ended October 31, 2010 (as restated)
	Number of Options and Warrants			Weighted Average Exercise Price		Number of Options and Warrants			Weighted Average Exercise Price
Balance at April 30		11,079,955		$	3.98		12,306,305		$	1.50
Granted		4,085,000			5.48		425,000			5.22
Exercised		(869,000	)		1.48		(750,986	)		0.44
Expired		—			—		—			—
Cancelled		(50,000	)		5.94		(135,314	)		4.78
Balance at October 31		14,245,955			4.56		11,845,005			2.58

Options exercisable at October 31		5,746,790		$	2.90		6,370,005		$	1.61

The following table summarizes stock options and warrants outstanding and exercisable as of October 31, 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 $1.82		2,293,900		2.9	$	0.74		2,231,400	$	0.75
$	2.00 to $4.98		1,760,000		4.1		2.71		1,464,999		2.37
$	5.25 to $5.53		3,817,055		4.9		5.34		1,217,055		5.36
$	5.89 to $5.94		3,750,000		8.9		5.92		791,669		5.94
$	6.00 to $6.94		2,625,000		4.2		6.03		41,667		6.62
			14,245,955		5.4		4.56		5,746,790	$	2.90

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

(11) Income Tax

The Company has a significant deferred income tax liability recorded related to the excess of the book carrying value of oil and gas properties over their collective income tax bases. This difference will reverse (through lower tax depletion deductions) over the remaining recoverable life of the properties, resulting in future taxable income in excess of income for financial reporting purposes. As an independent producer of domestic oil and gas, the Company takes advantage of certain elective provisions presently in the Internal Revenue Code allowing for expensing of specified intangible drilling and development costs that are typically capitalized for book purposes. This temporary difference also reverses over the remaining life of the properties. As a result of these elections, the Company presently has a U.S. Federal and state net operating loss carryovers that management expects to be fully utilized against future taxable income resulting solely from the reversal of the temporary differences between the book carrying value of oil and gas properties and their tax bases. The Company is not relying on forecasts of taxable income from other sources in concluding that no valuation allowance is needed against any of its deferred tax assets.

The Company’s provision for income taxes for the previous interim reporting period in Fiscal 2012 was based on an estimate of the Company’s annual effective tax rate for the full fiscal year. The computation of the annual effective tax rate includes a forecast of the Company’s estimated “ordinary” income (loss), which is the Company’s annual income (loss) from operations before tax, excluding unusual or infrequently occurring (or discrete) items. Significant management judgment is required in the projection of ordinary income (loss) in order to determine the estimated annual effective tax rate. The low absolute levels of income (or loss) projected for Fiscal 2012 cause an unusual relationship between income (loss) and income tax expense (benefit), with small changes possibly resulting in: (i) a possible significant impact on the rate and, (ii) potentially unreliable estimates. As a result, the Company computed the provision for income taxes for the quarter and year-to-date ended October 31, 2011 by applying the actual effective tax rate to the year-to-date loss, as permitted by accounting principles generally accepted in the United States of America. The effective tax rate for the year-to-date period ended October 31, 2011 was a benefit of 37.8%. No cash payments of income taxes were made during the year-to-date period ended October 31, 2011, and no such payments are expected during the succeeding 12 months.

(12) Commitments and Contingencies

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. In the event that we successfully complete a 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.

On November 5, 2009, CIE entered into an Assignment Oversight Agreement with the Alaska Department of Natural Resources (“DNR”) which establishes certain terms under which the Alaska DNR would approve the assignment of certain specified state oil and gas leases from Pacific Energy Resources to CIE. This agreement remains in place following our acquisition of CIE in December 2009. Generally, the agreement requires CIE to provide the Alaska DNR with additional information and oversight authority to ensure that CIE 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 CIE has completed its development and operation obligations under the assigned leases, CIE agreed to the following:

file a monthly summary of expenditures by oil and gas filed, tied to objectives in CIE’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 CIE 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.

The agreement required CIE 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 CIE’s plan of development. The funds are to be used for workover and repair of the wells, repair of the physical infrastructure, and 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 CIE 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 drilling rights. 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.

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

CIE 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 CIE fail to submit the information required under the agreement and expenditure of funds for items or activities that 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 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 $18,000,000 for the bond. The Agreement includes a funding schedule, which requires payments annually on July 1, beginning in 2013, of amounts ranging from $1,000,000 to $2,500,000 per year, and totaling $12,000,000. The Agreement also clarifies that approximately $6,900,000 (as of October 31, 2011) from a bond funded by the previous owner and held in a State 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 (which currently holds the $6.9 million) 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.

The Agreement confirms that the obligation to post a performance bond for the Onshore Assets (as that term is defined in the Assignment Oversight Agreement) has been eliminated, and this Agreement supersedes the Assignment Oversight Agreement’s requirements to post a performance bond under the Assignment Oversight Agreement for the Offshore Assets (as that term is defined in the Assignment Oversight Agreement).

The amount of the performance bond is subject to adjustment if a material change in the assets occurs, for annual inflation, and upon the completion of certain performance obligations. CIE will be in default of the Agreement if it fails to comply with a material obligation under the Agreement or if it becomes insolvent. Certain conditions that would entitle Alaska DNR to declare CIE in default are subject to a 30 day cure period.

As of October 31, 2011, we have $475,000 in exploration work commitments arising from two exploration licenses of 534,383 acres located in the Susitna River Basin in Alaska. These commitments require the Company to invest in exploration efforts on those leases.

(13) Alaska Production Credits

The Company qualifies for several credits under Alaska statute 43.55.023:

43.55.023(a)(1) Qualified capital expenditure credit on or before June 30, 2010 (20%)

43.55.023(l)(1) Qualified capital expenditure credit after June 30, 2010 (40%)

43.55.023(a)(2) Qualified capital exploration credit on or before June 30, 2010 (20%)

43.55.023(l)(2) Qualified capital exploration credit after June 30, 2010 (40%)

43.55.023(b) Carried-forward annual loss credit (25%)

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

The Company recognizes a receivable when the amount of the credit is reasonably estimable and receipt is probable of occurrence (based on actual qualifying expenditures incurred). For expenditure and exploration based credits, the credit is recorded as a reduction to the related assets. For carried-forward annual loss credits, the credit is recorded as a reduction to the Alaska production tax. To the extent the credit amount exceeds the Alaska production tax, the credit is recorded as a reduction to general and administrative expenses.

As of April 30, 2011 and October 31, 2011, the Company has reduced the basis of capitalized assets by $3,658,354 and $7,563,446 for expenditure and exploration credits. Such reductions are recorded on our consolidated balance sheet in “oil and gas properties.” As of April 30, 2011 and October 31, 2011, the Company had an outstanding receivable balance from Alaska in the amount of $3,620,336 and $7,457,816, respectively.

(14) Litigation

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. Since entry of the temporary injunction, production of oil from the property has resumed. Until this matter is resolved by the court, all proceeds from the new production will be subject to disposition pursuant to further orders of the court. As of this time a trial date has not yet been assigned.

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 (“CNX”) 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 August 4, 2011, a breach of contract case was filed against us in the United States District Court for the Eastern District of Tennessee. The case, styled CNX Gas Company, LLC v. Miller Energy Resources, Inc., Chevron Appalachia, LLC as successor in interest to Atlas America, LLC Cresta Capital Strategies, LLC and Scott Boruff, arises from the same allegations as the previous action filed in state court and voluntarily dismissed on July 28, 2011. The federal case seeks money damages from us for breach of contract; however, unlike the previous action, it does not seek specific performance of the assignments at issue. The Plaintiff claims that the other defendants tortuously interfered with, or induced the breach of, the letter of intent between us and the Plaintiff. We have filed our Answer and intend to vigorously defend this suit.

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. 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 have filed our Answer and are presently conducting discovery.

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: (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 filed a Motion to Dismiss for lack of personal jurisdiction, which is pending while limited discovery is conducted.

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

Class Action Lawsuits

In August 2011, five class action lawsuits were filed against us in the United States District Court for the Eastern District of Tennessee. These lawsuits make similar claims, and we expect that they will be consolidated into one case. We have retained DLA Piper to defend us in these actions. Three motions for consolidation and appointment of a lead plaintiff have been filed, but have not been heard yet. Pursuant to stipulation, no response to the complaint is required until after a lead plaintiff is appointed and a consolidated complaint is filed. Descriptions of the individual cases follow.

On August 12, 2011, a lawsuit was filed against us in the United States District Court for the Eastern District of Tennessee. The case, styled Ruben Husu, Individually and on behalf of all others similarly situated v. Miller Energy Resources, Inc. f/k/a Miller Petroleum, Inc., Scott M. Boruff, and Paul W. Boyd was filed on August 12, 2011. The Plaintiff alleges two causes of action against the Defendants: (1) violation of Section 10(b) and Rule 10b-5 of the Exchange Act, (2) violation of Section 20(a) of the Exchange Act. The case seeks money damages against the Company and the other defendants, and payment of the Plaintiffs’ attorney’s fees.

On August 16, 2011, a lawsuit was filed against us in the United States District Court for the Eastern District of Tennessee. The case, styled James D. DiCenso, Individually and on behalf of all others similarly situated v. Miller Energy Resources, Inc. f/k/a Miller Petroleum, Inc., Deloy Miller, Scott M. Boruff, and Paul W. Boyd and David J. Voyticky. The Plaintiff alleges two causes of action against the Defendants: (1) violation of Section 10(b) and Rule 10b-5 of the Exchange Act, (2) violation of Section 20(a) of the Exchange Act. The case seeks money damages against the Company and the other defendants, and payment of the Plaintiffs’ attorney’s fees.

On August 16, 2011, a lawsuit was filed in the United States District Court for the Eastern District of Tennessee. The case is styled Steven Arlow, Individually and on behalf of all others similarly situated v. Miller Energy Resources, Inc. f/k/a Miller Petroleum, Inc., Scott M. Boruff, and Paul W. Boyd. The Plaintiff alleges two causes of action against the Defendants: (1) violation of Section 10(b) and Rule 10b-5 of the Exchange Act, (2) violation of Section 20(a) of the Exchange Act. The cases seek unspecified money damages against the Company and the other defendants, and payment of the Plaintiffs’ attorney’s fees.

On August 18, 2011, a lawsuit was filed against us in the United States District Court for the Eastern District of Tennessee. The case is styled Yingtao Liu, Individually and on behalf of all others similarly situated v. Miller Energy Resources, Inc. f/k/a Miller Petroleum, Inc., Scott M. Boruff, Paul W. Boyd, Deloy Miller, David J. Voyticky, Herman Gettelfinger, Jonathan S. Gross, David M. Hall, Merrill A. McPeak, Charles Stivers, and Don A. Turkleson. The Plaintiff alleges two causes of action against the Defendants: (1) violation of Section 10(b) and Rule 10b-5 of the Exchange Act, (2) violation of Section 20(a) of the Exchange Act. The case seeks unspecified money damages against the Company and the other defendants, and payment of the Plaintiffs’ attorney’s fees.

On August 19, 2011, a lawsuit was filed in the United States District Court for the Eastern District of Tennessee. The case is styled Brandon W. Ward, Individually and on behalf of all others similarly situated v. Miller Energy Resources, Inc. f/k/a Miller Petroleum, Inc., Scott M. Boruff, and Paul W. Boyd. The Plaintiff alleges two causes of action against the Defendants: (1) violation of Section 10(b) and Rule 10b-5 of the Exchange Act, (2) violation of Section 20(a) of the Exchange Act. The cases seek unspecified money damages against the Company and the other defendants, and payment of the Plaintiffs’ attorney’s fees.

Shareholder Derivative Lawsuits

In August 2011, three shareholder derivative actions were filed against us. Two were filed in the United States District Court for the Eastern District of Tennessee; the other was filed in Knox County Chancery Court. We removed the state action to federal court, but the plaintiff has filed a motion to remand the case to state court. We expect that the federal cases will be consolidated, but whether this will include the state case depends on the court’s ruling on the motion to remand. We have retained DLA Piper to defend us in these actions. We have filed motions to dismiss in each of the cases. Descriptions of the individual cases follow.

On August 23, 2011, a derivative action was filed against us in Knox County Chancery Court. The case is styled Marco Valdez, derivatively on behalf Miller Energy Resources, Inc. v. Deloy Miller, Scott M. Boruff, Jonathan S. Gross, Herman Gettelfinger, David Hall, Merrill A. McPeak, Charles M. Stivers, Don A. Turkleson, and David J. Voyticky, and Miller Energy Resources, Inc., nominal defendant. The suit alleges the following causes of action: (1) Breach of Fiduciary Duty for disseminating false and misleading information; (2) Breach of Fiduciary Duty for failure to maintain internal controls; (3) Breach of Fiduciary Duty for failing to properly oversee and manage the company; (4) Unjust Enrichment; (5) Abuse of Control; Gross Mismanagement, and; (6) Waste of Corporate Assets. The Plaintiff seeks unspecified money damages from the individual defendants, that the Company take certain actions with respect to its management, restitution to the Company, and the Plaintiff’s attorney fees and costs.

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

On August 25, 2011, a derivative action, styled Jacquelyn Flynn, derivatively on behalf Miller Energy Resources, Inc. v. Scott M. Boruff, Paul W. Boyd, Deloy Miller, Jonathan S. Gross, Herman Gettelfinger, David Hall, Merrill A. McPeak, Charles M. Stivers, Don A. Turkleson, and David Voyticky, and Miller Energy Resources, Inc., nominal defendant, was filed in the District Court for the Eastern District of Tennessee. It contains substantially similar claims as Valdez. The suit alleges the following causes of action: (1) Breach of Fiduciary Duty for disseminating false and misleading information; (2) Breach of Fiduciary Duty for failure to maintain internal controls; (3) Breach of Fiduciary Duty for failing to properly oversee and manage the company; (4) Unjust Enrichment; (5) Abuse of Control; Gross Mismanagement, and; (6) Waste of Corporate Assets. The Plaintiff seeks unspecified money damages from the individual defendants, that the Company take certain actions with respect to its management, restitution to the Company, and the Plaintiff’s attorney fees and costs.

On August 31, 2011, a derivative action, styled Patrick P. Lukas, derivatively on behalf Miller Energy Resources, Inc. v. Merrill A. McPeak, Scott M. Boruff, Deloy Miller, Jonathan S. Gross, Herman Gettelfinger, David Hall, Charles M. Stivers, Don A., Turkleson, and David J. Voyticky, and Miller Energy Resources, Inc., nominal defendant, was filed in the District Court for the Eastern District of Tennessee. It contains substantially similar claims as the other two purported derivative actions. The suit alleges the following causes of action: (1) Breach of Fiduciary Duty for disseminating materially false and misleading information; (2) Breach of Fiduciary Duty for failing to properly oversee and manage the company; (3) Unjust Enrichment; (4) Abuse of Control; (5) Gross Mismanagement and Waste of Corporate Assets. The Plaintiff seeks unspecified money damages from the individual defendants, that the Company take certain actions with respect to its management, restitution to the Company, and the Plaintiff’s attorney fees and costs.

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.

(15) Recently Issued Accounting Pronouncements

In May 2011, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. ASU 2011-04 generally provides a uniform framework for fair value measurements and related disclosures between GAAP and International Financial Reporting Standards (“IFRS”). Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements, quantitative information about unobservable inputs used, a description of the valuation process used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity’s use of a nonfinancial asset that is different from the asset’s highest and best use, the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required, the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosure of all transfers between Level 1 and Level 2 of the fair value hierarchy. This update is effective for annual and interim periods beginning on or after December 15, 2011. We are currently evaluating the effect of ASU 2011-04 on our financial statements and related disclosures.

In June 2011, the FASB issued guidance that allows an entity to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendment no longer allows an entity to show changes to other comprehensive income solely through the statement of equity. For publicly traded entities, the guidance is effective for annual and interim reporting periods beginning on or after December 15, 2011. While we are still evaluating this guidance, the adoption of this guidance will not have a material impact on our financial condition, results of operations, cash flows or financial disclosures.

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

(16) Restatement

During our fiscal 2011 third quarter ended January 31, 2011, we identified misstatements related to our interim unaudited consolidated balance sheet as of October 31, 2010, our unaudited consolidated statements of operations for the three and six month periods ended October 31, 2010, and our statement of cash flows for the six month period ended October 31, 2010. As a result, we restated our interim unaudited consolidated financial statements in our fiscal 2011 third quarter Form 10-Q filed with the SEC on March 22, 2011. During our fiscal 2011 fourth quarter ended April 30, 2011, we identified additional misstatements that related to our interim unaudited consolidated financial statements. As a result, we reported a second restatement of our interim unaudited consolidated financial statements in our fiscal 2011 Form 10-K filed with the SEC on August 29, 2011. A summary of the corrected misstatements is as follows:

We overstated depreciation, depletion and amortization for the three and six month periods ended October 31, 2010 by $18,125 and $775,946 due to our failure to properly record depletion, depreciation and amortization expense related to leasehold costs, wells and equipment, fixed assets, asset retirement obligations and a failure to appropriately record state production credits related to our Alaska operations.

We overstated oil and gas revenue and oil and gas operating expense for the three and six month periods ended October 31, 2010 by $1,036,987 and $1,861,733 due to our failure to appropriately account for overriding royalty interests. We incorrectly accounted for overriding royalty interests on a gross basis rather than on a net basis.

We understated oil and gas operating and overstated cost of other revenue for the three and six month periods ended October 31, 2010 by $143,837 and $389,389 due to the erroneous classification of certain expense accounts as oil and gas operating that should have been recorded in cost of other revenue.

·	We understated general and administrative expense for the three and six month periods ended October 31, 2010 by $791,779 and $332,801 due to our failure to appropriately calculate share based compensation expense for stock options and warrants.

We reported a net gain on derivatives of $781,938 rather than a loss of $1,761,152, for a total adjustment of $2,543,090 for the three month period ended October 31, 2010 and reported a gain of $3,687,895 rather than a gain of $1,143,705, for a total adjustment of $2,544,190 for the six month period ended October 31, 2010, due to our failure to appropriately calculate the mark-to-market adjustment for each of our warrant derivatives.

·	We failed to record a loss on exchange of $638,468 related to an unproved leasehold that was disposed of during the six months ended October 31, 2010.

·	We did not consolidate MEI, an entity that we control, the correction of which resulted in a decrease to notes payable, an increase to stockholders’ equity, and minor adjustments to cash, other assets and accrued expenses.

·	We did not appropriately record the income tax benefit, which after consideration of the restatement adjustments described herein, resulted in an increase in the tax benefit for the three and six month periods ended October 31, 2010 of $2,724,106 and $3,559,717.

Such misstatements resulted in adjustments to certain line items included in the calculation of net cash provided by operating activities in our interim unaudited consolidated statement of cash flows, but did not result in a material adjustment to our previously reported net cash provided by operating activities, net cash used by investing activities, or net cash provided by financing activities.

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

The following is a summary presentation of corrections made to the Company’s interim unaudited consolidated balance sheet as of October 31, 2010, as previously reported in the restatement footnote that was included in the Company’s Form 10-Q for the fiscal 2011 third quarter, filed with the SEC on March 22, 2011:

	October 31, 2010 (as reported)		Corrections			October 31, 2010 (as restated)
ASSETS

Cash and cash equivalents	$	986,547	$	243,793		$	1,230,340
Restricted cash		126,697		—			126,697
Accounts receivable, net		1,726,215		—			1,726,215
State production credits receivable		2,167,044		—			2,167,044
Inventory		627,746		—			627,746
Prepaid expenses		1,487,444		415,510			1,902,954
Oil and gas properties, net		481,630,866		(257,899	)		481,372,967
Equipment, net		7,087,429		73,688			7,161,117
Land		526,500		—			526,500
Restricted cash, non-current		2,314,517		—			2,314,517
Other assets		476,050		(302,916	)		173,134
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 taxes		184,468,878		(3,421,479	)		181,047,399
Asset retirement obligation		16,544,505		(39,962	)		16,504,543
Notes payable		2,284,871		(2,284,871	)		—
Total		226,152,213		(5,740,013	)		220,412,200

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			244,359,388
Total		273,004,842		5,912,189			278,917,031

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

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

The following is a summary presentation of corrections made to the Company’s interim unaudited consolidated statement of operations for the three month period ended October 31, 2010, as previously reported in the restatement footnote that was included in the Form 10-Q for the fiscal 2011 third quarter, filed with the SEC on March 22, 2011:

	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 revenues		6,675,662			(1,036,987	)		5,638,675

COSTS AND EXPENSES
Oil and gas operating		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		3,308,540			(18,125	)		3,290,415
Total costs and expenses		10,340,481			(263,333	)		10,077,148

OPERATING LOSS		(3,664,819	)		(773,654	)		(4,438,473	)

OTHER INCOME (EXPENSE)
Interest income		1,174			—			1,174
Interest expense		(618,938	)		—			(618,938	)
Gain (loss) on derivatives, net		781,938			(2,543,090	)		(1,761,152	)
Other income, net		7,125			—			7,125
Total other income (expense)		171,299			(2,543,090	)		(2,371,791	)

LOSS BEFORE INCOME TAXES		(3,493,520	)		(3,316,744	)		(6,810,264	)
INCOME TAX BENEFIT		—			2,724,106			2,724,106
NET LOSS	$	(3,493,520	)	$	(592,638	)	$	(4,086,158	)

LOSS PER SHARE:
Basic	$	(0.10	)	$	(0.02	)	$	(0.12	)
Diluted	$	(0.10	)	$	(0.02	)	$	(0.12	)

AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic		34,314,794						34,314,794
Diluted		34,314,794						34,314,794

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

The following is a summary presentation of corrections made to the Company’s interim unaudited consolidated statement of operations for the six month period ended October 31, 2010, as previously reported in the restatement footnote that was included in the Form 10-Q for the fiscal 2011 third quarter, filed with the SEC on March 22, 2011:

	For the Six Months Ended Oct. 31, 2010 (as reported)			Corrections			For the Six Months Ended Oct. 31, 2010 (as restated)
REVENUES
Oil and gas revenue	$	10,872,972		$	(1,861,733	)	$	9,011,239
Other revenue		1,002,937			—			1,002,937
Total revenue		11,875,909			(1,861,733	)		10,014,176

COSTS AND EXPENSES
Oil and gas operating		5,915,689			(1,472,344	)		4,443,345
Cost of other revenue		837,155			(389,389	)		447,766
General and administrative		6,848,366			332,801			7,181,167
Depreciation, depletion and amortization		7,044,717			(775,946	)		6,268,771
Other operating expense, net		—			638,468			638,468
Total costs and expenses		20,645,927			(1,666,410	)		18,979,517

OPERATING LOSS		(8,770,018	)		(195,323	)		(8,965,341	)

OTHER INCOME (EXPENSE)
Interest income		5,727			—			5,727
Interest expense		(838,276	)		—			(838,276	)
Gain on derivatives, net		3,687,895			(2,544,190	)		1,143,705
Other expense, net		(70,755	)		—			(70,755	)
Total other income (expense)		2,784,591			(2,544,190	)		240,401

LOSS BEFORE INCOME TAXES		(5,985,427	)		(2,739,513	)		(8,724,940	)
INCOME TAX BENEFIT		(69,791	)		3,559,717			3,489,926
NET LOSS	$	(6,055,218	)	$	820,204		$	(5,235,014	)

LOSS PER SHARE:
Basic	$	(0.18	)	$	0.02		$	(0.16	)
Diluted	$	(0.18	)	$	0.02		$	(0.16	)

AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic		33,575,258						33,575,258
Diluted		33,575,258						33,575,258

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

The following is a summary presentation of corrections made to the Company’s unaudited consolidated statement of cash flows for the six month period ended October 31, 2010, as previously reported in the Company’s Form 10-Q for the fiscal 2011 second quarter, filed with the SEC on December 10, 2010 (the interim unaudited consolidated statement of cash flows was not presented in the restatement footnote that was included in the fiscal 2011 third quarter Form 10-Q filed with the SEC on March 22, 2011, due to the fact that the restatement adjustments have no material impact on net cash provided by operating activities, net cash used by investing activities, or net cash provided by financing activities):

	For the Six Months Ended October 31, 2010						For the Six Months Ended October 31, 2010
	(as reported)			Corrections			(as restated)
Cash Flows from Operating Activities
Net loss	$	(1,005,768	)	$	(4,229,246	)	$	(5,235,014	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		4,266,568			1,515,232			5,781,800
Amortization of deferred financing fees		—			208,516			208,516
Gain on sale of equipment		(7,500	)		7,500			—
Gain on sale of oil and gas properties		(12,500	)		12,500			—
Issuance of equity for compensation		1,462,490			1,808,699			3,271,189
Issuance of equity for services		—			2,831,758			2,831,758
Deferred income taxes		—			(3,559,717	)		(3,559,717	)
Unrealized gain on derivative instruments, net		(3,687,895	)		260,584			(3,427,311	)
Accretion of asset retirement obligation		—			486,971			486,971
Changes in operating assets and liabilities:
Receivables, net		(233,925	)		—			(233,925	)
State production credits receivable		(1,060,043	)		—			(1,060,043	)
Inventory		(106,107	)		(246,029	)		(352,136	)
Prepaid expenses		(1,211,834	)		812,634			(399,200	)
Other assets		442,291			(375,983	)		66,308
Accounts payable, accrued expenses and other		5,024,965			(20,390	)		5,004,575
Net cash provided by operating activities		3,870,742			(486,971	)		3,383,771

Cash Flows from Investing Activities
Purchase of equipment and improvements		(171,029	)		(561,058	)		(732,087	)
Capital expenditures for oil and gas properties		(5,734,867	)		1,068,029			(4,666,838	)
Proceeds from sale of oil and gas properties		12,500			(12,500	)		—
Proceeds from sale of equipment		7,500			(7,500	)		—
Net cash used by investing activities		(5,885,896	)		486,971			(5,398,925	)

Cash Flows from Financing Activities
Payments on notes payable		—			(1,239,401	)		(1,239,401	)
Deferred financing costs		(7,580	)		7,580			—
Proceeds from borrowing		350,000			(350,000	)		—
Exercise of equity rights		151,751			1,581,188			1,732,939
Restricted cash		(243,311	)		633			(242,678	)
Net cash provided by financing activities		250,860			—			250,860
Net decrease in Cash in Cash and Cash Equivalents		(1,764,294	)		—			(1,764,294	)

Cash and Cash Equivalents at Beginning of Period		2,750,841			243,793			2,994,634
Cash and Cash Equivalents at End of Period	$	986,547		$	243,793		$	1,230,340

Cash paid for interest	$	632,226		$	(304,511	)	$	327,715

MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(UNAUDITED)

(17) Subsequent Events

On November 15, 2011, the Board of Directors adopted an indemnification program in order to establish procedures under which directors and officers could seek indemnification by the Company in accordance with the Company’s Bylaws and Tennessee law. Under the program, directors or officers seeking indemnification are required to execute an indemnification agreement with the Company. The indemnification agreement does not grant any additional substantive rights to the directors or officers than previously existed under the Company’s Bylaws and Tennessee law. When submitting a request for indemnification, the director or officer is required to affirm that he acted in good faith and in a manner he reasonably believed to be in, or not opposed to, the best interests of the Company. He must further agree to repay to the Company any funds advanced by the Company or the Company’s insurance carrier to him or on his behalf in the event that it is ultimately determined by a final non-appealable adjudication by a court of competent jurisdiction that he is liable for a breach of the duty of loyalty to the company or its shareholders, for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, or under Tennessee Code Annotated §48-18-304.

The foregoing description is qualified in its entirely by reference to the Indemnification Agreement, which is filed as Exhibit 10.58 to this report.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following is management’s discussion and analysis of certain significant factors that have affected aspects of our financial position and results of operations during the periods included in the accompanying unaudited financial statements. You should read this in conjunction with the discussion under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited financial statements for the year ended April 30, 2011 included in our amended Annual Report on Form 10-K and the unaudited financial statements included elsewhere herein.

Forward-Looking Statements

Certain statements in this report, including statements of the future plans, objectives, budgets, legal strategies and proceedings, projected costs and savings, and expected performance are “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, that are dependent upon certain events, risks and uncertainties that may be outside our control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to:

●

planned capital expenditures;

●

future drilling activity;

●

our financial condition;

●

business strategy;

●

the market prices of oil and gas;

●

uncertainties about the estimated quantities of oil and gas reserves, including uncertainties associated with the SEC’s new rules governing reserve reporting;

●

the availability of drilling rigs and equipment or fracturing and pressure pumping crews;

●

economic and competitive conditions;

●

legislative and regulatory changes;

●

financial market conditions and availability of capital;

●

production;

●

hedging arrangements;

●

future cash flows and borrowings;

●

litigation matters;

●

more stringent environmental laws and increased difficulty in obtaining environmental permits;

●

pursuit of potential future acquisition opportunities; and

●

sources of funding for exploration and development.

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. The drilling of exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns. Lease and rig availability, complex geology and other factors can affect these risks. Although from time to time we make use of futures contracts, swaps, costless collars and fixed-price physical contracts to mitigate risk, fluctuations in oil and gas prices or a prolonged continuation of low prices may substantially adversely affect our financial position, results of operations and cash flows.

These factors, as well as additional factors that could affect our operating results and performance, are described in our amended Annual Report on Form 10-K for the year ended April 30, 2011, under the headings “Business,” “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” We urge you to carefully consider those factors together with the other factors described in this report.

All forward-looking statements attributable to us are qualified in their entirety by this cautionary statement. We undertake no responsibility to update our forward-looking statements.

Overview

Miller Energy Resources, Inc. (“MER”) is an independent oil and gas exploration and production company that utilizes seismic data and other technologies for geophysical exploration and development of oil and gas properties in South central Alaska’s Cook Inlet and Susitna Basins, and the Appalachian region of eastern Tennessee. While our primary focus is the exploration for and production of crude oil and natural gas, we also provide drilling and other services to oil and gas companies on a contract basis.

We are continuing to develop properties we acquired during fiscal 2010 and 2011. We have a total acreage position of 699,402 gross acres of oil and gas leases and exploration licenses. This consist of 48,895 gross acres of oil and gas leases in Tennessee, 115,124 gross acres of oil and gas leases in Alaska and 534,383 gross acres of oil and gas exploration licenses in Alaska. Our exploration licenses include 471,474 acres under the Susitna Basin Exploration License No. 2 (South Susitna) and 62,909 acres under the Susitna Basin Exploration License No. 4 (North Susitna). We are continuing to assess and add strategic acreage to our Alaska land position.

On May 23, 2011, we recompleted the RU-1 well in the Redoubt Shoals field in the Cook Inlet of Alaska by replacing an electric submersible pump ("ESP"). The well initially tested at a flow rate of approximately 350 Bbls/d gross; however, on September 30, 2011, the new ESP failed and the well is currently not producing. We do not plan to replace the ESP until Rig 35 is operational on the Osprey platform.

On June 6, 2011, the Board of Directors appointed David J. Voyticky as President. Mr. Voyticky was initially elected to the Board of Directors at a special meeting of the shareholders held on April 26, 2010, and re-elected at the annual shareholders meeting on March 11, 2011. In addition to his position as President, Mr. Voyticky was appointed Acting Chief Financial Officer by the Board of Directors on September 16, 2011. Prior to joining MER as an officer, Mr. Voyticky was engaged as a consultant to MER, where he worked closely with our Chief Executive Officer on key strategic issues and financing matters.

On June 12, 2011, MER entered into a contract with Voorhees Equipment and Consulting, Inc. for the construction and purchase of a custom drilling rig to be used on our Osprey offshore platform located in the Cook Inlet of Alaska. The contract sets a total purchase price of $17,927,770. The addition of the rig will greatly enhance our drilling opportunities and capabilities on the Osprey platform. Commonly referred to as Rig 35, the new rig began arriving in Alaska during October 2011 and is expected to be assembled and operational in January 2012.

On June 13, 2011, MER closed a two year, $100 million credit facility with Guggenheim Corporate Funding, LLC, Citibank, N.A. and Bristol Investment Fund, Ltd. Munger, Tolles and Olson, LLP advised MER on the transaction. The credit facility, which provides for an initial borrowing base of $35 million, is secured by substantially all of MER's and its subsidiaries' assets. Proceeds from the loan will be utilized to fund recompletion and redevelopment of existing wells and the construction and installation of Rig 35.

On June 19, 2011, we successfully recompleted the RU-7 well in the Redoubt Shoals field in the Cook Inlet of Alaska by replacing the ESP. The well initially tested at a flow rate of approximately 250 Bbls/d gross.

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 total cash consideration of $399,934. We have also agreed to indemnify the sellers of the membership interests with respect to their guaranties of the construction loans entered into by the Pellissippi Pointe entities, but have not directly guaranteed the loans. The current principal balance of the loans is $5,139,394. The Pellissippi Pointe entities own two office buildings in Knoxville, Tennessee. MER has executed a five year lease agreement on approximately 4,156 square feet in the building owned by Pellissippi Pointe II, LLC. Effective November 7, 2011, this space is being used as MER’s corporate headquarters.

MER’s future growth strategy will focus on two key areas: (1) increasing our overall oil and gas production through redevelopment, recompletion and workovers of existing nonproducing and under producing wells in Alaska; and (2) organically increasing production through exploratory drilling on existing leases while retaining a majority working interest in new wells. The new credit facility and the addition of Rig 35 provide the foundation to continue the implementation of our growth strategy in fiscal year 2012 and beyond.

Results of Operations

The following table shows operating results for the three and six months ended October 31, 2011 and 2010:

	For the Three Months Ended				For the Six Months Ended
	10/31/2011		10/31/2010		10/31/2011		10/31/2010

Gross Sales Volumes (Alaska)
Oil (BBLs)		117,207		84,458		214,680		154,258
Gas (Mcf)		12,833		4,046		26,504		8,434

Gross Sales Volumes (Tennessee)
Oil (BBLs)		7,207		7,963		14,665		13,433
Gas (Mcf)		81,937		72,994		164,364		144,790

Gross Sales Volumes (Total)
Oil (BBLs)		124,414		92.,421		229,345		167,691
Gas (Mcf)		94,770		77,040		190,868		153,224
Sales Volumes (BOE)		140,209		105,261		261,156		193,228

Net Production Volume (BOE)
Alaska		101,258		69,211		183,250		130,065
Tennessee		10,185		7,945		20,199		15,678
Production Volume		111,443		77,156		203,449		145,743

Net Oil and Gas Revenue	$	8,441,770	$	5,044,806	$	16,761,133	$	9,011,239
Lease Operating Expenses	$	4,005,541	$	2,718,432	$	7,801,793	$	4,443,345
DD&A	$	4,675,077	$	3,498,931	$	8,505,340	$	6,477,287

Additional BOE Data:
Realized Sales Price	$	77.62	$	69.80	$	81.86	$	68.38
Lease Operating Expenses	$	28.57	$	25.83	$	29.87	$	23.00
DD&A	$	33.34	$	33.24	$	32.57	$	33.52

The three and six months ended October 31, 2011 as compared to the three and six months ended October 31, 2010 were periods of growth and development. We recorded losses of $4,484,310 or $0.11 per share and $4,666,991 or $0.11 per share for the three and six months ended October 31, 2011, respectively, which compares to losses of $4,086,158 or $0.12 per share and $5,235,014 or $0.16 per share for the three and six months ended October 31, 2010, respectively. Revenues increased $3,566,087 from the second quarter of 2010 compared to the second quarter of 2011 and $8,046,360 between the six month to date periods while costs and expenses increased $6,853,803 and $10,527,828 for the same time period. We recorded other income of $655,463 for the three months ended October 31, 2011 while the same quarter one year earlier was an expense of $2,371,791. We recorded other income of $3,946,247 for the six months ended October 31, 2011 as compared to other income of $240,401 for the six months ended October 31, 2010. The major components of our Consolidated Statements of Operations for the three months ended October 31, 2011 as compared to the three months ended October 31, 2010 are as follows:

	For the Three Months ended October 31,
	2011			2010			% Change
				(as restated)
Revenues	$	9,204,762		$	5,638,675			63	%
Costs and expenses		(16,930,951	)		(10,077,148	)		68	%
Other income (expense)		655,463			(2,371,791	)	>100		%
Income tax benefit		2,586,416			2,724,106			(5	)%
Net loss	$	(4,484,310	)	$	(4,086,158	)		10	%

The major components of our Consolidated Statements of Operations for the six months ended October 31, 2011 as compared to the six months ended October 31, 2010 are as follows:

	For the Six Months ended October 31,
	2011			2010			% Change
				(as restated)
Revenues	$	18,060,536		$	10,014,176			80	%
Costs and expenses		(29,507,345	)		(18,979,517	)		55	%
Other income		3,946,247			240,401		>100		%
Income tax benefit		2,833,571			3,489,926			(19	)%
Net loss	$	(4,666,991	)	$	(5,235,014	)		11	%

Revenues

The following table shows the components of our revenues for the three months ended October 31, 2011 and 2010, with their percentage change on a period-over-period basis.

	For the Three Months ended October 31,
	2011		2010		% Change
			(as restated)
Oil and natural gas sales	$	8,440,857	$	5,044,806		67	%
Other revenue		763,905		593,869		29	%
Total revenues	$	9,204,762	$	5,638,675		63	%

The following table shows the components of our revenues for the six months ended October 31, 2011 and 2010, with their percentage change on a period-over-period basis.

	For the Six Months ended October 31,
	2011		2010		% Change
			(as restated)
Oil and natural gas sales	$	16,760,220	$	9,011,239		86	%
Other revenue		1,300,316		1,002,937		30	%
Total revenues	$	18,060,536	$	10,014,176		80	%

Oil and natural gas sales represents net revenues from the sale of crude oil and natural gas produced by wells in which we have a revenue interest. We reported 67% and 86% increases in oil and natural gas sales for the three and six months ended October 31, 2011, respectively, as compared to the three and six months ended October 31, 2010. The increase principally resulted from restarting production at Alaska’s Redoubt Shoals field and increased oil prices. Two Redoubt Shoals oil wells, RU-1 and RU-7, were recompleted during the three months ended July 31, 2011. The increased production from these wells resulted in net barrels sold of 36,495 and 54,078 for the three and six months ended October 31, 2011, respectively. Due to the failure of the RU-1 ESP on September 30, 2011, we do not anticipate any production from this well during the third quarter of fiscal 2012. The well initially tested with a flow rate of 350 Bbls/day. Management currently anticipates bringing this well back online in the fourth quarter of fiscal 2012. For the three months ended October 31, 2011, total net barrels sold in Alaska were 97,599 at an average realized price of $84.98/Bbl which resulted in net oil sales of $8,044,614. This compared to 66,854 net barrels sold at an average realized price of $76.96/Bbl and net sales of $5,044,806 for the three months ended October 31, 2010. For the six months ended October 31, 2011, total net barrels sold in Alaska were 177,019 at an average realized price of $90.32/Bbl which resulted in net oil sales of $15,735,363. This compared to 122,104 net barrels sold at an average realized price of $75.90/Bbl and net sales of $9,011,239 for the six months ended October 31, 2010. During the three and six months ended October 31, 2011, we produced 51,028 Mcf and 100,832 Mcf of natural gas, respectively, which was used as fuel gas. During the three and six month periods ended October 31, 2010, we produced 55,664 Mcf and 111,218 Mcf of natural gas, respectively, that was used as fuel gas.

In Tennessee, during the three months ended October 31, 2011, we sold 81,937 Mcf of natural gas at an average of $4.54/Mcf, which resulted in net natural gas sales of $91,525, compared to 72,994 Mcf at an average price of $4.13/Mcf, which resulted in net natural gas sales of $56,235 for the three months ended October 31, 2010. During the six months ended October 31, 2011, we sold 164,364 Mcf of natural gas at an average of $4.72/Mcf, which resulted in net natural gas sales of $194,262, compared to 144,790 Mcf at an average price of $4.14/Mcf, which resulted in net natural gas sales of $98,123 for the six months ended October 31, 2010.

Other revenue consists primarily of servicing and drilling revenue. Other revenue increased 29% and 30% for the three and six months ended October 31, 2011, respectively, compared to the same periods in the prior fiscal year. This was primarily due to additional revenue generated from contracts for plugging, drilling, maintenance and repair of third party wells. In addition, we generated rental income of $130,607 for use of our Alaska facilities, but had no such rental income during the comparative periods in the prior year.

In summary, our total revenues increased 63% to $9,204,762 for the three months ended October 31, 2011 and 80% to $18,060,536 for the six months ended October 31, 2011 as compared to the six months ended October 31, 2010. Due to the September 30, 2011 failure of the RU-1 ESP, we do not anticipate any production from this well during the third quarter of fiscal 2012. The well initially tested with a flow rate of 350 Bbls/day. Management currently anticipates bringing this well back online in the fourth quarter of fiscal 2012. As we continue to recomplete and workover our existing wells, redevelop our proved producing reserves and develop our proved undeveloped reserves, we expect our oil and gas revenues to continue increasing during the remainder of fiscal 2012 if there is no significant decrease in oil prices.

Costs and Expenses

The following table shows the components of our direct costs and expenses for the three months ended October 31, 2011 and 2010. Percentages listed in the table reflect percentage change on a year-over-year basis for each component.

	For the Three Months ended October 31,
	2011			2010		% Change
				(as restated)
Oil and gas operating	$	4,374,869		$	2,718,432		61	%
Cost of other revenue		145,782			197,571		(26	)%
General and administrative		7,948,985			3,870,730	>100		%
Exploration expense		148,264			—		N/A
Depreciation, depletion, amortization and accretion		4,317,869			3,290,415		31	%
Other operating income, net		(4,818	)		—		N/A
Total costs and expenses	$	16,930,951		$	10,077,148		68	%

The following table shows the components of our direct costs and expenses for the six months ended October 31, 2011 and 2010. Percentages listed in the table reflect percentage change on a year-over-year basis for each component.

	For the Six Months ended October 31,
	2011			2010		% Change
				(as restated)
Oil and gas operating	$	8,171,121		$	4,443,345		84	%
Cost of other revenue		372,426			447,766		(17	)%
General and administrative		13,721,175			7,181,167		91	%
Exploration expense		179,792			—		N/A
Depreciation, depletion, amortization and accretion		7,960,109			6,268,771		27	%
Other operating expense (income), net		(897,278	)		638,468	>(100)		%
Total costs and expenses	$	29,507,345		$	18,979,517		55	%

Oil and gas operating expenses increased approximately 61% for the three months ended October 31, 2011 compared to the three months ended October 31, 2010 due to the previously mentioned increase in production volume from our Redoubt Shoals field. During the three months ended October 31, 2011, we produced net BOE of 111,443. Costs and expenses for the three months ended October 31, 2011 were $151.92 per BOE. This compares to $130.61 per BOE for the three months ended October 31, 2010 as gross production during this time was 77,156 BOE.

Oil and gas operating expenses increased approximately 84% for the six months ended October 31, 2011 compared to the six months ended October 31, 2010 due to the previously mentioned corresponding increase in production from our Redoubt Shoals field. Oil from the Redoubt Shoals field is recovered from our Osprey offshore platform and processed at our Kustatan Production Facility. Both facilities were not in operation during fiscal 2011. During the six months ended October 31, 2011, we produced net barrel of oil equivalent (“BOE”) of 203,449. Costs and expenses for the six months ended October 31, 2011 were $145.04 per BOE. This compares to $130.23 per BOE for the six months ended October 31, 2010 as net production during this time was 145,743 BOE. This increase was due to additional costs during the three months ended October 31, 2011 as we added thirteen new oil wells and twelve new gas wells to producing status and experienced higher workover costs. During the balance of fiscal 2012, we expect to continue bringing non-productive wells online and expect these expenses to continue to rise due to the cost of extracting and processing the additional production volume.

Cost of other revenue represents expenses incurred in the performance of drilling and related services to third parties. The primary component is direct labor costs associated with these services, as well as costs associated with equipment, parts and repairs. The first six months of fiscal 2012 showed a 17% decrease for this component from the first six months of fiscal 2011. During the six months ended October 31, 2011, we drilled three wells and also continued our 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. The efficiencies of performing these services are partially responsible for the small decrease, as we have been more efficient during the last twelve months. The second quarter of fiscal 2012 showed a 26% decrease for this component from the second quarter of fiscal 2011.

General and administrative expense includes salaries, general overhead expenses, insurance costs, professional fees and consulting fees. These expenses increased 91% for the first six months of fiscal 2012 from the first six months of fiscal 2011. This increase was primarily due to an increase in compensation and professional and consulting fees. Cash salaries were $1,727,561 for the first six months of fiscal 2012, an increase of $711,750 from the first six months of fiscal 2011. During this time, staffing grew from 56 on October 31, 2010 to 67 at October 31, 2011 as we added staff in Alaska for the offshore platform and in Tennessee for our service subsidiary. Non-cash compensation grew from $1,462,490 for the six months ended October 31, 2010 to $6,473,106 for the six months ended October 31, 2011, an increase of $5,010,616. This was due to grants of stock options and warrants to directors, officers, key employees and a consultant over the last 12 months. General and administrative expense increased 105% for the second quarter of fiscal 2012 from the second quarter of fiscal 2011. The majority of the increase relates to non-cash compensation and professional and consulting fees. Non-cash compensation grew from $946,599 for the three months ended October 31, 2010 to $3,756,905 for the three months ended October 31, 2011, an increase of $2,810,306. As we continue to grow our business, particularly in Alaska, we expect these general and administrative expenses will continue to rise during the balance of fiscal 2012.

Depreciation, depletion, amortization and accretion (“DD&A”) expense increased 27% in the six months ended October 31, 2011 as compared to the six months ended October 31, 2010. During the first six months of fiscal 2012, DD&A expense was $32.57 per produced BOE, as compared to $33.52 per produced BOE for the first six months of fiscal 2011. DD&A expense increased 31% in the three months ended October 31, 2011 as compared to the three months ended October 31, 2010. During the first quarter of fiscal 2012, DD&A expense was $33.34 per produced BOE, as compared to $33.24 per produced BOE for the first quarter of fiscal 2011. The increase in DD&A expense resulted from the addition of wells and equipment and added production from our Redoubt Shoals field that was not producing in the same period of the prior year. These non-cash expenses will continue at increasingly higher levels as our Alaska assets are exploited and producing at increasing rates.

During the six months ended October 31, 2011, the Company recorded other operating income of $897,278 which was due to the settlement of an Alaska royalty dispute. For the six months ended October 31, 2010, the Company recorded other operating expense of $638,468 due to a loss on the exchange of an Alaska lease known as “Raptor” for an overriding royalty interest in the same property.

As a result of these components, total costs and expenses were $29,507,345, which contributed to an operating loss of $11,446,809 for the six months ended October 31, 2011. This compares to $18,979,517 in costs and expenses and an operating loss of $8,965,341 for the six months ended October 31, 2010.

Total costs and expenses were $16,930,951, which contributed to an operating loss of $7,726,189 for the three months ended October 31, 2011. This compares to $10,077,148 in costs and expenses and an operating loss of $4,438,473 for the three months ended October 31, 2010.

Other Income (Expense)

The following table shows the components of certain of our other income and expenses for the three months ended October 31, 2011 and 2010. Percentages listed in the table reflect percentage change on a year-over-year basis for each component of other income (expense).

	For the Three months ended October 31,
	2011			2010			% Change
				(as restated)
Interest expense, net	$	(879,362	)	$	(617,764	)		42	%
Gain on derivatives, net		1,506,189			(1,761,152	)	>(100		%)
Other income, net		28,636			7,125		>100		%
Total	$	655,463		$	(2,371,791	)	>(100		%)

The following table shows the components of certain of our other income and expenses for the six months ended October 31, 2011 and 2010. Percentages listed in the table reflect percentage change on a year-over-year basis for each component of other income (expense).

	For the Six months ended October 31,
	2011			2010			% Change
				(as restated)
Interest expense, net	$	(1,375,492	)	$	(832,549	)		65	%
Gain on derivatives, net		5,261,845			1,143,705		>100		%
Other income (expense), net		59,894			(70,755	)	>100		%
Total	$	3,946,247		$	240,401		>100		%

Interest expense, net of interest income, increased 42% in the second quarter of fiscal 2012 compared to the second quarter of fiscal 2011. This was primarily due to the increase in our borrowings at October 31, 2011 reflecting amounts outstanding under the Guggenheim credit facility. Interest expense, net of interest income, increased 65% for the first six months of fiscal 2012 compared to the first six months of fiscal 2011. This was primarily due to the increase in our borrowings at October 31, 2011 reflecting amounts outstanding under the Guggenheim credit facility. Offsetting these increases in interest expense is a $1,641,145 and $1,950,483 decline due to capitalized interest for the three and six-month periods ended October 31, 2011, respectively.

Our derivatives consist of warrants with exercise price reset provisions and commodity derivatives. The estimated fair value of our commodity derivatives fluctuate from period to period based on the price of crude oil. The estimated fair value of warrant derivatives fluctuates based on Black-Scholes assumptions, including MER’s ending stock price, risk free rate, expected term, expected volatility and expected dividend rate.

The Company participated in two fixed price swap commodity derivatives for 300 barrels of oil per day each 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. The hedges are priced at $92.13 and $108.25, respectively, per barrel of oil. MER 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 the statement of operations. The asset recorded for these instruments as of October 31, 2011 was $810,379 as the price for a barrel of oil at October 31, 2011 was lower than the average hedging price of $100.19. The derivative long-term liability as of October 31, 2011 of $1,207,846 relates to 817,055 warrants issued and outstanding in connection with an equity financing in March 2010. The warrants expire in March 2015. The related fair value of this derivative has been recorded as a non-current liability.

During the six months ended October 31, 2011 and 2010, the Company recorded gains on derivatives of $5,261,845 and $1,143,705, respectively. For the six months ended October 31, 2011, $4,640,310 related to the change in fair value and $621,534 related to realized cash settlements. During the three months ended October 31, 2011 and 2010, the Company recorded gains on derivatives of $1,506,189 and a loss of $1,761,152, respectively. For the three months ended October 31, 2011, $986,158 was related to the change in fair value and $520,031 related to realized cash settlements. The application of this accounting treatment on our financial statements in future periods could result in significant non-cash gains or losses.

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 the first quarter of fiscal 2012 and the first quarter of fiscal 2011 and had a working capital deficit as of October 31, 2011 of $28,908,850 as compared to a working capital deficit of $7,681,516 at April 30, 2011. This increase in working capital deficit is primarily due to an increase in short term borrowings of $26,894,615 under our Credit Facility which closed after April 30, 2011. We anticipate that our operating expenses will continue to increase as we fully develop our proved Alaskan assets. Although we expect an increase in our revenues to come from these development activities, we will continue using our cash flow to fund operating expenses until such time as the additional revenues are realized.

During the first quarter of fiscal 2012 we secured a $100 million Credit Facility with an initial borrowing base of $35 million which we are using to further develop our off-shore and on-shore Alaskan assets. The borrowing base is subject to reassessment semi-annually and may also be redetermined upon our request. While we do not have any other external sources of working capital other than this Credit Facility, we are seeking other potential sources of funds. We currently have approximately $6.1 million of remaining availability under the Credit Facility.

Although the Loan Agreement doesn’t mature until June 13, 2013, the Company is required to make monthly repayments based on 90% of its “consolidated net revenues.” Under the Loan Agreement, “consolidated net revenues” are gross revenues less royalties, transportation, lease operating and after general and administrative expenses to the extent permitted by the Loan Agreement. In addition, proceeds of certain asset sales and other proceeds received outside the ordinary course of business are required to be used to repay amounts outstanding under the credit facility. As a result, the Company has classified amounts outstanding under the Loan Agreement as of October 31, 2011 as a current liability in the accompanying consolidated balance sheet.

Draws under the credit facility are subject to the discretion of Guggenheim and the other lenders. The borrowing base is redetermined on a scheduled basis twice per year, and more often at the request of MER or the 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.

Management believes that the credit facility, along with projected cash flow and other potential sources of funds, are adequate to meet our funding needs for the next twelve months; however, we are restricted as to our borrowings under the credit facility and are subject to the minimum financial requirements and certain other provisions as detailed in Note 7 “Debt Obligations”.

From April 30, 2011 to October 31, 2011, cash increased by $984,496 to $2,543,429. This increase was primarily due to cash provided by financing activities of $25,406,526 and cash provided by operating activities of $1,694,068, offset by an increase in cash used by investing activities of $26,116,098.

Our capital expenditures budget for the remainder of the fiscal year ending April 30, 2012 is approximately $35 million. The majority of the budget is allocated to restoring additional production from our Redoubt Shoals field in Alaska. Our ability to fully utilize our remaining budget will be dependent on a number of factors including, but not limited to, access to capital, Rig 35 being operational in a timely manner, weather and regulatory approval. Our existing $100 million credit facility has a current borrowing base of $35 million and an outstanding balance at October 31, 2011 of $28,894,615. We will continue to identify and evaluate additional capital sources to fulfill our projected capital expenditures.

Cash flows

Net cash provided by operating activities for the first six months of fiscal 2012 and fiscal 2011 were $1,694,068 and $3,383,771 respectively. These increases primarily reflect the increase of oil sales received in excess of the direct cash related costs paid during the period, partially offset by the cash portions of general and administrative expense.

Net cash used in investing activities for the six months ended October 31, 2011 included $26,116,098 for additions to equipment and improvements of $21,197,3271 and capital expenditures for oil and gas properties of $4,518,837. Net cash used by investing activities for the six months ended October 31, 2010 of $5,398,925 is primarily due to the $4,666,838 capital expenditures related to wells we acquired in December 2010.

Net cash provided by financing activities of $25,406,526 for the six months ended October 31, 2011 primarily reflects the proceeds from borrowings of $28,894,615, which were partially offset by payments of $2,000,000 and deferred financing costs of $2,799,099. Net cash provided by financing activities of $250,860 for the six months ended October 31, 2010, reflects the exercise of equity rights of $1,732,939 offset by payments of $1,239,401 for notes payable.

Off Balance Sheet Arrangements

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 total cash consideration of $399,934. 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 $5,139,394. The Pellissippi Pointe entities own two office buildings in West Knoxville, Tennessee. We moved our corporate offices into the building on November 7, 2011. We have executed a five year lease for the space, and the building is fully occupied by tenants. As the Company is in a position to exercise significant influence, but not control the financial and operating policy decisions of the investee, we account for this investment using the equity method.

We have no other off-balance sheet arrangements that that should be disclosed pursuant to SEC 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.

Effects of Inflation and Changes in Price

Our results of operations and cash flows are affected by changing oil and natural gas production levels and prices. As production levels and prices of oil and natural gas increases or decreases, there will be a corresponding increase or decrease in operating cost, as well as an increase or decrease in revenues.

Critical Accounting Policies and Recently Adopted Accounting Pronouncements

During the six months ended October 31, 2011, there were no material changes to the critical accounting policies and recently adopted accounting pronouncements previously reported by us in our amended Annual Report on Form 10-K for the year ended April 30, 2011.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.

Price Fluctuations

Our major market risk is pricing applicable to our oil and gas production. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil and gas production has been volatile and unpredictable. We periodically hedge a portion of our price risk associated with our future oil and gas production.

As of October 31, 2011, the Company participated in two fixed price swap commodity derivatives for 300 barrels of oil per day each 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. 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 the statement of operations. The asset recorded for these instruments as of October 31, 2011 was $810,379 as the price for a barrel of oil was below the average hedging price of $100.19.

Interest Rate Risk

At October 31, 2011 our borrowings consisted solely of our Guggenheim Loan Agreement. 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 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 interest rate to 25% in the event the amounts are paid by June 30, 2012, 30% in the event repayment is made between July 1 and December 31, 2012, and 35% if payment is made on or after January 1, 2013. The Company is recording interest expense, using the effective interest method, assuming an interest rate of 35%.

ITEM 4. CONTROLS AND PROCEDURES.

Evaluation of 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 this report (the “Evaluation Date”). In conducting its evaluation, management considered the material weaknesses in our disclosure controls and procedures and internal control over financial reporting described in Item 9A. of our amended Annual Report on Form 10-K for the year ended April 30, 2011 as filed with the SEC on August 29, 2011.

We have not yet remediated those material weaknesses. As a result of the continuing material weaknesses in our disclosure controls and procedures an internal control over financial reporting identified in our amended Annual Report on Form 10-K for the year ended April 30, 2011 as filed with the SEC on August 29, 2011, 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.

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.

Additionally, in designing disclosure controls and procedures, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible disclosure controls and procedures. The design of any disclosure controls and procedures is also 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.

Changes in Internal Control over Financial Reporting.

We have made the following changes in our internal control over financial reporting during the quarter ended October 31, 2011 that have improved, or are reasonably likely to materially improve, our internal control over financial reporting: The Company has hired a certified public accountant as its financial reporting manager to evaluate, document and implement improved internal controls over financial reporting and we have engaged a consulting firm to perform our internal audit function, as well as to provide consulting services to augment our accounting staff. We have reassigned personnel within our accounting department to better address our financial reporting requirements. We are evaluating whether additional personnel are required.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

The information set forth under Note 14 Litigation, to our unaudited consolidated financial statements included in Item 1 of Part 1 of this report is incorporated herein by reference.

ITEM 1A. RISK FACTORS.

Risk factors describing the major risks to our business can be found under Item 3, “Quantitative and Qualitative Disclosures About Market Risk” above. There have been no material changes in our risk factors from those previously discussed in our Annual Report on Form 10-K for the year ended April 30, 2011, as amended.

ITEM 6. EXHIBITS

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 (34)
10.54		Form of Assignment of Membership Interest in Pellissippi Pointe, LLC (34)
10.55		Form of Assignment of Membership Interest in Pellissippi Pointe II, LLC (34)
10.56		First Amendment and Limited Waiver to Loan Agreement (35)
10.57		Limited Consent and Extension*
10.58		Indemnification Agreement*
14.1		Amended and Restated Code of Business Conduct and Ethics (34)
23.1		Consent of Ralph E. Davis Associates, Inc. (34)
23.2		Consent of Lee Keeling and Associates, Inc. (34)
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 and Chief Financial Officer*
99.1		Reserve Report of Ralph E. Davis Associates, Inc. at April 30, 2011 on Cook Inlet assets (34)
99.2		Reserve Reports of Lee Keeling and Associates, Inc. at April 30, 2011 on Appalachian region assets (34)
101.INS		XBRL Instance Document *
101.SCH		XBRL Taxonomy Extension Schema Document *
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document*
101.LAB		XBRL Taxonomy Extension Label Linkbase Document *
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document *
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document *

————

* 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.

(34) Incorporated by reference to the Annual Report on Form 10-K for the year ended April 30, 2011, as amended.

(35) Incorporated by reference to the Current Report on Form 8-K filed on August 29, 2011.

SIGNATURES

Pursuant to the requirements 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.

	MILLER ENERGY RESOURCES, INC.

Dated: December 12, 2011	By:	/s/ Scott M. Boruff
		Scott M. Boruff,
		Chief Executive Officer, principal executive officer

	MILLER ENERGY RESOURCES, INC.

Dated: December 12, 2011	By:	/s/ David J. Voyticky
		David J. Voyticky,
		Chief Financial Officer, principal financial officer

EXHIBIT INDEX

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 (34)
10.54		Form of Assignment of Membership Interest in Pellissippi Pointe, LLC (34)
10.55		Form of Assignment of Membership Interest in Pellissippi Pointe II, LLC (34)
10.56		First Amendment and Limited Waiver to Loan Agreement (35)
10.57		Limited Consent and Extension*
10.58		Indemnification Agreement*
14.1		Amended and Restated Code of Business Conduct and Ethics (34)
23.1		Consent of Ralph E. Davis Associates, Inc. (34)
23.2		Consent of Lee Keeling and Associates, Inc. (34)
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 and Chief Financial Officer*
99.1		Reserve Report of Ralph E. Davis Associates, Inc. at April 30, 2011 on Cook Inlet assets (34)
99.2		Reserve Reports of Lee Keeling and Associates, Inc. at April 30, 2011 on Appalachian region assets (34)
101.INS		XBRL Instance Document **
101.SCH		XBRL Taxonomy Extension Schema Document **
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document**
101.LAB		XBRL Taxonomy Extension Label Linkbase Document **
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document **
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document **

———————

* filed herewith

**	will be filed by amendment