Edgar Filing: MILLER ENERGY RESOURCES, INC.

MILL Q1 10Q 07.31.13

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

(Mark One)

Form 10-Q

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

For the quarterly period ended July 31, 2013

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

For the transition period from __________________ to __________________________

Commission file number: 001-34732

Miller Energy Resources, Inc.

(Name of registrant as specified in its charter)



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

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

(865) 223-6575

(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

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



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

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. The number of shares of common stock issued and outstanding as of September 3, 2013 was 43,675,459.

TABLE OF CONTENTS





			Page
PART I		Financial Information
	Item 1.	Financial Statements:	1
		Condensed Consolidated Balance Sheets as of July 31, 2013 and April 30, 2013	1
		Condensed Consolidated Statements of Operations for the Three Months Ended July 31, 2013 and 2012	2
		Condensed Consolidated Statements of Stockholders' Equity for the Three Months Ended July 31, 2013 and 2012	3
		Condensed Consolidated Statements of Cash Flows for the Three Months Ended July 31, 2013 and 2012	4
		Notes to Condensed Consolidated Financial Statements	5
	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	21
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33
	Item 4.	Controls and Procedures	33

PART II		Other Information
	Item 1.	Legal Proceedings	34
	Item 1A.	Risk Factors	34
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
	Item 6.	Exhibits	35
	SIGNATURES		36

Table of Contents

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

MILLER ENERGY RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(dollars in thousands, except share and per share data)



	July 31, 2013		April 30, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,125	$	2,551
Restricted cash	3,946		7,531
Accounts receivable	8,008		3,204
Alaska production tax credits receivable	18,355		12,713
Inventory	2,518		3,382
Prepaid expenses and other	4,176		1,183
	40,128		30,564
OIL AND GAS PROPERTIES, NET	503,822		486,009
EQUIPMENT, NET	42,460		42,876
OTHER ASSETS:
Land	542		542
Restricted cash, non-current	11,196		10,207
Deferred financing costs, net	4,386		4,666
Other assets	556		541
	$	603,090	$	575,405
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	27,279	$	13,129
Accrued expenses	6,914		6,338
Short-term portion of derivative instruments	1,707		842
Current portion of long-term debt	6,000		6,000
	41,900		26,309
OTHER LIABILITIES:
Deferred income taxes	152,911		157,530
Asset retirement obligation	20,192		19,890
Long-term portion of derivative instruments	1,654		—
Long-term debt, less current portion	51,577		51,559
	268,234		255,288
COMMITMENTS AND CONTINGENCIES (Note 14)
MEZZANINE EQUITY:
Series C cumulative preferred stock, redemption amount of $64,386	53,663		31,236

STOCKHOLDERS' EQUITY:
Common stock, $0.0001 par, 500,000,000 shares authorized, 43,584,959 and 43,444,694 shares issued and outstanding, respectively	4		4
Additional paid-in capital	89,913		88,184
Retained earnings	191,276		200,693
	281,193		288,881
	$	603,090	$	575,405

See accompanying notes to the condensed consolidated financial statements.

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MILLER ENERGY RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(dollars in thousands, except share and per share data)



	Three Months Ended July 31,
	2013			2012
REVENUES:
Oil sales	$	12,258		$	7,646
Natural gas sales	270			83
Other	480			533
	13,008			8,262
OPERATING EXPENSES:
Oil and gas operating	6,265			3,974
Cost of other revenue	284			548
General and administrative	6,360			5,305
Exploration expense	286			29
Depreciation, depletion, and amortization	5,692			3,125
Accretion of asset retirement obligation	297			284
	19,184			13,265
OPERATING LOSS	(6,176		)	(5,003		)
OTHER INCOME (EXPENSE):
Interest expense, net	(2,281		)	(131		)
Gain (loss) on derivatives, net	(3,076		)	8,941
Other expense, net	(14		)	(75		)
	(5,371		)	8,735
INCOME (LOSS) BEFORE INCOME TAXES	(11,547		)	3,732
Income tax benefit (expense)	4,619			(1,121		)
NET INCOME (LOSS)	(6,928		)	2,611
Accretion of preferred stock	(453		)	(2,422		)
Series C accumulated dividends	(2,036		)	—
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(9,417	)	$	189

INCOME (LOSS) PER COMMON SHARE:
Basic	$	(0.22	)	$	0.00
Diluted	$	(0.22	)	$	0.00
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic	43,455,054			41,425,645
Diluted	43,455,054			43,807,338

See accompanying notes to the condensed consolidated financial statements.

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MILLER ENERGY RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(Unaudited)

(dollars in thousands, except share data)



	Common Stock			Additional Paid-in Capital		Retained Earnings			Total
	Shares	Amount		Additional Paid-in Capital		Retained Earnings			Total
Balance at April 30, 2012	41,086,751	$	4	$	64,813	$	226,188		$	291,005
Net income	—	—		—		2,611			2,611
Accretion of preferred stock	—	—		—		(2,422		)	(2,422		)
Issuance of equity for services	351,477	—		1,843		—			1,843
Issuance of equity for assets	14,000	—		63		—			63
Issuance of equity for compensation	382,165	—		3,622		—			3,622
Exercise of equity rights	125,000	—		125		—			125
Preferred stock redemption	—	—		2,510		—			2,510
Balance at July 31, 2012	41,959,393	4		72,976		226,377			299,357
Net loss	—	—		—		(23,031		)	(23,031		)
Series C preferred dividends	—	—		—		(2,209		)	(2,209		)
Accretion of preferred stock	—	—		—		(444		)	(444		)
Issuance of equity for services	—	—		311		—			311
Other equity issuance	178,800	—		1,278		—			1,278
Issuance of equity for compensation	145,500	—		8,072		—			8,072
Exercise of equity rights	1,161,001	—		3,707		—			3,707
Modification of warrants	—	—		1,840		—			1,840
Balance at April 30, 2013	43,444,694	4		88,184		200,693			288,881
Net loss	—	—		—		(6,928		)	(6,928		)
Series C preferred dividends	—	—		—		(2,036		)	(2,036		)
Accretion of preferred stock	—	—		—		(453		)	(453		)
Issuance of equity for services	—	—		110		—			110
Issuance of equity for compensation	115,265	—		1,556		—			1,556
Exercise of equity rights	25,000	—		63		—			63
Balance at July 31, 2013	43,584,959	$	4	$	89,913	$	191,276		$	281,193

See accompanying notes to the condensed consolidated financial statements.

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MILLER ENERGY RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(dollars in thousands)



	Three Months Ended July 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(6,928	)	$	2,611
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization	5,692			3,125
Amortization of deferred financing fees	280			—
Expense from issuance of equity	1,666			2,075
Dry hole costs, leasehold impairments, and non-cash exploration expenses	157			—
Deferred income tax (benefit) expense	(4,619		)	1,121
Unrealized (gain) loss on derivative instruments, net	2,519			(4,880		)
Accretion of asset retirement obligation	297			284
Changes in operating assets and liabilities:
Receivables	(4,804		)	227
Inventory	946			(259		)
Prepaid expenses and other assets	(669		)	(1,616		)
Accounts payable and accrued expenses, and other	1,032			920
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	(4,431		)	3,608

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for oil and gas properties	(15,235		)	(4,714		)
Prepayment of drilling costs	(2,339		)	—
Purchase of equipment and improvements	(739		)	(4,611		)
Proceeds from sale of equipment	—			2,000
NET CASH USED IN INVESTING ACTIVITIES	(18,313		)	(7,325		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid	(1,315		)	—
Payments on debt	—			(24,130		)
Debt acquisition costs	—			(3,757		)
Proceeds from borrowings	—			40,000
Redemption of preferred stock	—			(11,240		)
Issuance of preferred stock	23,508			—
Equity issuance costs	(1,534		)	—
Exercise of equity rights	63			125
Restricted cash	2,596			640
NET CASH PROVIDED BY FINANCING ACTIVITIES	23,318			1,638
NET CHANGE IN CASH AND CASH EQUIVALENTS	574			(2,079		)

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	2,551			3,971
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	3,125		$	1,892
SUPPLEMENTARY CASH FLOW DATA:
Cash paid for interest	$	694		$	4,697
SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Capital expenditures in accounts payable and accrued expenses	$	(12,991	)	$	(2,282	)
Reduction of oil and gas properties from applications for Alaska production tax credits	$	5,642		$	—

See accompanying notes to the condensed consolidated financial statements.

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(dollars in thousands, except share and per share data and unit and per unit data)

1. ORGANIZATION AND BASIS OF PRESENTATION

Overview

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

We are an independent exploration and production company that utilizes seismic data and other technologies for the geophysical exploration, development and production of oil and natural gas wells in the Cook Inlet Basin of southcentral Alaska and the Appalachian region of eastern Tennessee. The accounting policies used by us and our subsidiaries reflect industry practices and conform to U.S. generally accepted accounting principles ("GAAP"). Significant policies are discussed below.

Basis of Presentation

The accompanying condensed consolidated financial statements are presented in accordance with GAAP and, in the opinion of management, include all adjustments (consisting only of normal recurring adjustments) necessary for a fair statement of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted under Securities and Exchange Commission ("SEC") rules and regulations. The results reported in these condensed consolidated financial statements are not necessarily indicative of the financial position or operating results that may be expected for the entire year.

The financial information included herein should be read in conjunction with the audited consolidated financial statements and notes thereto included in Item 8 of Part II of the Company's Annual Report on Form 10-K for the year ended April 30, 2013, which was filed with the SEC on July 15, 2013 and was further amended on August 28, 2013. Certain amounts in the condensed consolidated financial statements and notes thereto have been reclassified to conform to current period presentation.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our significant accounting policies are consistent with those discussed in our Annual Report on Form 10-K for the year ended April 30, 2013, as amended.

Principles of Consolidation

The accompanying condensed consolidated financial statements include our consolidated accounts, including the accounts of the Company, after elimination of intercompany balances and transactions. The condensed consolidated financial statements also include the accounts of all investments in which we, either through direct or indirect ownership, have more than a 50% interest or significant influence over the management of those entities.

Use of Estimates

The preparation of financial statements requires us to utilize estimates and make judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. These estimates are based on historical experience and on various other assumptions that we believe to be reasonable under the circumstances. The estimates are evaluated by management on an ongoing basis, and the results of these evaluations form a basis for making decisions about the carrying value of assets and liabilities that are not readily apparent from other sources. Although actual results may differ from these estimates under different assumptions or conditions, we believe that the estimates used in the preparation of our financial statements are reasonable.

Restricted Cash

As of July 31, 2013 and April 30, 2013, current restricted cash includes $3,407 and $7,144 of cash temporarily held in an account that is controlled by our lender. Current restricted cash balances also include amounts held in escrow to secure company related credit cards. Non-current restricted cash balances include amounts held in escrow to provide for the future plugging and abandonment of wells, the possible dismantling of our off-shore platform, performance bonds, and general liability bonds.

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(Unaudited)

(dollars in thousands, except share and per share data and unit and per unit data)

Oil and Gas Properties

We follow the successful efforts method of accounting for oil and gas properties. Under this method, exploration costs such as exploratory geological and geophysical costs, delay rentals and exploration overhead are charged against earnings as incurred. Acquisition costs and costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are charged to exploration expense.

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

When circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future net cash flows, calculated using the Company's estimate of future oil and natural gas prices, operating expenses, and production, to the net book value of the proved properties on a field by field basis. If the sum of the expected undiscounted future net cash flows is less that the next book value of the proved properties, an impairment loss is recognized for the excess, if any, of the net book value over its estimated fair value. No impairment of proved properties was recognized during the three months ended July 31, 2013 or July 31, 2012.

Acquisition costs of unproved properties are assessed for impairment during the holding period and transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment, based on our current exploration plans, and a valuation allowance is provided if impairment is indicated. Costs of expired or abandoned leases are charged to expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties are included in oil and gas operating expense and impairments of unsuccessful leases are included in exploration expense. During the three months ended July 31, 2013, our condensed consolidated statement of operations includes $157 related to impairment of certain unproved properties and, $129 in seismic and delay rentals incurred in the Cook Inlet region. We had no exploration expenses in the Appalachian region during the three months ended July 31, 2013.

Equipment

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

Equipment is reviewed for impairment when facts and circumstances indicate that book values may not be recoverable. In performing this review, an undiscounted cash flow test is performed on the impairment unit. If the sum of the undiscounted estimated future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property's net book value over its estimated fair value.

Investments

On June 24, 2011, we acquired a 48% minority interest in Pellissippi Pointe I, LLC and Pellissippi Pointe II, LLC (the "Pellissippi Pointe" entities or "investee") for total cash consideration of $400. In connection with the transaction, we executed a five-year lease agreement with the investee and relocated our corporate offices to the new facility on November 7, 2011. Since we do not exercise control over the financial and operating decisions made by the investee, we have accounted for these investments using the equity method. These investments are reflected in other assets in the accompanying condensed consolidated balance sheets.

Guarantees

On July 12, 2012, we signed a direct guarantee for 55% of the loan obligations outstanding of $5,074 with FSG Bank for the Pellissippi Pointe equity investment. The Company's guarantee is included within the scope of Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 460, "Guarantees" and was recorded at the estimated fair value of $250; such amount is included in accrued expenses on our condensed consolidated balance sheet as of July 31, 2013 and is being amortized over the five-year life of the guarantee. The fair value was calculated using the income approach and the estimated default rate was determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of Pellissippi Pointe and the term of the underlying loan obligations. The default rates are published by Moody's Investors Service. To the extent we are required to make payments under the guarantee, we will record the differences between the liability and the

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(Unaudited)

(dollars in thousands, except share and per share data and unit and per unit data)

associated payments in earnings. At July 31, 2013, our maximum potential undiscounted payment under this arrangement is $2,703 plus additional lender's costs.

Income (Loss) Per Share

We determine basic income (loss) per share and diluted income (loss) per share in accordance with the provisions of ASC 260, “Earnings Per Share.” Basic income (loss) per share excludes dilution and is computed by dividing earnings available to common stockholders by the weighted-average number of common shares outstanding for the period. The calculation of diluted earnings (loss) per share is similar to that of basic earnings per share, except that the denominator is increased, if net income is positive, to include the number of additional common shares that would have been outstanding if all potentially dilutive common shares, such as those issuable upon the exercise of stock options and warrants, had been exercised. We compute the numerator for basic income (loss) by subtracting accretion of preferred stock and cumulative preferred stock dividends from net income (loss) to arrive at net income (loss) attributable to common stockholders. Preferred stock dividends include dividends declared on preferred stock (regardless of whether the dividends have been paid) and dividends accumulated for the period on cumulative preferred stock (regardless of whether the dividends have been declared). As of July 31, 2013, our accumulated dividends were $2,036.

New Accounting Pronouncements Issued But Not Yet Adopted

In December 2011, the FASB issued Accounting Standards Update ("ASU") 2011-11, "Disclosures about Offsetting Assets and Liabilities," which increases disclosures about offsetting assets and liabilities. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards ("IFRS") related to the offsetting of financial instruments. The existing GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance in ASU 2011-11 is effective for annual and interim reporting periods beginning on or after January 1, 2013. The disclosures should be applied retrospectively for all prior periods presented. We have evaluated the new pronouncement and have determined that there is no material impact to our condensed consolidated financial statements.

There are no other recently issued accounting pronouncements that are expected to have a material impact on our financial condition, results of operations or cash flows.

3. MAJOR CUSTOMERS AND CONCENTRATIONS OF CREDIT RISK

For the three months ended July 31, 2013 and 2012, Tesoro Corporation accounted for $11,633, or 89%, and $7,242, or 88%, of our consolidated total revenues, respectively. Tesoro Corporation also accounted for $6,153, or 77%, and $1,709, or 55%, of our accounts receivable as of July 31, 2013 and April 30, 2013, respectively.

Credit is extended to customers based on an evaluation of their credit worthiness and collateral is generally not required. We experienced no credit losses of significance during the three months ended July 31, 2013 or 2012.

We maintain our cash and cash equivalents (including restricted cash), which at times may exceed federally insured amounts, in highly rated financial institutions. As of July 31, 2013, we held $5,626 in excess of the $250 limit insured by the Federal Deposit Insurance Corporation.

4. RELATED PARTY TRANSACTIONS

We use a number of contract labor companies to provide on demand labor at our Alaska operations. H&H Industrial, Inc. ("H&H Industrial") is an entity contracted by CIE, a wholly-owned subsidiary of the Company, to provide services related to the exploration and production of oil and natural gas. H&H Industrial is owned by the sister and father of David Hall, who is a member of our Board of Directors and Chief Operating Officer ("COO") of Miller, as well as the Chief Executive Officer ("CEO") of CIE. For the three months ended July 31, 2013 and 2012, we paid H&H Industrial, Inc. a total of $100 and $363, respectively. We have used Rediske Air, Inc. ("Rediske Air") to provide transportation to our facilities. Rediske Air was owned by David Hall's brother-in-law, who passed away on July 7, 2013. Rediske Air is no longer owned by a related party as of July 31, 2013. For the three months ended July 31, 2013 and 2012, we paid Rediske Air a total of $101 and $126, respectively. The audit committee of our Board of Directors determined that the amounts paid by us for the services performed were fair to and in the best interest of the Company.

From time to time the Company provides service work on oil and gas wells owned by Mr. Gettelfinger (and family), a member of the Board of Directors. As of July 31, 2013 and April 30, 2013, Mr. Gettelfinger owed us $6 and $11, respectively.

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(Unaudited)

(dollars in thousands, except share and per share data and unit and per unit data)

The audit committee of our Board of Directors determined that the amounts paid to us for the services performed were fair and in the best interest of the Company.

The Company is required to remit payroll taxes related to certain stock-based compensation transactions. As of July 31, 2013, we have recorded a related receivable of $79. At April 30, 2013, we recorded a related payable of $620 as well as a corresponding receivable from the respective employees of $593 which was collected subsequent to April 30, 2013.

In 2009 we formed both Miller Energy GP and Miller Energy Income 2009-A, LP ("MEI") to raise capital necessary to support strategic business initiatives. From November 2009 to May 2010 we entered into three secured promissory notes with MEI to borrow $3,071 with maturity dates ranging from November 2013 to May 2014. On June 29, 2012, the maturity dates on the promissory notes were amended to reflect, the later of (i) 91 days after the date on which the Apollo Credit Facility is extinguished, or (ii) July 31, 2017. Our wholly owned subsidiary, Miller Energy GP, owns 1% of MEI, however due to the shared management of our company and MEI, we consolidate this entity. We have not presented noncontrolling interest on our condensed consolidated balance sheets or our condensed consolidated statements of operations due to the fact that these amounts are immaterial.

5. OIL AND GAS PROPERTIES AND EQUIPMENT

Oil and gas properties (successful efforts method) are summarized as follows:



	July 31, 2013			April 30, 2013
Property costs
Proved property	$	332,585		$	326,936
Unproved property	213,283			196,500
Total property costs	545,868			523,436
Less: Accumulated depletion	(42,046		)	(37,427		)
Oil and gas properties, net	$	503,822		$	486,009

Equipment is summarized as follows:



	July 31, 2013			April 30, 2013
Machinery and equipment	$	8,136		$	7,413
Vehicles	1,851			1,851
Aircraft	476			476
Buildings	2,725			2,725
Office equipment	756			759
Leasehold improvements	485			482
Drilling rigs	35,422			35,422
	49,851			49,128
Less: Accumulated depreciation	(7,391		)	(6,252		)
Equipment, net	$	42,460		$	42,876

Depreciation, depletion and amortization consisted of the following:



	For the Three Months Ended July 31,
	2013		2012
Depletion of oil and gas related assets	$	4,537	$	2,824
Depreciation and amortization of equipment	1,155		301
Total	$	5,692	$	3,125

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(Unaudited)

(dollars in thousands, except share and per share data and unit and per unit data)

6. DERIVATIVE INSTRUMENTS

We are exposed to fluctuations in crude oil prices on the majority of our production. As a result, our management believes it is prudent to manage the variability in cash flows by occasionally entering into hedges on a portion of our crude oil production. We primarily utilize swap contracts to manage fluctuations in cash flows resulting from changes in commodity prices and account for these instruments as derivative assets or liabilities measured at fair value on a recurring basis in accordance with the provisions of ASC 815, "Derivatives and Hedging."

From time to time we issue warrants in connection with certain of our equity transactions. Certain warrants contain exercise reset provisions which are considered freestanding derivatives and are accounted for as liabilities measured at fair value in accordance with ASC 815.

Derivative Instruments

Commodity Derivatives

During the quarter ended July 31, 2013, we entered into five hedging agreements; one for 584,000 barrels at $101.10 per barrel, two for 292,000 barrels at $95.35 per barrel, one for 291,200 barrels at $91.95 per barrel, and one for 184,000 barrels at $106.10 per barrel. All are priced based on the ICE Brent crude oil futures as traded on the New York Mercantile Exchange.

As of July 31, 2013, we had the following open crude oil derivative positions:



	Fixed - Price Swaps
Production Period:	Bbls	Weighted Average Fixed Price
2014	436,800	$	101.63
2015	584,000	99.21
2016	683,200	93.90
	1,704,000	$	97.70

Warrants Issued in Connection with Other Equity Transactions. On March 26, 2010, purchasers of our common stock and certain third party consultants were issued warrants to purchase an aggregate amount of 817,055 shares of our common stock at an exercise price of $5.28 per share. Under the terms of the respective agreements, an adjustment to the exercise price was required if, at any time after issuance, we issue warrants at an exercise price lower than $5.28.

On September 21, 2012, the Company entered into a Special Warrant Exercise Agreement with warrant holders, pursuant to which warrant holders agreed to exercise 586,001 warrants immediately for $4.00 per share and waived their right to a cashless exercise. In addition, 42,857 warrants were cancelled in exchange for a settlement payment of $75. These modifications resulted in a loss of $210, which was included in other income (expense), net on our consolidated statement of operations for the twelve months ended April 30, 2013.

The term for the remaining 138,197 warrants outstanding was extended for one year in exchange for the removal of the exercise price reset provision. From May 1, 2012 to September 21, 2012 we had a mark-to-market loss adjustment of $260 that was recorded to gain (loss) on derivatives, net, and the remaining liability of $1,840 was reclassified to additional paid-in capital.

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(dollars in thousands, except share and per share data and unit and per unit data)

Fair Value Measurements

As of July 31, 2013 and April 30, 2013, the fair market value of our derivative liabilities is as follows:



	July 31, 2013		April 30, 2013
Current liabilities:
Commodity derivatives	$	1,707	$	842
Current portion of derivative instruments	1,707		842
Long-term liabilities:
Commodity derivatives	1,654		—
Long-term portion of derivative instruments	1,654		—
Total derivative liability	$	3,361	$	842

Commodity Derivatives

Our commodity derivatives consist of variable-to-fixed price commodity swaps. The fair values of our commodity derivatives are not actively quoted in the open market, thus we use an income approach to estimate fair value. The use of commodity derivative instruments also exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Thus, to minimize this exposure, we utilize an investment-grade rated counterparty. In measuring fair value, we also take into account the impact of counterparty risk on our derivative instruments and use observable market data for credit default swaps to assess the impact of non-performance credit risk when evaluating our net assets from the counterparty. We use the cumulative Standard & Poor's ("S&P") default rating for small, independent exploration and production companies to assess the impact of non-performance credit risk when evaluating our net obligations to the counterparty. As of July 31, 2013 and April 30, 2013, the effect of non-performance risk on our commodity derivatives was negligible.

Fair Value Hierarchy

ASC 820 provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

As of July 31, 2013 and April 30, 2013, all of our derivatives were classified as Level 2 instruments due to the lack of quoted prices readily available in an active market. The following table presents the hierarchy classification of our derivative instruments:



	Fair Value Measurements
At July 31, 2013	Level 1		Level 2		Level 3
Commodity derivative liability	$	—	$	3,361	$	—
Total	$	—	$	3,361	$	—
At April 30, 2013
Commodity derivative liability	$	—	$	842	$	—
Total	$	—	$	842	$	—

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Derivative Activities Reflected on Condensed Consolidated Statements of Operations

Changes in the fair value of our derivative liabilities are recorded in gain (loss) on derivatives, net on our condensed consolidated statements of operations.



	For the Three Months Ended July 31,
	2013			2012
Realized gain (loss) recognized in earnings	$	(557	)	$	4,061
Unrealized gain (loss) recognized in earnings	(2,519		)	4,880
Gain (loss) on derivatives, net	$	(3,076	)	$	8,941

7. DEBT

As of July 31, 2013 and April 30, 2013, we had the following debt obligations reflected at their respective carrying values on our condensed consolidated balance sheets:



	July 31, 2013		April 30, 2013
Apollo senior secured Credit Facility	$	55,307	$	55,307
Series B Preferred Stock	2,270		2,252
Total debt obligations	$	57,577	$	57,559

Apollo Senior Secured Credit Facility

On June 29, 2012 (the "Closing Date"), the Company entered into a Loan Agreement (the "Loan Agreement") with Apollo Investment Corporation ("Apollo"), as administrative agent and sole initial lender.

The Loan Agreement provides for a $100,000 credit facility (the "Apollo Credit Facility") with an initial borrowing base of $55,000. Of that initial $55,000, $40,000 was made available to, and was drawn by, Miller on the Closing Date. On February 7, 2013 and April 25, 2013, we borrowed an additional $5,000 and $10,000, respectively, under the Apollo Credit Facility.

The Apollo Credit Facility matures on June 29, 2017 and is secured by substantially all the assets of Miller and its consolidated subsidiaries (other than MEI), which subsidiaries also guarantee the loans. Amounts outstanding under the Apollo Credit Facility bear interest at a rate of 18% per annum, with interest payable on the last day of each of Miller's fiscal quarters. Miller will be required to pay the outstanding balance of the loan in full on the maturity date; however, beginning with the fiscal quarter ending on July 31, 2013, if requested by Apollo (at the direction of lenders holding a majority of the commitments under the Loan Agreement), Miller would be required to repay up to $1,500 in principal quarterly. Such payments of principal would be made, together with any interest due on such date, on the last day of Miller's fiscal quarter. No such request to repay principal has been made by Apollo.

In addition, the outstanding debt includes capitalized interest of $307 added to the principal amount as a part of the “PIK Election” as defined in the Loan Agreement. In connection with the Loan Agreement, the Company has granted Apollo a right of first refusal to provide debt financing for the acquisition, development, exploration or operation of any oil and gas related properties, including wells during the term of the Apollo Credit Facility and one year thereafter.

The Loan Agreement contains interest coverage, asset coverage, minimum and gross production covenants, as well as other affirmative and negative covenants. As previously reported by the Company, these covenants have been amended several times to adjust the covenant levels and the date on which compliance with the covenants would be measured, and to include our Tennessee production in the minimum production covenant. As of April 30, 2013, we were not in compliance with such covenants; however, we received a waiver of such violations from Apollo on July 11, 2013. Under the terms of the waiver, we will be required to maintain compliance with the financial and production covenants on a quarterly basis commencing with the quarter ending October 31, 2013. Based on our production levels existing at July 31, 2013, we believe we will achieve compliance with the minimum gross production covenant as of October 31, 2013. We believe we will be in compliance with the remaining covenants as of October 31, 2013 or, if not, that we will be able to obtain a waiver of those covenants.

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On the Closing Date, we paid Apollo a non-refundable structuring fee of $2,750, payable for the account of the lenders, and we have agreed to pay an additional 5% fee to Apollo for the benefit of the lenders on the amount of every additional borrowing over and above the $55,000 amount of the borrowing base at the date of closing. In addition, we paid Apollo a supplemental fee of $500 on the Closing Date, and have agreed to pay another $500 fee on each anniversary of the Closing Date so long as the Loan Agreement remains in effect.

Additional compensation was due to Bristol Capital, LLC, a consultant to us, in connection with the closing of the Loan Agreement. This fee was paid by issuing 312,500 shares of the Company's restricted common stock on July 23, 2012.

The Company has used a portion of the initial $40,000 loan made available under the Apollo Credit Facility to repay in full the amounts outstanding under the Guggenheim Senior Secured Credit Facility ("Guggenheim Credit Facility") of approximately $26,200. The remaining $13,800 was used to (i) redeem the Company's outstanding Series A Preferred Stock; (ii) pay certain outstanding payables of the Company; and (iii) pay transaction costs associated with the closing of the Apollo Credit Facility, such as attorneys' fees. The February and April 2013 borrowings were used to fund our drilling projects and pay outstanding operational and general and administrative expenses otherwise permitted under the Apollo Credit Facility.

The fair value of the July 31, 2013 outstanding balance of the Apollo Credit Facility was $54,678 as calculated using the discounted cash flows method.

Series B Preferred Stock

On September 24, 2012, we sold 25,750 shares of our Series B Cumulative Redeemable Preferred Stock (the "Series B Preferred Stock") to 10 accredited investors and issued those investors warrants to purchase 128,750 shares of common stock in a private offering exempt from registration under the Securities Act of 1933, as amended. We received gross proceeds of $2,575. We paid issuance costs of $167, which have been capitalized and are being amortized over the term of the instrument. The outstanding Series B Preferred Stock is classified as long-term debt, in accordance with ASC 480, "Distinguishing Liabilities from Equity." As of July 31, 2013, the fair value of Series B Preferred Stock is $2,462.

The designations, rights and preferences of the Series B Preferred Stock, include:


•	a stated value of $100 per share and a liquidation preference equal to the stated value;


•	the holders are not entitled to any voting rights and the shares of Series B Preferred Stock are not convertible into any other security;


•	the holders are entitled to receive annual cumulative dividends at the rate of 12% per annum, payable in arrears semi-annually, which began on March 1, 2013;

•

dividends will be paid in cash on each relevant dividend date provided that (i) we are in compliance with certain financial covenants (designated the "Capital Covenants") under the Apollo Credit Facility, with compliance to be determined as of the most recent reporting date and, on a pro forma basis, on the dividend date, and (ii) no "Default" or "Event of Default" (as defined in the Apollo Credit Facility) has occurred or is continuing on the dividend date;


•	the shares may not be redeemed until 30 days after "Security Termination" (as defined in the Apollo Credit Facility), but otherwise may be redeemed at any time by the Company, with a required redemption on the fifth anniversary of issuance or, if later, on the 30th day after Security Termination.

On March 1, 2013, in accordance with our charter and the designation for the Series B Preferred Stock, we paid a semiannual dividend of approximately $5.16 per share on the Series B Preferred Stock. In addition, on July 18, 2013, our Board approved the payment of a semiannual dividend, of approximately $6.05 per share, which was paid on September 3, 2013 as the regularly scheduled payment date of September 1, 2013 was not a business day. The record date was August 15, 2013.

Debt Issue Costs

As of July 31, 2013 and April 30, 2013, our unamortized debt issue costs were $4,386 and $4,666, respectively, which relates to the Apollo Credit Facility and the Series B Preferred Stock. These costs are being amortized over the term of the respective debt instruments.

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8. ASSET RETIREMENT OBLIGATIONS

The following table presents changes to the Company's asset retirement obligation ("ARO") liability for the three months ended July 31, 2013 and 2012:



	For the Three Months Ended July 31,
	2013		2012
Asset retirement obligation, as of April 30	$	19,890	$	18,366
Additions, net	5		—
Accretion expense	297		284
Asset retirement obligation, as of July 31	$	20,192	$	18,650

The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company's oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.

Any additional retirement obligations will increase the liability associated with new oil and natural gas wells and other facilities. Actual expenditures for abandonments of oil and natural gas wells and other facilities reduce the liability for asset retirement obligations. At July 31, 2013 and April 30, 2013, there were no significant expenditures for abandonments.

9. STOCK-BASED COMPENSATION

During fiscal year 2010 and 2011, our Compensation Committee and Board of Directors adopted share-based compensation plans authorizing 3,000,000 and 8,250,000 shares of common stock under each plan, respectively. The share-based compensation plans allow us to offer our employees, officers, directors and others an opportunity to acquire a proprietary interest in the Company and enable us to attract, retain, motivate and reward such persons in order to promote the success of the Company. Each plan authorizes the issuance of incentive stock options, nonqualified stock options and restricted stock. All awards issued under the share-based compensation plans must be approved by our Compensation Committee. On June 21, 2013 and July 29, 2013, our Compensation Committee approved additional grants of shares in the amount of 350,000 of our common stock and 7,299,996 in options to purchase our common stock, which in each case are subject to the approval by our shareholders of an increase in the number of shares authorized under the 2011 share-based compensation plan sufficient to cover these grants. As a result of the pending shareholder resolution, these shares have not been included in our calculation for available shares. At July 31, 2013 and April 30, 2013, there were 15,328 and 329,328 additional shares available under the compensation plans, respectively.

Allocated between general and administrative expenses and cost of oil and gas sales within the condensed consolidated statements of operations is stock-based compensation expense for the three months ended July 31, 2013 and 2012 of approximately $1,556 and $1,990, respectively. We also recognized non-employee expense related to warrants issued for the three months ended July 31, 2013 and 2012 of approximately $110 and $85, respectively.

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The following table summarizes our stock-based compensation activities for the three months ended July 31, 2013 and 2012:



	For the Three Months Ended				For the Three Months Ended
	July 31, 2013				July 31, 2012
	Number of Options and Warrants		Weighted Average Exercise Price		Number of Options and Warrants		Weighted Average Exercise Price
Beginning balance at April 30	14,403,847		$	4.25	15,405,955		$	4.60
Granted	470,000		4.45		725,000		4.23
Exercised	(25,000	)	2.52		(125,000	)	1.00
Canceled	—		—		(440,000	)	5.07
Ending balance	14,848,847		4.61		15,565,955		4.60
Options exercisable at July 31	11,040,573		$	4.36	9,332,345		$	4.04

The following table summarizes our stock options and warrants outstanding, including exercisable shares at July 31, 2013:



Options and Warrants Outstanding					Options and Warrants Exercisable
Range of Exercise Price	Number Outstanding	Weighted Average Remaining Contractual Life (in years)	Weighted Average Exercise Price		Number Exercisable	Weighted Average Exercise Price
$0.01 to $1.82	1,818,900	1.3	$	0.75	1,818,900	$	0.75
$2.00 to $4.99	2,828,000	4.8	3.17		2,011,397	2.82
$5.25 to $5.53	4,266,947	3.2	5.32		2,883,613	5.31
$5.89 to $5.94	3,310,000	7.1	5.92		2,951,663	5.92
$6.00 to $6.94	2,625,000	2.4	6.03		1,375,000	6.06
	14,848,847	4.0	$	4.61	11,040,573	$	4.36

10. STOCKHOLDERS' EQUITY

Common Stock

At July 31, 2013, we had 43,584,959 shares of common stock outstanding. We issued 140,265 shares during the three months ended July 31, 2013, of which 115,265 shares were issued to employees for compensation, and 25,000 shares were related to the exercise of equity rights.

At July 31, 2012, we had 41,959,393 shares of common stock outstanding. We issued 872,642 shares during the three months ended July 31, 2012, of which 312,500 shares were issued to Bristol Capital, LLC as payment for fees related to the closing of our credit facility, 421,142 shares were issued to employees and non-employees for compensation, 14,000 shares were issued for oil and gas leases, and 125,000 shares were related to the exercise of equity rights.

Series C Preferred Stock

On September 28, 2012, we sold 685,000 shares of the Company's newly designated 10.75% Series C Cumulative Redeemable Preferred Stock (the "Series C Preferred Stock"). These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated September 28, 2012, and the Company's registration statement on Form S-3 (Registration No. 333-183750), which was declared effective by the SEC on September 18, 2012. The shares were offered to the public at $23.00 per share for gross proceeds of $15,755. We incurred issuance costs of $1,335, yielding net proceeds of $14,420.

On October 12, 2012, we entered into an At Market Issuance Sales Agreement ("ATM Agreement") with MLV & Co. LLC ("MLV"). The ATM Agreement contemplates periodic sales by MLV of our Series C Preferred as and when directed by the Company. These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus

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supplement dated October 12, 2012, and the Company's registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012. On and after October 12, 2012 through July 31, 2013, we sold 384,353 shares of Series C Preferred Stock under the ATM Agreement and related prospectus supplement at prices ranging from $21.48 per share to $23.51 per share through our At the Market Agreement dated October 12, 2012 with MLV. We received gross proceeds of $8,405 and incurred issuance costs of $294, yielding net proceeds of $8,111.

On February 12, 2013, we entered into an Underwriting Agreement with MLV as representative for a group of underwriters for a follow-on "best efforts" offering of our Series C Preferred Stock. We sold an additional 625,000 shares of the Series C Preferred Stock in this offering at a price of $22.90 per share. We received gross proceeds of $14,312 and incurred issuance costs of $1,052, yielding net proceeds of $13,260 in connection with the offering. These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated February 13, 2013, and the Company's registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012.

On May 7, 2013, we entered into an Underwriting Agreement with MLV as representative for a group of underwriters for a follow-on "best efforts" offering of our Series C Preferred Stock. We sold an additional 500,000 shares of our Series C Preferred Stock, at a price of $22.25 per share. We received gross proceeds of $11,125 and incurred issuance costs of $805, yielding net proceeds of $10,320. These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated May 7, 2013, and the Company's registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012.

On June 27, 2013, we entered into an Underwriting Agreement with MLV as representative for a group of underwriters for a follow-on "best efforts" offering of our Series C Preferred Stock. We sold an additional 335,000 shares of our Series C Preferred Stock, at a price of $21.50 per share. We received gross proceeds of $7,203 and incurred issuance costs of $547, yielding net proceeds of $6,656. These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated June 27, 2013, and the Company's registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012.

The Series C Preferred Stock is classified as temporary equity in accordance with ASC 480 and is being accreted to redemption value through the earliest repayment date of November 1, 2017, which resulted in accretion of $453 during the three months ended July 31, 2013. The fair value of the Series C Preferred Stock was $54,255 based on the closing price at July 31, 2013. The designations, rights and preferences of the Series C Preferred Stock, include:


•	The holders are entitled to receive a 10.75% per annum cumulative quarterly dividend, on March 1, June 1, September 1, and December 1, payable in cash on each dividend date unless the Company is prohibited by making such payment pursuant to the terms of any agreement of the Company (including any other class or series of equity securities or any agreement related to indebtedness);


•	The dividend may increase to a penalty rate of 12.75% if we fail to (A) pay dividends for four or more quarterly dividend periods, whether or not consecutive, or (B) maintain the listing of our Series C Preferred Stock on a national securities exchange (the events listed in clauses (A) and (B) being "Penalty Events");

•

There is no mandatory redemption or stated maturity with respect to the Series C Preferred Stock, and it is not redeemable prior to November 1, 2017 unless: (A) there is a change in control and redemption occurs pursuant to a special right of redemption related to that change in control or (B) the Closing Bid Price of our common stock has equaled or exceeded the conversion price initially set at $10.00 per share by 150% for at least 20 trading days in any 30 consecutive trading day period (a "Market Trigger");


•	The redemption price is $25.00 per share plus any accrued and unpaid dividends;


•	Liquidation preference is $25.00 per share plus any accrued and unpaid dividends;


•	The Series C Preferred Stock is senior to all our other securities except our Series B Redeemable Preferred Stock, which is senior to the Series C Preferred Stock;


•	There is a general conversion right with respect to the Series C Preferred Stock with an initial conversion price of $10.00 per share, a special conversion right upon a change in control, and a market trigger conversion at our option in the event of a Market Trigger;


•	The Series C Preferred Stock has been listed on the NYSE and is registered under our universal shelf; and


•	Holders of the Series C Preferred Stock have no voting rights, except: 1) as otherwise required by law; 2) with respect to any proposal to (A) create, authorize or increase the authorized or issued amount of any class or series of our equity securities which rank senior to the Series C Preferred Stock or (B) amend, alter or repeal any

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provision of our charter, as amended, in a manner which materially and adversely affects any right, preference, privilege or voting power of the holders of the Series C Preferred Stock; and 3) the holders of the Series C Preferred Stock will have the right to elect two directors to our board of directors upon the occurrence of a Penalty Event.

On July 18, 2013, our Board of Directors declared a dividend of approximately $0.67 per share on our Series C Preferred Stock which was paid on the next regularly scheduled dividend payment date of September 3, 2013, in accordance with the terms of our charter as September 1, 2013 was not a business day. The dividend payment is equivalent to an annualized 10.75% per share, based on the $25.00 per share stated liquidation preference for the Series C Preferred Stock, accruing from March 2013 through August 2013. The record date was August 16, 2013.

11. INCOME TAXES

We have a significant deferred income tax liability related to the excess of the book carrying value of oil and gas properties over their collective income tax bases. This difference will reverse (through lower tax depletion deductions) over the remaining recoverable life of the properties, resulting in future taxable income in excess of income for financial reporting purposes. As an independent producer of domestic oil and gas, we take advantage of certain elective provisions presently in the Internal Revenue Code allowing for expensing of specified intangible drilling and development costs that are typically capitalized for book purposes. This temporary difference also reverses over the remaining life of the properties. As a result of these elections, we presently have U.S. federal and state net operating loss carryovers that are expected to be fully utilized against future taxable income resulting solely from the reversal of the temporary differences between the book carrying value of oil and gas properties and their tax bases. We are not relying on forecasts of taxable income from other sources in concluding that no valuation allowance is needed against any of our deferred tax assets. Our provision for income taxes for the first interim reporting period in fiscal 2014 is based on the actual year-to-date effective rate, as this is our best estimate of our annual effective tax rate for the full fiscal year. The computation of the annual effective tax rate includes a forecast of our estimated “ordinary” income (loss), which is our annual income (loss) from operations before tax, excluding unusual or infrequently occurring (or discrete) items. Significant management judgment is required in the projection of ordinary income (loss) in order to determine the estimated annual effective tax rate. The level of income (or loss) projected for fiscal 2014 causes an unusual relationship between income (loss) and income tax expense (benefit), with small changes resulting in: (i) a potential significant impact on the rate and, (ii) potentially unreliable estimates. As a result, we computed the provision for income taxes for the quarters ended July 31, 2013 and July 31, 2012 by applying the actual effective tax rate to the year-to-date income (loss), as permitted by GAAP. The effective tax rate for the year-to-date period ended July 31, 2013 is a benefit of 40%. The principal differences in our effective tax rate (benefit) for this period and the federal statutory rate of 35% are state income taxes, change in state rate, state and local income taxes net of federal benefit, and unfavorable permanent difference related to incentive stock options. No valuation allowance was deemed necessary in order to fully benefit the Company's year-to-date loss due to the presence of sufficient future taxable income related to the excess of book carrying value in oil and gas properties over their corresponding tax bases. No other sources of taxable income were considered by Management in reaching this conclusion. No cash payments of income taxes were made during the year-to-date period ended July 31, 2013, and no significant payments are expected during the succeeding twelve months.

12. ALASKA PRODUCTION TAX CREDITS

Upon qualifying, the Company can apply for several credits under Alaska Statutes 43.55.023 and 43.55.025:


•	43.55.023(a)(1) Qualified capital expenditure credit (20%)


•	43.55.023(l)(1) Well lease expenditure credit (effective June 30, 2010) (40%)


•	43.55.023(a)(2) Qualified capital exploration expenditure credit (20%)


•	43.55.023(l)(2) Well lease exploration expenditure credit (effective June 30, 2010) (40%)


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


•	43.55.025 Seismic exploration credits (40%)

We recognize a receivable when the amount of the credit is reasonably estimable and receipt is probable. For expenditure and exploration based credits, the credit is recorded as a reduction to the related assets. For carried-forward annual loss credits, the credit is recorded as a reduction to the Alaska production tax. To the extent the credit amount exceeds the Alaska production tax, the credit is recorded as a reduction to general and administrative expenses.

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As of July 31, 2013 and April 30, 2013, the Company has reduced the basis of capitalized assets by $20,189 and $14,547 for expenditure and exploration credits, respectively. The reductions are recorded on our condensed consolidated balance sheets in "oil and gas properties." As of July 31, 2013 and April 30, 2013, the Company had outstanding net receivables from the State of Alaska in the amount of $18,355 and $12,713, respectively.

13. LITIGATION

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

This action was revived on August 4, 2011, when a breach of contract case was filed against us in the United States District Court for the Eastern District of Tennessee. The case, styled CNX Gas Company, LLC v. Miller Energy Resources, Inc., Chevron Appalachia, LLC as successor in interest to Atlas America, LLC, Cresta Capital Strategies, LLC and Scott Boruff, arises from the same allegations as the previous action in the state court. The federal case seeks money damages from us for breach of contract; however, unlike the previous action, it does not seek specific performance of the assignments at issue. The Plaintiff claims that the other defendants tortiously interfered with, or induced the breach of, the letter of intent between us and the Plaintiff. We have filed our Answer and intend to vigorously defend this suit. We are presently conducting discovery, and trial is scheduled to begin on November 18, 2013. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.

On May 17, 2011, we were served with a lawsuit filed in the United States District Court for the Eastern District of Tennessee at Knoxville by Troy D. Stafford, the former Chief Financial Officer of our wholly owned subsidiary, Cook Inlet Energy, LLC. The suit, styled Troy D. Stafford v. Miller Petroleum, Inc., Civil Action No. 3-11CV-206, claims that we terminated Mr. Stafford's employment without cause in contravention of the terms of the Purchase and Sale Agreement between us and the sellers of CIE ("PSA"), failed or refused to pay his salary, severance, percentage of purchase price, expenses or stock warrant and violated a duty of good faith and fair dealing. The suit seeks damages in excess of $3,000, which includes $2,687 of damages for loss of vested warrants. We believe that all of the asserted claims are baseless, particularly in view of the fact that we issued the warrants in accordance with the terms of the PSA. We believe that we had appropriate cause to dismiss Mr. Stafford's employment after discovering that he had breached certain representations and warranties in the PSA, and had acted in violation of our Code of Conduct. We have filed our Answer, conducted discovery and are presently awaiting further action by the plaintiff. On January 21, 2013, Mr. Stafford's attorney filed a motion to withdraw as counsel, and on April 2, 2013, Mr. Stafford filed a motion to proceed pro se. We do not yet know how this will affect the timing of this matter. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.

On June 15, 2011, a breach of contract lawsuit was filed against us and CIE in the United States District Court for the Eastern District of Pennsylvania styled VAI, Inc. v. Miller Energy Resources, Inc., f/k/a Miller Petroleum, Inc. and Cook Inlet Energy, LLC. The Plaintiff alleges three causes of action: (1) breach of contract, (2) unfair enrichment, and (3) breach of the implied covenant of good faith and fair dealing. The case seeks damages in warrants to purchase our common stock and monetary damages for certain fees and expenses. The Sale Agreement with David Hall, Walter "JR" Wilcox, and Troy Stafford dated December 10, 2009 contains indemnification provisions relevant to this claim. We filed a Motion to Dismiss for lack of personal jurisdiction, but this motion was not granted by the court. We filed an Answer to the complaint in this case on October 10, 2012, and we have conducted discovery. We have filed a motion for summary judgment which is pending. Trial is set for November 4, 2013. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.

In August 2011, several purported class action lawsuits were filed against us in the United States District Court for the Eastern District of Tennessee. The lawsuits made similar claims and have been consolidated into one case, styled In re Miller Energy Resources, Inc. Securities Litigation. The suit names us, along with several of our current and former executive officers, Scott Boruff, Paul Boyd, Ford Graham, David Hall, and Deloy Miller, as defendants. The Plaintiffs allege two causes of action

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against the defendants: (1) violation of Section 10(b) and Rule 10b-5 of the Exchange Act, (2) violation of Section 20(a) of the Exchange Act. The case seeks money damages against us and the other defendants, and payment of the Plaintiffs' attorney's fees. We have filed a Motion to Dismiss the case, which is pending before the court. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.

On August 23, 2011, a derivative action was filed against us in Knox County Chancery Court. The case is styled Marco Valdez, derivatively on behalf Miller Energy Resources, Inc. v. Deloy Miller, Scott M. Boruff, Jonathan S. Gross, Herman Gettelfinger, David Hall, Merrill A. McPeak, Charles M. Stivers, Don A. Turkleson, and David J. Voyticky, and Miller Energy Resources, Inc., nominal defendant. The suit alleges the following causes of action: (1) Breach of Fiduciary Duty for disseminating false and misleading information; (2) Breach of Fiduciary Duty for failure to maintain internal controls; (3) Breach of Fiduciary Duty for failing to properly oversee and manage the company; (4) Unjust Enrichment; (5) Abuse of Control; Gross Mismanagement, and; (6) Waste of Corporate Assets. The Plaintiff seeks unspecified money damages from the individual defendants, that we take certain actions with respect to our management, restitution to us, and the Plaintiff's attorney fees and costs. We have filed a Motion to Dismiss and, in the alternative, a Motion to Stay pending the outcome of the Class Action. The Plaintiff has agreed to stay this case awaiting a ruling on the plaintiff's appeal in the federal derivatives case in Lukas v. Miller Energy Resources, Inc., et al, as described in the next paragraph. The Plaintiff has also agreed to voluntarily dismiss the case in the event the plaintiff's appeal in Lukas is denied. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.

On August 25, 2011, and August 31, 2011, two derivative actions were filed against us and our Board of Directors and former Chief Financial Officer in the United States District Court for the Eastern District of Tennessee. These cases were consolidated into Patrick P. Lukas, derivatively on behalf Miller Energy Resources, Inc. v. Merrill A. McPeak, Scott M. Boruff, Deloy Miller, Jonathan S. Gross, Herman Gettelfinger, David Hall, Charles M. Stivers, Don A. Turkleson, and David J. Voyticky, and Miller Energy Resources, Inc., nominal defendant. As noted below, this case has been dismissed by the trial court, but that dismissal is being appealed by the plaintiffs. It contained substantially similar claims as Valdez. The suit alleged the following causes of action: (1) Breach of Fiduciary Duty for disseminating false and misleading information; (2) Breach of Fiduciary Duty for failing to properly oversee and manage the company; (3) Unjust Enrichment; (4) Abuse of Control; (5) Gross Mismanagement, and; (5) Waste of Corporate Assets. The Plaintiffs sought unspecified money damages from the individual defendants, to have us take certain actions with respect to our management, restitution to us, and the Plaintiffs' attorney fees and costs. We filed a Motion to Dismiss, which was granted on September 21, 2012. On October 16, 2012, a notice of appeal of this dismissal was filed by the Plaintiffs with the Sixth Circuit Court of Appeals. The appeal has been fully briefed, and the Court heard oral arguments on July 24, 2013. The parties are awaiting further action by the appeals court. Given the current stage of the proceedings with respect to this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.

On August 31, 2012, we terminated an agreement with Voorhees Equipment and Consulting, Inc. (“Voorhees”) for the construction and sale of the rig currently being used on the Osprey Platform, Rig 35. We terminated the agreement based on our belief that Voorhees was in breach of its obligations thereunder. Although no action has been filed in connection with that termination, Voorhees has indicated its desire to arbitrate claims it believes it has under invoices arising between May 29, 2012 and August 31, 2012. We believe we have grounds to dispute liability with respect to some or all of these outstanding invoices. In addition, we expect to assert counterclaims against Voorhees for damages exceeding the amounts Voorhees claims are owed to it, for breach of the relevant contract by Voorhees. The parties have elected to engage a private arbitrator to settle this dispute and are currently conducting discovery. The date of the arbitration has been postponed, but we expect that arbitration to begin on or about January 7, 2014. Given the current stage of the proceedings with respect to this matter, we believe that any loss would be limited to the payment of the outstanding invoices of approximately $531, plus the cost of defense. Based on the information currently available, we have accrued our best estimate of the potential loss on our consolidated balance sheet.

On April 4, 2013, we filed suit against a former contractor of CIE and its parent company (collectively “Cudd”) in the United States District Court for the District of Alaska at Anchorage. This case is styled Cook Inlet Energy, LLC v. Cudd Pressure Control Inc. and RPC, Inc. In our suit we are seeking declaratory relief and damages for breach of contract, breach of implied warrant of merchantability, breach of implied covenant of fitness for a particular purpose and breach of the implied covenant of good faith and fair dealing arising out of a dispute regarding certain equipment and services provided by Cudd on the Osprey Platform that did not meet our needs or expectations as promised. We have not yet determined the full amount of damages claimed. On May 29, 2013, Cudd filed its Answer denying our claims and including a counterclaim for equipment and services, totaling approximately $1,889, plus the costs of defense. We have filed our counteranswer and denied that these amounts are owed, in whole or in part. We are presently beginning the discovery process. Given the current stage of the proceedings with respect to this case, we believe that any loss would be limited to $1,889 plus the cost of defense, related to this matter. Based on the information currently available, we have accrued our best estimate of the potential loss on our consolidated balance sheet.

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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.

14. COMMITMENTS AND CONTINGENCIES

On November 5, 2009, CIE entered into an Assignment Oversight Agreement ("AOA") with the Alaska Department of Natural Resources ("Alaska DNR") which set out certain terms under which the Alaska DNR would approve the transfer of oil and gas leases owned by the State of Alaska from Pacific Energy to CIE. This agreement remains in place following our acquisition of CIE in December 2009. Generally, the agreement requires CIE to provide the Alaska DNR with additional information and oversight authority to ensure that CIE is acting diligently to develop the oil and gas from Redoubt and West McArthur River units ("WMRU"). Under the terms of the AOA, until the Alaska DNR determines that CIE has completed certain development and operational commitments relating to the WMRU and Redoubt Units, CIE must do the following, in addition to the normal requirements under the terms of the leases:


•	file a quarterly summary of expenditures by oil and gas field, tied to objectives in CIE's business plan and plan of development previously presented to the Alaska DNR,


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


•	notify the Alaska DNR 10 days prior to commitment when CIE is preparing to spend funds on a purchase, project or item relating to the WMRU or Redoubt Leases of more than $5,000,


•	annually submit a new plan of development for the Alaska DNR's approval.

The AOA required CIE to demonstrate funding commitments of $5,150 to support the redevelopment of the WMRU and an estimated $31,000 to support the development of the Redoubt Unit. The Company believes it has adequately fulfilled these commitments.

On March 11, 2011, the Company entered into a Performance Bond Agreement under its AOA with the state of Alaska. Under the Performance Bond Agreement, the Company is required to post a total bond of $18,000 for the dismantling and abandonment of the properties. As agreed with the state of Alaska, the Performance Bond Agreement fulfills our commitment under the AOA to fund the full dismantlement costs with respect to our onshore and offshore assets. The Performance Bond Agreement also stipulated that funds held by the state in an escrow account will be credited towards the $18,000. As a result, the Company recorded a $6,910 gain on acquisition during the year ended April 30, 2011.

The AOA also prohibits CIE from using proceeds from operation at WMRU or Redoubt for non-core oil and gas activities, or activities unrelated to WMRU or Redoubt, without the prior written approval of the Alaska DNR until the parties mutually agree that the full dismantlement obligation under the assigned leases is funded.

Failure to submit the information required by the AOA or expenditure of proceeds from WMRU or Redoubt for items or activities unrelated to core oil and gas activities at WMRU or Redoubt would constitute a default under the AOA. If the default could not be cured within 30 days, the leases would be subject to termination by the Alaska DNR.

Under the terms of the Performance Bond Agreement, the Company is obligated to fund an additional $12,000 towards the bond in addition to the amount held by the state in the escrow account. As of July 31, 2013, $1,000 of this amount has been funded. The remaining $11,000 (subject to annual inflation adjustments) will be funded through annual payments as follows:



July 1, 2014	$	1,500
July 1, 2015	2,000
July 1, 2016	2,500
July 1, 2017	2,000
July 1, 2018	1,500
July 1, 2019	1,500
	$	11,000

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15. SUBSEQUENT EVENTS

Series C Preferred Stock

Pursuant to our ATM Agreement with MLV, between August 1 and September 3 of 2013, we offered and sold an additional 362,848 shares of our Series C Preferred Stock, at prices ranging from $21.51 and $21.59 per share. The Company received $7,825 in gross proceeds as a result of these sales, from which MLV was paid a commission of $274. These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated October 12, 2012, and the Company's registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012.

Apollo Credit Facility Waiver and Amendment

On August 5, 2013, we entered into Amendment No. 6 to the Apollo Credit Facility with Apollo. The fee for the Amendment was $300. The Amendment provided for an increase of $20,000 in the effective borrowing base under the Apollo Credit Facility (the "New Availability") which is subject to an initial, reduced, interest rate of 9%, and is not subject to any pre-payment penalty. We drew the $20,000 of New Availability on August 5, 2013; however, if the we do not repay all outstanding loans under the Apollo Credit Facility (“Loans”) on or before January 31, 2014, then the prepayment penalties will again apply to the New Availability after that date and the interest rate on the New Availability will revert to the 18% rate ordinarily payable for Loans under the Loan Agreement.

The Amendment clarifies that when and if any prepayment of the Loans is made from the proceeds of tax credits received by the Company under Alaska's Clear and Equitable Share program, that prepayment will be applied pro rata to both the New Availability and previously drawn Loans (the “Prior Loans”).

In addition to the increase in the borrowing base and the adjustment to the interest rate on those amounts, among other things, the Amendment: (i) clarifies that the option under the Loan Agreement to pay interest in-kind, rather than in cash, which applies to the Prior Loans only and not the New Availability, (ii) establishes separate conditions precedent to borrowings from the New Availability, (iii) adjusts restrictions contained in Sections 7.10 and 7.12 of the Loan Agreement, and (iv) establishes interpretive rules related to the repayment and prepayment of the Loans.

Payment of Dividends

On September 3, 2013, we paid a semi-annual dividend of approximately $6.05 per share on our Series B Preferred Stock. The dividend payment is equivalent to an annualized 12% per share, based on the $100.00 per share stated value, accruing from March 2013 through August 2013. The record date was August 15, 2013.

On September 3, 2013, we paid a quarterly dividend of approximately $0.67 per share on the Series C Preferred Stock. The dividend payment is equivalent to an annualized 10.75% per share, based on the $25.00 per share stated liquidation preference, accruing from June 2013 through August 2013. The record date was August 16, 2013.

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

The following discussion and analysis should be read in conjunction with the condensed consolidated financial statements and accompanying notes included herein and the consolidated financial statements and accompanying notes included in our most recent Annual Report on Form 10-K, as amended.

Forward Looking Statements

We have made forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company's operations, economic performance and financial condition in this report, our Annual Report on Form 10-K, as amended, for the year ended April 30, 2013, and may make other forward-looking statements from time to time in other public filings, press releases and discussions with our management. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include those statements preceded by, followed by or that otherwise include the words "may," "could," "believes," "expects," "anticipates," "intends," "estimates," "projects," "target," "goal," "plans," "objective," "should" or similar expressions or variations on such expressions. For these statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that our expectations will prove to be correct. We undertake no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise.

See the discussion in the "Risk Factors" and "Caution Concerning Forward-Looking Statements" sections of the Company's Annual Report on Form 10-K filed with the SEC on July 15, 2013 and was further amended on August 28, 2013. All written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements contained in the section entitled "Risk Factors" included in such Annual Report as well as other cautionary statements that are made from time to time in our other SEC filings and public communications. You should evaluate all forward-looking statements made in this report in the context of these risks and uncertainties.

Executive Overview

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

Strategy

Our mission is to grow a profitable exploration and production company for the long-term benefit of our shareholders by focusing on the development of our reserves, continued expansion of our oil and natural gas properties and increasing our production and related cash flow. We intend to accomplish these objectives through the execution of our core strategies, which include:


•	Develop Acquired Acreage. We will focus on organically growing production through drilling for our own benefit on existing leases and acreage in the exploration licenses with a view towards retaining the majority of working interest in the new wells. This strategy will allow us to maintain operational control, which we believe will translate to long-term benefits;

•

Increase Production. We plan on increasing oil and gas production through the maintenance, repair and optimization of wells located in the Cook Inlet region and development of wells in the Appalachian region of east Tennessee. Our operational team will employ a combination of the latest available technologies along with tried and true technologies to restore as well as explore and develop our properties;

•

Expand Our Revenue Stream. We intend to fully exploit our mid-stream facilities, such as our injection wells and the Kustatan Production Facility, our ability to engage in the commercial disposal of waste generated by oil and gas operations, and our capacity to process third party fluids and natural gas and, when available, to offer excess electrical power to net users in the Cook Inlet region; and

•

Pursue Strategic Acquisitions. We have significantly increased our oil and gas properties through strategic low-cost / high-value acquisitions. Under the same strategy, our management team will continue to seek opportunities that meet our criteria for risk, reward, rate of return, and growth potential. We plan to leverage our management team's expertise to pursue value-creating acquisitions when the opportunities arise, subject to the availability of sufficient capital.

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Our management team is focused on maintaining the financial flexibility required to successfully execute these core strategies.

Our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing current reserves and economically finding, acquiring and developing additional recoverable reserves. We may not be able to find, acquire or develop additional reserves to replace our current and future production at acceptable costs, which could materially adversely affect our business, financial condition and results of operations. We will focus on adding reserves through new drilling and well workovers and recompletions of our current wells. Additionally, we will seek to grow our production and our asset base by pursuing both organic growth opportunities and acquisitions of producing oil and natural gas reserves that are suitable for us.

Financial and Operating Results

We continued to utilize operational cash flow along with funds raised from sales of our Series C Preferred Stock made in "at-the-market" and "follow-on" public offerings to support our capital expenditures during our first quarter of fiscal 2014. For the three-month period ended July 31, 2013, we reported notable achievements in several key areas. Highlights for the period include:

•

Starting May 1, 2013, and periodically during the quarter, we issued 239,452 shares of our Series C Preferred Stock in "at-the-market" offerings pursuant to the ATM Agreement and a prospectus supplement dated October 12, 2012 (issued under our existing S-3 registration statement, filed with the SEC as file number 333-183750). These sales were made at an average price on the date of such sale ranging from $21.48 to $22.35 per share. We received net proceeds of $4,999 in connection with these sales.


•	On May 10, 2013, we issued 500,000 shares of our Series C Preferred Stock in a "follow-on" best efforts public offering. The shares were registered in the prospectus supplement dated May 7, 2013 and we received net proceeds of $10,320.


•	Effective May 15, 2013, we entered into a new commercial gas sales agreement in the Cook Inlet region. We will primarily deliver gas on the new agreement with production from the RU-3 and RU-4A wells in the Redoubt Shoals field. Contractual gas sales commenced during the month of May and continued throughout the quarter.

•

On June 19, 2013, we began drilling our Sword #1 well located near our West McArthur River Unit ("WMRU") in the Cook Inlet region. The Sword #1 well has been planned as an extended reach well intended to be drilled directionally to approximately 19,000 feet total in an adjacent fault block to the WMRU. The 3D seismic data shows a faulted four-way closure and an estimated 240-acre structure with an estimated ultimate recovery ("EUR") of approximately 800,000 barrels of oil from the Sword #1 well.


•	On June 20, 2013, we brought a new oil well, RU-2A, into production. This well is a sidetrack of a previously producing oil well, RU-2. After clearing the well of drilling fluids from the sidetrack, a subsequent well test showed an initial daily production of 1,281 barrels of oil per day and a water cut of 19% and a rate of production of 1,307 barrels of oil per day through July 31, 2013.


•	On July 2, 2013, we issued 335,000 shares of our Series C Preferred Stock in a "follow-on" best efforts public offering. The shares were registered in the prospectus supplement dated June 27, 2013 and we received net proceeds of $6,655.


•	On July 22, 2013, we announced that our Board of Directors appointed David M. Hall to Chief Operating Officer ("COO"). Mr. Hall has been the Chief Executive Officer of our wholly-owned Alaskan operating subsidiary, Cook Inlet Energy, since 2009 and will continue in that capacity. In his new role as COO, Mr. Hall will oversee our drilling operations in both Alaska and Tennessee.


•	On July 25, 2013, we announced that we elected Marceau Schlumberger to our board of Directors. Mr. Schlumberger is Miller's sixth independent director. Mr. Schlumberger has nearly twenty years of investment banking experience, including international and domestic mergers and acquisitions, restructuring, strategic analysis, and financial experience.

Subsequent to the end of the first quarter of fiscal 2014, we amended the Apollo Credit Facility and brought our RU-1A oil well online. For additional information on the Apollo Credit Facility, refer to Note 7 - Debt and Note 15 - Subsequent Events. Our RU-1A oil well was successfully brought online on August 17, 2013. The well was a sidetrack of our previously producing RU-1 well. From August 18, 2013 through August 29, 2013, the well produced in excess of 700 barrels of oil per day.

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Fiscal 2014 Outlook

As we head into the second quarter of fiscal 2014, we believe our inventory of recompletion, workovers, and exploration and development projects offers numerous growth opportunities. We are currently working on recompleting our RU-5B oil well. We also have several development projects onshore, which we expect will contribute additional production in fiscal 2014. No assurance can be made regarding the success of these development and recompletion efforts. Our current fiscal 2014 capital budget is $125,000. The majority of this budget is expected to be spent on projects in Alaska, with the remaining amount allocated to our Appalachian region. Due to the uncertainty associated with changes in commodity prices, we closely monitor our cost levels and revise our capital budgets based on changes in forecasted cash flows. This means our plan for capital expenditures may change as a result of anticipated changes in the market place. Further, our ability to fully utilize the budget will be dependent on a number of factors including, but not limited to, access to capital, favorable weather and regulatory approval.

We note that, although we expect to continue to sell our Series C Preferred Stock in additional “at-the-market” offerings during fiscal 2014, we cannot guarantee that market conditions will continue to permit such sales at prices we would find acceptable. If that occurred, cash generated from those offerings would cease.

Significant Operational Factors


•	Realized Prices: Our average realized oil price for the three months ended July 31, 2013 and 2012 was $104.57 and $99.59, respectively. These results exclude the impact of commodity derivative settlements.


•	Production: Our net production, excluding fuel gas, for the three months ended July 31, 2013 and 2012 was 125,080 boe and 77,079 boe, respectively.


•	Capital Expenditures and Drilling Results: During the three months ended July 31, 2013, we incurred $28,965 which is inclusive of the increase in our capital accrual account of $12,991. Cash paid for capital expenditures was $15,974 for the three months ended July 31, 2013.

We experience earnings volatility as a result of not using hedge accounting for our crude oil commodity derivatives, which are used to hedge our exposure to changes in commodity prices. This accounting treatment can cause earnings volatility as the positions of future crude oil production are marked-to-market. The non-cash unrealized gains or losses are included on our condensed consolidated statement of operations until the derivatives are cash settled as the commodities are produced and sold. We do not enter into speculative trading positions and we only use commodity derivatives to lock in the future sales price for a portion of our expected crude oil production.

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Results of Operations

Three Months Ended July 31, 2013 Compared to Three Months Ended July 31, 2012

Revenues



	For the Three Months Ended July 31,
	2013		Increase (Decrease)	2012
Oil revenues:
Cook Inlet	$	11,633	61%	$	7,242
Appalachian region	625		55	404
Total	$	12,258	60	$	7,646
Natural gas revenues:
Cook Inlet	$	156	2,500	$	6
Appalachian region	114		48	77
Total	$	270	225	$	83
Other revenues:
Cook Inlet	$	247	(10)	$	273
Appalachian region	233		(10)	260
Total	480		(10)	533
Total revenues	$	13,008	57	$	8,262

Net Production



	For the Three Months Ended July 31,
	2013	Increase (Decrease)	2012
Oil volume - bbls:
Cook Inlet	108,435	62%	66,758
Appalachian region	6,975	61	4,345
Total	115,410	62	71,103
Natural gas volume¹- mcf:
Cook Inlet	28,173	1,129	2,293
Appalachian region	29,848	(11)	33,565
Total	58,021	62	35,858
Total production² - boe:
Cook Inlet	113,130	68	67,140
Appalachian region	11,950	20	9,939
Total	125,080	62	77,079

———————


¹	Cook Inlet natural gas volume excludes natural gas produced and used as fuel gas.


²	These figures show production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the current price ratio between the two products.

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Pricing

Oil Prices

All of our oil production is sold at prevailing market prices, which are subject to fluctuations driven by market factors outside of our control. As volatility increases in response to the rise in global demand for oil combined with economic uncertainty, prices will continue to experience volatility at unpredictable levels. Prices received for crude oil in the first quarter of 2014 were 5% above the same period last year. For the three months ended July 31, 2013, realized oil prices averaged $104.57 per bbl, compared with $99.59 per bbl for the same period in the prior year.

Natural Gas Prices

Natural gas is subject to price variances based on local supply and demand conditions. Prices received for natural gas in the first quarter of fiscal 2014 were substantially above the same period last year. For the three months ended July 31, 2013, realized natural gas prices averaged $4.63 per mcf, compared with $2.38 per mcf for the same period in the prior year. The increase in the averaged realized gas prices resulted from our new natural gas sales contract in the Cook Inlet region with a gross price of $6.00 per mcf.

Oil Revenues

During the first quarter of fiscal 2014, oil revenues totaled $12,258, 60% higher than the same period in the prior year. The increase resulted from a 62% increase in production and a 5% increase in realized oil prices. Oil sales represented 94% of our first quarter consolidated total revenues. Oil production increased 44,307 bbls, driven by a 41,677 bbls increase in the Cook Inlet region and a 2,630 barrel increase in the Appalachian region. The production increase in the Cook Inlet region resulted from RU-2A in our Redoubt Shoals field being on line during the three months ended July 31, 2013.

Natural Gas Revenues

During the first quarter of fiscal 2014, natural gas revenues totaled $270, 225% higher than the same period in the prior year. The increase resulted from a combination of a 95% increase in average realized prices and a 62% increase in production. The increase in the averaged realized gas prices resulted from our new natural gas sales contract in the Cook Inlet region with a gross price of $6.00 per mcf. The increase in natural gas production resulted from selling natural gas in excess of our fuel gas needs from our RU-3 and RU-4A wells in the Cook Inlet region. Natural gas represented 2% of our first quarter consolidated total revenues.

Other Revenues

Other revenues primarily represent revenues generated from contracts for road building, plugging, drilling, maintenance and repair of third party wells as well as rental income we receive for services and use of facilities in the Cook Inlet region. During the first quarters of fiscal 2014 and 2013, other revenues totaled $480, or 4%, and $533, or 6%, respectively, of our consolidated total revenues.

Cost and Expenses

The table below presents a comparison of our expenses for the three months ended July 31, 2013 and 2012:



	For the Three Months Ended July 31,
	2013		2012		$ Variance			% Variance
Oil and gas operating costs	$	6,265	$	3,974	$	2,291		58	%
Cost of other revenues	284		548		(264		)	(48	)
General and administrative	6,360		5,305		1,055			20
Exploration expense	286		29		257			886
Depreciation, depletion, and amortization	5,692		3,125		2,567			82
Accretion of asset retirement obligation	297		284		13			5
Total costs and expenses	$	19,184	$	13,265	$	5,919		45	%

Oil and Gas Operating Costs

Oil and gas operating costs increased $2,291 from first quarter fiscal 2013, or 58%. The increased oil and gas operating costs are directly attributable to increased production and drilling activity. The increased production creates additional labor and camp facility costs, well maintenance, and transportation costs. The increased drilling activity substantially increases the cost of

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control of well insurance. Approximately $1,043 of the increase resulted from the sale of crude oil inventory that was recorded in the previous period at a higher cost per barrel due to well workovers.

Cost of Other Revenues

Our business is primarily focused on exploration and production activities. The cost of other revenues represent costs of services to third parties as a result of excess capacity, and are derived from the direct labor costs of employees associated with these services, as well as costs associated with equipment, parts and repairs. During the first quarter of fiscal 2014, we experienced decreases in cost of other revenues in the Cook Inlet region as we had limited projects during the period.



	For the Three Months Ended July 31,
	2013		Increase (Decrease)	2012
Direct labor	$	165	(43)%	$	287
Equipment	39		(58)	92
Repairs	70		(42)	121
Insurance	—		(100)	38
Other	10		—	10
Total	$	284	(48)%	$	548

General and Administrative Expenses

General and administrative ("G&A") expenses include the costs of our employees, related benefits, professional fees, travel and other miscellaneous general and administrative expenses.



	For the Three Months Ended July 31,
	2013		Increase (Decrease)	2012
Salaries	$	923	6%	$	872
Professional fees	2,162		56	1,384
Travel	454		22	371
Employee benefits	413		97	210
Stock-based compensation	1,600		(23)	2,075
Other	808		106	393
Total	$	6,360	20%	$	5,305

G&A expenses increased $1,055 from first quarter fiscal 2013, or 20%. Included in the overall 20% fluctuation, salaries increased 6% from the same period in the prior fiscal year as we continue to expand our corporate accounting and legal staff from the prior period. Professional fees increased 56% over the same period last year due to an increase in litigation related expenses and employee recruitment during the quarter. Stock-based compensation declined 23% due to the expense associated with awards that became fully vested exceeding the expense associated with newly granted awards. The increase in other expense resulted from an increase in liability insurance premiums due to our increased drilling activities and an increase in office rent related to the addition of office space in both Tennessee and Alaska. Salary increases for our named executive officers, in the aggregate annual amount of $1,035, which were approved by our Compensation Committee on July 29, 2013, were made effective as of July 17, 2013. As a result, the impact of these increases are not fully reflected in the G&A expenses for our last fiscal quarter, and will be relatively higher in future periods.

Exploration Expense

Exploration expense consists of abandonments of drilling locations, dry hole costs, delay rentals, geological and geophysical costs, and the impairment, amortization, and abandonment associated with leases on unproved properties.

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Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization (“DD&A”) expenses include the depreciation, depletion, and amortization of leasehold costs and equipment. Depletion is calculated on a unit-of-production basis. Depreciation is calculated on a straight-line basis.



	For the Three Months Ended July 31,
	2013		2012
Depletion:
Cook Inlet region	$	4,192	$	2,604
Appalachian region	345		220
	4,537		2,824
Depreciation:
Cook Inlet region	119		58
Appalachian region	1,036		243
	1,155		301
Total DD&A	$	5,692	$	3,125

The increase in DD&A is primarily a result of increased production from our Alaska properties and Rig-35 being in service during the three months ended July 31, 2013.

Other Income and Expense

The following table shows the components of other income and expense for the first quarters indicated.



	For the Three Months Ended July 31,
	2013			Increase (Decrease)	2012
Interest expense, net	$	(2,281	)	1,641%	$	(131	)
Gain (loss) on derivatives, net	(3,076		)	(134)	8,941
Other expense, net	(14		)	81	(75		)
Total	$	(5,371	)	(161)%	$	8,735

Interest Expense, Net

Interest expense, net, increased $2,150 from the first quarter of fiscal 2013, or 1,641%. The increase in interest expense resulted from a combination of higher debt balances, a reduction in the percentage of interest expense that could be capitalized on self-constructed assets and administration and amendment fees on the Apollo Credit Facility.

Gain (Loss) on Derivatives, Net

We experience earnings volatility as a result of not using hedge accounting to account for changes in commodity prices. As the positions of future oil production are marked-to-market, both realized and unrealized gains or losses are included on our condensed consolidated statements of operations. We do not engage in speculative trading and utilize commodity derivatives only as a mechanism to lock in future prices for a portion of our expected crude oil production.

During the first quarter of fiscal 2014, unrealized losses on commodity derivatives totaled $2,519, while realized losses on commodity derivatives totaled $557. Conversely, during the first quarter of fiscal 2013, we experienced a net gain on commodity and warrant derivatives of $8,941 of which $4,880 was unrealized.

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Liquidity and Capital Resources

Our cash flows, both in the short-term and long-term, are impacted by highly volatile oil and natural gas prices. Significant deterioration in commodity prices negatively impacts revenues, earnings and cash flows, capital spending, and potentially our liquidity. Sales volumes and costs also impact cash flows; however, historically these have not been as volatile or as impactful as commodity prices in the short-term.

Our long-term cash flows are highly dependent on our success in efficiently developing current reserves and economically finding, developing and acquiring additional recoverable reserves. Cash investments are required continuously to fund exploration and development projects and acquisitions, which are necessary to offset the inherent declines in production and proven reserves. We may not be able to find, develop or acquire additional reserves to replace our current and future production at acceptable costs, which could materially adversely affect our future liquidity. For a discussion of risk factors related to our business and operations, please refer to the section entitled "Risk Factors" in our Annual Report on Form 10-K for the fiscal year ended April 30, 2013, as amended.

We may elect to utilize additional borrowing capacity under the Apollo Credit Facility when available, proceeds from the sales of both debt and equity in the capital markets, or proceeds from the occasional sale of nonstrategic assets to supplement our liquidity and capital resource needs.

For the three months ended July 31, 2013, we experienced an operating loss. We anticipate that our operating expenses will continue to increase as we fully develop our assets in the Cook Inlet and Appalachian regions. Although we expect an increase in revenues from these development activities, we will continue depleting our cash resources to fund drilling and workover activities as well as other operating expenses until such time as we are able to significantly increase our revenues above costs.

We believe that the liquidity and capital resource alternatives available to us through the public offerings of additional Series C Preferred Stock, in both “at-the-market” sales in additional underwritten offerings, combined with additions to the borrowing base under our Apollo Credit Facility which may become available and internally generated cash flows and other potential sources of funds, will be adequate to fund our short-term and long-term operations, including our capital budget, repayment of debt maturities, and any amount that may ultimately be paid in connection with contingencies; however, the Apollo Credit Facility gives Apollo control of certain operational accounts (the "Restricted Accounts").

Apollo's control notwithstanding, absent an event of default, the Apollo Credit Facility requires that Apollo release to us funds needed to pay for approved operational activity ("Required Releases"), subject to certain limitations on the order in which we undertake new projects, and for the payment of certain permitted expenses that arise in the ordinary course of business. The release of funds for other purposes is subject to Apollo's discretion, except that, absent an event of default and so long as at least half of these funds are spent on projects included in our plan of development, we do have the right to use 50% of all proceeds raised from sales of equity securities in excess of $20,000 on such matters as we see fit. We reached this $20,000 threshold on October 5, 2012, the date of the initial public offering of Series C Preferred Stock. The intent of the restrictions in the Apollo Credit Facility on our ability to access cash in our accounts is to require the Company allocate available cash to high-priority projects first and to control spending that is not strongly linked to the development of our existing assets. To date, the restrictions have not impeded our ability to run the business in any way, except that we have requested from time to time that Apollo agree to change the priorities of certain projects on our approved plan of development to better respond to changing market conditions in the Cook Inlet region. Periodic adjustments to our approved plan of development were contemplated by the terms of the Apollo Credit Facility, and, to date, Apollo has granted our requests when made. Were an event of default to occur under the Loan Agreement, including a failure to comply with the restrictive covenants contained in the Loan Agreement, Apollo would have the authority to prevent our accessing the Restricted Accounts. We do not anticipate that the restrictions placed on our accounts under the Apollo Credit Facility will interfere with, or require any alteration of, management's overall plans in the future, subject to the need to make additional adjustments to the approved plan of development as market conditions change.

Pursuant to the Acknowledgment and Amendment No. 2 to the Loan Agreement, upon each sale of our Series C Preferred Stock, we have agreed to deposit a portion of the proceeds of the sale into a separate account (the "Dividend Account") in an amount at least equal to the dividends scheduled to come due on our Series B Preferred Stock and our Series C Preferred Stock on or prior to September 3, 2013. As of July 31, 2013, the balance in this account was $793. Apollo has taken a security interest in this Dividend Account, and the terms of the Apollo Credit Facility state that we may only disburse funds from this account as needed to pay dividends on the Series B Preferred Stock and Series C Preferred Stock. If an event of default were to occur under the Apollo Credit Facility, Apollo would have the right to take control over the Dividend Account. On September 3, 2013, we paid a cash dividend on the Series B Preferred Stock and our Series C Preferred Stock of approximately $6.05 and approximately $0.67 per share, respectively, in accordance with the terms of the Series B Preferred Stock and the Series C Preferred Stock as set forth in our charter. Following this payment of dividends, we expect the Dividend Account will remain empty, unless an extension on its use is otherwise agreed to by Apollo.

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Current restricted cash balances include amounts held in escrow to secure company related credit cards. As of July 31, 2013 and April 30, 2013, current restricted cash also includes $3,407 and $7,144 of cash temporarily held in an account that is controlled by our lender and is inclusive of the aforementioned dividend account. Non-current restricted cash balances include amounts held in escrow to provide for the future plugging and abandonment of wells, the possible dismantling of our off-shore platform, performance bonds, and general liability bonds.

Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents for the periods presented:



	For the Three Months Ended July 31,
	2013			2012
Sources of cash and cash equivalents:
Net cash provided by operating activities	$	—		$	3,608
Proceeds from borrowings, net of debt acquisition costs	—			36,243
Proceeds from sale of equipment	—			2,000
Exercise of equity rights	63			125
Issuance of preferred stock, net of issuance costs	21,974			—
Release of restricted cash	2,596			640
	24,633			42,616
Uses of cash and cash equivalents:
Net cash used in operating activities	(4,431		)	—
Dividends paid	(1,315		)	—
Capital expenditures for oil and gas properties	(15,235		)	(4,714		)
Prepayment of drilling costs	(2,339		)	—
Purchase of equipment and improvements	(739		)	(4,611		)
Payments on debt	—			(24,130		)
Redemption of preferred stock	—			(11,240		)
	(24,059		)	(44,695		)

Increase (decrease) in cash and cash equivalents	$	574		$	(2,079	)

Net Cash Provided by (Used in) Operating Activities

Our sources of capital and liquidity are partially supplemented by cash flows from operations, both in the short-term and long-term. These cash flows, however, are highly impacted by volatility in oil and natural gas prices. The factors in determining operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, asset retirement obligation ("ARO") accretion, non-cash compensation, and deferred income tax expense, which affect earnings but do not affect cash flows.

Net cash used in operating activities for the first quarter of fiscal 2014 totaled $4,431, down $8,039 from the $3,608 net cash provided by operating activities for the same period in fiscal 2013. The decrease resulted primarily from an unfavorable shift in the timing of cash receipts in the ordinary course of business.

Proceeds from Credit Facilities and Other Items

During the first quarter of fiscal 2013, borrowings under our Apollo Credit Facility totaled $40,000. In connection with the establishment of the new facility, we incurred approximately $3,757 in deferred financing costs. The proceeds were used to repay our Guggenheim credit facility and redeem our outstanding Series A Cumulative Preferred Stock. As of July 31, 2013, our Apollo Credit Facility had a balance of $55,307, and the net change was a result of borrowings and interest which had been capitalized during the 2013 fiscal year. For additional information on the credit facilities, please see Note 7 - Debt.

During the first quarter of our 2014 fiscal year, we had an exercise of 25,000 stock options that provided for $63 in proceeds from the exercise of equity rights compared to the $125 reflected in the same period for the prior year.

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We had no proceeds from the sales of equipment during the first quarter of our 2014 fiscal year whereas during the same period in the prior year we received proceeds from the sale of a generator totaling $2,000.

The significant increase in net cash flows provided by financing activities was a result of $23,508 received from issuances of our Series C Preferred Stock partially offset by issuance costs of $1,534.

For the quarter ended July 31, 2013, release of restricted cash was $2,596 as compared to $640 in the same period last year. The net change in restricted cash is reflected as either a release or a use of restricted cash in the sources and uses of cash table. The classification is dependent on whether unrestricted cash is transferred to or from our restricted cash accounts, on a net basis.

Short-term restricted cash primarily relates to the Restricted Accounts controlled by Apollo and the Dividend Account, which is subject to contractual restriction discussed above. Apollo requires revenues and certain other items to be deposited directly into the Restricted Accounts. As Apollo controls the Restricted Accounts, it has the ability to prevent disbursements from those accounts to our unrestricted cash accounts; subject however, to the Required Releases discussed above. Amounts deposited into Restricted Accounts in excess of interest on the credit facility, lender fees, etcetera are generally released to us in a timely manner. Accordingly, the amount released from or transferred to our Restricted Accounts depends on hold backs and the timing of transfers at Apollo's discretion. In addition, prior to September 3, 2013, Apollo required we maintain a balance in the Dividend Account sufficient to meet certain dividend payments on our Series B and Series C Preferred Stock, and which we were, under the terms of the Loan agreement, prohibited from using for any other purpose.

Long-term restricted cash balances include amounts held in escrow to provide for the future plugging and abandonment of wells, the possible dismantling of our off-shore platform, performance bonds and general liability bonds. Amounts released from our long-term restricted cash accounts, if any, would be the result of a release from escrow by the beneficiary. Amounts transferred to our long-term restricted cash accounts result from bonding requirements for new wells and additions to our current bonding requirements.

On April 30, 2013, the Board of Directors declared a quarterly dividend of approximately $0.67 per share on the Series C Preferred Stock. The dividend payment is equivalent to an annualized 10.75% per share, based on the $25.00 per share stated liquidation preference, accruing from March 2013 through May 2013. The record date was May 15, 2013 and the dividend was payable on June 1, 2013. June 1, 2013 was not a business day, and in accordance with our charter, the dividend was paid on June 3, 2013 in the amount of $1,315.

Capital Expenditures

We use a combination of operating cash flows, borrowings under credit facilities and, from time to time, issuances of debt or common stock to fund significant capital projects. Due to the volatility in oil and natural gas prices, our capital expenditure budgets, both in the short-term and long-term, are adjusted on a frequent basis to reflect changes in forecasted operating cash flows, market trends in drilling and acquisition costs, and production projections.

Total spending on capital projects increased significantly from the same period last year. For the three months ending July 31, 2013, we incurred total capital expenditures of $28,965 which is inclusive of the increase in our capital accrual account of $12,991. Cash paid for capital expenditures was $15,974 for the three months ended July 31, 2013. During the first quarter of fiscal 2014, we completed drilling of our RU-2A well and began drilling our RU-1A, Sword #1 and Olson Creek #1 wells, all in the Cook Inlet region. During the first quarter of fiscal 2013, capital spending primarily related to the drilling of our Otter #1 well in the Cook Inlet region and the construction of Rig 35.

Prepayment of Drilling Costs

We occasionally are required to pay in advance for certain equipment rental and services related to our drilling activities. The advance payments are recorded in prepaid expenses at the time of payment and amortized to capital expenditures as the costs are incurred. At July 31, 2013, we had $2,339 in prepaid drilling costs related to the rental of the drilling rig being used on Sword #1 that had not been incurred as of such date.

Liquidity

Cash and Cash Equivalents

As of July 31, 2013, we had $3,125 in cash and cash equivalents.

Debt and Available Credit Facilities

As of July 31, 2013, outstanding debt consisted of $55,307 under our Apollo Credit Facility, $6,000 of which is classified as a current debt obligation with the remainder classified as long-term debt on the accompanying condensed consolidated balance sheet. As of July 31, 2013 we had no additional borrowing capacity under our Apollo Credit Facility.

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Contractual Obligations

On June 29, 2012, we entered into a loan agreement with Apollo which provides for a $100,000 credit facility with an initial borrowing base of $55,000. In conjunction with the initiation of the Apollo Credit Facility, we paid in full all outstanding principal and interest balances under the Guggenheim Credit Facility. Refer to Note 7 - Debt of the accompanying unaudited condensed consolidated financial statements for additional information regarding these credit facilities.

On September 24, 2012, we sold 25,750 shares of our Series B Preferred Stock for gross proceeds of $2,575. We paid $167 of issuance costs which have been capitalized and are being amortized over the term of the instrument. The outstanding Series B Preferred Stock is classified as long-term debt, in accordance with ASC 480. See Note 7 - Debt in the Notes as set forth in the accompanying unaudited condensed consolidated financial statements.

On September 28, 2012, we sold 685,000 shares of our Series C Preferred Stock for gross proceeds of $15,755. We incurred issuance costs of $1,335, yielding net proceeds of $14,420. These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated September 28, 2012, and the Company's registration statement on Form S-3 (Registration No. 333-183750), which was declared effective by the SEC on September 18, 2012. The Series C Preferred Stock is classified as temporary equity in accordance with ASC 480 and is being accreted to redemption value through the earliest repayment date of November 1, 2017. See Note 10 - Stockholders' Equity in the Notes as set forth in the accompanying unaudited condensed consolidated financial statements.

On October 12, 2012, we entered into an At Market Issuance Sales Agreement with MLV. This Agreement provides for the issuance by us of our common stock or Series C Preferred Stock, and for the subsequent sale of those shares into the market at the prevailing market price by MLV. These securities are registered for sale to the public pursuant to a prospectus, dated September 19, 2012, a prospectus supplement dated October 12, 2012, and our registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012. Under this Agreement, if and when we request MLV to engage in the sale of any or our securities, we will be obligated to pay to MLV a commission equal to 3.0% of the gross proceeds of any sale of our common stock and 3.5% of the gross proceeds of any sale of our Series C Preferred Stock. Although there are conditions on our initiating any new sale of securities and there are customary indemnities and cost reimbursement requirements, as described in the ATM Agreement, there are no operational or financial covenants that restrict our operations.

On May 7, 2013, we entered into an Underwriting Agreement with MLV as representative for a group of underwriters for a follow-on "best efforts" offering of our Series C Preferred Stock. We sold an additional 500,000 shares of our Series C Preferred Stock, at a price of $22.25 per share. We received gross proceeds of $11,125 in connection with the offering, from which MLV was paid a commission of $805. These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated May 7, 2013, and the Company's registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012.

On June 27, 2013, we entered into an Underwriting Agreement with MLV as representative for a group of underwriters for a follow-on "best efforts" offering of our Series C Preferred Stock. We sold an additional 335,000 shares of our Series C Preferred Stock, at a price of $21.50 per share. We received gross proceeds of $7,203 in connection with the offering, from which MLV was paid a commission of $547. These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated June 27, 2013, and the Company's registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012.

As of July 31, 2013 and for the first quarter of fiscal 2014, there were no additional material changes outside the ordinary course of business in our contractual obligations and commitments other than the aforementioned agreements. For additional information regarding these obligations, please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations-Contractual Cash Obligations and Commitments" contained in our Annual Report on Form 10-K for the fiscal year ended April 30, 2013, as amended, and incorporated by reference herein.

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Non-GAAP Measures

Adjusted Earnings

Adjusted earnings before interest, taxes, depreciation and amortization ("EBITDA") is a significant performance metric used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts and others to assess:


•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;


•	the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and


•	our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure.

We define Adjusted EBITDA as net income (loss) before taxes adjusted by:


•	depreciation, depletion and amortization;


•	write-off of deferred financing fees;


•	asset impairments;


•	(gain) loss on sale of assets;


•	accretion expense;


•	exploration costs;


•	(gain) loss from equity investment;


•	stock-based compensation expense;


•	unrealized (gain) loss from mark-to-market activities;


•	interest expense and interest (income)

Our Adjusted EBITDA should not be considered as a substitute for net income (loss), operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

The following tables present a reconciliation of net income (loss) before income taxes to Adjusted EBITDA, our most directly comparable GAAP performance measure, for each of the periods presented:



	For the Three Months Ended July 31,
	2013			2012
Income (loss) before income taxes	$	(11,547	)	$	3,732
Adjusted by:
Interest expense, net	2,281			131
Depreciation, depletion, and amortization	5,692			3,125
Accretion of asset retirement obligation	297			284
Exploration expense	286			29
Stock-based compensation	1,666			2,075
Unrealized (gain) loss on derivatives	2,519			(4,880		)
Adjusted EBITDA	$	1,194		$	4,496

Recent Accounting Pronouncements

In December 2011, the FASB issued ASU 2011-11, "Disclosures about Offsetting Assets and Liabilities," which increases disclosures about offsetting assets and liabilities. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and IFRS related to the offsetting of financial instruments. The existing GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance in ASU 2011-11 is effective for annual and interim reporting periods beginning on or after January 1,

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2013. The disclosures should be applied retrospectively for all prior periods presented. We have evaluated the new pronouncement and have determined that there is no impact to our condensed consolidated financial statements.

There are no other recently issued accounting pronouncements that are expected to have a material impact on our financial condition, results of operations or cash flows.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our exposure to market risk. The term market risk relates to the risk of loss arising from adverse changes in oil, gas, and interest rates, or adverse governmental actions. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil production and, to some extent, our natural gas production. Our realized oil price is primarily driven by the NYMEX pricing of the West Texas Intermediate (Cushing, Oklahoma) and ANS (West Coast Alaskan North Slope) crude oil. Historically, pricing for oil and natural gas has been volatile and unpredictable and we expect this volatility to continue in the future. The prices we receive for oil and natural gas production depend on many factors outside our control, including weather, economic conditions, and the total supply of oil and natural gas available for sale in the market.

We have entered into hedging arrangements with respect to a portion of our projected future production through various derivatives that hedge the future prices received. These hedging activities are intended to support commodity sales prices at targeted levels and to manage our exposure to commodity price fluctuations. We do not hold or issue derivative instruments for speculative trading purposes. The use of hedging transactions also involves the risk that our counterparty will be unable to meet the financial terms of the transactions executed. We attempt to minimize this risk by entering into derivative transactions with a counterparty that is a creditworthy financial institution deemed by management and our lenders as a competent and competitive market maker.

The following tables summarize, for the periods indicated, our hedges currently in place through June 2016. All of these derivatives are accounted for as mark-to-market activities.



	For the Quarter Ended (in bbls)
	July 31,			October 31,			January 31,			April 30,			Total
Fiscal	Volume	Avg. Price		Volume	Avg. Price		Volume	Avg. Price		Volume	Avg. Price		Volume	Avg. Price
2014	—	$	—	147,200	$	102.05	147,200	$	101.73	142,400	$	101.10	436,800	$	101.63
2015	147,200	101.10		147,200	101.10		147,200	99.16		142,400	95.35		584,000	99.21
2016	147,200	95.35		147,200	95.35		147,200	94.20		144,000	91.95		585,600	94.23
2017	97,600	91.95		—	—		—	—		—	—		97,600	91.95
													1,704,000	$	97.70

Interest Rate Risk

We consider our interest rate risk exposure to be minimal as a result of fixing interest rates on 100% of our debt. At July 31, 2013, there was no float-rate debt that would expose us to market fluctuations in interest rates.

ITEM 4. CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our CEO and our Chief Financial Officer ("CFO"), we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended, at the end of the period covered by this report (the “evaluation date”). In conducting its evaluation, management considered the material weaknesses in our disclosure controls and procedures and internal control over financial reporting described in Item 9A. of our Annual Report on Form 10-K for the year ended April 30, 2013 as filed with the SEC on July 15, 2013 and as further amended on August 28, 2013.

As of the evaluation date, our CEO and CFO have concluded that 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 disclosures.

Our management, including the CEO and CFO, 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

We are currently working to remediate the material weaknesses identified in our Annual Report on Form 10-K for the year ended April 30, 2013 as filed with the SEC on July 15, 2013 and as further amended on August 28, 2013. Such efforts have involved searching for additional accounting resources and shifting the financial reporting responsibilities of certain accounting personnel to more closely align their talents with the necessary skill sets. We believe the adjustments we made to our existing accounting personnel during the three months ended July 31, 2013 improved the quality of our financial reporting process; however, we are still searching for the appropriate accounting resources to supplement our finance and accounting department.

Other than the initiatives described above, there have been no changes 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.

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(dollars in thousands, except share and per share data and unit and per unit data)

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

The information set forth in Note 13 - Litigation in the accompanying unaudited condensed consolidated financial statements is incorporated herein by reference.

ITEM 1A. RISK FACTORS.

For a detailed discussion of the risks and uncertainties associated with our business see “Risk Factors” in our 2013 Annual Report. There have been no material changes to these risk factors since that report.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

None.

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ITEM 6. EXHIBITS.

The following documents are filed as a part of this report:



EXHIBIT NO.		DESCRIPTION
3.1	–	Certificate of Incorporation (incorporated by reference to Registrant's Annual Report on Form 10-KSB (Commission file number 033-02249-FW) for the year ended December 31, 1995).
3.2	–	Certificate of Amendment of Certificate of Incorporation (incorporated by reference to Registrant's Annual Report on Form 10-KSB (Commission file number 033-02249-FW) for the year ended December 31, 1995).
3.3	–	Certificate of Amendment of Certificate of Incorporation (incorporated by reference to Registrant's Annual Report on Form 10-KSB (Commission file number 033-02249-FW) for the year ended December 31, 1995).
3.4	–	Certificate of Ownership and Merger and Articles of Merger between Triple Chip Systems, Inc. and Miller Petroleum, Inc. (incorporated by reference to Registrant's exhibits filed with the registration statement on Form SB-2, SEC File No. 333-53856, as amended).
3.5	–	Amended and Restated Charter of Miller Petroleum, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on April 29, 2010).
3.6	–	Amended and Restated Bylaws of Miller Petroleum, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on April 29, 2010).
3.7	–	Articles of Amendment to the Bylaws of Miller Petroleum, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on March 17, 2011).
3.8	–	Articles of Amendment to the Charter of Miller Petroleum, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on April 15, 2011).
3.9	–	Articles of Amendment to the Charter of Miller Energy Resources, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on April 2, 2012).
3.10	–	Articles of Amendment to the Charter of Miller Energy Resources, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on August 17, 2012).
3.11	–	Articles of Amendment to the Charter of Miller Energy Resources, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on September 4, 2012).
3.12	–	Articles of Amendment to the Charter of Miller Energy Resources, Inc. (incorporated by reference to Exhibit 3.20 to Registrant's Registration Statement on Form 8-A as filed on September 28, 2012).
10.1	–	Underwriting Agreement dated May 7, 2013 between Miller Energy Resources, Inc. and MLV & Co. LLC, as representative for the underwriters identified therein (incorporated by reference to Registrant's Current Report on Form 8-K filed on May 7, 2013).
10.2	–	Underwriting Agreement dated June 27, 2013 by and among the Miller Energy Resources, Inc. and MLV & Co. LLC as representative for the underwriters identified therein (incorporated by reference to Registrant's Current Report on Form 8-K filed on June 28, 2013).
10.3	–	Waiver and Amendment No. 5 dated July 11, 2013 (incorporated by reference to Registrant's Current Report on Form 8-K filed on July 12, 2013).
10.4	–	Amended and Restated Employment Agreement with Catherine A. Rector dated July 22, 2013 (incorporated by reference to Registrant's Current Report on Form 8-K filed on July 26, 2013).
10.5	–	Employment Agreement with Scott M. Boruff, dated as of July 29, 2013 (incorporated by reference to Registrant's Current Report on Form 8-K/A filed on August 28, 2013).
10.6	–	Employment Agreement with David J. Voyticky, dated as of July 29, 2013 (incorporated by reference to Registrant's Current Report on Form 8-K/A filed on August 28, 2013).
10.7	–	Employment Agreement with Deloy Miller, dated as of July 29, 2013 (incorporated by reference to Registrant's Current Report on Form 8-K/A filed on August 28, 2013).
10.8	–	Employment Agreement with David M. Hall, dated as of July 29, 2013 (incorporated by reference to Registrant's Current Report on Form 8-K/A filed on August 28, 2013).
10.9	–	Employment Agreement with Kurt C. Yost, dated as of July 29, 2013 (incorporated by reference to Registrant's Current Report on Form 8-K/A filed on August 28, 2013).
31.1	–	Rule 13a-14(a)/15d-14(a) certification of Chief Executive Officer *
31.2	–	Rule 13a-14(a)/15d-14(a) certification of Chief Financial Officer *
32.1	–	Section 1350 certification of Chief Executive Officer*
32.2	–	Section 1350 certification of Chief Financial Officer*
101.INS	–	XBRL Instance Document **
101.SCH	–	XBRL Taxonomy Extension Schema Document **
101.CAL	–	XBRL Taxonomy Extension Calculation Linkbase Document**
101.LAB	–	XBRL Taxonomy Extension Label Linkbase Document **
101.PRE	–	XBRL Taxonomy Extension Presentation Linkbase Document **
101.DEF	–	XBRL Taxonomy Extension Definition Linkbase Document **

———————

* filed herewith.

** In accordance with Regulation S-T, the XBRL-formatted interactive data files that comprise Exhibit 101 in this report on Form 10-Q shall be deemed “furnished” and not “filed”.

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SIGNATURES

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



Dated:	September 9, 2013	MILLER ENERGY RESOURCES, INC.

		By:	/s/ SCOTT M. BORUFF
			Scott M. Boruff, Chief Executive Officer, principal executive officer


Dated:	September 9, 2013	MILLER ENERGY RESOURCES, INC.

		By:	/s/ DAVID J. VOYTICKY
			David J. Voyticky, Chief Financial Officer, principal financial officer