Edgar Filing: MILLER PETROLEUM INC

Miller Petroleum 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

———————

FORM 10-Q

———————


ü	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
	ACT OF 1934
For the quarterly period ended: January 31, 2011
or

	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
	ACT OF 1934
For the transition period from:_____________ to _____________

Commission File Number: 001-34732

———————

MILLER PETROLEUM, INC.

(Exact 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.)

3651 Baker Highway, Huntsville, TN 37756

(Address of Principal Executive Offices) (Zip Code)

(865) 223-6575

(Registrant’s telephone number, including area code)

N/A

(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.				ü	Yes		No

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

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

Large accelerated filer			Accelerated filer
Non-accelerated filer	(Do not check if a smaller		Smaller reporting company			ü
	reporting company)

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Title of Class		No. of Shares Outstanding at March 14, 2011
Common Stock		39,667,751

MILLER PETROLEUM, INC.

FORM 10-Q

JANUARY 31, 2011

TABLE OF CONTENTS

Page

No.

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements.

Unaudited Consolidated Balance Sheets at January 31, 2011 and April 30, 2010

Unaudited Consolidated Statements of Operations for the Three and Nine Month Periods Ended

January 31, 2011 and 2010

Unaudited Consolidated Statement of Cash Flows for the Nine Month Period Ended

January 31, 2011 and 2010

Notes to Unaudited Consolidated Financial Statements

Item 2.

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

Item 3.

Quantitative and Qualitative Disclosures About Market Risk.

Item 4.

Controls and Procedures.

PART II – OTHER INFORMATION

Unregistered Sales of Equity Securities and Use of Proceeds

Item 3.

Defaults Upon Senior Securities.

Item 4.

(Removed and Reserved).

EXPLANATORY NOTE

On March 17, 2011 the Audit Committee of the Board of Directors of Miller Petroleum, Inc. determined that our unaudited consolidated balance sheet at July 31, 2010, and our unaudited consolidated statements of operations and cash flows for the period ended July 31, 2010, as well as our unaudited consolidated balance sheet at October 31, 2010, and our unaudited consolidated statements of operations and cash flows for the three and six month periods ended October 31, 2010 could no longer be relied upon as a result of errors in those financial statements. We failed to properly accrete our asset retirement obligations in each of the first two quarters of fiscal 2011. In these periods we also failed to properly record depletion, depreciation and amortization expenses related to leasehold costs, wells and equipment, fixed assets and asset retirement obligations and did not properly record the state tax credits expected from our Alaska operations.

Accordingly, our unaudited consolidated balance sheet at July 31,2010 and the unaudited consolidated statement of operations and unaudited consolidated statement of cash flows for the three month period ended July 31, 2010 as contained in our Quarterly Report on Form 10-Q for the period ended July 31, 2010, together with our unaudited consolidated balance sheet at October 31, 2010 and the unaudited consolidated statement of operations and unaudited consolidated statement of cash flows for the three and six month periods ended October 31, 2010 as contained in our Quarterly Report on Form 10-Q for the period ended October 31, 2010 will be restated.

The Audit Committee of our Board of Directors has discussed the matters disclosed in this filing with KPMG LLP, our current independent registered public accounting firm. In addition, our Chief Financial Officer has discussed the matters disclosed in this filing with Sherb & Co., LLP, our former independent registered public accounting firm.

See footnote 13 in the notes to the unaudited consolidated financial statements for restatement corrections applied to these periods.

OTHER PERTINENT INFORMATION

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

The information which appears on our web site at www.millerenergyresources.com is not part of this report.

PART I - FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS.

MILLER PETROLEUM, INC.

UNAUDITED CONSOLIDATED BALANCE SHEETS

ASSETS


	January 31, 2011		April 30, 2010
CURRENT ASSETS

Cash	$	3,158,946	$	2,750,841
Cash, restricted		290,531		126,064
Accounts receivable, net		1,428,932		1,444,844
Accounts receivable - related parties		58,737		47,446
State production tax credits receivable		5,417,126		1,107,000
Inventory		528,573		521,639
Prepaid expenses		1,926,357		275,610

Total Current Assets		12,809,202		6,273,444

PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, net
(On the basis of successful efforts accounting)		480,387,148		484,216,621
Fixed assets, net		8,016,302		6,820,779
Land		526,500		526,500

Total Property, Plant and Equipment		488,929,950		491,563,900

OTHER ASSETS
Cash - restricted, long-term		2,299,538		2,071,839
Other assets		289,009		542,972

Total Other Assets		2,588,547		2,614,811

TOTAL ASSETS	$	504,327,699	$	500,452,155

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

MILLER PETROLEUM, INC.

UNAUDITED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND STOCKHOLDERS' EQUITY


	January 31, 2011		April 30, 2010

CURRENT LIABILITIES

Accounts payable – trade	$	9,124,924	$	3,579,112
Accounts payable – related parties		58,692		—
Accrued expenses		766,507		421,938
Current derivative liability		6,012		720,840
Unearned revenue		41,443		106,443
Short-term payable		2,500,000		—

Total Current Liabilities		12,497,578		4,828,333

LONG-TERM LIABILITIES

Deferred income tax liability		184,468,878		184,468,878
Asset retirement liability		16,913,376		15,662,002
Long-term derivative liability		1,255,279		16,708,947
Notes payable - related parties, net		2,350,419		1,803,775
Notes payable - other, net		—		1,239,399

Total Long-term Liabilities		204,987,952		219,883,001

Total Liabilities		217,485,530		224,711,334

STOCKHOLDERS' EQUITY

Common stock, 500,000,000 shares authorized at $0.0001 par value, 39,409,751 and 32,224,894 shares issued and outstanding, respectively		3,941		3,223
Additional paid-in capital		43,866,501		27,620,605
Retained earnings		242,971,727		248,116,993

Total Stockholders' Equity		286,842,169		275,740,821

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	504,327,699	$	500,452,155

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

MILLER PETROLEUM, INC.

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS


	For the Three Months Ended January 31, 2011			For the Three Months Ended January 31, 2010			For the Nine Months Ended January 31, 2011			For the Nine Months Ended January 31, 2010
							(as restated)
REVENUES
Oil and gas revenue	$	7,039,457		$	438,525		$	17,912,429		$	1,055,142
Service and drilling revenue		775,664			723,582			1,778,601			967,989

Total Revenue		7,815,121			1,162,107			19,691,030			2,023,131

COSTS AND EXPENSES
Cost of oil and gas revenue		2,994,888			201,341			8,910,577			229,718
Cost of service and drilling revenue		691,504			1,916,638			1,528,659			2,375,291
State production tax credits, net		(2,015,535	)		—			(908,535	)		—
Selling, general and administrative		3,219,651			2,623,553			9,135,066			4,304,785
Depreciation, depletion and amortization		3,357,654			630,251			10,506,628			1,136,835

Total Costs and Expenses		8,248,162			5,371,783			29,172,395			8,046,629

LOSS FROM OPERATIONS		(433,041	)		(4,209,676	)		(9,481,365	)		(6,023,498	)

OTHER INCOME (EXPENSE)
Interest income		9,253			6,295			14,979			21,766
Interest expense		(111,162	)		(121,848	)		(740,920	)		(140,975	)
Gain on derivative instruments		1,444,900			—			5,132,795			—
Loan fees and costs		—			(576,086	)		(90,755	)		(691,463	)
Gain (loss) on sale of equipment		—			—			7,500			(9,755	)
Gain on sale of oil and gas properties		—			—			12,500			—
Gain on acquisitions		—			472,473,332			—			474,292,096

Total Other Income		1,342,991			471,781,693			4,336,099			473,471,669

INCOME (LOSS) BEFORE INCOME TAXES		909,950			467,572,017			(5,145,266	)		467,448,171
INCOME TAX EXPENSE		—			(195,619,527	)		—			(195,579,490	)

NET INCOME (LOSS)	$	909,950		$	271,952,490		$	(5,145,266	)	$	271,868,681

INCOME (LOSS) PER SHARE
Basic	$	0.02		$	12.44		$	(0.15	)	$	14.14
Diluted	$	0.02		$	9.51		$	(0.15	)	$	10.47

WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		37,774,861			21,856,076			34,975,126			19,227,773
Diluted		41,392,130			28,597,465			34,975,126			25,969,162

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

MILLER PETROLEUM, INC.

UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS


	For the Nine Months Ended January 31, 2011			For the Nine Months Ended January 31, 2010
	(as restated)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (loss)	$	(5,145,266	)	$	271,868,681

Adjustments to Reconcile Net Income (Loss) to Net Cash Provided (Used) by Operating Activities:
Depreciation, depletion and amortization		10,506,628			1,136,835
Loss (gain) on sale of equipment		(7,500	)		9,755
Gain on sale of oil and gas properties		(12,500	)		—
Gain on acquisitions		—			(474,292,096	)
Write off of prepaid offering costs		—			361,118
Issuance of equity for services		—			1,093,693
Issuance of equity for compensation		2,042,165			—
Issuance of equity for financing costs		—			235,588
Deferred income taxes		—			195,509,068
Gain on derivative instruments		(5,132,795	)		—
State production tax credits		(908,535	)		—

Changes in Operating Assets and Liabilities:
Accounts receivable		4,621			(550,830	)
Inventory		(6,934	)		67,277
Prepaid expense		(1,650,747	)		(20,651	)
Accounts payable		5,604,504			715,254
Accrued liabilities		344,569			(54,032	)
Deferred revenue		(65,000	)		(22,064	)
Asset retirement liability		125,387			184,681
Deferred interest		—			6,892
Other assets		603,434			—

Net Cash Provided (Used) by Operating Activities	$	6,302,031		$	(3,750,831	)

CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of equipment and improvements		(808,662	)		(43,382	)
Proceeds from the sale of oil and gas properties		12,500			25,000
Capital expenditures for oil and gas properties		(8,573,846	)		(20,849	)
Proceeds from sale of equipment		7,500			50,000
Purchase of Alaska assets		—			(4,541,251	)

Net Cash Used by Investing Activities	$	(9,362,508	)	$	(4,530,482	)

CASH FLOWS FROM FINANCING ACTIVITIES
Payments on notes payable		—			(1,959,205	)
Payments for debt acquisition costs		—			(619,360	)
Proceeds from borrowing		2,850,000			5,576,444
Proceeds from sale of stock, net		—			5,689,000
Cash acquired through acquisition		—			203,993
Exercise of equity rights		1,010,748			1,800
Restricted cash		(164,467	)		1,851,053
Restricted cash non-current		(227,699	)		(792	)

Net Cash Provided by Financing Activities	$	3,468,582		$	10,742,933

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

MILLER PETROLEUM, INC.

UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS

(continued)


	For the Nine Months Ended January 31, 2011		For the Nine Months Ended January 31, 2010
	(as restated)
NET INCREASE IN CASH		408,105		2,461,620

CASH, BEGINNING OF PERIOD		2,750,841		46,566

CASH, END OF PERIOD	$	3,158,946	$	2,508,186

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

MILLER PETROLEUM, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(1)

ORGANIZATION AND DESCRIPTION OF BUSINESS

These consolidated financial statements include the accounts of Miller Petroleum, Inc. (the "Company") and the accounts of its subsidiaries, Miller Drilling TN, LLC, Miller Energy Services, LLC, East Tennessee Consultants, Inc. and East Tennessee Consultants II, LLC, Miller Energy GP, LLC and Cook Inlet Energy, LLC (“CIE”).

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

Certain information and footnote disclosures normally included in the financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted. It is suggested that these financial statements be read in conjunction with the Company's April 30, 2010 Annual Report on Form 10-K. The results of operations for the period ended January 31, 2011 are not necessarily indicative of operating results for the full year. In the opinion of management, all adjustments (consisting of only normal recurring accruals) considered necessary for a fair presentation have been included.

(2)

ACCOUNTING POLICIES

Reclassifications

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

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly-owned at January 31, 2011. All material intercompany transactions have been eliminated.

Use of Estimates

The preparation of the Company's unaudited consolidated financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Company's unaudited consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company's unaudited consolidated financial statements are based on a number of significant estimates, including the revenue and expense accruals, deferred tax assets and liabilities, depletion, depreciation and amortization, asset impairments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months' financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month's financial results. Management believes that the operating results presented for the three and nine month periods ended January 31, 2011 represent actual results in all material respects.

MILLER PETROLEUM, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(2)

ACCOUNTING POLICIES (Continued)

Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset's estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of the Company's oil and gas properties is done by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company's plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

Oil and gas properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of oil and gas properties or unproved properties recorded by the Company for the nine month periods ended January 31, 2011 and 2010.

Inventory

Inventory consists primarily of crude oil in tanks and is carried at the lower of cost or market on a "FIFO" basis.

Recent Accounting Pronouncements

All issued, but not yet effective accounting pronouncements are determined to be not applicable or significant by management and once adopted are not expected to have a material impact on the financial position of the Company.

(3)

PARTICIPANT RECEIVABLES, RELATED PARTY RECEIVABLES AND PAYABLES

Participant and related party receivables consist of receivables contractually due from our various joint venture partners in connection with routine exploration, betterment and maintenance activities. Our collateral for these receivables generally consists of lien rights over the related oil producing properties.

Accounts receivable, related parties was $58,737 and $47,446 at January 31, 2011 and April 30,2010, respectively. This was primarily due to account receivables from members of its Board of Directors, and families, at January 31, 2011 and April 30, 2010 in the amounts of $38,758 and $46,450, respectively, for work performed on oil and gas wells. One board member and his son own partial interests in oil and gas wells the Company also owns.

The Company had notes payable (net of discount) at January 31, 2011 and April 30, 2010 of $2,350,419 and $1,803,775, respectively, to Miller Energy Income, 2009, LP (“MEI”). MEI's general partner is Miller Energy GP, LLC, a 100% owned subsidiary of the Company.

MILLER PETROLEUM, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

FIXED ASSETS


	January 31, 2011			April 30, 2010
Machinery & Equipment	$	5,325,031		$	4,620,219
Vehicles		1,952,675			1,402,094
Buildings		2,682,810			2,682,810
Office Equipment		83,681			77,411

		10,044,197			8,782,534
Less: accumulated depreciation		(2,027,895	)		(1,961,755	)

Net Fixed Assets	$	8,016,302		$	6,820,779

(5)

DERIVATIVES

Effective May 1, 2009, the Company adopted the provisions of Emerging Issues Task Force (“EITF”) 07-05, Determining Whether an Instrument (or Embedded Feature) is Indexed to a Company's Own Stock, which was codified into Accounting Standards Codification (“ASC”) Topic 815, Derivatives and Hedging. ASC Topic 815 applies to any freestanding financial instruments or embedded features that have characteristics of a derivative and to any freestanding financial instruments that are potentially settled in an entity's own common stock. As of January 31, 2011, the Company has 1,016,715 of warrants with exercise reset provisions, which are considered freestanding derivative instruments. ASC Topic 815 requires these warrants to be recorded as liabilities as they are no longer afforded equity treatment. The Company issued 716,715 warrants in an equity financing in March 2010 and 300,000 warrants pursuant to a consulting arrangement in March 2010. These warrants are still outstanding as of January 31, 2011 and are recorded at $1,255,279. The derivative liability as of April 30, 2010 of $17,429,787 relates to 2,013,814 warrants issued in connection with financing transactions. Such warrants were subject to a dispute that was resolved on December 3, 2010. Accordingly, these warrants are no longer outstanding as of January 31, 2011.

The Company utilized the Black-Scholes pricing model for the 716,715 and 300,000 warrants with the following weighted average assumptions: a risk free rate of 0.98%, expected life terms ranging from 1.2 years to 1.3 years, an expected volatility of 44% and a dividend rate of 0.0%. During the nine months ended January 31, 2011, the Company recorded non-cash gains of $5,138,807 relating to the change in fair value of these derivative instruments.

As of January 1, 2011, the Company entered into a commodity derivative financial instrument. These instruments are used to manage the inherent uncertainty of future revenues due to oil price volatility and to manage the Company’s exposure to oil pricing volatility. The Company has elected not to designate any of its derivative instruments for hedge accounting treatment. As a result, both realized and unrealized gains and losses are recognized in earnings. The liability recorded for this instrument as of January 31, 2011 is $6,012, which is also the unrealized los recognized in earnings for the three and nine month periods ended January 31, 2011.

(6)

FAIR VALUE MEASUREMENTS

ASC Topic 820, Fair Value Measurements and Disclosures, 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. ASC Topic 820 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;

MILLER PETROLEUM, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(6)

FAIR VALUE MEASUREMENTS (Continued)

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 January 31, 2011 and April 30, 2010 are as follows:


	Fair Value Measurements at Reporting Date Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
April 30, 2010:
Warrant Derivatives	$	—	$	—	$	17,429,787

January 31, 2011:
Warrant Derivatives	$	—	$	—	$	1,255,279
Commodity Derivatives		—		—		6,012

The following table presents cash settlements and unrealized gains and losses on fair value changes included in the accompanying unaudited consolidated statements of operations associated with these derivative financial instruments. Cash settlements and unrealized gains and losses on fair value changes associated with the Company’s oil pricing derivatives are presented in the “Gain on derivative instruments” caption in the accompanying consolidated statements of operations.


	For the Three Months Ended January 31, 2011			For the Three Months Ended January 31, 2010		For the Nine Months Ended January 31, 2011			For the Nine Months Ended January 31, 2010
Cash Settlements
Oil price derivatives	$	23,724		$	—	$	23,724		$	—
Total Cash Settlements		23,724			—		23,724			—

Unrealized Losses:
Oil price derivatives	$	(6,012	)	$	—	$	(6,012	)	$	—
Total Unrealized Losses		(6,012	)		—		(6,012	)		—

MILLER PETROLEUM, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(7)

LONG-TERM DEBT

The Company had the following debt obligations at January 31, 2011 and April 30, 2010:


	January 31, 2011			April 30, 2010
6% convertible secured promissory notes, secured by 35,235 lease acreage, bearing interest at 6%, due December 4, 2016	$	—		$	1,705,000

Secured promissory notes, secured by certain equipment, bearing interest at 12%, due November 1, 2013 and December 1, 2013		3,071,444			2,721,444
Total Notes Payable		3,071,444			4,426,444
Less current maturities on other notes payable		—			—
Less debt discount		(721,025	)		(1,383,270	)
Notes Payable - Long-term	$	2,350,419		$	3,043,174

In December 2009, the Company raised $2,855,000 as 6% convertible secured promissory notes. From April 6, 2010 through October 18, 2010, the convertible secured notes, including any accrued and unpaid interest were converted into shares of the Company’s common stock at $0.55 per share. The conversion price was below market at the time the debt was initiated and the fair value of this beneficial conversion feature was computed to be $829,263. This beneficial conversion feature was recorded as a debt discount and was being amortized over the term of the debt. Amortization expense for the nine month period ended January, 31 2011 was $116,130.

On November 1, 2009, December 15, 2009 and May 15, 2010, MEI, a controlled entity of the Company, extended loans, as amended, of $2,365,174, $356,270, and $350,000, respectively, totaling $3,071,444 to the Company. These loans bear interest at a rate of 12% per year and are due November 1, 2013 and December 1, 2013. These loans require monthly payments of interest only, with the principal due at the maturity date. The Company provided oil and gas drilling equipment as collateral for the loan. The Company issued 1,329,250 shares of common stock and 1,329,250 warrants to purchase common stock at an exercise price of a $1.00 per share. These common shares and warrants issued had a fair value of $1,048,765, which have been recorded as a debt discount to be amortized over 48 month periods, the term of such debt. Amortization expense of the debt discount costs for the nine month period ended January 31, 2011 was $196,644.

ASC Subtopic 410-20, Accounting for Asset Retirement Obligations, addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement requires companies to record the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. The liability is capitalized as part of the estimated costs to capitalize a well and site remediation once a well is abandoned. Over time, accretion of the liability is recognized as an operating expense and the capitalized cost is depreciated over the expected useful life of the related asset. Changes in the Company's liability for the nine month period ended January 31, 2011 are as follows:


Asset retirement obligation as of April 30, 2010	$	15,662,002
Accretion expense		1,125,987
Estimate revisions		125,387
Asset retirement obligation as of January 31, 2011	$	16,913,376

MILLER PETROLEUM, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(8)

STOCKHOLDERS' EQUITY

During the nine months ended January 31, 2011, we issued the following securities: 7,184,857 shares, which included four warrant holders who exercised warrants for 194,600 shares in a cashless exercise that netted the holders 153,784 shares and eight other warrant holders exercised warrants for 1,268,750 shares for exercise prices ranging from $0.01 to $2.00 per share. In addition, fifteen note holders converted $1,705,000 of their 6% secured convertible notes at a conversion rate of $0.55 and we issued 3,099,999 shares. We also issued 30,000 shares to an advisor to the Company’s Board of Directors for services rendered. 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. On November 17, 2010, we issued 100,000 shares of stock in a transaction in which we acquired a jet from three sellers, one of which is a consultant to the Company. Another one of the sellers is affiliated with that consultant. The seller is an unrelated party. The Board of Directors made a good faith valuation of the jet at approximately $550,000, based on the value of comparable jets. We plan on leasing the jet when it is not in use by us. On December 3, 2010, we entered into a settlement agreement with Prospect Capital Corporation (“Prospect”) to resolve all potential claims arising from the loan transaction in May 2004 in which Prospect acted as one of the lenders. This dispute was rooted in the same facts and circumstances as the previously settled lawsuit with Petro Capital III, LP and Petro Capital Advisors, LLC. The terms of the settlement agreement are similar to the terms upon which Petro settled their claims. We issued Prospect a total of 2,013,814 shares of our common stock, in exchange for waivers of their claims.

The shares are subject to certain volume limitations for future sales. The Company also issued 3,175,000 employee and director options between February 18, 2010 and January 31, 2011 and 100,000 options to an advisor to the Company’s Board of Directors on October 1, 2010 which is included in non-cash compensation expense of $2,042,166 for the nine month period ended January 31, 2011.

The Company presents "basic" earnings (loss) per share and, if applicable, "diluted" earnings per share pursuant to the accounting guidance issued by the FASB. The calculation of diluted earnings per share is similar to that of basic earnings per share, except that the denominator is increased to include the number of additional common shares that would have been outstanding if all potentially dilutive common shares, such as those issuable upon the exercise of stock options and warrants, were issued during the period.

As of January 31, 2011, the exercise price of warrants and options below market value was $7,442,087, and therefore there are dilutive effects of the common stock equivalents for the outstanding vested stock options and warrants for the nine month period ended January 31, 2011.

(9)

STOCK OPTIONS AND WARRANTS

We record share-based payments at fair value and record compensation expense for all share-based awards granted, modified, repurchased or cancelled after the effective date, in accord with ASC Topic 718, Share Based Compensation. We record compensation expense for outstanding awards for which the requisite service had not been rendered as of the effective date over the remaining service period.

We estimated the fair value of options and warrants outstanding granted during the nine month periods ended January 31, 2011 and 2010 on the date of grant, using the Black-Scholes pricing model with the following assumptions:


	2011		2010
Weighted average of expected risk-free interest rates (approximate three-year Treasury Bill rate)		1.44%		1.43%
Expected years from vest date to exercise date		2.8		2.2
Expected stock volatility		34-72%		314-403%
Expected dividend yield		0%		0%

MILLER PETROLEUM, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(9)

STOCK OPTIONS AND WARRANTS (Continued)

ASC Subtopic 718-10 requires companies to expense the value of employee stock options and similar awards and applies to all outstanding and vested stock-based awards. In computing the impact, the fair value of each option is estimated on the date of grant based on the Black-Scholes options-pricing model utilizing certain assumptions for a risk free interest rate; volatility; and expected remaining lives of the awards. The assumptions used in calculating the fair value of share-based payment awards represent management's best estimates, but these estimates involve inherent uncertainties and the application of management judgment.

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

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

The Company recorded $2,042,166 and $697,683 of compensation expense, net of related tax effects, relative to stock options and warrants for the nine month period ended January 31, 2011 and 2010, respectively. Net loss per basic share for this expense is $0.06 and $0.04 and net loss per diluted share for this expense is $0.05 and $0.03.

The aggregate intrinsic value is calculated as the difference between the exercise price of the underlying awards and the quoted price of our common stock for those awards that have an exercise price currently below the closing price. During the nine months ended January 31, 2011 and 2010, the aggregate intrinsic value of stock options and warrants outstanding was $17,711,809 and $9,058,525, respectively.

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


	Nine Months Ended January 31, 2011					Nine Months Ended January 31, 2010
	Number of Options and Warrants			Weighted Average Exercise Price		Number of Options and Warrants			Weighted Average Exercise Price
Balance at April 30, 2010		12,306,305		$	1.50		4,090,000		$	0.88
Granted		3,275,000			5.82		6,671,750			1.00
Exercised		(4,052,534	)		0.62		(685,430	)		0.00
Expired		—			—		(75,000	)		0.82
Cancelled		(140,816	)		4.59		(194,570	)		0.94

Balance at January 31, 2011		11,387,955			3.90		9,806,750			0.98

Options exercisable at January 31. 2011		4,562,955		$	1.92		7,119,250		$	0.85

MILLER PETROLEUM, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(9)

STOCK OPTIONS AND WARRANTS (Continued)

The following table summarizes information concerning stock options and warrants outstanding and exercisable at January 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 0.40		850,000		3.7	$	0.22		725,000	$	0.20
1.00 to 1.82		2,370,900		3.3		1.03		2,370,900		1.03
2.00 to 4.98		1,850,000		4.4		2.61		550,000		2.41
5.28 to 5.94		3,692,055		8.3		5.72		917,055		5.31
6.00 to 6.94		2,625,000		5.2		6.03		—		—
		11,387,955		5.5	$	3.90	$	4,562,955	$	1.92

(10)

STATE PRODUCTION TAX CREDITS

The Company operates several oil and gas wells in Alaska and has leased properties for other oil and gas exploration purposes. Alaska has investment tax incentives whereby through June 30, 2010, up to 20% of certain qualified expenditures are reimbursable via a tax credit which can be sold to other oil and gas companies at a discount to obtain an immediate realization of such benefits or such tax credits could be utilized by the Company to offset production taxes due or obtain a refund based on certain future reinvestment criteria. Effective July 1, 2010, the state of Alaska has increased the tax incentive rate from 20% to 40% and relaxed the criteria for a refund requirement to be obtained from the state of Alaska. Additionally, the state allows for a tax credit of 25% of a carried-forward annual loss, the amount of the producer’s or explorer’s “adjusted lease expenditures” for a previous calendar year that was not deductible for that year.

The Company recognizes Alaska production tax credits in its financial statements in the period in which the tax credit is reasonably estimable and probable of occurrence. The qualified expenditure credits are recorded quarterly and are included as a reduction to property, plant and equipment and are amortized against depletion expense or depreciation expense over the estimated useful life of the related property plan and equipment. The Company recorded $187,390 and $0 of amortization as a reduction to depletion expense during the nine month period ended January 31, 2011 and 2010. The carried-forward annual loss credits are recorded annually as a reduction to operating expenses.

The Company has recorded $3,401,591 and $1,107,000 in qualified expenditure tax credits receivable as of January 31, 2011 and April 30, 2010. The Company has recorded $2,015,535, and $0 in carry-forward annual loss credits receivable as of January 31, 2011 and April 30, 2010.

(11)

LITIGATION

CNX Gas Company, LLC commenced litigation on June 11, 2008 in the Chancery Court of Campbell County, State of Tennessee in a case style CNX Gas Company, LLC vs. Miller Petroleum Inc., Civil Action No. 08-071, 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. A Notice of Lien Lis Pendens was issued June 11, 2008. We moved for entry of summary judgment dismissing the claims asserted against us by CNX and on January 30, 2009 the court found that CNX's claims had no merit. The court granted our motion and dismissed all claims asserted by CNX in that action. CNX has appealed the ruling, and briefs have been submitted to the Court of Appeals of Tennessee. Oral arguments were held on May 18, 2010, and an opinion from the Court of Appeals is expected soon.

MILLER PETROLEUM, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(11)

LITIGATION (Continued)

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 the oil and gas lease owned by us is still in full force and effect. The defendant filed an Answer and Counterclaim, seeking in the Counterclaim a declaration that the oil and gas lease has expired. Although no compensatory monetary damages have been sought against us, the Counterclaim does seek attorney fees, expenses and costs. On October 27, 2010, a temporary injunction was granted allowing us access to the property at issue in this case. We are presently conducting discovery.

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

(12)

SUBSEQUENT EVENTS

On February 11, 2011 we were awarded Susitna Basin Exploration License No. 4 from the State of Alaska Department of Natural Resources (“DNR”). The license encompasses 62,909 acres and will have a ten-year term. Our work commitment is $2.25 million. We countersigned the lease on March 3, 2011 and placed a $225,000 bond on March 8, 2011. The DNR Director signed the license on March 18, 2011.

CIE was one of nine successful bidders in the State of Alaska's Division of Oil & Gas Cook Inlet Area wide 2010 Competitive Oil and Gas Lease Sale. CIE acquired seven tracts which cover an estimated 17,187 acres upon payment of the balance of the purchase price, which was $451,274. This amount was paid on February 8, 2011, and the leases were issued on February 25, 2011 with an effective date of March 1, 2011. All of these tracts complete acreage positions covering prospects acquired in CIE's purchase of a portfolio of Pacific Energy Alaska assets. We have not included this acreage in our calculation of gross or net lease acres in this report.

On February 15, 2011, we received a cash payment of approximately $1,500,000 pursuant to the true-up. CIPL retained another $250,000 that will be credited toward our costs on our next shipments.

On March 11, 2011, CIE entered into a Performance Bond Agreement with the DNR concerning certain bonding requirements initially established by the Assignment Oversight Agreement between these two parties dated November 5, 2009. The performance bond is intended to ensure that CIE has sufficient funds to meet its dismantlement, removal and restoration obligations under the applicable agreements, leases, and state laws and regulations. The Performance Bond Agreement applies only to the Redoubt Unit and Redoubt Shoal Field, and sets forth an amount of $18,000,000 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 $6,600,000 (as of June 30, 2010) 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 $6.6 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.

MILLER PETROLEUM, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(12)

SUBSEQUENT EVENTS (Continued)

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.

We entered into an employment agreement with our Chief Financial Officer, Mr. Paul W. Boyd, on March 11, 2011. The employment agreement has a one year term and will automatically renew for successive one year periods unless either party delivers a notice of non-renewal 60 days prior to the termination date. Mr. Boyd’s base salary is $185,000, which is consistent with the terms of his hire. Mr. Boyd also receives a $500 per month automobile allowance and he is eligible for an annual performance bonus to be determined each year by the Compensation Committee of the Board of Directors. The agreement contains a maximum severance amount of one year’s salary, which is only payable in the case of termination without cause, and a one-year non-compete clause. Upon a termination of employment because of a change in control, Mr. Boyd will be paid an amount equal to 2.99 multiplied by his annualized salary that he is then earning, payable in a lump-sum payment upon the closing of the change in control. Mr. Boyd may also terminate the agreement without cause upon 90 days notice to us. We will pay for all of Mr. Boyd’s expenses incurred in maintaining his professional license as a Certified Public Accountant. Mr. Boyd is entitled to receive the same benefits that all of our employees receive with respect to health and life insurance.

On March 16, 2011, the State of Alaska Department of Natural Resources approved the Redevelopment Plan for the Redoubt Unit. Along with the previously disclosed bond agreement that we entered into on March 11, 2011, we have now met the State’s requirements to bring the offshore Osprey oil platform out of lighthouse mode and back into production.

(13)

RESTATEMENT

As disclosed in our Current Report on Form 8-K filed on March 18, 2011, on March 17, 2011 the Audit Committee of the Board of Directors of Miller Petroleum, Inc. determined that our unaudited consolidated balance sheet at July 31, 2010, and our unaudited consolidated statements of operations and cash flows for the period ended July 31, 2010, as well as our unaudited consolidated balance sheet at October 31, 2010, and our unaudited consolidated statements of operations and cash flows for the three and six month periods ended October 31, 2010 could no longer be relied upon as a result of errors in those financial statements. We failed to properly accrete our asset retirement obligations in each of the first two quarters of fiscal 2011. In these periods we also failed to properly record depletion, depreciation and amortization expenses related to leasehold costs, wells and equipment, fixed assets and asset retirement obligations and did not properly record the state tax credits expected from our Alaska operations.

MILLER PETROLEUM, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(13)

RESTATEMENT (Continued)

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


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

CURRENT ASSETS
Cash	$	472,543	$	—		$	472,543
Cash, restricted		126,379		—			126,397
Accounts receivable, net		1,444,047		—			1,444,047
Accounts receivable – related parties		45,573		—			45,573
State production tax credits receivable		1,603,358		—			1,603,358
Inventory		767,678		—			767,678
Prepaid expenses		177,556		—			177,556
Total Current Assets		4,637,134		—			4,637,134

PROPERTY PLANT AND EQUIPMENT
Oil and gas properties, net (On the basis of successful efforts accounting)		486,509,510		(3,271,141	)		483,238,369
Fixed assets, net		6,577,983		665,553			7,243,536
Land		526,500		—			526,500
Total Property, Plant and Equipment		493,613,993		(2,605,588	)		491,008,405

OTHER ASSETS
Cash – restricted, long-term		2,070,445		—			2,070,445
Other assets		599,550		—			599,550
Total Other Assets		2,669,995		—			2,669,995

TOTAL ASSETS	$	500,921,122	$	(2,605,588	)	$	498,315,534

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable – trade	$	5,244,203	$	—		$	5,244,203
Accrued expenses		440,570		—			440,570
Current derivative liability		326,950		—			326,950
Unearned revenue		41,442		—			41,442
Total Current Liabilities		6,053,165		—			6,053,165

LONG-TERM LIABILITIES
Deferred income tax liability		184,367,963		—			184,367,963
Asset retirement liability		15,662,003		639,017			16,301,020
Long-term derivative liability		14,196,880		—			14,196,880
Notes payable – related parties, net		2,219,323		—			2,219,323
Notes payable – other, net		885,421					885,421
Total Long-term Liabilities		217,331,590		639,017			217,970,607
Total Liabilities		223,384,755		639,017			224,023,772

STOCKHOLDERS’ EQUITY
Common stock		3,339		—			3,339
Additional paid-in capital		28,733,128		—			28,733,128
Retained earnings		248,799,900		(3,244,605	)		245,555,295
Total Stockholders’ Equity		277,536,367		(3,244,605	)		274,291,762

TOTAL LIAB. AND STOCKHOLDERS’ EQUITY	$	500,921,122	$	(2,605,588	)	$	498,315,534

MILLER PETROLEUM, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(13)

RESTATEMENT (Continued)

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


	For the Three Months Ended July 31, 2010 As Reported			Corrections			For the Three Months Ended July 31, 2010 As Restated
REVENUES
Oil and gas revenue	$	4,791,179		$	—		$	4,791,179
Service and drilling revenue		409,068			—			409,068
Total Revenue		5,200,247			—			5,200,247

COSTS AND EXPENSES
Cost of oil and gas revenue		2,304,107			—			2,304,107
Cost of service and drilling revenue		495,747			—			495,747
State production tax expense		—			1,107,000			1,107,000
Selling, general and administrative		2,662,415			—			2,662,415
Depreciation, depletion and amortization		2,094,930			1,641,247			3,736,177
Total Costs and Expenses		7,557,199			2,748,247			10,305,446

LOSS FROM OPERATIONS		(2,356,952	)		(2,748,247	)	$	(5,105,199	)

OTHER INCOME(EXPENSE)
Interest income		4,553			—			4,533
Interest expense		(219,338	)		—			(219,338	)
Gain on derivative instruments		2,905,957			—			2,905,957
Loan fees and costs		(90,380	)					(90,380	)
Gain on sale of oil and gas properties		12,500			—			12,500
Total Other Income		2,613,292			—			2,613,292

INCOME (LOSS) BEFORE INCOME TAXES		256,340			(2,748,247	)		(2,491,907	)
INCOME TAX BENEFIT (EXPENSE)		426,567			(496,358	)		(69,791	)
NET INCOME (LOSS)	$	682,907		$	(3,244,605	)	$	(2,561,698	)
INCOME (LOSS) PER SHARE
Basic	$	0.02					$	(0.08	)
Diluted	$	0.02					$	(0.08	)

WEIGHTED AVERAGE SHARES OUTSTANDING
Basic		32,835,722						32,835,722
Diluted		40,591,670						32,835,722

MILLER PETROLEUM, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(13)

RESTATEMENT (Continued)

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


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

CURRENT ASSETS
Cash	$	986,547	$	—		$	986,547
Cash, restricted		126,697		—			126,697
Accounts receivable, net		1,676,475		—			1,676,475
Accounts receivable – related parties		49,740		—			49,740
State production tax credits receivable		2,167,044		—			2,167,044
Inventory		627,746		—			627,746
Prepaid expenses		1,487,444		—			1,487,444
Total Current Assets		7,121,693		—			7,121,693

PROPERTY PLANT AND EQUIPMENT
Oil and gas properties, net (On the basis of successful efforts accounting)		486,714,358		(5,083,492	)		481,630,866
Fixed assets, net		6,170,884		916,545			7,087,429
Land		526,500		—			526,500
Total Property, Plant and Equipment		493,411,742		(4,166,947	)		489,244,795

OTHER ASSETS
Cash – restricted, long-term		2,314,517		—			2,314,517
Other assets		476,050		—			476,050
Total Other Assets		2,790,567		—			2,790,567

TOTAL ASSETS	$	503,324,002	$	(4,166,947	)	$	499,157,055

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable – trade	$	8,604,077	$	—		$	8,604,077
Accrued expenses		399,517		—			399,517
Current derivative liability		11,035,701		—			11,035,701
Unearned revenue		108,473		—			108,473
Income taxes payable		272,950		(272,950	)		—
Total Current Liabilities		20,420,718		(272,950	)		20,147,768

LONG-TERM LIABILITIES
Deferred income tax liability		184,195,928		272,950			184,468,878
Asset retirement liability		15,662,003		882,502			16,544,505
Long-term derivative liability		2,706,191		—			2,706,191
Notes payable, related parties, net		2,284,871		—			2,284,871
Total Long-term Liabilities		204,848,993		1,155,452			206,004,445
Total Liabilities		225,269,711		882,502			226,152,213

STOCKHOLDERS’ EQUITY
Common stock		3,617		—			3,617
Additional paid-in capital		30,939,449		—			30,939,449
Retained earnings		247,111,225		(5,049,449	)		242,061,776
Total Stockholders’ Equity		278,054,291		(5,049,449	)		273,004,842

TOTAL LIAB. AND STOCKHOLDERS’ EQUITY	$	503,324,002	$	(4,166,947	)	$	499,157,055

MILLER PETROLEUM, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(13)

RESTATEMENT (Continued)

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


	For the Three Months Ended Oct. 31, 2010 As Reported			Corrections			For the Three Months Ended Oct. 31, 2010 As Restated
REVENUES
Oil and gas revenue	$	6,081,793		$	—		$	6,081,793
Service and drilling revenue		593,869			—			593,869
Total Revenue		6,675,662			—			6,675,662

COSTS AND EXPENSES
Cost of oil and gas revenue		3,611,582			—			3,611,582
Cost of service and drilling revenue		341,408			—			341,408
Selling, general and administrative		3,148,743			(69,792	)		3,078,951
Depreciation, depletion and amortization		2,275,897			1,241,159			3,517,056
Total Costs and Expenses		9,377,630			1,171,367			10,548,997

LOSS FROM OPERATIONS		(2,701,968	)		(1,171,367	)		(3,873,335	)

OTHER INCOME (EXPENSE)
Interest income		1,174			—			1,174
Interest expense		(410,422	)		—			(410,422	)
Gain on derivatives		781,938			—			781,938
Loan fees and costs		(375	)		—			(375	)
Gain on sale of equipment		7,500			—			7,500
Total Other Income		379,815			—			379,815

LOSS BEFORE INCOME TAXES		(2,322,153	)		(1,171,367	)		(3,493,520	)
INCOME TAX BENEFIT (EXPENSE)		633,477			(633,477	)		—
NET LOSS	$	(1,688,676	)	$	(1,804,844	)	$	(3,493,520	)

LOSS PER SHARE
Basic	$	(0.05	)				$	(0.10	)
Diluted	$	(0.05	)				$	(0.10	)

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

ITEM 2.

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

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

the impact of the global economic crisis on our business,

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

the imprecise nature of our reserve estimates,

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

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

the costs and impact associated federal and state regulations,

changes in existing federal and state regulations,

our dependence on third party transportation facilities,

insufficient insurance coverage,

conflicts of interest related to our dealings with MEI,

cashless exercise provisions of outstanding warrants,

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

adverse impacts on the market price of our common stock from sales by the holders of our common stock and warrants purchased in recent private offerings.

Most of these factors are difficult to predict accurately and are generally beyond our control. You should consider the areas of risk described in connection with any forward-looking statements that may be made herein or in our Annual Report on Form 10-K for the year ended April 30, 2010. Readers are cautioned not to place undue reliance on these forward-looking statements and readers should carefully review this report in its entirety. Except for our ongoing obligations to disclose material information under the Federal securities laws, we undertake no obligation to release publicly any revisions to any forward-looking statements, to report events or to report the occurrence of unanticipated events. These forward-looking statements speak only as of the date of this report, and you should not rely on these statements without also considering the risks and uncertainties associated with these statements and our business.

We are an independent exploration and production company that utilizes seismic data, and other technologies for geophysical exploration and development of oil and gas wells in the Cook Inlet Basin in south central Alaska and the Appalachian region of eastern Tennessee . In addition to our engineering and geological capabilities, we provide land drilling services on a contract basis to customers primarily engaged in natural gas exploration and production.

Currently, we are continuing to develop the acreage we acquired during fiscal 2009 and 2010. These acquisitions have grown our acreage position to approximately 622,938 acres of gross oil and gas leases and exploration license rights (602,018 net acres), which includes 471,474 acres under the Susitna Basin Exploration License. We are continuing to assess and add strategic acreage to our Alaska leases and licenses. On February 11, 2011, we were awarded Susitna Basin Exploration License No. 4 from the State of Alaska Department of Natural Resources. The license encompasses 62,909 acres and will have a ten-year term. We have not included this acreage in our calculation of gross or net lease acres in this report as it is a fourth quarter event.

During the nine months ended January 31, 2011, we began to recomplete three Alaska wells that were previously shut in, of which two have been completed. We capitalized approximately $8.6 million of costs associated with those efforts. In addition, we plan to recomplete eight previously shut in wells in the next three to six months.

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

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

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

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

Our ability, however, to implement one or more of these goals in a timely manner is dependent upon the availability of additional capital. To expand our operations as set forth above, we will need from $35 million to $60 million of additional capital to develop our Alaska reserves.

We are seeking to leverage our existing assets and fund our working capital needs through the issuance of debt. Although we do not have any firm commitments in place, we are currently evaluating and negotiating term sheets for the additional capital we need to fully fund our operations and there are no assurances the capital will be available to us upon terms acceptable to us, if at all. If we are not able to raise capital as required, we will be delayed in fully implementing our expanded business model. We may also be required to reduce overhead until further capital is obtained.

During the first nine months of fiscal 2011, we have been the successful bidder on additional acreage in Alaska that complements our current acreage, strategically assigned other leases to another producer, settled two of our significant lawsuits, and secured the extension of the Susitna Basin Exploration License for an additional three years. We obtained a $5,000,000 line of credit that provides financial flexibility to us while we continue to seek financing. We reduced our transportation costs in Alaska by settling a tariff dispute, proposed a stock plan compliant with Section 162(m) of the Internal Revenue Code to allow us to deduct certain compensation under the exemption in that section, added an experienced oil and gas accounting executive to our Board of Directors, and continued to move forward with our redevelopment of our Alaskan properties. Our fourth quarter will reflect the booking of the additional acreage won at auction, as well as our new North Susitna exploration license, and result in an increase of 80,096 acres in our gross acreage to 703,034 acres.

On May 25, 2010, CIE assigned four leases with a total gross acreage of 8,828.5 acres to Buccaneer Alaska for total consideration of $12,500, as of June 1, 2010. We retained the overriding royalty interests in each lease including 2% in the ADL-391108 and ADL-17595-2 leases and 4% in the ADL-390379 and ADL-390370 leases. If Buccaneer Alaska fails to drill at least one well on the leased acreage by 2013, we will be entitled to a payment of $303,613, and may choose to cause Buccaneer Alaska to assign any of the leases to us that remain active.

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.

On October 29, 2010, CIE secured a three year extension of its Susitna Basin Exploration License, which is comprised of 471,474 acres. The terms of the extension require us to spend an aggregate of $750,000 over the next three years under a new work commitment. This extension will allow us to identify the most valuable acres covered by the license and convert only the most promising prospects to leases at the expiration of the license.

On November 19, 2010, the Regulatory Commission of Alaska accepted a settlement agreement between CIE and the Cook Inlet Pipe Line Company ("CIPL"). CIPL, a subsidiary of Chevron Pipeline Co., operates a 42-mile pipeline on the west side of Cook Inlet, and is the sole means by which CIE can export its oil production. This settlement reduced transportation costs for all CIE production by $6.57 per barrel to a rate of $8.00 per barrel for the

remainder of 2010. The actual rate to be paid by CIE to CIPL for 2010 shall be determined in accordance with the annual true-up procedure detailed below. The actual rate to be paid for 2010 may be more or less than $8.00 per barrel after the true-up. The settlement also lays out a methodology for determining CIE's future pipeline transportation rates. The rates to be paid by CIE to CIPL during calendar years 2011 through 2014 shall be determined by dividing the agreed annual CIPL revenue requirement of $17.28 million for each year of the term of the Settlement Agreement by the forecasted total annual CIPL throughput. CIE has committed to pay for transportation of a minimum of 260,063 barrels of production in 2010 and 346,750 barrels in each of the years 2011 through 2014. Each February, a true-up adjustment for the previous year will be made by dividing the $17.28 million revenue requirement of the pipeline by the actual number of barrels put through the line by all shippers to determine the rate due to CIPL. After the rate due to CIPL is determined in accordance with the true-up terms, any overpayment by CIE up to $250,000 will be credited against future shipments, and any amount above $250,000 shall be repaid to CIE in cash. In the event that CIE had underpaid CIPL for the previous year, payment of that shortfall would be made after the annual true up. On February 15, 2011, we received a cash payment of approximately $1,500,000 pursuant to the true-up. CIPL retained another $250,000 that will be credited toward our costs on our next shipments.

On December 3, 2010, we entered into a settlement agreement with Prospect Capital Corporation that resolved similar claims to those in the Petro Capital lawsuit settled on October 29, 2010. We issued a total of 2,013,814 shares of our common stock to Prospect Capital Corporation upon the cashless exercise of certain warrants. In addition to the attorney fee savings and certainty that comes from the settlement and dismissal of the Petro lawsuit and Prospect claims, as a result of the settlements, we have eliminated a substantial amount of the derivative liability that we had booked as a result of the anti-dilution clause in the warrants at issue in this matter. These warrants accounted for the majority of our long-term derivative liability, which has been eliminated and has resulted in a decrease in our total derivative liability from $17,429,787 at April 30, 2010 to $1,261,291 at January 31, 2011.

On December 22, 2010, a $5,000,000 line of credit was made available to us by PlainsCapital Bank in anticipation of a larger, permanent facility. The line of credit bears an interest rate of 6% but may vary if the Prime Rate exceeds 5%. This loan is short term with an original maturity date of February 21, 2011. We intend to use the proceeds from this loan for working capital and to continue development in Alaska. The loan is personally guaranteed by our Chairman of the Board and Chief Operating Officer, Deloy Miller, and by our President and Chief Executive Officer, Scott Boruff. Mr. Miller and Mr. Boruff have also each pledged a portion of their shares of our common stock owned by them as security for the loan. On March 2, 2011, the aforementioned line of credit was extended to April 21, 2011. The effective date of the new note executed on March 2, 2011 is February 21, 2011, the date of maturity of the original line of credit. The terms of the new note are the same as the terms of the original note. While we have made draws on the line of credit, we have paid off the line and no amounts are currently outstanding. However, the line of credit remains available to us as we continue to work toward a permanent facility.

On January 17, 2011, we added Don Turkleson to our Board of Directors to fill a vacancy created by the resignation of one of our Directors last summer. Mr. Turkleson has over 35 years of accounting and financial experience with emphasis in the oil and gas business.

On January 28, 2011, we entered into a settlement agreement with Gunsight Holdings, LLC. The lease in dispute in the lawsuit was declared to be in full force and effect, and we agreed to drill at least one well on the property subject to the lease each year for the next four years. We granted Gunsight an option to purchase our interest in the lease for $1,000,000, which expires when we drill the first required well. We, Gunsight, and Ky-Tenn Oil, Inc. (“KTO”) mutually released our claims against each other with respect to the lawsuit. The parties entered a stipulation of dismissal in accordance with the settlement agreement that has been accepted by the Court.

RESULTS OF OPERATIONS

Revenues

The following table shows the components of our revenues for the three and nine months ended January 31, 2011 and 2010, together with their percentages of total revenue in fiscal 2011 and percentage change on a period-over-period basis.


	For the Three Months Ended
	January 31, 2011		% of Revenue		January 31, 2010		% of Revenue		% Change
REVENUES

Oil and gas revenue	$	7,039,457		90%	$	438,525		38%		1505%
Service and drilling revenue		775,664		10%		723,582		62%		7%
Total Revenue	$	7,815,121		100%	$	1,162,107		100%		572%

	For the Nine Months Ended
	January 31, 2011		% of Revenue		January 31, 2010		% of Revenue		% Change
REVENUES

Oil and gas revenue	$	17,912,429		91%	$	1,055,142		52%		1598%
Service and drilling revenue		1,778,601		9%		967,989		48%		84%
Total Revenue	$	19,691,030		100%	$	2,023,131		100%		873%

Oil and gas revenue represents revenues generated from the sale of oil and natural gas produced from the wells in which we have a partial ownership interest. Oil and gas revenue is recognized as income as production is extracted and sold.

The significant increases in oil and gas revenues for the three and nine month periods ended January 31, 2011 over the three and nine month periods ended January 31, 2010 were due to the addition of the Alaskan oil production as a result of our Alaska property acquisition in December 2009 which accounted for revenues of $6,583,486 and $17,089,071, respectively, during the three and nine month periods ended January 31, 2011.

At January 31, 2011 oil was priced at $90.99 per barrel versus $72.85 at January 31, 2010, and at January 31, 2011 natural gas was $4.42 per Mcf as compared to $5.13 per Mcf at January 31, 2010. In addition, we had 187 producing oil wells and 313 producing gas wells on January 31, 2011 compared to 196 producing oil wells and 249 producing gas wells on January 31, 2010. For the three month period ended January 31, 2011 we produced 65,961 barrels of oil and 77,977 Mcf of natural gas as compared to 7,103 barrels of oil and 43,540 Mcf of natural gas during the three month period ended January 31, 2010. For the nine month period ended January 31, 2011 we produced 215,630 barrels of oil and 239,212 Mcf of natural gas as compared to 13,045 barrels of oil and 81,043 Mcf of natural gas during the nine month period ended January 31, 2010. These increases were primarily due to the addition of Alaska production.

Service and drilling revenue represents revenues generated from drilling, maintenance and repair of third party wells. Service and drilling income is recognized at the time it is both earned and we have a contractual right to receive the revenue. Our service and drilling revenue increased 7% for the three month period ended January 31, 2011 as compared to the three month period ended January 31, 2010 and 84% for the nine month period ended January 31, 2011 as compared to the nine month period ended January 31, 2010. During the nine month period ended January 31, 2011 we entered into a contract with National Park Service for plugging non-company related abandoned wells located in the Big South Fork area in Tennessee and Kentucky and recorded revenue of $261,803 for the three month period ended January 31, 2011 and $691,220 for the nine month period ended January 31, 2011. In addition, for the nine month period ended January 31, 2011, we recorded a full nine month's worth of service revenue for our subsidiary, East Tennessee Consultants, Inc. which resulted in revenue of $617,464 as compared to $350,715 recorded during the nine month period ended January 31, 2010. East Tennessee Consultants, Inc. was acquired on June 18, 2009.

COSTS AND EXPENSES

The following tables show the components of our costs and expenses for the three and nine month periods ended January 31, 2011 and 2010. Percentages listed in the table reflect margins for each component of costs and expenses (as applicable) to our revenues for the periods.


	For the Three Months Ended
	January 31, 2011		Margin		January 31, 2010		Margin
COSTS AND EXPENSES

Oil and gas	$	2,994,888		57%	$	201,340		54 %
Service and drilling		691,504		11%		1,916,639		(165)%
State production tax credits, net		(2,015,535)		n/a		—		n/a
Selling, general and administrative		3,219,651		n/a		2,623,553		n/a
Depreciation, depletion and amortization		3,357,654		n/a		630,251		n/a
Total Costs and Expenses	$	8,248,162		(6)%	$	5,371,783		(362)%

	For the Nine Months Ended
	January 31 2011		Margin		January 31, 2010		Margin
COSTS AND EXPENSES

Oil and gas	$	8,910,577		50%	$	229,719		78 %
Service and drilling		1,528,659		14%		2,375,292		(145)%
State production tax credits, net		(908,535)		n/a		—		n/a
Selling, general and administrative		9,135,066		n/a		4,304,785		n/a
Depreciation, depletion and amortization		10,506,628		n/a		1,136,835		n/a
Total Costs and Expenses	$	29,172,395		(48)%	$	8,046,629		(298)%

We follow the successful efforts method of accounting for our oil and gas activities. Accordingly, costs associated with the acquisition, drilling and equipping of successful exploratory wells are capitalized. During the nine month period ended January 31, 2011, we capitalized $8,573,486 of costs associated with the acquisition, drilling and equipping of these wells as compared to $20,849 during the nine month period ended January 31, 2010. Geological and geophysical costs, delay and surface rentals and drilling costs of unsuccessful exploratory wells are charged to expense as incurred and are included in the cost of service and drilling revenue.

Finally, costs of drilling development wells are capitalized. Upon the sale or retirement of oil and gas properties, the cost thereof and the accumulated depreciation or depletion are removed from the accounts and any gain or loss is credited or charged to operations.

Costs and expenses represent direct and indirect labor costs of employees, as well as costs associated with equipment, parts, repairs and other general and administrative expenses. During the three and nine month periods ended January 31, 2011, costs and expenses increased $2,876,379 and $21,125,766 from the three and nine month periods ended January 31, 2010, respectively, which was primarily due to the lease operating expenses relating to our Alaska operations.

The oil and gas margins increased slightly from 54% to 57% but decreased 78% to 50% for the three and nine month periods ended January 31, 2011. During 2010 the producing wells required no new expenditures to produce oil and gas. With the Alaska wells, there were expenditures required in order to rework these wells to get them to produce.

The cost of service and drilling revenue represents direct labor costs of employees associated with these services, as well as costs associated with equipment, parts and repairs. During the three and nine month periods ended January 31, 2011, service and drilling expenses decreased $1,225,135 and $846,633 from the three and nine month periods ended January 31, 2010, respectively. During the three and nine month periods ended January 31, 2010, we spent significant time and expense maintaining and repairing our drilling equipment. This is primarily the

reason the three and nine month periods ended January 31, 2011 had decreases in expense as well as why the three and nine month periods ended January 31, 2010 reflected negative margins.

Depletion of capitalized costs of proved oil and gas properties is provided on a field by field basis using the units-of-production method based upon proved reserves. Acquisition costs of proved properties are amortized by using total estimated units of proved reserves as the denominator. All other costs are amortized using total estimated units of proved developed reserves. During the three and nine month periods ended January 31, 2011, depreciation, depletion and amortization expense was $3,357,654, or 43% of total revenue, and $10,506,628, or 53% of total revenue, respectively, as compared to 54% and 56% for each of the three and nine month periods ended January 31, 2010. The primary reasons for the increased percentage of depletion expense for the three and nine month periods ended January 31, 2011 was the addition of the our Alaska property.

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

Selling, general and administrative expense includes salaries, general overhead expenses, insurance costs, professional fees and consulting fees. The increases of $596,098 and $4,830,281 for the three and nine month periods ended January 31, 2011 as compared to the three and nine month periods ended January 31, 2010 primarily reflects the addition of our new Alaska acquisition which showed an additional $1,341,445 and $3,287,576 in costs for the three and nine month periods ended January 31, 2011, respectively. This new layer of expense will continue in future quarters and may increase as further development in Alaska occurs. In addition, $579,675 and $2,042,166 of non-cash items were recorded as compensation expense during the three and nine month periods ended January 31, 2011. This reflected an increase of $1,344,483 from the non-cash compensation amount recorded for nine month period ended January 31, 2010 of $697,683. Professional fees increased $149,574 and $465,649 from the three and nine month periods ended January 31, 2010 to the three and nine month periods ended January 31, 2011 primarily due to increased costs associated with the new acquisitions and onetime costs associated with a registration statement filed with the SEC, as well as increases in investor relations and public relations expenses.

As a result of these components, total costs and expenses reflected a margin of (6)% and (48)% for the three and nine month periods ended January 31, 2011, respectively. The current quarter and year to date margins have risen from the quarter and year to date margins for the period ended January 31, 2010. This was in part, due to the reduction of CIPL transportation costs, as previously discussed. This represented an increase over the negative margins of (362)% and (298)% experienced for the three and nine month periods ended January 31, 2010, respectively. However, as a result of higher depreciation, depletion, and amortization costs, pipeline transportation costs and royalties payable to Alaska, our gross margins on oil and gas sales from our Alaskan operations will generally be less than oil and gas sales from our Appalachian operations. Given that oil and gas sales from our Alaskan operations are expected to represent the majority of our oil and gas sales in future periods, we anticipate that our gross margins will be lower than those which were historically reported before we acquired these assets.

OTHER INCOME (EXPENSES)

The following tables show the components of our other income (expenses) for the three and nine month periods ended January 31, 2011 and 2010. Percentages listed in the table reflect percentages of total revenue for each component.


	For the Three Months Ended
	January 31, 2011			% of Revenue		January 31, 2010			% of Revenue
OTHER INCOME (EXPENSES)

Interest expense, net of interest income	$	(101,909	)		(1)%	$	(115,553	)		(10)%
Gain on derivative instruments		1,444,900			18%		—			n/a
Loan fees and costs		—			n/a		(576,086	)		(50)%
Gain on acquisitions		—			n/a		472,473,332			>1,000%
Total Other Income	$	1,342,991			17%	$	471,781,693			>1,000%

	For the Nine Months Ended
	January 31, 2011			% of Revenue		January 31, 2010			% of Revenue
OTHER INCOME (EXPENSES)

Interest expense, net of interest income	$	(725,941	)		(4)%	$	(119,209	)		(6)%
Gain on derivative instruments		5,132,795			26%		—			n/a
Loan fees and costs		(90,755	)		<(1)%		(691,463	)		(34)%
Gain (loss) on sale of property and equipment		20,000			<1%		(9,755	)		<(1)%
Gain on acquisitions		—			n/a		474,292,096			>1,000%
Total Other Income	$	4,336,099			22%	$	473,471,669			>1,000%

Interest expense, net of interest income decreased $13,644, but increased $606,732 in the three and nine month periods ended January 31, 2011 as compared to the three and nine month periods ended January 31, 2010. The three month decrease and the nine month increase were primarily due to interest associated with the 6% convertible note program as these notes were initiated during the three months ended January 31, 2010, but converted into equity prior to the three month period ended January 31, 2011, as previously described.

The derivative liability fluctuates from quarter to quarter based on changes in the price of oil for our commodity derivative positions as well as for changes in components of the Black-Scholes pricing model including the Company's ending stock price, risk free rates, expected life terms, expected volatility and expected dividend rates for our outstanding warrants that have reset provisions. During the three and nine month periods ended January 31, 2011, the Company recorded non-cash gains of $1,444,900 and $5,132,795 relating to the change in fair value of these derivative instruments. The application of this accounting treatment on our financial statements in future periods could likewise result in non-cash gains or losses, which could be significant.

As described earlier in this report, and due primarily to the reasons described above, during the three and nine month periods ended January 31, 2011 we recorded net income of $909,950 and net loss of $5,145,266, respectively.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity is the ability of a company to generate adequate amounts of cash to meet the enterprise's needs for cash. At January 31, 2011 we had working capital of $(311,624) compared to $1,445,111 at April 30, 2010. The current assets increased $6,535,758 from April 30, 2010 to January 31, 2011 primarily due to a $4,310,126 increase in state production tax credits receivable for our Alaska subsidiary as well as an increase in prepaid expenses of $1,650,747 that was due primarily to prepaid shipping costs in Alaska. Current liabilities increased $7,669,245 from April 30, 2010 to January 31, 2011 primarily due to an increase in trade payables of $5,545,812 as our Alaska subsidiary’s costs to recomplete wells that were previously shut in have increased during the period. In addition, we had $2,500,000 in notes payable on January 31, 2010 and $0 on April 30, 2010. This represented draws on a $5,000,000 line of credit.

Net cash provided by operating activities for the nine month period ended January 31, 2011 was $6,302,031. This primarily reflects a $5,604,504 increase in accounts payable. Net cash used by operating activities for the nine months ended January 31, 2010 was $3,750,831. This primarily reflects the cash paid for the costs of revenues and selling, general and administrative expense in excess of revenues received for the nine month period.

Net cash used in investing activities for the nine months ended January 31, 2011 of $9,362,508 is primarily due to the $8,573,846 of capital expenditures to recomplete wells acquired in Alaska that were previously shut in. Net cash used in investing activities for the nine months ended January 31, 2010 of $4,530,482 primary reflects the cash of $4,541,251 we paid for our Alaska subsidiary during that time frame.

Net cash provided by financing activities of $3,468,582 for the nine month period ended January 31, 2011 primarily reflects cash received from the exercise of equity rights of $1,010,748 and the $2,850,000 received from two sources; $350,000 in proceeds from borrowing on May 15, 2010 from MEI as previously discussed as well as proceeds from borrowing from PlainsCapital Bank of $2,500,000 during the current quarter. Net cash provided by financing activities of $10,742,933 for the nine month period ended January 31, 2010 primarily reflects cash received from the proceeds of borrowings of $5,576,444 and sale of stock of $5,689,000.

We do not presently have any commitment for capital expenditures other than related to the Osprey platform and onshore assets as described below. However, as set forth earlier in this section we require a substantial amount of capital to fund our other obligations associated with the acquisition of the Alaskan assets.

Under the terms of the purchase agreement for the Alaskan assets and the Assignment Oversight Agreement, Cook Inlet Energy assumed all liabilities related to the plugging, abandonment, decommissioning, removal and/or restoration liabilities associated with or arising from the acquired assets with respect to all periods prior to, on or after the closing date. Under the terms of the purchase agreement for the Alaskan assets, these assumed liabilities include approximately $7.1 million for the onshore assets and approximately $17.7 million associated with a retirement liability for the Osprey platform, of which approximately $6.6 million is presently on deposit in an escrow fund with the State of Alaska. During the third quarter of 2010 we accrued approximately $15.6 million for these liabilities, which includes approximately $5.4 million for the onshore assets and approximately $10.2 million for the Osprey platform.

In addition, our long-term cash flows are subject to a number of variables including the level of production and prices as well as various economic conditions that have historically affected the oil and gas business. A material increase in oil prices has recently increased our potential liquidity. At January 31, 2011 oil was priced at $90.99 per barrel versus $72.85 at January 31, 2010.

However, a reduction in production, oil and gas prices, and reserves would reduce our operating results in future periods. We operate in an environment with numerous financial and operating risks, including, but not limited to, the inherent risks of the search for, development and production of oil and gas, the ability to buy properties and sell production at prices which provide an attractive return and the highly competitive nature of the industry. While we do not anticipate a worst case scenario, if we are not successful in securing new capital and the price of oil and gas falls significantly and if we were unable to secure more drilling and servicing contracts, we would need to consider reducing overhead in an attempt to achieve an operating profit, based on the revenue of our existing producing oil and gas wells.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Not applicable to a smaller reporting company.

ITEM 4.

CONTROLS AND PROCEDURES.

Disclosure Controls and Procedures. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended, at the end of the period covered by this report (the "Evaluation Date"). Subsequent to the Evaluation Date, but prior to the filing of this report with the Securities and Exchange Commission, the Audit Committee of the Board of Directors determined that our unaudited consolidated balance sheet at July 31, 2010, and our unaudited consolidated statements of operations and cash flows for the three month periods ended July 31, 2010, as well as our unaudited consolidated balance sheet at October 31, 2010, and

our unaudited consolidated statements of operations and cash flows for the three and six month periods ended October 31, 2010 could no longer be relied upon as a result of errors in those financial statements. We failed to properly accrete our asset retirement obligations in each of the first two quarters of fiscal 2011. In these periods we also failed to properly record depletion, depreciation and amortization expenses related to leasehold costs, wells and equipment, fixed assets and asset retirement obligations and did not properly record the state tax credits expected from our Alaska operations. We have corrected these accounting errors in our financial statements contained in this report. As a result of these accounting errors, which are deemed to result from material weaknesses in our internal controls over financial reporting, our Chief Executive Officer and Chief Financial Officer have concluded that as of the Evaluation Date we did not maintain disclosure controls and procedures that were effective in providing reasonable assurances that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 was recorded, processed, summarized and reported within the time periods prescribed by SEC rules and regulations, and that such information was accumulated and communicated to our management to allow timely decisions regarding required disclosure.

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.

Changes in Internal Control Over Financial Reporting. There was no change in our internal control over financial reporting during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS.

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

ITEM 1A.

RISK FACTORS.

Not applicable to a smaller reporting company.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

On January 19, 2011, a warrant holder exercised warrants for 1,000,000 shares of our common stock for $742,000, which included exercise prices ranging from $0.01 to $2.00. The recipient was an accredited investor and the issuance was exempt from registration under the Securities Act of 1933 in reliance on an exemption provided by Section 3(a)(9) of that act.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES.

None

ITEM 4.

(REMOVED AND RESERVED).

ITEM 5.

OTHER INFORMATION.

None

ITEM 6.

EXHIBITS.

31.1

Rule 13a-14(a)/15d-14(a) certificate of Chief Executive Officer

31.2

Rule 13a-14(a)/15d-14(a) certificate of Chief Financial Officer

32.1

Section 1350 certification of Chief Executive Officer

32.2

Section 1350 certification of Chief Financial Officer

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	MILLER PETROLEUM, INC.

Date: March 22, 2011	By:	/s/ Scott M. Boruff
		Scott M. Boruff
		Chief Executive Officer,
		principal executive officer


	MILLER PETROLEUM, INC.

Date: March 22, 2011	By:	/s/ Paul W. Boyd
		Paul W. Boyd
		Chief Financial Officer, principal
		financial and accounting officer