Edgar Filing: MILLER ENERGY RESOURCES, INC.

2015 MILL Q1 10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

———————

FORM 10-Q

———————

(Mark One)

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

For the quarterly period ended July 31, 2014

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

For the transition period from __________________ to __________________________

Commission file number: 001-34732

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MILLER ENERGY RESOURCES, INC.

(Exact name of registrant as specified in its charter)

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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 Office) (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, 2014 was 46,351,471.

TABLE OF CONTENTS





			Page
PART I		Financial Information
	Item 1.	Financial Statements:	1
		Condensed Consolidated Balance Sheets as of July 31, 2014 and April 30, 2014	1
		Condensed Consolidated Statements of Operations for the Three Months Ended July 31, 2014 and 2013	2
		Condensed Consolidated Statement of Stockholders' Equity for the Three Months Ended July 31, 2014	3
		Condensed Consolidated Statements of Cash Flows for the Three Months Ended July 31, 2014 and 2013	4
		Notes to Condensed Consolidated Financial Statements	5
		Forward Looking Statements	22
	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	22
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36
	Item 4.	Controls and Procedures	37

PART II		Other Information
	Item 1.	Legal Proceedings	38
	Item 1A.	Risk Factors	39
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
	Item 5.	Other Information	39
	Item 6.	Exhibits	40
	SIGNATURES		41

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 data)



	July 31, 2014			April 30, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,719		$	5,749
Restricted cash	1,455			679
Accounts receivable, net of allowances of $364 and $252	6,188			6,409
Alaska production credits receivable, net of allowances of $2,159 and $7,124	53,614			49,121
Inventory	9,839			5,102
Prepaid expenses and other	4,373			3,940
Assets held for sale	236			236
Total current assets	79,424			71,236
OIL AND GAS PROPERTIES, NET	635,655			644,827
EQUIPMENT, NET	40,064			35,369
OTHER ASSETS:
Land	1,848			1,848
Restricted cash, non-current	13,580			12,075
Deferred financing costs, net	2,603			803
Other assets	822			664
Total assets	$	773,996		$	766,822
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	45,228		$	38,836
Accrued expenses	11,439			20,446
Short-term portion of derivative instruments	5,697			3,315
Deferred income taxes	5,060			2,858
Current portion of long-term debt, including capital leases	8,401			9,459
Total current liabilities	75,825			74,914
OTHER LIABILITIES:
Deferred income taxes	130,217			139,768
Asset retirement obligation	23,372			22,872
Long-term portion of derivative instruments	6,964			4,006
Long-term debt and capital leases, less current portion	196,872			174,743
Other	25			—
Total liabilities	433,275			416,303

MEZZANINE EQUITY:
Series C Cumulative Preferred Stock, redemption amount of $78,124, 3,250,000 shares authorized, 3,069,968 and 3,069,968 shares issued and outstanding as of July 31, 2014 and April 30, 2014, respectively	68,454			67,760

STOCKHOLDERS' EQUITY:
Series D Cumulative Redeemable Preferred Stock, redemption amount of $35,034 and $32,378, 4,000,000 shares authorized, 1,132,752 and 1,070,448 shares issued and outstanding as of July 31, 2014 and April 30, 2014, respectively	31,711			30,041
Series D Cumulative Redeemable Preferred Stock, 213,586 shares held in escrow	(5,000		)	(5,000		)
Common stock, $0.0001 par, 500,000,000 shares authorized, 46,108,061 and 45,756,697 shares issued and outstanding as of July 31, 2014 and April 30, 2014, respectively	5			4
Additional paid-in capital	102,247			98,788
Retained earnings	143,304			158,926
Total stockholders' equity	272,267			282,759
Total liabilities and stockholders' equity	$	773,996		$	766,822

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 data)



	Three Months Ended July 31,
	2014			2013
REVENUES:
Oil sales	$	19,301		$	12,258
Natural gas sales	5,797			270
Other	281			480
Total revenues	25,379			13,008
OPERATING EXPENSES:
Lease operating expense	6,626			5,640
Transportation costs	2,984			625
Cost of purchased gas sold	972			—
Cost of other revenue	340			284
General and administrative	9,511			6,360
Alaska carried-forward annual loss credits, net	(3,055		)	—
Exploration expense	296			286
Depreciation, depletion and amortization	16,978			5,692
Accretion of asset retirement obligation	346			297
Other operating expense, net	4			—
Total operating expense	35,002			19,184
OPERATING LOSS	(9,623		)	(6,176		)
OTHER EXPENSE:
Interest expense, net	(2,799		)	(2,281		)
Loss on derivatives, net	(6,903		)	(3,076		)
Other income (expense), net	122			(14		)
Total other expense	(9,580		)	(5,371		)
LOSS BEFORE INCOME TAXES	(19,203		)	(11,547		)
Income tax benefit	7,349			4,619
NET LOSS	(11,854		)	(6,928		)
Accretion of Series C and D preferred stock	(822		)	(453		)
Series C and D preferred stock cumulative dividends	(2,946		)	(2,036		)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(15,622	)	$	(9,417	)

LOSS PER COMMON SHARE:
Basic	$	(0.34	)	$	(0.22	)
Diluted	$	(0.34	)	$	(0.22	)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic	45,922,162			43,455,054
Diluted	45,922,162			43,455,054

See accompanying notes to the condensed consolidated financial statements.

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MILLER ENERGY RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

(Unaudited)

(Dollars in thousands, except share data)



	Series D Preferred Stock			Common Stock			Additional Paid-in Capital		Retained Earnings			Total
	Shares	Amount		Shares	Amount		Additional Paid-in Capital		Retained Earnings			Total
Balance at April 30, 2014	1,070,448	$	25,041	45,756,697	$	4	$	98,788	$	158,926		$	282,759
Net loss	—	—		—	—		—		(11,854		)	(11,854		)
Series C preferred stock dividends	—	—		—	—		—		(2,062		)	(2,062		)
Accretion of Series C preferred stock	—	—		—	—		—		(694		)	(694		)
Issuance of Series D preferred stock	62,304	1,542		—	—		—		—			1,542
Series D preferred stock dividends	—	—		—	—		—		(884		)	(884		)
Accretion of Series D preferred stock	—	128		—	—		—		(128		)	—
Issuance of equity for services	—	—		—	—		416		—			416
Issuance of equity for compensation	—	—		40,010	—		1,645		—			1,645
Exercise of equity rights	—	—		311,354	1		1,398		—			1,399
Balance at July 31, 2014	1,132,752	$	26,711	46,108,061	$	5	$	102,247	$	143,304		$	272,267

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,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(11,854	)	$	(6,928	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	16,978			5,692
Amortization of deferred financing fees and debt discount	362			280
Expense from issuance of equity	2,599			1,666
Dry hole costs, leasehold impairments and non-cash exploration expenses	—			157
Deferred income taxes	(7,349		)	(4,619		)
Derivative contracts:
Loss on derivatives, net	6,903			3,076
Cash settlements	(1,449		)	(557		)
Alaska carried-forward annual loss credits, net	(3,055		)	—
Accretion of asset retirement obligation	346			297
Other, net	(792		)	1,043
Changes in operating assets and liabilities:
Receivables	687			(4,804		)
Inventory	(52		)	(97		)
Prepaid expenses and other assets	571			(669		)
Accounts payable, accrued expenses and other	3,529			1,032
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	7,424			(4,431		)

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for oil and gas properties	(40,182		)	(15,235		)
Proceeds from Alaska expenditure and exploration based credits	21,837			—
Prepayment of drilling costs	(1,151		)	(2,339		)
Purchase of equipment and improvements	(6,129		)	(739		)
NET CASH USED IN INVESTING ACTIVITIES	(25,625		)	(18,313		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Cash dividends	(2,904		)	(1,315		)
Payments on debt	(2,306		)	—
Proceeds from First Lien RBL	30,000			—
Payments on First Lien RBL	(10,000		)	—
Proceeds from capital lease obligations	3,250			—
Principal payments on capital lease obligations	(112		)	—
Debt acquisition costs	(2,417		)	—
Issuance of preferred stock	1,587			23,508
Equity issuance costs	(45		)	(1,534		)
Exercise of equity rights	1,399			63
Restricted cash	(2,281		)	2,596
NET CASH PROVIDED BY FINANCING ACTIVITIES	16,171			23,318
NET CHANGE IN CASH AND CASH EQUIVALENTS	(2,030		)	574

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	5,749			2,551
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	3,719		$	3,125
SUPPLEMENTARY CASH FLOW DATA:
Cash paid for interest	$	5,355		$	694
SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Increases in capital expenditures included in accounts payable and accrued expenses	$	—		$	12,991
Reduction of oil and gas properties and equipment from applications for Alaska expenditure and exploration based credits	$	23,275		$	5,642
Accretion of preferred stock	$	822		$	453

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 per share data 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," 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 Energy Colorado 2014-1, LLC, Miller Drilling, TN LLC, Miller Energy Services, LLC, East Tennessee Consultants, Inc. ("ETC"), East Tennessee Consultants II, LLC ("ETCII"), 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 southcentral Alaska, including the Cook Inlet and Kenai Peninsula, 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, 2014, which was filed with the SEC on July 14, 2014, and amended on July 15, 2014.

Certain amounts in prior fiscal years have been reclassified to conform with the presentation adopted in the current year.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our significant accounting policies are consistent with those disclosed in our Annual Report on Form 10-K for the year ended April 30, 2014.

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.

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

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(Unaudited)

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

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 depleted 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 than the net 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, 2014 or July 31, 2013.

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, 2014 our condensed consolidated statement of operations includes no impairment of certain unproved properties and $296 in seismic and delay rentals incurred in the Cook Inlet region.

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). For the three months ended July 31, 2014, our cumulative preferred dividends were $2,946.

Deferred Escalating Minimum Rent

Certain of our operating leases contain predetermined fixed escalations of the minimum rentals during the term of the lease, which includes option periods where failure to exercise such options would result in an economic penalty. For these leases, we recognize the related rental expense on a straight-line basis over the life of the lease, beginning with the point at which we obtain control and possession of the leased properties, and record the difference between the amounts charged to operations and amounts paid as deferred escalating minimum rent. Any lease incentives received are deferred and subsequently amortized on a straight-line basis over the life of the lease as a reduction to rent expense.

New Accounting Pronouncements Issued But Not Yet Adopted

In July 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2013-11, "Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists." The amendments in ASU 2013-11 require an entity to present an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for a net operating loss ("NOL") carryforward, a similar tax loss, or a tax credit carryforward except when: (1) a NOL carryforward, a similar tax loss, or a tax credit carryforward is not available as of the reporting date under the governing tax law to settle taxes that would result from the disallowance of the tax position; or (2) the entity does not intend to use the deferred tax asset for this purpose (provided that the tax law permits a choice). If either of these conditions exists, an entity should present an unrecognized tax benefit in the financial statements as a liability and should not net the unrecognized tax benefit with a deferred tax asset. The amendment does not affect the recognition or measurement of uncertain tax positions under ASC Topic 740, "Income Taxes." The amendments in this ASU are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The amendments should be applied prospectively to all

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(Unaudited)

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

unrecognized tax benefits that exist at the effective date. Retrospective application is permitted. We do not expect this ASU to have a material impact to our condensed consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)." ASU 2014-09 is intended to improve the financial reporting requirements for revenue from contracts with customers by providing a principle based approach. The core principle of the standard is that revenue should be recognized when the transfer of promised goods or services is made in an amount that the entity expects to be entitled to in exchange for the transfer of goods and services. ASU 2014-09 also requires disclosures enabling users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. This standard will be effective for financial statements issued by public companies for annual reporting periods beginning after December 15, 2016. Early adoption is not permitted. The Company is currently evaluating the potential impact of ASU 2014-09 on the condensed consolidated financial statements.

New Accounting Pronouncements Issued and Adopted

In April 2014, the FASB issued ASU 2014-08, "Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." ASU 2014-08 changes the definition of a discontinued operation to include only those disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity's operations and financial results. In addition, ASU 2014-08 requires additional disclosures about both discontinued operations and the disposal of an individually significant component of an entity that does not qualify for discontinued operations presentation in the financial statements. The guidance is effective prospectively for fiscal years, and interim periods within those years, beginning after December 15, 2014, with early adoption permitted. We adopted the provisions of ASU 2014-08 on a prospective basis during the first quarter of fiscal year 2015. The adoption of this ASU did not have a material impact on 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. ACQUISITIONS AND DIVESTITURES

Merger Agreement with Savant Alaska, LLC

On May 8, 2014, we entered into an Agreement and Plan of Merger with Savant Alaska, LLC ("Savant") to acquire Savant, subject to due diligence and regulatory approval, for $9,000. We have formed a wholly-owned subsidiary, Miller Energy Colorado 2014-1, LLC, which will merge with Savant to facilitate the acquisition. Savant currently owns, and we would acquire as a result of this merger, a 67.5% working interest in the Badami Unit and 100% ownership in certain nearby leases. ASRC Exploration, LLC owns the remaining 32.5% working interest in the Badami Unit. In addition to the working interest in the Badami Unit and the leases, we would acquire certain midstream assets located in the North Slope with a design capacity of 38,500 bopd, a 500,000 gallon diesel storage tank, 20 megawatts of power generation, a grind and inject solid waste disposal facility and Class 1 disposal well, a one mile airstrip, and two pipelines each running 25 miles in length from Badami to the Endicott Pipeline. Production from the Savant assets was approximately 1,100 bopd gross (600 bopd net) at the time of our announcement of the acquisition.

We expect the transaction to close by December 2014, following regulatory approval, with a May 1, 2014 effective date as defined in the Agreement and Plan of Merger.

North Fork Purchase

On November 22, 2013, CIE entered into a purchase and sale agreement by and among Armstrong Cook Inlet, LLC, GMT Exploration Company, LLC, Dale Resources Alaska, LLC, Jonah Gas Company, LLC and Nerd Gas Company, LLC (together, the "North Fork Sellers") and CIE (the "North Fork Purchase Agreement"). Pursuant to the North Fork Purchase Agreement, CIE (i) acquired a 100% working interest in six natural gas wells and related leases (consisting of approximately 15,465 net acres) referred to as the "North Fork Unit" in the Cook Inlet region of the State of Alaska, together with other associated rights, interests and assets for cash consideration of $59,557 and (ii) all the issued and outstanding membership interests of Anchor Point Energy, LLC (the "Anchor Point Equity"), a limited liability company owning certain pipeline facilities and related assets which service the North Fork Properties (as defined below), for 213,586 shares (valued at approximately $5,000) of the Company's Series D Preferred Stock. Collectively we refer to the assets as the "North Fork Properties." The Company used $56,577 of funds under the Second Lien Credit Facility (defined below) to finance the acquisition and paid $3,000 in cash as a deposit on November 22, 2013 that was applied toward the purchase price.

The acquisition of the North Fork Properties closed on February 4, 2014 and the acquisition of the Anchor Point Equity closed upon receiving approval from the Regulatory Commission of Alaska, which occurred subsequent to the end of our first

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(Unaudited)

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

quarter, on August 8, 2014. The portion of consideration consisting of Series D Preferred Stock and an assignment of the Anchor Point Equity were deposited into an escrow account. These were disbursed upon the closure of the Anchor Point Equity acquisition pursuant to the terms of the North Fork Purchase Agreement.

The purchase of the North Fork Properties has been accounted for under ASC 805, "Business Combinations." Under ASC 805, the Company is required to allocate the purchase price to assets acquired and liabilities assumed based on their fair values at the acquisition date. The estimated fair value of the properties approximates the fair value of consideration, and as a result, no goodwill was recognized. The following table summarizes the consideration paid for the North Fork Properties and the allocation of the purchase price to the assets acquired and liabilities assumed that have been included in the Company's condensed consolidated financial statements for periods subsequent to the acquisition date. The Company is in the process of finalizing the evaluation of the assigned fair values to the assets acquired and liabilities assumed.



	As of February 3, 2014			Fiscal 2015 Adjustment			As of July 31, 2014
Accounts receivable	$	49		$	—		$	49
Proved oil and gas properties	55,454			159			55,613
Unproved oil and gas properties	5,958			—			5,958
Accounts payable	(433		)	—			(433		)
Asset retirement obligation	(1,437		)	(159		)	(1,596		)
Long-term liabilities	(34		)	—			(34		)
Total identifiable net assets	$	59,557		$	—		$	59,557

Acquisition-related costs of $404 were expensed by the Company. Net revenue of $5,675 was included in the consolidated statements of operation for the three months ended July 31, 2014 related to the North Fork Properties. Pro forma presentation of revenue and earnings for the three months ended July 31, 2013, as required by ASC 805 is impractical due to the present inaccessibility of sufficient financial records to produce relevant and reliable financial information.

Intended Divestiture of Tennessee Assets

On June 24, 2014, we announced our intent to divest our Tennessee assets in order to allocate our capital to our Alaskan operations and investment opportunities. No definitive agreement has been reached with any potential buyer in connection with this proposed transaction and, until that has occurred, we will continue to conduct our business as usual in Tennessee.

4. MAJOR CUSTOMERS AND CONCENTRATIONS OF CREDIT RISK

For the three months ended July 31, 2014 and 2013, Tesoro Corporation accounted for 74% and 89% of our consolidated total revenues, respectively. Tesoro Corporation also accounted for 13% and 5%, of our accounts receivable as of July 31, 2014 and April 30, 2014, 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, 2014 or 2013.

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, 2014, we held $3,754 in excess of the $250 limit insured by the Federal Deposit Insurance Corporation.

We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. We attempt to minimize credit-risk exposure to derivative counterparties through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements and guarantees of payment by credit worthy parties. We also enter into master netting agreements to mitigate counterparty performance and credit risk. During the three months ended July 31, 2014 and 2013, we did not incur any significant losses due to counterparty bankruptcy filings. We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts.

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

5. 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 Chief Operating Officer ("COO") of Miller, as well as the Chief Executive Officer ("CEO") of CIE. For the three months ended July 31, 2014 and 2013, we recorded capital and lease operating expenses related to H&H Industrial of $718 and $100, respectively. These expenses are not presumed to be carried out on an arm's length basis. The Audit Committee of our Board of Directors determined that the amounts paid by us for the services performed were fair and in the best interest of the Company.

6. OIL AND GAS PROPERTIES AND EQUIPMENT

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



	July 31, 2014			April 30, 2014
Property costs
Proved property	$	476,932		$	467,740
Unproved property	244,668			243,107
Total property costs	721,600			710,847
Less: Accumulated depletion	(85,945		)	(66,020		)
Oil and gas properties, net	$	635,655		$	644,827

Equipment is summarized as follows:



	July 31, 2014			April 30, 2014
Machinery and equipment	$	7,192		$	7,759
Vehicles	1,877			1,877
Buildings	2,726			2,726
Office equipment	1,213			1,108
Leasehold improvements	676			527
Drilling rigs	34,325			30,210
Capital lease asset	3,250			1,500
	51,259			45,707
Less: Accumulated depreciation	(11,195		)	(10,338		)
Equipment, net	$	40,064		$	35,369

The Company classified its aircraft as an asset held for sale on our condensed consolidated balance sheets as of April 30, 2014. The aircraft is recorded at estimated fair value less cost to sell. Proceeds received from the sale of the aircraft are required to pay down the Company's Second Lien Credit Facility (defined below).

Depreciation, depletion and amortization consisted of the following:



	For the Three Months Ended July 31,
	2014		2013
Depletion of oil and gas related assets	$	15,984	$	4,537
Depreciation and amortization of equipment	994		1,155
Total	$	16,978	$	5,692

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

We have obtained multiple reserve reports in the last twelve months due to our acquisition and drilling activity in Alaska. The reserve reports have provided incremental information to allow us to better understand the reserves on a field basis. These changes in reserve estimates have caused an increase in proved property depletion.

Entry into Glacier Rig Purchase Option

Effective as of July 4, 2014, we entered into a Purchase and Sale Agreement with Teras Oilfield Support Limited which grants us the right to purchase the Glacier Drilling Rig #1, a Mesa 1000 carrier-mounted land drilling rig (the "Glacier Rig") and related equipment (the Glacier "PSA"). During the three months ended July 31, 2014, a payment of $700 was made in connection with the execution and delivery of the Glacier PSA. An additional payment of $5,600 was made on August 8, 2014.

Acquisition of Rig 36 and Related Capital Lease

On May 5, 2014, we entered into a Rig Equipment Purchase Agreement with Baker Process, Inc. to purchase a 2400 HP rig, which we have named Rig 36, and related equipment. On May 9, 2014, the Company entered into a capital lease with First National Capital, LLC to finance the purchase of and planned future modifications to Rig 36. We have drawn $3,250 under the capital lease, which can be expanded to $5,000 as we continue to upgrade Rig 36.

7. DERIVATIVE INSTRUMENTS

Derivative Instruments

Commodity Derivatives

From time to time, we enter into derivative financial instruments to mitigate our exposure to crude oil price volatility. The derivative financial instruments, which are placed with financial institutions that we believe are acceptable credit risks, take the form of over-the-counter variable-to-fixed price commodity swaps. All derivative financial instruments are recognized in our condensed consolidated financial statements at fair value. The fair values of our derivative instruments are determined based on discounted cash flows derived from quoted forward prices. We do not use hedge accounting for commodity derivatives; thus, the open positions are recorded at fair value with the change in value recorded to earnings.

We have experienced and could continue to experience significant changes in the estimate of unrealized derivative gains or losses recognized due to fluctuations in the value of these commodity derivative contracts. The lack of hedge accounting has no impact on our reported cash flows, although our results of operations are affected by the volatility of mark-to-market gains and losses and changes in fair value, which fluctuate with changes in crude oil prices. These fluctuations could be significant in a volatile pricing environment.

As of July 31, 2014, we had the following open crude oil derivative positions. All are priced based on the Brent crude oil futures as traded on the Intercontinental Exchange.



	Fixed - Price Swaps
Production Period ending April 30,	Bbls	Weighted Average Fixed Price
2015	586,800	99.81
2016	787,600	95.36
2017	232,600	93.97

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

Derivative Activities Reflected on Condensed Consolidated Balance Sheets

The following table presents the fair value of commodity derivatives. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements.



	Asset Derivatives						Liability Derivatives
	July 31, 2014			April 30, 2014			July 31, 2014				April 30, 2014
Derivatives not designated as hedging instruments under ASC 815	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value			Balance Sheet Location	Fair Value
Commodity derivatives	Prepaid expenses and other	$	—	Prepaid expenses and other	$	88	Current portion of derivative instruments	$	(5,697	)	Current portion of derivative instruments	$	(3,315	)
Commodity derivatives	Other assets	—		Other assets	26		Long-term portion of derivative instruments	(6,964		)	Long-term portion of derivative instruments	(4,006		)
Total derivatives not designated as hedging instruments under ASC 815		$	—		$	114		$	(12,661	)		$	(7,321	)

Offsetting of Derivative Assets and Liabilities

The following table presents our gross and net derivative assets and liabilities:



	Gross Amount Presented on Balance Sheet			Netting Adjustments ^(a)			Net Amount
July 31, 2014
Derivative liabilities with right of offset or master netting agreements	$	(12,661	)	$	—		$	(12,661	)
April 30, 2014
Derivative assets with right of offset or master netting agreements	$	114		$	(114	)	$	—
Derivative liabilities with right of offset or master netting agreements	$	(7,321	)	$	114		$	(7,207	)

—————————


(a)	The Company has an agreement in place that allows for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of default under the agreement.

Derivative Activities Reflected on Condensed Consolidated Statements of Operations

Gains and losses on derivatives are reported in the condensed consolidated statements of operations. The following represents the Company's reported gains and losses on derivative instruments for the periods presented:



	For the Three Months Ended July 31,
	2014			2013
Loss on derivatives, net	$	(6,903	)	$	(3,076	)

As of July 31, 2014, we did not own derivative instruments that were classified as fair value hedges or trading securities. In addition, as of July 31, 2014, we did not own derivative instruments containing credit risk contingencies.

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

8. FAIR VALUE MEASUREMENTS

Fair Value Measurement on a Recurring Basis

The carrying amounts reported in the condensed consolidated balance sheets for cash and cash equivalents, trade receivables, account payables and other short-term liabilities approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. The fair values of the Company's commodity derivative instruments are classified as Level 2 measurements as they are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, and discount factors. The following summarizes the fair value of the Company's commodity derivative assets and liabilities according to their fair value hierarchy as of the reporting dates indicated:



	Fair Value Measurements
At July 31, 2014	Level 1		Level 2			Level 3
Commodity derivative asset	$	—	$	—		$	—
Commodity derivative liability	—		(12,661		)	—
Total	$	—	$	(12,661	)	$	—
At April 30, 2014
Commodity derivative asset	$	—	$	114		$	—
Commodity derivative liability	—		(7,321		)	—
Total	$	—	$	(7,207	)	$	—

There were no transfers between Level 1, Level 2 or Level 3 during the three months ended July 31, 2014 or July 31, 2013.

9. DEBT

As of July 31, 2014 and April 30, 2014, we had the following debt obligations reflected at their respective carrying values on our condensed consolidated balance sheets:



	July 31, 2014			April 30, 2014
Second Lien Credit Facility	$	175,000		$	175,000
Debt discount related to Second Lien Credit Facility	(3,077		)	(3,296		)
First Lien RBL	20,000			—
Gunsight Promissory Note payable	950			950
Apollo prepayment and extension fee note payable	6,918			9,223
Capital lease obligation	3,138			—
Series B Preferred Stock	2,344			2,325
Total debt obligations	205,273			184,202
Less: Current maturities	(8,401		)	(9,459		)
Total debt less current maturities	$	196,872		$	174,743

Second Lien Credit Facility

On February 3, 2014, we refinanced our $100,000 credit facility with Apollo Investment Corp. ("Apollo") (the "Prior Credit Facility") by entering into a Credit Agreement with Apollo and Highbridge Capital Strategies (the "New Apollo Loan Agreement") which set forth the terms of a credit facility of up to $175,000 (the "Second Lien Credit Facility").

The New Apollo Loan Agreement provides for a $175,000 term credit facility, all of which was made available to and drawn by us on the closing date. The amounts drawn were subject to a 2% original issue discount. Amounts outstanding under

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the Second Lien Credit Facility bear interest at a rate of LIBOR plus 9.75%, subject to a 2% LIBOR floor. The Second Lien Credit Facility permitted us to enter into a reserve-based revolving credit facility of up to $100,000 on certain agreed terms which would be secured on a first-lien basis. Upon entering into such revolving credit facility and a related intercreditor agreement, the Second Lien Credit Facility would become a second-lien credit facility. We entered into a credit agreement for a revolving credit facility (the "First Lien Loan Agreement"), among us, as borrower, KeyBank National Association ("KeyBank"), as administrative agent (in that capacity the "RBL Administrative Agent"), and the lenders from time to time party thereto (the "RBL Lenders") on June 2, 2014. The First Lien Loan Agreement provides for a $250,000 senior secured, reserve-based revolving credit facility (the "First Lien RBL"). In connection with our entry into the First Lien Loan Agreement, we amended the New Apollo Loan Agreement. The Second Lien Credit Facility carries a four year maturity. The Second Lien Credit Facility contains covenants, including but not limited to, a leverage ratio, interest coverage ratio, current ratio, asset coverage ratio, minimum gross production and change of management control covenants, as well as other covenants customary for a transaction of this type. We were in compliance with the required financial and production covenants as of July 31, 2014. Subject to certain conditions contained in the New Apollo Loan Agreement, the Second Lien Credit Facility also allows for us to implement a discretionary share repurchase plan on terms and conditions reasonably satisfactory to Apollo (in its capacity as administrative agent) and the lenders.

We used $75,306 of the proceeds drawn under the Second Lien Credit Facility to refinance the Prior Credit Facility with Apollo and $56,577 to finance the acquisition of the North Fork Unit. In addition, $3,071 was used to retire the obligations owed under the MEI Loan Documents. The remainder of the proceeds from the Second Credit Facility were used for general corporate purposes. The fair value of the outstanding balance of the Second Lien Credit Facility was $176,922 as of July 31, 2014, as calculated using the discounted cash flows method.

On the closing date, in connection with the Second Lien Credit Facility, we, along with all of our consolidated subsidiaries (other than MEI), entered into an Amended and Restated Guarantee and Collateral Agreement (the "Second Lien Guarantee") with Apollo, for the benefit of the lenders from time to time party to the New Apollo Loan Agreement. Under the terms of the Second Lien Guarantee and related security documents, each of our consolidated subsidiaries (other than MEI) have guaranteed our obligations under the Second Lien Credit Facility and we and those subsidiaries have granted a security interest in substantially all of their assets to secure the performance of the obligations arising under the Second Lien Credit Facility.

On June 2, 2014, we entered into the Amendment No. 1 to Credit Agreement and Guarantee and Collateral Agreement to the Second Lien Credit Facility and the Second Lien Guarantee. This amendment conforms certain of the covenants, terms and conditions in the Second Lien Credit Facility to match those of the First Lien RBL, including the financial covenants.

Subsequent to the end of our first quarter, we entered into Amendment No. 2 to the New Apollo Loan Agreement, which amended a default provision to remove its reference to David Voyticky, our former president. Prior to this amendment, under the New Apollo Loan Agreement, the resignation of Mr. Voyticky would have been a default. In addition, this amendment removes references to Mr. Voyticky from certain defined terms used in the New Apollo Loan Agreement.

Subsequent to the end of our first quarter, we entered into Amendment No. 3, dated as of August 19, 2014, to the New Apollo Loan Agreement, which (1) increases the total amount of obligations we may enter into under capital leases from time to time, (2) allows us to make certain investments in Savant, and (3) increases the amount of preferred stock that we may issue, among other things.

First Lien RBL

On June 2, 2014, we entered into the First Lien Loan Agreement, among the Company, as borrower, KeyBank, as the RBL Administrative Agent, and the RBL Lenders. In addition to KeyBank, the syndicate includes CIT Finance LLC, Mutual of Omaha Bank and OneWest Bank N.A.

The First Lien Loan Agreement provides for a $250,000 senior secured, reserve-based revolving credit facility, $60,000 of which was made available to us on the closing date. The borrowing base will be redetermined semi-annually on February 1st and August 1st of each year. Amounts outstanding under the First Lien RBL are priced on a sliding scale, based on LIBOR plus 300 to 400 basis points, depending upon the level of borrowing (per the table below).

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Borrowing Base Utilization Grid
Borrowing base utilization percentage	<25%	≥ 25%, but <50%	≥ 50%, but <75%	≥ 75%, but <90%	≥ 90%, but ≤100%
Spread above LIBOR	3.00%	3.25%	3.50%	3.75%	4.00%
Undrawn commitment fee rate	0.50%	0.50%	0.75%	0.75%	0.75%

The First Lien RBL will expire on the third anniversary of its closing. It contains customary covenants, including, but not limited to, a leverage, interest coverage, current ratio, minimum gross production, minimum liquidity, asset coverage and change of management control covenants. We were in compliance with the required financial and production covenants as of July 31, 2014. Subject to certain conditions contained in the First Lien Loan Agreement, the First Lien RBL also allows us to implement a discretionary share repurchase plan on terms and conditions reasonably satisfactory to the RBL Administrative Agent and the RBL Lenders. The First Lien RBL contemplates up-front fees, arrangement fees, and ongoing commitment and other fees customary for transactions of this nature.

The Company drew $20,000 on the closing date under the First Lien RBL, which was used to provide working capital for development drilling in Alaska. The amounts available were subject to an upfront fee equal to 1% of the initial borrowing base. On June 20, 2014, we requested an additional $10,000, which was funded on June 24, 2014. We repaid borrowings of $10,000 on July 31, 2014, and subsequent to quarter end, drew down $16,000 on August 1, 2014. The fair value of floating-rate debt approximates the carrying amount because the interest rates paid are based on short-term maturities.

Also on June 2, 2014, in connection with the First Lien RBL, we, along with all of our consolidated subsidiaries (other than MEI, Miller Energy Colorado 2014-1, LLC, and Miller Drilling 2009-A, L.P.), entered into a First Lien Guarantee and Collateral Agreement (the "First Lien Guarantee") with KeyBank, for the benefit of the RBL Lenders from time to time party to the First Lien Loan Agreement. Under the terms of the First Lien Guarantee and related security documents, each of our consolidated subsidiaries (other than MEI, Miller Energy Colorado 2014-1, LLC, and Miller Drilling 2009-A, L.P.) have guaranteed the obligations under the First Lien RBL. Along with the aforementioned subsidiaries, we have granted a security interest in substantially all of our assets to secure the performance of the obligations arising under the First Lien RBL.

Subsequent to the end of our first quarter, we entered into the First Amendment, dated as of August 11, 2014, to our First Lien Loan Agreement, which amended a default provision to remove its reference to Mr. Voyticky. Prior to this amendment, under the First Lien Loan Agreement, the resignation of Mr. Voyticky would have been a default. In addition, this amendment removes references to Mr. Voyticky from certain defined terms used in the First Lien Loan Agreement.

Subsequent to the end of our first quarter, we entered into the Second Amendment, dated as of August 19, 2014, to our First Lien Loan Agreement, which (1) increases the total amount of obligations we may enter into under capital leases from time to time, (2) allows us to make certain investments in Savant, and (3) increases the amount of preferred stock that we may issue, among other things.

Series B Preferred Stock

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, 2014, the fair value of Series B Preferred Stock was $2,197, as calculated using the discounted cash flow method.

On July 28, 2014, our Board approved a semiannual dividend to shareholders of approximately $6.05 per share on our Series B Preferred Stock, which was paid on the next regularly scheduled divided payment date of September 2, 2014, in accordance with the terms of our charter, as September 1, 2014 was not a business day. The dividend payment is equivalent to an annualized 12% per share, based on the $100.00 per share stated liquidation preference for the Series B Preferred Stock, accruing from March 2014 through August 2014. The record date, as required in accordance with our charter, was August 15, 2014.

Debt Issue Costs

As of July 31, 2014 and April 30, 2014, our unamortized deferred financing costs were $2,603 and $803, respectively, which relates to the First Lien RBL and the Second Lien Credit Facility. These costs are being amortized over the term of the respective debt instruments.

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

10. ASSET RETIREMENT OBLIGATIONS

The following table presents changes to the Company's asset retirement obligation ("ARO") liability for the three months ended July 31, 2014 and 2013:



	2014			2013
Asset retirement obligation, as of April 30,	$	22,872		$	19,890
Additions	—			5
Accretion expense	346			297
Settlements	(5		)	—
North Fork Properties purchase price adjustment	159			—
Asset retirement obligation, as of July 31,	$	23,372		$	20,192

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, 2014 and April 30, 2014, there were no significant expenditures for abandonments.

11. STOCK-BASED COMPENSATION

During fiscal years 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. On April 16, 2014, the number of shares of common stock available for issuance increased by 5,000,000 shares of common stock under the 2011 Equity Compensation Plan (the "2011 Plan"). The amendment to the 2011 Plan providing for the increase was adopted by our Board of Directors on March 10, 2014, and approved by our shareholders on April 16, 2014. 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 our success. 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. At July 31, 2014 and April 30, 2014, there were 2,728,078 and 3,134,578 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, 2014 and 2013 of approximately $1,645 and $1,556 respectively. We also recognized non-employee expense related to warrants issued for the three months ended July 31, 2014 and 2013 of approximately $416 and $110, respectively.

The following table summarizes stock options and warrants activity for the period presented:



	Number of Options and Warrants		Weighted Average Exercise Price
Beginning balance at April 30, 2014	15,021,347		$	4.99
Granted	410,500		5.61
Exercised	(311,354	)	4.55
Cancelled	(38,179	)	3.65
Ending balance	15,082,314		5.02
Options and warrants exercisable at July 31, 2014	11,802,470		$	4.83

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The following table summarizes stock options and warrants outstanding, including exercisable shares at July 31, 2014:



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	1,490,200	1.0	$	0.70	1,490,200	$	0.70
$2.00 to $4.99	1,659,667	5.1	3.56		1,471,989	3.49
$5.15 to $5.53	4,332,447	3.0	5.32		3,095,281	5.33
$5.68 to $5.94	3,655,000	6.5	5.90		3,295,000	5.92
$6.00 to $6.95	3,945,000	3.3	6.13		2,450,000	6.08
	15,082,314	4.0	$	5.01	11,802,470	$	4.73

The following table summarizes restricted stock activity for the three months ended July 31, 2014:



Unvested at April 30, 2014	465,432
Granted	16,000
Vested	(188,765	)
Unvested at July 31, 2014	292,667

12. STOCKHOLDERS' EQUITY

Common Stock

At July 31, 2014, we had 46,108,061 shares of common stock outstanding. We issued 351,364 shares during the three months ended July 31, 2014, of which 40,010 shares were issued to employees for compensation, and 311,354 shares were related to the exercise of equity rights.

Series C Preferred Stock

On July 28, 2014, 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 2, 2014, in accordance with the terms of our charter as September 1, 2014 was not a business day. The dividend payment will be 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 June 2014 through August 2014. The record date, as required in accordance with our charter, was August 15, 2014.

Series D Preferred Stock

During the three months ended July 31, 2014, we sold 62,304 shares of our 10.5% Series D Fixed Rate/Floating Rate Cumulative Redeemable Preferred Stock (the "Series D Preferred Stock"), yielding net proceeds of $1,542.

On July 28, 2014, our Board of Directors declared a dividend of approximately $0.66 per share on our Series D Preferred Stock which was paid on the next regularly scheduled dividend payment date of September 2, 2014, in accordance with the terms of our charter as September 1, 2014 was not a business day. The dividend payment will be equivalent to an annualized 10.5% per share, based on the $25.00 per share stated liquidation preference for the Series D Preferred Stock, accruing from June 2014 through August 2014. The record date, as required in accordance with our charter, was August 15, 2014.

Subsequent to the end of our first quarter, on August 25, 2014, we completed and closed a public offering of our 10.5% Series D Fixed Rate/Floating Rate Cumulative Redeemable Preferred Stock liquidation preference $25.00 per share. We issued 750,000 shares which were offered to the public at $24.50 per share for gross proceeds of $18,375. We incurred issuance costs of $1,352, yielding net proceeds of $17,023.

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13. 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. Our provision for income taxes for the first interim reporting period in fiscal 2015 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 2015 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 three month periods ended July 31, 2014 and July 31, 2013 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, 2014 is a benefit of (38%). 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 and local income taxes net of federal benefit and a valuation allowance against our Tennessee net operating loss carry-forwards and credits. No other valuation allowances were 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 significant cash payments of income taxes were made during the year-to-date period ended July 31, 2014, and no significant payments are expected during the succeeding 12 months.

14. ALASKA PRODUCTION 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, which we receive in the ordinary course of business, the credit is recorded as a reduction to the related assets. For carried-forward annual loss credits, which we receive in the ordinary course of business, the credit is recorded as a reduction to the Alaska production tax. We did not incur any Alaska production taxes in fiscal 2014, 2013 or 2012, and accordingly, the carried-forward annual loss credits are presented separately in our operating expenses on the condensed consolidated statement of operations.



Balance, April 30, 2014	$	49,121
Alaska carried-forward annual loss credits, net ¹	3,055
Applications for expenditure and exploration based credits ¹	23,275
Cash collections for expenditure and exploration based credits	(21,837		)
Balance, July 31, 2014	$	53,614

———————————


1	Applications for carried-forward annual loss credits and for expenditure and exploration based credits are recorded net of established reserves and also include revisions to prior period applications, if applicable.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(Unaudited)

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

During three months ended July 31, 2014 and 2013, the Company recorded net carried-forward annual loss credits of $3,055 and $0, respectively. The Company has reduced the basis of capitalized assets by a cumulative total of $70,025 for expenditure and exploration credits. The reductions are recorded on our condensed consolidated balance sheets in "oil and gas properties" and "equipment." As of July 31, 2014 and April 30, 2014, the Company had outstanding net receivables from the State of Alaska in the amount of $53,614 and $49,121, respectively.

15. LITIGATION

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 CIE. The suit, styled Troy D. Stafford v. Miller Petroleum, Inc., Civil Action No. 3-11CV-206, claims that we terminated Mr. Stafford's employment without cause in contravention of the terms of the Purchase and Sale Agreement between us and the sellers of CIE ("PSA"), failed or refused to pay his salary, severance, percentage of purchase price, expenses or stock warrants and violated a duty of good faith and fair dealing. The suit sought 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 were 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 filed our Answer and conducted discovery. 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. On February 24, 2014, we filed a Motion to Dismiss with Prejudice based on Plaintiff's failure to prosecute his case since April 2, 2013, Plaintiff's having missed filing deadlines, and his having failed to appear to give his deposition both times we have noticed it. On February 26, 2014, the Court entered an Order to Show Cause, requiring the plaintiff to demonstrate why his case should not be dismissed. On March 14, 2014, the plaintiff filed a Motion for Voluntary Dismissal, Without Prejudice through his new attorney. On June 3, 2014, the court granted plaintiff's motion to dismiss without prejudice, but did so with the condition that plaintiff must reimburse us for costs incurred by us as a result of his failure to cooperate in discovery in this case in the amount of $9 prior to his being allowed to refile the case. As such, this case has been dismissed and there is no further action currently required.

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) unjust 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. Trial was previously set for November 4, 2013. On October 21, 2013, the trial was postponed with no new trial date having been set. On October 31, 2013, the judge ruled on our outstanding Motion for Summary Judgment, granting it as to the unjust enrichment claim and breach of the implied covenant of good faith and fair dealing claim, and denying it as to the breach of contract claim. We expect to proceed to trial on the breach of contract claim once a new trial date is set. In February 2014, we received notice from a third party seeking to intervene in the case in order to secure payment of a debt allegedly owed by the Plaintiff to the third party. On May 29, 2014, the court put down a new scheduling order setting forth certain pre-trial deadlines with the final pre-trial conference being set for October 30, 2014. On June 5, 2014, the court entered an order denying the motion to intervene. We expect the court to set a trial date that will be shortly after the final pre-trial conference. 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, David Voyticky, and Deloy Miller, as defendants. The Plaintiffs allege two causes of action against the defendants: (1) violation of Section 10(b) and Rule 10b-5 of the Exchange Act, (2) violation of Section 20(a) of the Exchange Act. The case seeks money damages against us and the other defendants, and payment of the Plaintiffs' attorney's fees. We have filed a Motion to Dismiss the case, which was denied on February 4, 2014 as to all defendants save Ford Graham. On July 3, 2014, we agreed upon a potential settlement with the Plaintiffs would dismiss the lawsuit with prejudice in exchange for a settlement payment of $2,950, which is within the remaining policy limits of our director and officer insurance policy. The proposed settlement remains subject to court approval and class notice administration before it will be effective. The

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(Unaudited)

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

case has been stayed through and including September 30, 2014 at the agreement of the Parties while we finalize the stipulation of settlement and supporting papers. We expect to complete full documentation of the settlement and file a motion for preliminary approval of the class action settlement and approval of the class no later than the first week of October 2014. The estimated potential loss and expected insurance recovery are accrued on our condensed consolidated balance sheets as of April 30, 2014 and July 31, 2014.

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 alleged 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 sought 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. The Plaintiff 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 previously disclosed. The Plaintiff also agreed to voluntarily dismiss the case in the event the plaintiff's appeal in Lukas was denied. Following the dismissal of Lukas, on October 1, 2013, the Court entered an Order dismissing the case without prejudice on the motion of the Plaintiff. On October 24, 2013, we filed a Motion to Amend the Order of Dismissal as the agreement with the Plaintiff was that the case would be dismissed with prejudice if the Sixth Circuit Court of Appeals affirmed the dismissal of the Lukas case, which it did. On June 3, 2014, after reaching an agreement with the Plaintiff, we filed an amended agreed final order of dismissal with prejudice in this case.

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, (the “Rig 35 Agreement”). We terminated the agreement based on our belief that Voorhees was in breach of its obligations thereunder. Voorhees later indicated its desire to arbitrate claims it believes it has under invoices arising between May 29, 2012 and August 31, 2012. We believed we had grounds to dispute liability with respect to some or all of those invoices, in addition to having certain counterclaims we expected to assert. The parties elected to engage a private arbitrator to settle this dispute (the “Voorhees Matter”) and conducted discovery. On September 18, 2013, we received a third-party complaint from Voorhees in connection with a lawsuit by Carlile Transportation Systems, Inc., in the Superior Court for the State of Alaska. The case is styled Carlile Transportation Systems, Inc. v. Voorhees Rig International, Inc. v. Cook Inlet Energy, LLC (the "Carlile Matter"). The dispute in the Carlile Matter related solely to unpaid transportation fees arising from the transportation of equipment for Rig 35. These fees were already the subject of the planned arbitration with Voorhees over the Voorhees Matter. As all disputes under the Rig 35 Agreement are subject to mandatory arbitration, we filed a motion to compel arbitration in the Carlile Matter, which the Court granted, along with an award of our legal costs incurred in connection with the Carlile Matter. On February 20, 2014, we reached an agreement in principle to settle the Voorhees Matter (including the transportation fees at issue in the Carlile Matter), and we entered into a settlement agreement which was effective as of May 12, 2014. We agreed to return to Voorhees the following equipment previously delivered to us under the Rig 35 Agreement, but which we subsequently replaced on that rig:


•	an iron roughneck that we had to replace on Rig 35 due to mechanical unreliability; and


•	a BOP stack originally included on Rig 35, but later removed and replaced with a better functioning replacement.

We also agreed to return to Voorhees two moving containers, left-over electrical equipment and tools belonging to Voorhees but left with CIE when Voorhees ceased working on Rig 35. No costs of defense or other cash payment are expected to be required of us in connection with this settlement, although we will pay the transportation costs of the equipment being returned. As a result, we recorded a gain of $113 related to this settlement in other income (expense), net in our condensed consolidated statements of operations for the three months ended July 31, 2014.

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 the implied warranty of merchantability, breach of the 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 conducting discovery. Given the current stage of the proceedings with respect to this case, we believe

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(Unaudited)

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

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 condensed consolidated balance sheet.

On February 7, 2014, we were served with a lawsuit filed by Vulcan Capital Corporation ("Vulcan") in the District Court for the Southern District of New York styled Vulcan Capital Corp. v. Miller Energy Resources, Inc. and PlainsCapital Bank. The suit asserts various causes of action against PlainsCapital Bank, and appears to assert the following causes of action against us: (1) Breach of Fiduciary Duty and (2) Concert of Action. The case stems from an agreement Vulcan had with PlainsCapital Bank wherein Vulcan secured certain loans by pledging four warrants to purchase our common stock that were issued as part of the employment package of Ford F. Graham, our former President. Upon Vulcan's default of the loan agreement, PlainsCapital presented the warrants to us for transfer, and, after requesting certain tenders required under Tennessee law, we registered the transfer of the warrants. We have retained counsel and we have filed a Motion to Transfer as the warrants have a valid exclusive forum clause that requires the case be tried in Knox County, Tennessee. In addition, PlainsCapital Bank has agreed to indemnify us for our first $500 of expenses related to this dispute. Given the current state 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.

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.

16. SUBSEQUENT EVENTS

Acquisition of Anchor Point Energy

On August 8, 2014, we received approval of our application to acquire 100% ownership in Anchor Point Energy, LLC from the Regulatory Commission of Alaska. Anchor Point owns and operates the North Fork Pipeline that services the North Fork Unit we acquired in February 2014.

Acquisition of Rig 37

On August 8, 2014, we announced the completion of our acquisition of the Glacier Drilling Rig #1, which we have renamed Rig 37, for approximately $5,600 in cash. Rig 37 is a Mesa 1000 carrier-mounted land-drilling rig that has been mobilized to the North Fork Unit to begin drilling this winter. We are currently performing certain rig maintenance that is required prior to commencing drilling.

Amendments to First Lien Loan Agreement and New Apollo Loan Agreement

As discussed above under Note 9 - Debt, we entered into amendments to both our First Lien Loan Agreement and New Apollo Loan Agreement effective as of August 11, 2014, and August 19, 2014, respectively. The August 11, 2014 amendments were required in order to avoid a default which would have been caused by the resignation of our former President, David Voyticky. In addition, the amendments removed references to Mr. Voyticky from certain defined terms used in the First Lien Loan Agreement and New Apollo Loan Agreement. The August 19, 2014 amendments (1) increased the total amount of obligations we may enter into under capital leases from time to time, (2) allowed us to make certain investments in Savant, and (3) increased the amount of preferred stock that we may issue, among other things.

Entry into Withdrawal Agreement and Acceleration of Vesting of Equity Awards for David Voyticky

On August 11, 2014, we entered into a Departure and Withdrawal Agreement (the “Withdrawal Agreement”) with David Voyticky, our former President, in connection with his resignation. The Withdrawal Agreement was effective as of August 12, 2014. The Agreement provides for, among other things, (a) early expiration of his employment period under his Employment Agreement dated July 29, 2014 (as extended by the Extension Agreement dated July 3, 2014) between Mr. Voyticky and us, (b) a compensation package described below and (c) confidentiality restrictions, mutual releases, cooperation and non-disparagement covenants, indemnities and other agreements related to Mr. Voyticky’s withdrawal from his employment with us.

The Withdrawal Agreement also memorialized the compensation package approved by our Board of Directors and the Compensation Committee of the Board (the “Committee”), in connection with Mr. Voyticky’s withdrawal from his employment, which included (a) a service award in the amount of (i) $460 in cash and (ii) the issuance of 79,655 shares of the Company's common stock and (b) the continued vesting of certain options and common stock (the "Grants") previously granted to Mr. Voyticky. The Company further agreed to recommend at the Committee's next meeting that the Committee accelerate the vesting of the portion of the Grants which have not yet vested, so that, if approved, they would vest on the day of the Committee's further approval. This further approval was obtained on August 15, 2014, and resulted in the accelerated vesting of the following stock

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

and option awards: (i) options to purchase 575,000 shares of our common stock at an exercise price of $5.35 per share, which would have vested on June 9, 2015, (ii) a grant of 21,250 shares of our common stock, which would have vested on July 24, 2015 and (iii) a grant of 21,250 shares of our common stock, which would have vested on July 24, 2016. Following the Committee's action, Mr. Voyticky is fully vested in these awards.

Series D Preferred Stock Offering

On August 25, 2014, we completed and closed a public offering of our Series D Preferred Stock. We issued 750,000 shares which were offered to the public at $24.50 per share for gross proceeds of $18,375. We incurred issuance costs of $1,352, yielding net proceeds of $17,023.

Payment of Dividends

On September 2, 2014, 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 2014 through August 2014. The record date was August 15, 2014.

On September 2, 2014, 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 2014 through August 2014. The record date was August 15, 2014.

On September 2, 2014, we paid a quarterly dividend of approximately $0.66 per share on the Series D Preferred Stock. The dividend payment is equivalent to an annualized 10.5% per share, based on the $25.00 per share stated liquidation preference, accruing from June 2014 through August 2014. The record date was August 15, 2014.

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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, and our Annual Report on Form 10-K, as amended, for the year ended April 30, 2014, 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 14, 2014, and amended on July 15, 2014. 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.

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.

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 southcentral Alaska, including the Cook Inlet and Kenai Peninsula, and the Appalachian region of east Tennessee. During fiscal 2015, we expect to expand our operations on the North Slope through acquiring the Badami field and pipeline system.

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 are focused 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 are increasing oil and gas production through the maintenance, repair, and optimization of wells located in the Cook Inlet region. Our operational team employs 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, 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 continues to seek opportunities that meet our criteria for risk, reward, rate of return, and growth potential. We pursue value-creating acquisitions when the opportunities arise, subject to the availability of sufficient capital.

Our management team is focused on maintaining the financial flexibility, assembling the right complement of personnel, and procuring the equipment required to successfully execute these core strategies.

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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, developing and acquiring additional recoverable 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 business, financial condition and results of operations. We will focus on adding reserves through new drilling, 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 from our credit facilities and have the ability to raise funds from the sales of our Series C Preferred Stock and Series D Preferred Stock, including "at-the-market" public offerings to support our capital expenditures during our first quarter of fiscal 2015. For the three-month period ended July 31, 2014, we reported notable achievements in several key areas. Highlights for the period include:

•

On May 8, 2014, we entered into an Agreement and Plan of Merger with Savant subject to due diligence and regulatory approval for $9,000. Savant currently owns, and we would acquire as a result of this merger, a 67.5% working interest in the Badami Unit and 100% ownership in certain nearby leases. ASRC Exploration, LLC owns the remaining 32.5% working interest in the Badami Unit. In addition to the working interest in the Badami Unit and the leases, we would acquire certain midstream assets located on the North Slope. We expect the transaction to close by December 2014, following regulatory approval.

•

On June 2, 2014 we entered into a credit agreement, among the Company, as borrower, and KeyBank National Association, as administrative agent. In addition to KeyBank, the syndicate includes CIT Finance LLC, Mutual of Omaha Bank and OneWest Bank N.A. The First Lien Loan Agreement provides for a $250,000 senior secured, reserve-based revolving credit facility, $60,000 of which was made available to us on the closing date. Amounts outstanding under the First Lien RBL are priced on a sliding scale, based on LIBOR plus 300 to 400 basis points, depending upon the level of borrowing. We drew $20,000 on the closing date under the First Lien RBL to provide working capital for development drilling in Alaska.


•	On June 7, 2014, we successfully brought online WMRU-2B, an onshore oil well in our West McArthur River Unit field.


•	On June 24, 2014, we drew an additional $10,000 under the First Lien RBL to provide working capital for development drilling in Alaska.


•	On June 24, 2014, we received the proceeds of Alaska production credits totaling $21,837 from the State of Alaska.

•

On July 4, 2014, we entered into a Purchase and Sale Agreement for the right to purchase the Glacier Drilling Rig #1, and related equipment. An initial payment of $700 was made in connection with the execution and delivery of the agreement. On August 8, 2014, an additional payment of $5,600 was made in connection with the closing of the purchase of the Glacier Rig, which we have renamed Rig 37. Rig 37 is a Mesa 1000 carrier-mounted land-drilling rig that has been mobilized to the North Fork Unit to begin drilling this winter. We are currently performing certain rig maintenance that is required prior to commencing drilling.

Subsequent to the end of our first quarter, and prior to the date of this report, we continued to make significant progress as highlighted by the following events:


•	On August 11, 2014, we announced that we were named the successful bidder for an exploration license consisting of 168,581 acres located on the Iniskin Peninsula. We have committed to spend $1,501 over the next four years to explore the acreage, which includes a work commitment bond of $375. A bonus bid payment in the amount of approximately $135 will be due upon the award of the license.


•	On August 20, 2014, we announced a substantial increase in our reserves as the result of an updated reserve report by Ryder Scott Company. Our total proved PV-10 increased from approximately $360,900 at April 30, 2014 to approximately $447,600 at July 31, 2014. Our total proved reserves increased from approximately 10.5 MBOE to 11.7 MBOE for the same periods.


•	On August 21, 2014, we announced the receipt of a tax credit certificate from the State of Alaska in the amount of approximately $31,200.

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•	On August 25, 2014, the Company completed and closed a public offering of its Series D Preferred Stock. The Company issued 750,000 shares which were offered to the public at $24.50 per share for gross proceeds of $18,375. We incurred issuance costs of $1,352, yielding net proceeds of $17,023.

Fiscal 2015 Outlook

As we head into the second quarter of fiscal 2015, we believe our inventory of recompletion, workovers, and exploration and development projects offers numerous growth opportunities. We are currently completing our RU-9 well with Rig 35, preparing Rig 36 to drill our Sabre prospect, preparing Rig 37 to drill at North Fork, and drilling the Olson Prospect with the Patterson 191 rig. Following these activities, we also have several projects at Redoubt, Sabre and North Fork, which we expect will contribute additional production in fiscal 2015. No assurance can be made regarding the success of these development and recompletion efforts. Our current fiscal 2015 capital budget is approximately $160,000, after tax credits, which is expected to be spent on projects both in the Cook Inlet and on the North Slope, once our acquisition of Savant has closed. Due to the uncertainty associated with forecasting production, development costs and 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 performance. 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.

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Results of Operations

Three Months Ended July 31, 2014 Compared to Three Months Ended July 31, 2013

Revenues



	For the Three Months Ended July 31,
	2014		2013		$ Variance			% Variance
Oil sales:
Cook Inlet	$	18,755	$	11,633	$	7,122		61	%
Appalachian region	546		625		(79		)	(13	)
Total	$	19,301	$	12,258	7,043			57
Natural gas sales:
Cook Inlet	$	5,680	$	156	5,524			3,541
Appalachian region	117		114		3			3
Total	$	5,797	$	270	5,527			2,047
Other:
Cook Inlet	$	60	$	247	(187		)	(76	)
Appalachian region	221		233		(12		)	(5	)
Total	$	281	$	480	(199		)	(41	)
Total revenues	$	25,379	$	13,008	$	12,371		95	%

Net Production



	For the Three Months Ended July 31,
	2014	2013	Variance		% Variance
Oil volume - bbls:
Cook Inlet	202,775	108,435	94,340		87	%
Appalachian region	6,046	6,975	(929	)	(13	)
Total	208,821	115,410	93,411		81
Natural gas volume¹- mcf:
Cook Inlet	547,587	28,173	519,414		1,844
Appalachian region	28,296	29,848	(1,552	)	(5	)
Total	575,883	58,021	517,862		893
Total production² - boe:
Cook Inlet	294,040	113,130	180,910		160
Appalachian region	10,762	11,950	(1,188	)	(10	)
Total	304,802	125,080	179,722		144	%

———————


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



	For the Three Months Ended July 31,
	2014		2013		$ Variance			% Variance
Average realized oil sales price - per barrel:
Cook Inlet	$	100.52	$	105.59	$	(5.07	)	(5	)%
Appalachian region	97.63		88.59		9.04			10
Total	$	100.44	$	104.57	$	(4.13	)	(4	)
Average realized natural gas sales price - per mcf:
Cook Inlet	$	6.92	$	5.55	$	1.37		25
Appalachian region	4.15		3.77		0.38			10
Total	$	6.83	$	4.63	$	2.20		48	%

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 2015 were 4% below the same period last year. For the three months ended July 31, 2014, realized oil prices averaged $100.44 per bbl, compared with $104.57 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 2015 increased over the same period last year. For the three months ended July 31, 2014, realized natural gas prices averaged $6.83 per mcf, compared with $4.63 per mcf for the same period in the prior year. The increase in the averaged realized gas prices resulted from natural gas sales at higher realized prices resulting from the acquisition of the North Fork Properties.

Oil Sales

During the first quarter of fiscal 2015, oil revenues totaled $19,301, which represents a 57% increase over the same period in the prior year. Oil revenues represented 76% of our first quarter consolidated total revenues. Net barrels sold for the current period were 186,582, which represents a 76,407 bbl, or 69%, increase as compared to the same period last year. The increase in barrels sold was partially offset by a 4% decrease in realized oil prices.

The increase in net barrels sold results from an increase in oil production for the period. Oil production increased 93,411 bbls, or 81%, to 208,821 bbls. The increase was driven by a 94,340 bbl increase in the Cook Inlet region offset a 929 bbl decrease in the Appalachian region. The production increase in the Cook Inlet region resulted from WMRU-2B in our West McArthur River Unit field; RU-1A, RU-2A, and RU-5B in our Redoubt Shoals field; and Sword #1.

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

The difference between barrels sold and barrels produced is approximately equal to the change in quantity of our crude oil inventory balance during the period. Although we attempt to minimize crude oil inventory balances, shipping schedules in the Cook Inlet region are beyond our control and occasionally require us to store crude oil. In addition, we are required to maintain certain inventory levels in third party pipelines and storage facilities. As noted in the following table, we experienced an above average increase in inventory levels during the first quarter of fiscal 2015, which significantly reduced the potential revenue that may have resulted from our increased oil production during the current period. The increase in our inventory balance primarily resulted from shipping schedules and a requirement to maintain increased inventory levels in third party facilities in the Cook Inlet region.



	For the Three Months Ended July 31,
	Cook Inlet		Appalachian		Total
In barrels:
Beginning inventory balance	82,495		10,895		93,390
Addition to inventory - gross production	241,515		6,046		247,561
Reduction to inventory - gross sales	(223,728	)	(5,593	)	(229,321	)
Pipeline adjustments	(379	)	—		(379	)
Ending inventory balance	99,903		11,348		111,251

Net change in inventory	17,408		453		17,861

Natural Gas Sales

During the first quarter of fiscal 2015, natural gas revenues totaled $5,797, which was 2,047% higher than the same period in the prior year. The increase resulted from a combination of a 48% increase in average realized prices and a 893% increase in production, primarily as a result of the acquisition of the North Fork Properties. Natural gas represented 23% of our first quarter consolidated total revenues.

Other

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 2015 and 2014, other revenues totaled $281 and $480, respectively.

Cost and Expenses

The table below presents a comparison of our expenses for the three months ended July 31, 2014 and 2013:



	For the Three Months Ended July 31,
	2014			2013		$ Variance			% Variance
Lease operating expense	$	6,626		$	5,640	$	986		17	%
Transportation costs	2,984			625		2,359			377
Cost of purchased gas sold	972			—		972			NM
Cost of other revenue	340			284		56			20
General and administrative	9,511			6,360		3,151			50
Alaska carried-forward annual loss credits, net	(3,055		)	—		(3,055		)	NM
Exploration expense	296			286		10			3
Depreciation, depletion and amortization	16,978			5,692		11,286			198
Accretion of asset retirement obligation	346			297		49			16
Other operating expense, net	4			—		4			NM
Total operating expense	$	35,002		$	19,184	$	15,818		82	%

———————————

NM = Not Meaningful

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Lease Operating Expense

The table below presents a comparison of our lease operating expense for the years ended April 30, 2014 and 2013:



	For the Three Months Ended July 31,
	2014		2013		$ Variance		% Variance
Lease operating expense	$	6,626	$	5,640	$	986	17	%
Net production - boe	304,802		125,080
Lease operating expense per boe produced	$	21.74	$	45.09

Lease operating expense increased $986 from fiscal 2014, or 17%. The increased lease operating expense is primarily attributable to increased production. The increased production creates marginal increases in labor and camp facility costs and well maintenance; however, the majority of our production costs are fixed. For the first quarter of fiscal 2015, our lease operating expense per boe produced was $21.74 as compared to $45.09 for the first quarter of fiscal 2014. We expect our lease operating expense per boe produced to continue to decline as production increases.

Transportation Costs

Transportation costs increased $2,359 from fiscal 2014, or 377%, due to increased oil production and increased gas transportation costs, as a result of the acquisition of the North Fork Properties for which we incurred $1,813 in gas transportation costs.

Cost of Purchased Gas Sold

We engaged in natural gas marketing by aggregating third-party volumes and selling those volumes into intrastate pipeline systems. We incurred $972 in purchased gas costs during the first quarter of fiscal 2015 and none during the first quarter of fiscal 2014.

Cost of Other Revenue

Our business is primarily focused on exploration and production activities. The cost of other revenue 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.



	For the Three Months Ended July 31,
	2014		2013		$ Variance			% Variance
Direct labor	$	214	$	165	$	49		30	%
Equipment	38		39		(1		)	(3	)
Repairs	79		70		9			13
Other	9		10		(1		)	(10	)
Total	$	340	$	284	$	56		20	%

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

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,
	2014		2013		$ Variance			% Variance
Stock-based compensation	$	2,565	$	1,600	$	965		60	%
Professional fees	2,359		2,162		197			9
Salaries	3,091		923		2,168			235
Travel	421		454		(33		)	(7	)
Employee benefits	289		413		(124		)	(30	)
Other	786		808		(22		)	(3	)
Total	$	9,511	$	6,360	$	3,151		50	%

G&A expenses increased $3,151 from fiscal 2014, or 50% from the same period in the prior fiscal year. Salaries increased 235% from the same period in the prior fiscal year primarily due to additions to our engineering and accounting staff, salary increases of our named executive officers, effective as of July 17, 2013, and an increase in bonus accruals. Stock-based compensation increased 60% due to recent grants to directors and key employees.

Alaska Carried-Forward Annual Loss Credits, Net

Alaska carried-forward annual loss credits, net increased $3,055. Alaska carried-forward annual loss credits, net are generated when there is an annual loss per the State of Alaska tax statues. Increased expenses and increased drilling activity led to higher annual losses per the State of Alaska tax statutes for carried-forward annual loss credits.

Exploration Expense

Exploration expense incurred increased $10 from fiscal 2014, or 3%. 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.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization ("DD&A") expenses include the DD&A 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,
	2014		2013		$ Variance			% Variance
Depletion:
Cook Inlet region	$	15,637	$	4,192	$	11,445		273	%
Appalachian region	347		345		2			1
	15,984		4,537		11,447			252
Depreciation:
Cook Inlet region	838		974		(136		)	(14	)
Appalachian region	156		181		(25		)	(14	)
	994		1,155		(161		)	(14	)
Total DD&A	$	16,978	$	5,692	$	11,286		198	%

The increase in DD&A expense is primarily a result of increased production from the Cook Inlet region and fluctuations in the estimated volumes of our proved reserves.

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Accretion of Asset Retirement Obligation

Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Accretion of asset retirement obligations increased 16% to $346 primarily due to additions to asset retirement obligations during fiscal 2014 related to the North Fork Properties.

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,
	2014			2013			$ Variance			% Variance
Interest expense, net	$	(2,799	)	$	(2,281	)	$	(518	)	23	%
Loss on derivatives, net	(6,903		)	(3,076		)	(3,827		)	124
Other income (expense), net	122			(14		)	136			971
Total	$	(9,580	)	$	(5,371	)	$	(4,209	)	78	%

Interest Expense, Net

Interest expense, net, increased $518 from fiscal 2014, or 23%. The increase in interest expense was driven primarily by an increase in the average debt balance outstanding, slightly offset by lower interest rates on our borrowings.

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 used to hedge 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.

Loss on derivatives, net experienced an unfavorable change of $3,827 during the three months ended July 31, 2014 compared to the three months ended July 31, 2013. Of the total change, $892 was due to an unfavorable change in realized cash settlements related to our derivative positions in the three months ended July 31, 2014 compared to the three months ended July 31, 2013. The remaining amount was due to changes in the fair value of our open derivative positions in each period.

Income Tax Benefit

Income tax benefit increased $2,730 from fiscal 2014, or 59%, due to an increase in loss before income taxes. Our effective income tax rate for the first quarter of fiscal 2015 was 38%. This rate differed from the statutory rate primarily due to state income taxes, change in state rate, state and local income taxes net of federal benefit and a valuation allowance against our Tennessee net operating loss carry-forwards and credits.

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 and production. 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.

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 proved 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, 2014, as amended.

For the three months ended July 31, 2014, 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 and make additional acquisitions. Although we expect an increase in revenues from these development activities, we will continue to utilize our cash 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 our operating expenses and capital costs.

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Current restricted cash balances include amounts held in escrow to secure Company related credit cards. As of July 31, 2014 and April 30, 2014, current restricted cash also includes $858 and $38 of cash temporarily held in an account that is controlled by our lender. 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.

On February 3, 2014, we refinanced the Prior Credit Facility by entering into the New Apollo Loan Agreement which set forth the terms of the Second Lien Credit Facility. The New Apollo Loan Agreement provided for a $175,000 term credit facility, all of which was made available to and drawn by us on the closing date and was used to refinance the Prior Credit Facility, to close the North Fork Properties acquisition and for general corporate purposes. The amounts drawn were subject to a 2% original issue discount. Amounts outstanding under the Second Lien Credit Facility bear interest at a rate of LIBOR plus 9.75%, subject to a 2% LIBOR floor. The Second Lien Credit Facility carries a four year maturity and contains covenants, including but not limited to, a leverage ratio, interest coverage ratio, current ratio, asset coverage ratio, minimum gross production and change of management control covenants as well as other covenants customary for a transaction of this type. The Second Lien Credit Facility permitted us to enter into a reserve-based revolving credit facility in the nature of the First Lien RBL.

On June 2, 2014, we entered into the First Lien RBL contemplated by the Second Lien Credit Facility, with an initial borrowing base of $60,000. At closing, we drew $20,000, and on June 24, 2014, we drew an additional $10,000. On July 31, 2014, we repaid $10,000 and drew down $16,000 on August 1, 2014. The remaining availability under the First Lien RBL was $40,000 as of July 31, 2014. As reserves grow, the borrowing base may be adjusted to provide additional capital to fund our development program. The borrowing base of our First Lien RBL is calculated at the discretion of the lenders based on our proved reserves, commodity prices, total debt and other factors at their sole discretion. As such, it is possible our borrowing base could be reduced in the future. The First Lien RBL carries a three-year maturity and contains covenants matching those contained in the Second Lien Credit Agreement.

Additionally, during the three months ended July 31, 2014, we entered into a capital lease for the newly purchased Rig 36, for a total of $3,250, which can be expanded up to $5,000, as we upgrade Rig 36.

On August 20, 2014, we entered into an Underwriting Agreement by and between us and MLV, as representative for the underwriters, with respect to the sale by the Company of 750,000 shares of the Company's Series D Preferred Stock through the offering. The Shares were being offered to the public at $24.50 per share, and we raised gross proceeds of $18,375. The offering closed on August 25, 2014.

We believe that we will be able 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 with State of Alaska production credits, potential joint ventures, and through the debt, equity and preferred equity capital markets.

Although we have the ability to sell our Series C and Series D Preferred Stock in additional "at-the-market" offerings during fiscal 2015, subject to certain limits under our First Lien RBL and Second Lien Credit Facilities, 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. In the event we are unable to raise additional capital on acceptable terms, we may reduce our capital spending.

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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,
	2014			2013
Sources of cash and cash equivalents:
Net cash provided by operating activities	$	7,424		$	—
Proceeds from First Lien RBL, net of debt acquisition costs	27,583			—
Proceeds from capital lease obligations	3,250			—
Proceeds from Alaska production tax credits	21,837			—
Exercise of equity rights	1,399			63
Issuance of preferred stock, net of issuance costs	1,542			21,974
Release of restricted cash	—			2,596
	63,035			24,633
Uses of cash and cash equivalents:
Net cash used by operating activities	—			(4,431		)
Cash dividends	(2,904		)	(1,315		)
Capital expenditures for oil and gas properties	(40,182		)	(15,235		)
Prepayment of drilling costs	(1,151		)	(2,339		)
Purchase of equipment and improvements	(6,129		)	(739		)
Payments on debt	(2,306		)	—
Payments of First Lien RBL	(10,000		)	—
Principal payments on capital lease obligations	(112		)	—
Increase in restricted cash	(2,281		)	—
	(65,065		)	(24,059		)

Increase in cash and cash equivalents	$	(2,030	)	$	574

Net Cash Provided by 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, accretion, non-cash compensation, and deferred income tax expense, which affect earnings but do not affect cash flows.

Net cash provided by operating activities for the first three months of fiscal 2015 totaled $7,424, up $11,855 from the same period in fiscal 2014. The increase resulted primarily from an increase in revenue and a favorable shift in the timing of cash receipts and payments to vendors in the ordinary course of business.

Proceeds from First Lien RBL and Other Items

During the first quarter of our 2015 fiscal year, borrowings totaled $30,000 under our First Lien RBL, which were offset by a payment of $10,000 on our First Lien RBL. Additionally, we incurred $2,417 in deferred financing costs.

During the first quarter of our 2015 fiscal year, increase in restricted cash was $2,281 as compared to a release of restricted cash of $2,596 in the same period last year. The classification of the net change in restricted cash is dependent on whether unrestricted cash is transferred to or from our restricted cash accounts, on a net basis.

During the first quarter of fiscal 2015, we paid $2,904 in quarterly dividends on our Series C Preferred Stock and Series D Preferred Stock, compared to $1,315 in quarterly dividends on our Series C Preferred Stock during the first quarter of fiscal 2014.

During the first quarter of fiscal 2015, we received proceeds of $3,250 under the Rig 36 capital lease. Additionally, we made our first installment payment of $2,306 on the prepayment and extension fee owed to Apollo.

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

During the first quarter of fiscal 2015, we sold 62,304 shares of Series D Preferred Stock, yielding net proceeds of $1,542. During the same period in fiscal 2014, we sold 1,074,452 shares of Series C Preferred Stock, yielding net proceeds of $21,974.

Capital Expenditures and Alaska Production Tax Credits

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, 2014, cash paid for capital expenditures was $46,311, which is inclusive of the decrease in our capital accrual account of $6,313.

During the three months ended July 31, 2014, we collected $21,837 related to our Alaska production tax credits applied for in prior periods.

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, 2014, we had $1,151 in prepaid drilling costs and other capital related items.

Liquidity

Cash and Cash Equivalents

As of July 31, 2014, we had $3,719 in cash and cash equivalents.

Debt and Available Credit Facilities

As of July 31, 2014, outstanding debt consisted of $20,000 and $171,923 under our First Lien RBL, and Second Lien Credit Facility, respectively, classified as long-term debt on the accompanying condensed consolidated balance sheets. As of July 31, 2014 we had no additional borrowing capacity under our Second Lien Credit Facility.

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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:


•	interest expense, net;


•	depreciation, depletion and amortization;


•	accretion of asset retirement obligation;


•	exploration costs;


•	stock-based compensation expense;


•	non-cash employee bonuses;


•	non-recurring litigation settlements and related matters;


•	non-recurring North Fork Properties gas transportation costs;


•	(gain) loss on derivatives, net less cash settlements.

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,
	2014			2013
Loss before income taxes	$	(19,203	)	$	(11,547	)
Adjusted by:
Interest expense, net	2,799			2,281
Depreciation, depletion and amortization	16,978			5,692
Accretion of asset retirement obligation	346			297
Exploration costs	296			286
Stock-based compensation	2,599			1,666
Non-cash employee bonuses	1,545			—
Non-recurring litigation settlements and related matters	1,374			—
Non-recurring North Fork Properties gas transportation costs	1,813			—
Derivative contracts:
Loss on derivatives, net	6,903			3,076
Cash settlements	(1,449		)	(557		)
Adjusted EBITDA	$	14,001		$	1,194

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

Recent Accounting Pronouncements

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.

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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 revenues, earnings, cash flow, capital investments, and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil and natural gas, which have historically been very volatile due to unpredictable events such as macro-economic conditions, weather, and political climate.

We periodically enter into commodity derivative contracts to economically hedge a portion of our projected oil production in order to support oil prices at targeted levels and to manage our overall exposure to oil price fluctuations. During the three months ended July 31, 2014, approximately 82% of our crude oil production was economically hedged with derivative contracts. Realized gains or losses from our price-risk management activities are recognized in gain (loss) on derivatives, net when the associated production occurs. We do not hold or issue derivative instruments for trading purposes.

On July 31, 2014, we had open oil derivative instruments in a net liability position with a fair value of $12,661. A 10% increase in oil prices would result in a net liability position with an approximate fair value of $29,306, while a 10% decrease in prices would result in a net asset position with an approximate fair value of $3,985.

We conduct our risk management activities for commodities under the controls and governance of our risk management policy. The Audit Committee of our Board of Directors approves and oversees these controls, which have been implemented by designated members of the management team. The treasury and accounting departments also provide separate checks and reviews on the results of hedging activities. Controls for our commodity risk management activities include limits on volume, segregation of duties, delegation of authority and a number of other policy and procedural controls.

The following tables summarize, for the periods indicated, our hedges currently in place through December 2016. All of these derivatives are accounted for as mark-to-market activities. All of these derivatives are variable-to-fixed price commodity swap contracts which price is based on the Brent crude oil futures as traded on the Intercontinental Exchange.



	For the Quarter Ended (in barrels)
	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
2015	—	—	197,200	102.00	198,200	100.28	191,400	97.09	586,800	99.81
2016	198,200	96.74	197,200	96.36	198,200	95.16	194,000	93.16	787,600	95.36
2017	148,600	93.30	50,000	95.47	34,000	94.68	—	—	232,600	93.97
									1,607,000	$	96.79

Interest Rate Risk

We are subject to interest rate risk in connection with our First Lien RBL and our Second Lien Credit Facility. Our principal interest rate exposure relates to our First Lien RBL which is based on LIBOR plus 300 to 400 basis points. Our Second Lien Credit Facility is based on LIBOR plus 9.75%, subject to a 2.0% LIBOR floor. Given current LIBOR rates, we do not believe LIBOR is likely to exceed the 2.0% floor. Thus, we believe our interest rate risk is primarily associated with our First Lien RBL.

Customer Credit Risk

We are exposed to the credit risk of our customers. For the three months ended July 31, 2014, 74% of our total consolidated revenues and 13% of our consolidated accounts receivable resulted from one of our oil and gas customers. No significant uncertainties related to the collectability of amounts owed to us exist in regard to these customers.

This customer concentration increases our exposure to credit risk on our receivables, since the financial solvency of these customers could have a significant impact on our results of operations. If our customers become financially insolvent, they may not be able to continue to operate or meet their payment obligations. Any material losses as a result of customer defaults could harm and have an adverse effect on our business, financial condition or results of operations. Substantially all of our trade accounts receivable are unsecured.

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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, 2014 as filed with the SEC on July 14, 2014, and amended on July 15, 2014.

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, 2014 as filed with the SEC on July 14, 2014, and amended on July 15, 2014. Such efforts have included hiring an additional accounting and finance director and enhancing the business understanding and relevant knowledge possessed by those operating management review controls. We can give no assurance that the measures we have taken will remediate the material weakness that we identified or that any additional material weaknesses will not arise in the future.

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 per share data and per unit data)

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

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

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 alleged 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 sought 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. The Plaintiff 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 previously disclosed. The Plaintiff also agreed to voluntarily dismiss the case in the event the plaintiff's appeal in Lukas was denied. Following the dismissal of Lukas, on October 1, 2013, the Court entered an Order dismissing the case without prejudice on the motion of the Plaintiff. On October 24, 2013, we filed a Motion to Amend the Order of Dismissal as the agreement with the Plaintiff was that the case would be dismissed with prejudice if the Sixth Circuit Court of Appeals affirmed the dismissal of the Lukas case, which it did. On June 3, 2014, after reaching an agreement with the Plaintiff, we filed an amended agreed final order of dismissal with prejudice in this case.


•	an iron roughneck that we had to replace on Rig 35 due to mechanical unreliability; and


•	a BOP stack originally included on Rig 35, but later removed and replaced with a better functioning replacement.

ITEM 1A. RISK FACTORS.

For a detailed discussion of the risks and uncertainties associated with our business see "Risk Factors" in our 2014 Annual Report filed with the SEC on July 14, 2014, and amended on July 15, 2014. There have been no material changes to these risk factors since that report.

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

In May 2014, we issued 11,354 shares of our common stock to a warrant holder upon a cashless exercise of a common stock purchase warrant to purchase 16,200 shares of our common stock with an exercise price of $1.69 per share in a private transaction exempt from registration under the Securities Act of 1933 in reliance on an exemption provided by Section 4(2) of that act. The recipient was an accredited or otherwise sophisticated investor who had such knowledge and experience in business matters and was capable of evaluating the merits and risks of the prospective investment in our securities. The recipient had access to business and financial information concerning our company.

ITEM 5. OTHER INFORMATION.

None.

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ITEM 6. EXHIBITS.

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



EXHIBIT NO.		DESCRIPTION
2.1	–	Purchase and Sale Agreement, dated November 22, 2013, by and among Armstrong Cook Inlet, LLC, GMT Exploration Company, LLC, Dale Resources Alaska, LLC, Jonah Gas Company, LLC and Nerd Gas Company, LLC, as sellers and Cook Inlet Energy, LLC, as buyer (incorporated by reference to Registrant's Current Report on Form 8-K filed on November 25,2013).
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).
3.13	–	Articles of Amendment to the Charter of Miller Energy Resources, Inc. (incorporated by reference to Exhibit 3.21 to Registrant's Registration Statement on Form 8-A as filed on September 26, 2013).
10.1	–	Rig Equipment Purchase Agreement by and between Miller Energy Resources, Inc., as Buyer and Baker Process, Inc., as Seller (incorporated by reference to Registrant's Current Report on Form 8-K filed on May 6, 2014).
10.2	–	Master Lease between Miller Energy Resources, Inc. and First National Capital, LLC (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K filed on May 14, 2014).
10.3	–	Equipment Schedule No. 1 between Miller Energy Resources, Inc. and First National Capital, LLC (incorporated by reference to Exhibit 10.2 to Registrant's Current Report on Form 8-K filed on May 14, 2014).
10.4	–	Interim Term Lease Schedule between Miller Energy Resources, Inc. and First National Capital, LLC (incorporated by reference to Exhibit 10.3 to Registrant's Current Report on Form 8-K filed on May 14, 2014).
10.5	–	Credit Agreement dated as of June 2, 2014 among Miller Energy Resources, Inc. as Borrower, and KeyBank National Association, as Administrative Agent (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K filed on June 6, 2014).
10.6	–	Guarantee and Collateral Agreement in favor of KeyBank National Association, as Administrative Agent (incorporated by reference to Exhibit 10.2 to Registrant's Current Report on Form 8-K filed on June 6, 2014).
10.7	–	Amendment No. 1 to Credit Agreement and Guarantee and Collateral Agreement dated as of June 2, 2014 (incorporated by reference to Exhibit 10.3 to Registrant's Current Report on Form 8-K filed on June 6, 2014).
10.8	–	Extension Agreement dated June 3, 2014 between David J. Voyticky and Miller Energy Resources, Inc. (incorporated by reference to Exhibit 10.4 to Registrant's Current Report on Form 8-K filed on June 6, 2014).
10.9	–	Purchase and Sale Agreement between the Company and Teras (incorporated by reference to Registrant's Current Report on Form 8-K filed on July 8, 2014).
*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.

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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, 2014	MILLER ENERGY RESOURCES, INC.

		By:	/s/ SCOTT M. BORUFF
			Scott M. Boruff
			Chief Executive Officer
			(Principal Executive Officer)


Dated:	September 9, 2014	MILLER ENERGY RESOURCES, INC.

		By:	/s/ JOHN M. BRAWLEY
			John M. Brawley
			Chief Financial Officer
			(Principal Financial Officer)