10-Q 1 millq110q73112.htm 10-Q MILL Q1 10Q 7.31.12

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549

(Mark One)
Form 10-Q

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

For the quarterly period ended July 31, 2012
OR

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

For the transition period from __________________ to __________________________
Commission file number: 001-34732

Miller Energy Resources, Inc.
(Name of registrant as specified in its charter)

Tennessee
 
62-1028629
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
9721 Cogdill Road, Suite 302, Knoxville,  TN
 
37932
(Address of principal executive offices)
 
(Zip Code)
 
(865) 223-6575
(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes o    No þ
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes þ    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.  42,021,893 shares of common stock are issued and outstanding as of August 31, 2012.



TABLE OF CONTENTS

 
 
 
Page
 
 
 
 
 
 
 
 
PART I
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART II
 
 
 
 
 
 
 
 


i


PART I - FINANCIAL INFORMATION
 
ITEM 1.    FINANCIAL STATEMENTS.

MILLER ENERGY RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
July 31,
2012
 
April 30,
2012
ASSETS
(In thousands, except share data)
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
1,892

 
$
3,971

Restricted cash
1,605

 
2,250

Accounts receivable
2,880

 
3,107

State production credits receivable
2,958

 
2,958

Inventory
1,866

 
1,835

Prepaid expenses
1,887

 
482

 
13,088

 
14,603

OIL AND GAS PROPERTIES, NET
478,131

 
475,802

EQUIPMENT, NET
39,020

 
33,728

OTHER ASSETS:
 
 
 
Land
542

 
542

Restricted cash, non-current
9,880

 
9,875

Deferred financing costs, net of accumulated amortization
5,231

 
1,426

Other assets
624

 
413

 
$
546,516

 
$
536,389

LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable
$
11,785

 
$
9,504

Accrued expenses
5,172

 
6,744

Short-term portion of derivative instruments
1,396

 
2,803

Current portion of long-term debt
1,500

 
24,130


19,853

 
43,181

OTHER LIABILITIES:
 
 
 
Deferred income taxes
168,440

 
167,319

Asset retirement obligation
18,650

 
18,366

Long-term portion of derivative instruments
1,716

 
7,700

Long-term debt
38,500

 

Total Liabilities
247,159

 
236,566

COMMITMENTS AND CONTINGENCIES (Note 14)

 

MEZZANINE EQUITY:
 
 
 
Series A cumulative preferred stock, redemption amount of $11.2 million

 
8,818

 
 
 
 
STOCKHOLDERS' EQUITY:
 
 
 
Common stock, $0.0001 par, 500,000,000 shares authorized, 41,959,393 and 41,086,751 shares issued and outstanding, respectively
4

 
4

Additional paid-in capital
72,976

 
64,813

Retained earnings
226,377

 
226,188

 
299,357

 
291,005

 
$
546,516

 
$
536,389


See accompanying notes to the unaudited condensed consolidated financial statements.

1


MILLER ENERGY RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
 
For the Three Months Ended
 
July 31,
2012
 
July 31,
2011
 
(In thousands, except share and per share data)
REVENUES:
 
 
 
Oil sales
$
7,646

 
$
8,191

Natural gas sales
83

 
128

Other
533

 
536

 
8,262

 
8,855

OPERATING EXPENSES:
 

 
 

Oil and gas operating
3,974

 
3,796

Cost of other revenue
548

 
227

General and administrative
5,330

 
5,772

Exploration expense
29

 
32

Depreciation, depletion and amortization
3,125

 
3,373

Accretion of asset retirement obligation
284

 
269

Other operating income, net
(25
)
 
(892
)
 
13,265

 
12,577

OPERATING LOSS
(5,003
)
 
(3,722
)
OTHER INCOME (EXPENSE):
 

 
 

Interest income
3

 
1

Interest expense
(134
)
 
(496
)
Gain on derivatives, net
8,941

 
3,756

Other income (expense), net
(75
)
 
31

 
8,735

 
3,292

INCOME (LOSS) BEFORE INCOME TAXES
3,732

 
(430
)
Income tax (provision) benefit
(1,121
)
 
247

NET INCOME (LOSS)
2,611

 
(183
)
Accretion of preferred stock
(2,422
)
 

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS
$
189

 
$
(183
)
 
 
 
 
INCOME PER COMMON SHARE:
 

 
 

Basic
$
0.00

 
$
0.00

Diluted
$
0.00

 
$
0.00

WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
 

 
 

Basic
41,425,645

 
40,339,610

Diluted
43,807,338

 
40,339,610


See accompanying notes to the unaudited condensed consolidated financial statements.

2


MILLER ENERGY RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Unaudited)


 
 
Common Stock
 
Additional Paid-in Capital
 
Retained Earnings (Deficit)
 
Total
 
 
Shares
 
Amount
 
 
 
 
 
(In thousands, except share data)
Balance at April 30, 2011
 
39,880,251

 
$
4

 
$
49,013

 
$
245,725

 
$
294,742

Net loss
 

 

 

 
(183
)
 
(183
)
Issuance of equity for services
 

 

 
218

 

 
218

Issuance of equity for compensation
 

 

 
2,498

 

 
2,498

Exercise of equity rights
 
869,000

 

 
1,283

 

 
1,283

Balance at July 31, 2011
 
40,749,251

 
4

 
53,012

 
245,542

 
298,558

Net loss
 

 

 

 
(18,507
)
 
(18,507
)
Accretion of preferred stock
 

 

 

 
(847
)
 
(847
)
Issuance of equity for services
 
130,000

 

 
1,283

 

 
1,283

Issuance of equity for compensation
 
107,500

 

 
10,418

 

 
10,418

Exercise of equity rights
 
100,000

 

 
100

 

 
100

Balance at April 30, 2012
 
41,086,751

 
4

 
64,813

 
226,188

 
291,005

Net income
 

 

 

 
2,611

 
2,611

Accretion of preferred stock
 

 

 

 
(2,422
)
 
(2,422
)
Issuance of equity for services
 
351,477

 

 
1,843

 

 
1,843

Issuance of equity for assets
 
14,000

 

 
63

 

 
63

Issuance of equity for compensation
 
382,165

 

 
3,622

 

 
3,622

Exercise of equity rights
 
125,000

 

 
125

 

 
125

Preferred stock redemption
 

 

 
2,510

 

 
2,510

Balance at July 31, 2012
 
41,959,393

 
$
4

 
$
72,976

 
$
226,377

 
$
299,357



See accompanying notes to the unaudited condensed consolidated financial statements.


3


MILLER ENERGY RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 (Unaudited)
 
 
For the Three Months Ended
 
July 31,
2012
 
July 31,
2011
 
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net income (loss)
$
2,611

 
$
(183
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 

 
 

Depreciation, depletion, and amortization
3,125

 
3,561

Expense from issuance of equity
2,075

 
2,716

Deferred income taxes
1,121

 
(247
)
Gain on derivative instruments, net
(4,880
)
 
(3,756
)
Accretion of asset retirement obligation
284

 
269

Changes in operating assets and liabilities:
 

 
 

Receivables
227

 
(33
)
Inventory
(259
)
 
75

Prepaid expenses and other assets
(1,616
)
 
(244
)
Accounts payable and accrued expenses
920

 
645

NET CASH PROVIDED BY OPERATING ACTIVITIES
3,608

 
2,803

 
 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES:
 

 
 

Purchase of equipment and improvements
(4,611
)
 
(12,790
)
Proceeds from sale of equipment
2,000

 

Capital expenditures for oil and gas properties
(4,714
)
 
(7,004
)
Investment in equity method investee

 
(400
)
NET CASH USED IN INVESTING ACTIVITIES
(7,325
)
 
(20,194
)
 
 
 
 
CASH FLOWS FROM FINANCING ACTIVITIES:
 

 
 

Payments on debt
(24,130
)
 
(2,000
)
Debt acquisition costs
(3,757
)
 
(1,954
)
Proceeds from borrowings
40,000

 
23,119

Redemption of preferred stock
(11,240
)
 

Exercise of equity rights
125

 
1,283

Restricted cash
640

 
(52
)
NET CASH PROVIDED BY FINANCING ACTIVITIES
1,638

 
20,396

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(2,079
)
 
3,005

 
 
 
 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
3,971

 
1,559

CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
1,892

 
$
4,564

SUPPLEMENTARY CASH FLOW DATA:
 
 
 
Cash paid for interest
$
4,697

 
$
142


See accompanying notes to the unaudited condensed consolidated financial statements.

4


MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 (Unaudited)
(dollars in thousands)

1.    ORGANIZATION AND BASIS OF PRESENTATION

Overview

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

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

Basis of Presentation

The accompanying unaudited Condensed Consolidated Financial Statements as of, and for the period ended July 31, 2012, are presented in accordance with U.S. generally accepted accounting principles ("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 unaudited 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, 2012, which was filed with the SEC on July 16, 2012 and which was further amended on August 28, 2012. Certain amounts in the unaudited Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to current period presentation.

Principles of Consolidation

The accompanying unaudited Condensed Consolidated Financial Statements include our consolidated accounts, including the accounts of our wholly-owned subsidiaries (collectively, the "Company"), after elimination of intercompany balances and transactions. The unaudited 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.

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our significant accounting policies are consistent with those discussed in our Annual Report on Form 10-K for the year ended April 30, 2012, as amended.

Investments

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


5

MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 (Unaudited)
(dollars in thousands)


Guarantees

On July 12, 2012, we signed a direct guarantee for 55% of the loan obligations outstanding of $5,074 with FSG Bank for the Pellissippi Pointe equity investment. As a result, Miller's guarantee is included within the scope of Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 460, "Guarantees" and is recorded at an estimated fair value of $250. It is included in other non-current liabilities on our unaudited Condensed Consolidated Balance Sheet as of July 31, 2012. The fair value was calculated using the income approach. Further, the estimated default rate was determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of Pellissippi Pointe and the term of the underlying loan obligations. The default rates are published by Moody's Investors Service. We will amortize this liability over the five-year term of the guarantee. To the extent we are required to make payments under the guarantee, we will record the differences between the liability and the associated payments in earnings. Our maximum potential undiscounted payments under this arrangement are $2,791 plus additional lender's costs at July 31, 2012. If estimable, the approximate extent to which the proceeds from liquidation of assets held either as collateral or by third parties would be expected to cover the maximum potential amount of future payments under the guarantee.

Other Comprehensive Income

We do not have items of other comprehensive income for the periods presented in these financial statements.

New Accounting Pronouncements Issued But Not Yet Adopted

In December 2011, the FASB issued Accounting Standards Update ("ASU") 2011-11, "Disclosures about Offsetting Assets and Liabilities," which increases disclosures about offsetting assets and liabilities. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards ("IFRS") related to the offsetting of financial instruments. The existing GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance in ASU 2011-11 is effective for annual and interim reporting periods beginning on or after January 1, 2013. The disclosures should be applied retrospectively for all prior periods presented. We do not expect the adoption of this pronouncement to have a material impact to our condensed consolidated financial statements.

There are no other recently issued accounting pronouncements that are expected to have a material impact on our financial condition, results of operations or cash flows.
 
3.    MAJOR CUSTOMERS AND CONCENTRATIONS OF CREDIT RISK

For the three months ended July 31, 2012 and 2011, Tesoro Corporation accounted for $7,242 or 88% and $8,044 or 91% of our consolidated total revenues. Tesoro Corporation also accounted for $2,343 or 81%, and $2,581 or 83% of our accounts receivable as of July 31, 2012 and April 30, 2012, 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, 2012 and 2011.

We maintain our cash and cash equivalents, which at times may exceed federally insured amounts, in highly rated financial institutions. As of July 31, 2012, we held $1,006 in excess of the $250 limit insured by the Federal Deposit Insurance Corporation.

4.    RELATED PARTY TRANSACTIONS

We use a number of contract labor companies to provide on demand labor at our Alaska operations. H&H Industrial, Inc. 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. The company is owned by the sister and father of David Hall, CEO of CIE and member of our Board of Directors. The audit committee of our board of directors determined that the amounts paid by us for the services performed were fair to and in the best interests of the Company. For the three months ended July 31, 2012 and 2011, we recorded expenses of $363 and $135, respectively, for amounts due to H&H Industrial, Inc.
 
    

6

MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 (Unaudited)
(dollars in thousands)


From time to time our company provides service work on oil and gas wells owned by Mr. Gettelfinger, a member of the Board of Directors, and his wife. The audit committee of our board of directors determined that the amounts paid to us for the services performed were fair to and in the best interests of the Company. As of July 31, 2012 and April 30, 2012, Mr. and Mrs. Gettelfinger owed us $4 and $17, respectively.
 
In 2009, we entered into a marketing agreement with The Dimirak Companies, an affiliate of Dimirak Financial Corp. and Dimirak Securities Corporation, a broker-dealer and member of FINRA. Mr. Boruff, our Chief Executive Officer (“CEO”), was then a director and 49% owner of Dimirak Securities Corporation. Under the terms of this agreement, we engaged The Dimirak Companies to serve as our exclusive marketing agent in a $20,000 income fund and a $25,500 drilling offering, which included the MEI offering. The terms of the agreement will expire upon the termination of the offerings. We agreed to pay The Dimirak Companies a monthly consulting fee of $5, a marketing fee of 2% of the gross proceeds received in the offerings or within 24 months from the expiration of the term of the agreement, a wholesaling fee of 2% of the proceeds and a reimbursement of certain pre-approved expenses. The agreement contains customary indemnification, non-circumvention and confidentiality clauses. For the three months ended July 31, 2012 and 2011, we recorded expenses related to The Dimirak Companies and their affiliates of $29 and $18, respectively. Effective July 24, 2012, Mr. Boruff sold his interest in Dimirak Securities Corporation.
 
5.    OIL AND GAS PROPERTIES AND EQUIPMENT
 
Oil and gas properties (successful efforts method) are summarized as follows:
 
July 31,
2012
 
April 30,
2012
Property costs
 
 
 
Proved property
$
325,925

 
$
321,066

Unproved property
182,769

 
182,704

Total property costs
508,694

 
503,770

Less: Accumulated depletion
(30,563
)
 
(27,968
)
Oil and gas properties, net
$
478,131

 
$
475,802


Equipment is summarized as follows:
 
July 31,
2012
 
April 30,
2012
Machinery and equipment
$
6,115

 
$
5,595

Vehicles
1,787

 
1,689

Aircraft
460

 
460

Buildings
2,683

 
2,683

Office equipment
555

 
533

Leasehold improvements
423

 
423

Drilling rigs
3,714

 
3,714

Construction in progress
26,542

 
21,589

 
42,279

 
36,686

Less: Accumulated depreciation
(3,259
)
 
(2,958
)
Equipment, net
$
39,020

 
$
33,728

 








7

MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 (Unaudited)
(dollars in thousands)


Depreciation, depletion and amortization consisted of the following:
 
Three Months Ended
 
Three Months Ended
 
July 31,
2012
 
July 31,
2011
Depletion of oil and gas related assets
$
2,824

 
$
3,206

Depreciation and amortization of equipment
301

 
167

Total
$
3,125

 
$
3,373

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

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

Derivative Instruments

Commodity Derivatives
As of July 31, 2012, we had the following open crude oil derivative positions:

 
 
Fixed - Price Swaps
Production Period:
 
Bbls
 
Weighted Average Fixed Price
2013
 
179,100

 
$
96.47

2014
 
147,000

 
95.30


Warrant Derivatives
Series A Cumulative Preferred Stock In April 2012, purchasers of our Series A preferred stock were issued warrants to purchase an aggregate amount of 1,000,000 shares of our common stock at an exercise price of $5.28 per share. These warrants were subject to a reset provision requiring adjustment of the exercise price, from $5.28 to $3.00, if the preferred stock was not redeemed within 30 days of our refinancing and repayment of the Guggenheim credit facility.

The Series A preferred stock was redeemed on June 29, 2012 in connection with the initiation of the Apollo credit facility and the repayment of the Guggenheim credit facility. The market-to-market adjustment from May 1, 2012 to June 29, 2012 was recorded to gain on derivatives, net, and the remaining liability was reclassified to additional paid in capital.

Warrants Issued in Connection with Other Equity Transactions On March 26, 2010, purchasers of our common stock and certain third party consultants were issued warrants to purchase an aggregate amount of 817,055 shares of our common stock at an exercise price of $5.28 per share. Under the terms of the respective agreements, an adjustment to the exercise price is required if, at any time after issuance, we issue warrants at an exercise price lower than $5.28. As of July 31, 2012, 767,055 warrants remained outstanding.    






8

MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 (Unaudited)
(dollars in thousands)


Fair Value Measurements

As of July 31, 2012 and 2011, the fair market value of our derivative liabilities is as follows:

 
As of July 31,
 
As of April 30,
 
2012
 
2012
Current liabilities:
 
 
 
Commodity derivatives
$
1,396

 
$
2,803

Warrant derivatives

 

Current portion of derivative instruments
1,396

 
2,803

Long-term liabilities:
 
 
 
Commodity derivatives
407

 
2,551

Warrant derivatives
1,309

 
5,149

Long-term portion of derivative instruments
1,716

 
7,700

Total derivative liability
$
3,112

 
$
10,503


Commodity Derivatives    
Our commodity derivatives consist of variable-to-fixed price commodity swaps. The fair values of our commodity derivatives are not actively quoted in the open market, thus we use an income approach to estimate fair value. The use of commodity derivative instruments also exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Thus, to minimize this exposure, we utilize an investment-grade rated counterparty. In measuring fair value, we also take into account the impact of counterparty risk on our derivative instruments and use observable market data for credit default swaps to assess the impact of non-performance credit risk when evaluating our net assets from the counterparty. We use the cumulative S&P default rating for small, independent exploration and production companies to assess the impact of non-performance credit risk when evaluating our net obligations to the counterparty. As of April 30, 2012 and 2011, the effect of non-performance risk on our commodity derivatives was negligible.
Warrant Derivatives
Due to their reset provisions, our warrants are considered freestanding derivative instruments and are given liability treatment with fair value measured on a recurring basis in accordance with the provisions of ASC 820, "Fair Value Measurements."
Series A Cumulative Preferred Stock We utilized a binomial, or lattice model, to value the warrants. In selecting a binomial tree model, we evaluated the model's capability to incorporate certain provisions present in these financial instruments and believe it is consistent with the fair value measurement objectives and requirements under ASC 820.
A binomial tree valuation model uses a "discrete-time" (lattice based) model of the varying price over the term of the underlying financial instrument. Each node in the lattice represents a possible price of the underlying (stock price) at a given point in time. Valuation is performed iteratively, starting at each of the final nodes (those that may be reached at the time of expiration), and then working backwards through the tree towards the first node (valuation date). When valuing the warrant instruments, a lattice representing all possible paths the stock price could take during the life of the conversion and a lattice representing variations in the strike price if certain conditions are met are developed and used in concert.
The following weighted average assumptions were used to determine fair value at June 29, 2012 and April 30, 2012: risk-free rate of 0.4%, expected volatility of 83% and an expected term of 2.80 years and 2.90 years, respectively. As of June 29, 2012 and April 30, 2012, the warrants had an aggregate fair value of $2,510 and $2,953, respectively.

Warrants Issued in Connection with Other Equity Transactions At July 31, 2012 and April 30, 2012, we had 767,055 warrants outstanding that were issued in connection with our March 26, 2010 equity transaction. These warrants contain an exercise price reset provision, whereby the exercise price would be adjusted downward in the event our common stock is subsequently issued to others at a price below the initial warrant exercise price. Due to the reset provision, the warrants are considered freestanding derivative instruments and are classified as liabilities with fair value measured on a recurring basis in accordance with generally accepted accounting principles. We utilized the Black-Scholes model to determine fair value at

9

MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 (Unaudited)
(dollars in thousands)


July 31, 2012 and April 30, 2012 with the following weighted average assumptions: risk-free rate of 0.3% and 0.4%, an expected term of 2.65 years and 2.90 years, expected volatility of 85% and 83% and a dividend rate of 0%.
Fair Value Hierarchy
ASC 820 provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.
The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

As of July 31, 2012 and April 30, 2012, all of our derivatives were classified as Level 2 instruments due to the lack of quoted prices readily available in an active market. The following table presents the hierarchy classification of our derivative instruments:
 
Fair Value Measurements
At July 31, 2012
Level 1
 
Level 2
 
Level 3
Warrant derivative liability
$

 
$
1,309

 
$

Commodity derivative liability

 
1,803

 

Total
$

 
$
3,112

 
$

At April 30, 2012
 

 
 

 
 

Warrant derivative liability
$

 
$
5,354

 
$

Commodity derivative liability

 
5,149

 

Total
$

 
$
10,503

 
$


Derivative Activities Reflected on Unaudited Condensed Consolidated Statements of Operations

Changes in the fair value of our derivative liabilities are recorded in gain of derivatives, net on our unaudited Condensed Consolidated Statements of Operations.
 
Three Months Ended July 31,
 
2012
 
2011
Realized gain recognized in earnings
$
4,061

 
$
3,654

Unrealized gain recognized in earnings
4,880

 
102

Gain on derivatives, net
$
8,941

 
$
3,756


On June 6, 2012, the Company terminated the commodity derivative contracts in place of April 30, 2012 which were settled against the NYMEX WTI Cushing Index. In consideration of such termination, the counterparty paid the Company settlement value of $4,283 which was recorded as a realized gain. This realized gain was partially offset by $222 in realized losses during the three months ended July 31, 2012 to arrive at the realized net gain of $4,061.

10

MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 (Unaudited)
(dollars in thousands)


7.    DEBT

As of July 31, 2012 and April 30, 2012, we had the following debt obligations reflected at their respective carrying values on our unaudited Condensed Consolidated Balance Sheets:
 
 
July 31,
2012
 
April 30,
2012
Guggenheim senior secured credit facility
 
$

 
$
24,130

Apollo senior secured credit facility
 
40,000

 

Total debt obligations
 
$
40,000

 
$
24,130


Apollo Senior Secured Credit Facility
On June 29, 2012 (the “Closing Date”), Miller Energy Resources, Inc. (“Miller”) entered into a Loan Agreement (the “Loan Agreement”) with Apollo Investment Corporation (“Apollo”), as administrative agent and sole initial lender.
The Loan Agreement provides for a $100,000 credit facility (the “Apollo Credit Facility”) with an initial borrowing base of $55,000. Of that initial $55,000, $40,000 was made available to, and was drawn by, Miller on the Closing Date. The remaining $15,000 of the initial borrowing base will be made available following the satisfaction of certain conditions by the Company, most notably, the Company's demonstration (to Apollo's satisfaction) that it can raise at least $15,000 in additional equity (the “Equity Requirement”). The Apollo Credit Facility matures on June 29, 2017 and is, pursuant to the Guarantee (discussed below) secured by substantially all the assets of Miller and its consolidated subsidiaries (other than MEI). Amounts outstanding under the Apollo Credit Facility bear interest at a rate of 18% per annum, with interest payable on the last day of each of Miller's fiscal quarters. Miller will be required to pay the outstanding balance of the loan in full on the maturity date; however, beginning with the fiscal quarter ending on July 31, 2013, if requested by Apollo (at the direction of lenders holding a majority of the commitments under the Loan Agreement), Miller would be required to repay $1,500 in principal. Such payments of principal would be made, together with any interest due on such date, on the last day of Miller's fiscal quarter.
The Loan Agreement contains interest coverage, asset coverage, minimum gross production and leverage covenants, as well as other affirmative and negative covenants. In connection with the Loan Agreement, Miller has granted Apollo a right of first refusal to provide debt financing for the acquisition, development, exploration or operation of any oil and gas related properties including wells during the term of the Apollo Credit Facility and one year thereafter.
On the Closing Date, we paid the Apollo a non-refundable structuring fee of $2,750, payable for the account of the lenders, and we have agreed to pay an additional 5% fee to Apollo for the benefit of the lenders on the amount of every additional borrowing over and above the $55,000 amount of the borrowing base at closing. In addition, we paid Apollo a supplemental fee of $500 on the Closing Date, and have agreed to pay another $500 fee on each anniversary of the Closing Date so long as the Loan Agreement remains in effect.
Additional compensation was due to Bristol Capital, LLC, a consultant to us, in connection with the closing of the Loan Agreement. This fee shall be paid solely in 312,500 shares of the Company's restricted common stock.
The Company has used a portion of the initial $40,000 loan made available under the Apollo Credit Facility to repay in full the amounts outstanding under the Guggenheim Senior Secured Credit Facility ("Guggenheim Credit Facility") of approximately $26,200. The remaining $13,800 was used to (i) redeem the Company's outstanding Series A preferred stock; (ii) pay certain outstanding payables of the Company; and (iii) pay transaction costs associated with the closing of the Apollo Credit Facility, such as attorneys' fees. The undrawn portion of the initial borrowing base as of the Closing Date is $15,000, the drawing of which will be subject to the Equity Requirement discussed above.
We expect to use the remaining proceeds of the loans made under the Apollo Credit Facility to increase oil production both onshore and offshore in Alaska through the drilling of new wells and the reworking of previously producing oil wells there, as well as the reworking of existing wells in Tennessee.
Guggenheim Senior Secured Credit Facility

On June 29, 2012, in conjunction with the initiation of Apollo Credit Facility, we paid in full all outstanding principal and interest balances under the Guggenheim Credit Facility. The final payment of $26,200 was comprised of $21,900

11

MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 (Unaudited)
(dollars in thousands)


principal, $4,100 in interest expense due to the make-whole premium and $200 accrued interest. The Loan Agreement under the Guggenheim Credit Facility and all related documents and security interests arising under them were terminated immediately upon the repayment.

Debt Issue Costs

As of July 31, 2012, our unamortized debt issue costs were $5,231, which relate to the Apollo Credit Facility. These costs are being amortized over the life of the credit facility through June 29, 2017.

As of April 30, 2012, our unamortized debt issue costs were $1,426. These costs were written off at the termination of the Guggenheim Credit Facility.

Compliance with Debt Covenants

The first Covenant Compliance date is October 31, 2012 for the Apollo Credit Facility. Based on current and anticipated production during the quarter ending October 31, 2012, we do not expect to be in compliance with the minimum daily production covenant of 1,500 bbls per day.

8.    ASSET RETIREMENT OBLIGATIONS

The following table presents changes to the Company's asset retirement obligation liability for the three months ended July 31, 2012 and 2011:
 
2012
 
2011
Asset retirement obligation, as of April 30
$
18,366

 
$
17,294

Accretion expense
284

 
269

Asset retirement obligation, as of July 31
$
18,650

 
$
17,563

 
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, 2012 and April 30, 2012, there were no significant expenditures for abandonments.
 
9.    STOCK-BASED COMPENSATION
 
During fiscal year 2010 and 2011, our Compensation Committee and Board of Directors adopted a share-based compensation plan authorizing 3,000,000 and 8,250,000 shares of common stock under each plan, respectively. The share-based compensation plans allow us to offer our employees, officers, directors and others an opportunity to acquire a proprietary interest in the Company and enable us to attract, retain, motivate and reward such persons in order to promote the success of the Company. Each plan authorizes the issuance of incentive stock options, nonqualified stock options and restricted stock. All awards issued under the share-based compensation plans must be approved by our Compensation Committee. At July 31, 2012 and April 30, 2012, there were 362,828 and 1,250,000 additional shares available under the compensation plans.
 
We recognized $1,990 and $2,498 of employee expense related to our share-based compensation plans in the three months ended July 31, 2012 and 2011, respectively. We also recognized $86 and $218 of non-employee expense related to warrants issued under the plans for the three months ended July 31, 2012 and 2011, respectively. These expenses are included on our unaudited Condensed Consolidated Statements of Operations as part of “general and administrative expenses.”
 
    







12

MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 (Unaudited)
(dollars in thousands)


The following table summarizes our stock-based compensation activities for the three months ended July 31, 2012 and 2011:

 
Three Months Ended July 31, 2012
 
Three Months Ended July 31, 2011
 
Number of Options and Warrants
 
Weighted Average Exercise Price
 
Number of Options and Warrants
 
Weighted Average Exercise Price
Beginning balance
15,405,955

 
$
4.60

 
11,079,955

 
$
3.98

Granted
725,000

 
4.23

 
3,975,000

 
5.55

Exercised
(125,000
)
 
1.00

 
(869,000
)
 
1.48

Canceled
(440,000
)
 
5.07

 

 

Ending balance
15,565,955

 
4.60

 
14,185,955

 
4.57

Options exercisable at July 31
9,332,345

 
$
4.04

 
5,685,957

 
$
2.93


The following table summarizes our stock options and warrants outstanding, including exercisable shares at July 31, 2012:

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
 
2,068,900

 
2.1
 
$
0.71

 
2,006,400

 
$
0.72

$2.00 to $4.99
 
2,395,000

 
5.1
 
2.95

 
1,590,555

 
2.48

$5.25 to $5.53
 
4,967,055

 
3.9
 
5.33

 
3,025,388

 
5.32

$5.89 to $5.94
 
3,510,000

 
8.2
 
5.92

 
2,001,668

 
5.93

$6.00 to $6.94
 
2,625,000

 
3.4
 
6.03

 
708,334

 
6.07

 
 
15,565,955

 
4.7
 
$
4.60

 
9,332,345

 
$
4.04


10.    STOCKHOLDERS' EQUITY
 
At July 31, 2012, we had 41,959,393 shares outstanding. We issued 872,642 shares during the three months ended July 31, 2012, of which 125,000 shares were related to the exercise of equity rights, 312,500 shares were issued to Bristol Capital, LTD as payment for fees related to the closing of our credit facility, and 421,142 shares were issued to employees and non-employees for compensation of services, and 14,000 shares were issued for oil and gas leases.
 
At July 31, 2011, we had 40,749,251 shares outstanding. We issued a total of 869,000 shares during the three months ended July 31, 2011, which all shares were related to the exercise of equity rights.
 
11.    INCOME TAXES
 
We have a significant deferred income tax liability related to the excess of the book carrying value of oil and gas properties over their collective income tax bases. This difference will reverse (through lower tax depletion deductions) over the remaining recoverable life of the properties, resulting in future taxable income in excess of income for financial reporting purposes. As an independent producer of domestic oil and gas, we take advantage of certain elective provisions presently in the Internal Revenue Code allowing for expensing of specified intangible drilling and development costs that are typically capitalized for book purposes. This temporary difference also reverses over the remaining life of the properties. As a result of these elections, we presently have U.S. federal and state net operating loss carryovers that are expected to be fully utilized against future taxable income resulting solely from the reversal of the temporary differences between the book carrying value of oil and gas properties and their tax bases. We are not relying on forecasts of taxable income from other sources in concluding that no valuation allowance is needed against any of our deferred tax assets. Our provision for income taxes for the first interim

13

MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 (Unaudited)
(dollars in thousands)


reporting period in fiscal 2013 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 2013 causes an unusual relationship between income (loss) and income tax expense (benefit), with small changes resulting in: (i) a potential significant impact on the rate and, (ii) potentially unreliable estimates. As a result, we computed the provision for income taxes for the quarters and year-to-dates ended July 31, 2012 and July 31, 2011 by applying the actual effective tax rate to the year-to-date income (loss), as permitted by accounting principles generally accepted in the United States of America. The effective tax rate for the year-to-date period ended July 31, 2012 is an expense of 29.8%. The principal differences in our effective tax rate and the Federal statutory rate of 35% are the presence of state income taxes and a favorable permanent difference related to mark-to-market accounting for Company warrants. No cash payments of income taxes were made during the year-to-date period ended July 31, 2012, and no significant payments are expected during the succeeding 12 months.
 
In light of the adjustments to our unaudited Condensed Consolidated Financial Statements during the year ended April 30, 2010, we amended our U.S. federal and state income tax returns for that year during this quarter. These adjustments had a carryforward effect into future years, beginning with the tax year ended April 30, 2011. Due to the significance and complexity of these tax adjustments, we filed our U.S. federal and state income tax returns for the year ended April 30, 2011on July 31, 2012. We do not expect significant cash taxes, interest, or penalties to result from these amended or delinquent filings and do not expect that the failure to timely amend or file our returns could reasonably be expected to result in a Material Adverse Change (as such term is defined under our loan agreement). Our U.S. Federal and state income tax returns for the year ended April 30, 2012, were timely extended, and we expect to have these filings complete by their respective extended due dates of January 15, and February 15, 2013.

12.    ALASKA PRODUCTION TAX CREDITS

The Company qualifies for several credits under Alaska statutes 43.55.023 and 43.55.025:

43.55.023(a)(1) Qualified capital expenditure credit (20)%
43.55.023(l)(1) Well lease expenditure credit (effective June 30, 2010) (40)%
43.55.023(a)(2) Qualified capital exploration expenditure credit (20)%
43.55.023(l)(2) Well lease exploration expenditure credit (effective June 30, 2010) (40)%
43.55.023(b) Carried-forward annual loss credit (25)%
43.55.025 Seismic exploration credits (40)%

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

As of July 31, 2012 and April 30, 2012, the Company has reduced the basis of capitalized assets by $7,837 for expenditure and exploration credits. The reductions are recorded on our unaudited Condensed Consolidated Balance Sheets in “oil and gas properties.” As of July 31, 2012 and April 30, 2012, the Company had outstanding receivables from the State of Alaska in the amount of $2,958.

13.    LITIGATION

On October 8, 2009, we filed an action styled Miller Petroleum, Inc. v. Maynard, Civil Action No. 9992 in the Chancery Court for Scott County, Tennessee, seeking a declaratory judgment that there has been continuing commercial production of oil, and oil and gas lease owned by us is still in full force and effect. The defendant filed an Answer and Counterclaim, seeking in the Counterclaim a declaration that the oil and gas lease has expired. Although no compensatory monetary damages have been sought against us, the Counterclaim does seek attorney fees, expenses and costs. On October 27, 2010, a temporary injunction was granted allowing us access to the property at issue in this case. Since entry of the temporary injunction, production of oil from the property has resumed. Until this matter is resolved by the court, all proceeds from the

14

MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 (Unaudited)
(dollars in thousands)


new production will be subject to disposition pursuant to further orders of the court. As of this time a trial date has not yet been assigned. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.

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

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

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

On June 15, 2011, a breach of contract lawsuit was filed against us and CIE in the United States District Court for the Eastern District of Pennsylvania styled VAI, Inc. v. Miller Energy Resources, Inc., f/k/a Miller Petroleum, Inc. and Cook Inlet Energy, LLC. The Plaintiff alleges three causes of action: (1) breach of contract, (2) unfair enrichment, and (3) breach of the implied covenant of good faith and fair dealing. The case seeks damages in warrants to purchase our common stock and monetary damages for certain fees and expenses. The Sale Agreement with David Hall, Walter “JR” Wilcox, and Troy Stafford dated December 10, 2009 contains indemnification provisions relevant to this claim. We have filed a Motion to Dismiss for lack of personal jurisdiction, which is pending while limited discovery is conducted. 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 lawsuit were filed against us in the United States District Court for the Eastern District of Tennessee.  The lawsuits made similar claims, and have been consolidated into one case, styled In re Miller Energy Resources, Inc. Securities Litigation. The suit names us, along with several of our current and former executive officers, Scott Boruff, Paul Boyd, Ford Graham, David Hall, and Deloy Miller, as defendants. The Plaintiffs allege two causes of action against the defendants: (1) violation of Section 10(b) and Rule 10b-5 of the Exchange Act, (2) violation of Section 20(a) of the Exchange Act.  The case seeks money damages against the Company and the other defendants, and payment of the Plaintiffs' attorney's fees. We have filed a Motion to Dismiss the case. 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.


15

MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 (Unaudited)
(dollars in thousands)


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

On August 25, 2011, and August 31, 2011, two derivative actions were filed against us and our Board of Directors and former Chief Financial Officer in the United States District Court for the Eastern District of Tennessee. These cases were consolidated into Patrick P. Lukas, derivatively on behalf Miller Energy Resources, Inc. v. Merrill A. McPeak, Scott M. Boruff, Deloy Miller, Jonathan S. Gross, Herman Gettelfinger, David Hall, Charles M. Stivers, Don A., Turkleson, and David J. Voyticky, and Miller Energy Resources, Inc., nominal defendant. It contains substantially similar claims as Valdez. The suit alleges the following causes of action: (1) Breach of Fiduciary Duty for disseminating false and misleading information; (2) Breach of Fiduciary Duty for failing to properly oversee and manage the company; (3) Unjust Enrichment; (4) Abuse of Control; (5) Gross Mismanagement, and; (5) Waste of Corporate Assets.  The Plaintiffs seek unspecified money damages from the individual defendants, that we take certain actions with respect to our management, restitution to us, and the Plaintiff's attorney fees and costs. We have filed a Motion to Dismiss. 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.

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

14.     COMMITMENTS AND CONTINGENCIES

On November 5, 2009, CIE entered into an Assignment Oversight Agreement with the Alaska DNR which set out certain terms under which the Alaska DNR would approve the assignment of certain specified state oil and gas leases from Pacific Energy to CIE. This agreement remains in place following our acquisition of CIE in December 2009. Generally, the agreement requires CIE to provide the Alaska DNR with additional information and oversight authority to ensure that CIE is acting diligently to develop the oil and gas from Redoubt Shoal, West McArthur River Field and West Foreland Field. Under the terms of the agreement, until the Alaska DNR determines, in its sole discretion, that CIE has completed its development and operational obligations under the assigned leases, CIE agreed to the following:
file a monthly summary of expenditures by oil and gas filed, tied to objectives in CIE’s business plan and plan of development previously presented to the Alaska DNR,
meet monthly with the Alaska DNR to provide an update on operations and progress towards meeting these objectives,
notify the Alaska DNR 10 days prior to commitment when CIE is preparing to spend funds on a purchase, project or item of more than $100 during the first 12 months, more than $1,000 during the second 12 months and more than $5,000 thereafter, and
submit a new plan of development and plan of operations for the Alaska DNR’s approval on or before December 15, 2009 and submit a plan of development annually thereafter on or before February 1, 2010.
The agreement required CIE to obtain financing in the minimum amount of $5,150 to provide funds to be used for expenditures approved by the Alaska DNR as part of CIE’s plan of development. The funds are to be used for workover and repair of the wells, repair of the physical infrastructure, construction of a grind and inject plant at the West McArthur River facility, normal operating expenses associated with the leases and infrastructure and other capital project which are to be pre-approved by the Alaska DNR. The agreement also required CIE to demonstrate funding commitments to support restoration of the base production at the Redoubt Unit, including bringing a number of the shut-in wells back on line, which was estimated at $31,000 in the agreement but which we have internally increased to $35,000 to accommodate the purchase of a drilling rig. We have subsequently provided these funds for the West McArthur River facility using a portion of the proceeds of our capital

16

MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
 (Unaudited)
(dollars in thousands)


raising efforts described elsewhere herein, and intend to seek alternative sources of funding for the balance of the necessary capital.

CIE is prohibited from using any of the proceeds from the operations under the assigned leases of the funding commitments for non-core oil and gas activities under the assigned leases, or any activities outside the assigned leases, without the prior written approval of the Alaska DNR until the parties mutually agree that the full dismantlement obligation under the assigned leases is funded. The assigned leases will be subject to default and termination should CIE fail to submit the information required under the agreement and expenditure of funds for items or activities do not support core oil and gas activities, as reasonably determined by the Alaska DNR.

On March 11, 2011, the Company entered into a Performance Bond Agreement under its Assignment Oversight Agreement with the state of Alaska. Under the Performance Bond Agreement, the Company is required to post a total bond of $18,000 for the dismantling and abandonment of the properties. The Performance Bond Agreement also stipulates that $6,000 held by the state in an escrow account will be credited towards the $18,000. Until this point in time, the Company could not verify that they had legal rights to the escrow account. As a result, the Company recorded a $6,900 (which includes $900 of accrued interest) gain on acquisition during the year ended April 30, 2011.

The Company is obligated to pay the remaining $12,000 (subject to annual inflation adjustments) through annual payments as follows:

July 1, 2013
 
$
1,000

 
July 1, 2014
 
1,500

 
July 1, 2015
 
2,000

 
July 1, 2016
 
2,500

 
July 1, 2017
 
2,000

 
July 1, 2018
 
1,500

 
July 1, 2019
 
1,500

 
 
 
$
12,000

 

Other Commitments

In August 2008, we engaged a related party broker-dealer and member of FINRA, The Dimirak Companies ("Dimirak"), to assist us in raising capital by means of a private placement of securities. As initial compensation for their services, we paid a $25 retainer and issued 250,000 shares of our common stock, valued at $100 and agreed to pay a monthly consulting fee of $5. Upon the successful completion of the private offering we will be obligated to pay the firm certain cash compensation and issue them up to an additional 150,000 shares of our common stock in amounts to be determined based upon the gross proceeds received by us from the financing.



17


ITEM 2.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(dollars in thousands)

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
We have made forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company's operations, economic performance and financial condition in this report, our Annual Report on Form 10-K for the year ended April 30, 2012, as amended, 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. These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:
the potential for Miller to experience additional operating losses;
high debt costs under our existing senior credit facility;
potential limitations imposed by debt covenants under our senior credit facility on our growth and our ability to meet our business objectives;
our need to enhance our management, systems, accounting, controls and reporting performance;
litigation risks;
our ability to perform under the terms of our oil and gas leases, and exploration licenses with the Alaska DNR, including meeting the funding or work commitments of those agreements;
our ability to successfully acquire, integrate and exploit new productive assets in the future;
our ability to recover proved undeveloped reserves and convert probable and possible reserves to proved reserves;
risks associated with the hedging of commodity prices;
our dependence on third party transportation facilities;
concentration risk in the market for the oil we produce in Alaska;
the impact of natural disasters on our Cook Inlet Basin operations;
adverse effects of the national and global economic downturns on our profitability;
the imprecise nature of our reserve estimates;
drilling risks;
fluctuating oil and gas prices and the impact on our results from operations;
the need to discover or acquire new reserves in the future to avoid declines in production;
differences between the present value of cash flows from proved reserves and the market value of those reserves;
the existence within the industry of risks that may be uninsurable;
constraints on production and costs of compliance that may arise from current and future environmental, FERC and other statutes, rules and regulations at the state and federal level;
the impact that future legislation could have on access to tax incentives currently enjoyed by Miller;
that no dividends may be paid on our common stock for some time;
cashless exercise provisions of outstanding warrants;
market overhang related to restricted securities and outstanding options, and warrants;


18


the impact of non-cash gains and losses from derivative accounting on future financial results; and
risks to non-affiliate shareholders arising from the substantial ownership positions of affiliates.
Most of these factors are difficult to predict accurately and are generally beyond our control. You should consider the areas of risk described in connection with any forward-looking statements that may be made herein. Readers are cautioned not to place undue reliance on these forward-looking statements, and readers should carefully review this report together with our Annual Report on Form 10-K for the year ended April 30, 2012, as amended, in its entirety, including the risks described in Item 1A. Risk Factors appearing in such Annual Report. Except for our ongoing obligations to disclose material information under the Federal securities laws, we undertake no obligation to release publicly any revisions to any forward-looking statements, to report events or to report the occurrence of unanticipated events. These forward-looking statements speak only as of the date of this report, and you should not rely on these statements without also considering the risks and uncertainties associated with these statements and our business.

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

Executive Overview
Strategy
Our mission is to grow a profitable exploration and production company for the long-term benefit of our shareholders by focusing on the development of our reserves, continued expansion of our oil and natural gas properties and increase in our production and related cash flow. We intend to accomplish these objectives through the execution of our core strategies, which include:
Develop Acquired Acreage. We will focus on organically growing production through drilling for our own benefit on existing leases and acreage in the exploration licenses with a view towards retaining the majority of working interest in the new wells. This strategy will allow us to maintain operational control, which we believe will translate to long-term benefits;
Increase Production. We plan on increasing oil and gas production through the maintenance, repair and optimization of wells located in the Cook Inlet Basin and development of wells in the Appalachian region of East Tennessee. Our management team will employ the latest available technologies to restore as well as explore and develop our properties;
Expand Our Revenue Stream. We intend on fully exploiting our mid-stream facilities, such as our injection wells and the Kustatan Production Facility, our ability to engage in the commercial disposal of waste generated by oil and gas operations, and our capacity to process third party fluids and natural gas and to offer excess electrical power to net users in the Cook Inlet area; and
Pursue Strategic Acquisitions. We have significantly increased our oil and gas properties through strategic low-cost / high-value acquisitions. Under the same strategy, our management team will continually seek for opportunities that meet our criteria for risk, reward, rate of return, and growth potential. We plan to leverage our management team's expertise to pursue value-creating acquisitions when the opportunities arise, subject to the availability of sufficient capital.

Our management team is focused on obtaining the financial flexibility required to successfully execute these core strategies.
However, 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 drilling and well recompletions, as well as the corresponding costs necessary to produce such reserves and 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.


19


Financial and Operating Results
We continued to utilize funds under our credit facilities along with other financing sources and operational cash flow to support our capital expenditures during our first quarter of fiscal 2013. For the three-month period ended July 31, 2012, we reported notable achievements in several key areas. Highlights for the quarter include:
On April 6, 2012, we issued a new class of Series A Cumulative Preferred Stock to 20 accredited and institutional investors in a private offering exempt from registration under the Securities Act of 1933, as amended. On June 29, 2012, we fully redeemed the outstanding shares.
On June 29, 2012, we closed our new credit facility with Apollo Investment Corporation and repaid our Guggenheim credit facility. For additional information refer to Note 7, Debt, in the unaudited Condensed Consolidated Financial Statements.
Rig 34 was mobilized to the Otter natural gas prospect and the drilling phase was completed at a depth of 5,680 feet in the Beluga formation. Mud logs have reported two significant hydrocarbon gas shows in the zone of interest. Additional work is now needed to fully evaluate the Beluga formation as we plan to conduct a chemical treatment, a hydraulic fracture or both to stimulate the well. These two processes are commonly performed in wells in the Beluga formation.
On August 21, 2012, we gained approval from state regulators to commence drilling with Rig 35 on the Osprey offshore platform. The rig was already positioned over the RU-1 well. We are currently in the process of removing and repairing electronic submersible pumps and conducting wellbore optimization with a goal of increasing RU-1's historical flow rates. The well was previously producing approximately 270 barrels of oil per day.
 
2013 Outlook
As we head into 2013, we believe our inventory of recompletion as well as exploration and development projects offers numerous growth opportunities. Our current 2013 capital budget is $50 to 100 million. Nearly all of our budget is expected to be spent on projects in Alaska, with the remaining amount allocated to our Appalachian region. Due to the uncertainty associated with changes in commodity prices, we closely monitor our cost levels and revise our capital budgets based on changes in forecasted cash flows. This means our plan for capital expenditures may change as a result of anticipated changes in the market place. Further, our ability to fully utilize the budget will be dependent on a number of factors including, but not limited to, access to capital, weather and regulatory approval.             
We expect to fund our 2013 capital budget with funds borrowed under the Apollo Credit Facility, proceeds received from anticipated preferred stock offerings, cash flows from operations and proceeds from potential asset dispositions. We may also access the capital markets as necessary to fund specific drilling programs and continue developing our assets. In the event we are unable to raise additional capital on acceptable terms, we may reduce our capital spending.

Significant Operational Factors

Realized Prices: Our average realized oil price for the three months ended July 31, 2012 was $99.59 compared to $95.69 for the same period in the prior year. These results exclude the impact of commodity derivative settlements.
Production: Our net production for the three months ended July 31, 2012 was 77,079 BOE as compared to 92,008 BOE for the same period in the prior year.  The decrease in production is attributable to a normal decline curve, fluctuation and shipping schedules, and RU-1 in our Redoubt Shoals field being off-line in the current period.
Capital Expenditures and Drilling Results: During the three months ended July 31, 2012, we spent approximately $9,325 in capital expenditures. Rig 34 and Rig 35 have been approved by state regulators and are currently operational.

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

20


Results of Operations

Revenues
 
Three Months Ended July 31
 
2012
 
2011
 
$ Value
 
Increase (Decrease)
 
$ Value
 
(In thousands, except percentages)
Oil revenues:
 
 
 
 
 
Cook Inlet
$
7,242

 
(4)%
 
$
7,554

Appalachian region
404

 
(37)
 
637

Total
$
7,646

 
(7)
 
$
8,191

Natural gas revenues:
 
 
 
 
 
Cook Inlet
$
6

 
(84)
 
$
37

Appalachian region
77

 
(15)
 
91

Total
$
83

 
(35)
 
$
128

Other revenues:
 
 
 
 
 
Cook Inlet
$
273

 
184
 
$
96

Appalachian region
260

 
(41)
 
440

Total
533

 
(1)
 
536

Total revenues
$
8,262

 
(7)
 
$
8,855


Net Production
 
Three Months Ended July 31
 
2012
 
Increase
(Decrease)
 
2011
 
(In thousands, except percentages)
Oil volume - bbls:
 
 
 
 
 
Cook Inlet
66,758
 
(16)%
 
79,714
Appalachian region
4,345
 
1
 
4,303
Total
71,103
 
(15)
 
84,017
Natural gas volume1- mcf:
 
 
 
 
 
Cook Inlet
2,293
 
(83)
 
13,671
Appalachian region
33,565
 
(2)
 
34,270
Total
35,858
 
(25)
 
47,941
Total production2 - boe
 
 
 
 
 
Cook Inlet
67,140
 
(18)
 
81,993
Appalachian region
9,939
 
(1)
 
10,015
Total
77,079
 
(16)
 
92,008

———————
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.





21


Pricing
Oil Prices

All of our oil production is sold at prevailing market prices, which are subject to fluctuations driven by market factors outside of our control. As volatility increases in response to the rise in global demand for oil combined with economic uncertainty, prices will continue to experience volatility at unpredictable levels. Prices received for crude oil in the first quarter of 2013 were 4% above the same period last year. For the three months ending July 31, 2012, oil prices realized averaged $99.59 per barrel, compared with $95.69 per barrel 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. The majority of our natural gas sales contracts are indexed to prevailing local market prices. Average realized prices decreased 25% in the first quarter of 2013 compared to the same period in the prior year.

Oil Revenues

During the first quarter of 2013, oil revenues totaled $7,646, 7% lower than the same period in the prior year. The decline resulted from a 15% decrease in production partially offset by an increase in pricing. Oil sales represented 93% of our first quarter consolidated total revenues for the first quarters of 2013 and 2012.

Oil production decreased 12,914 bbls, driven by a 12,956 bbls decrease in the Cook Inlet region. The production decrease in the Cook Inlet region resulted from a normal decline curve, fluctuations in shipping schedules, and RU-1 in our Redoubt Shoals field being off-line in the current period.

Natural Gas Revenues

During the first quarter of 2013, natural gas revenues totaled $83, 35% lower than the same period in the prior year. The decline resulted from a combination of a 13% decrease in average realized prices and a 25% decrease in production. Natural gas represented 1% of our first quarter consolidated total revenues for the first quarters of 2013 and 2012.

Other Revenues

Other revenues primarily represent revenues generated from contracts for 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 2013 and 2012, other revenues totaled $533 and $536, respectively, which represented 6% of our consolidated total revenues.

Cost and Expenses

The table below presents a comparison of our expenses:
 
Three Months Ended July 31
 
 
 
 
 
2012
 
2011
 
$ Variance
 
% Variance
 
(In thousands, except percentages)
Oil and gas operating costs
$
3,974

 
$
3,796

 
$
178

 
5
 %
Cost of other revenues
548

 
227

 
321

 
141

General and administrative
5,330

 
5,772

 
(442
)
 
(8
)
Exploration expense
29

 
32

 
(3
)
 
(9
)
Depreciation, depletion, and amortization
3,125

 
3,373

 
(248
)
 
(7
)
Accretion of asset retirement obligation
284

 
269

 
15

 
6

Other operating expense (income), net
(25
)
 
(892
)
 
867

 
(97
)
Total costs and expenses
$
13,265

 
$
12,577

 
$
688

 
5
 %




22


Oil and Gas Operating Costs

Oil and gas operating costs increased $178 from first quarter fiscal 2012, or 5%. The majority of our operating costs are fixed, and as such, we did not experience a proportionate decrease in cost from current period declines in production.

Cost of Other Revenues

Our business is primarily focused on exploration and production activities. The cost of other revenues represent costs of services to third parties as a result of excess capacity, and are derived from the direct labor costs of employees associated with these services, as well as costs associated with equipment, parts and repairs.

 
Three Months Ended July 31
 
2012
 
Increase (Decrease)
 
2011
 
(In thousands, except percentage)
Direct labor
$
287

 
71
 %
 
$
168

Equipment
92

 
268

 
25

Repairs
121

 
1,110

 
10

Insurance
38

 
100

 

Other
10

 
(58
)
 
24

Total
$
548

 
141
 %
 
$
227


During first quarter fiscal of 2013, cost of other revenues increased 141% to $548. A substantial portion of this increase is related to labor costs associated with services provided under the Tennessee Department of Environment and Conservation contract for plugging abandoned wells located in the Big South Fork area in Tennessee and cost associated with the addition of our new grind and inject facility in Alaska.

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.

 
Three Months Ended July 31
 
2012
 
Increase (Decrease)
 
2011
 
(In thousands, except percentages)
Salaries
$
872

 
(17
)%
 
$
1,047

Professional fees
1,384

 
125

 
614

Travel
371

 
(19
)
 
458

Employee benefits
210

 
(14
)
 
243

Stock-based compensation
2,076

 
(24
)
 
2,716

Other
417

 
(40
)
 
694

Total
$
5,330

 
(8
)%
 
$
5,772


G&A expenses decreased $442 from first quarter fiscal 2012, or 8%. Salaries declined 17% from the same period in the prior fiscal year due to a decline in cash bonuses. Professional fees increased 125% over the same period last year due to an increase in legal and accounting fees. The 19% decline in travel related expenses primarily relates to a reduction in the use of our corporate aircraft. Stock-based compensation declined 24% due to the fact that the expense associated with awards that became fully vested exceeded the expense associated with newly granted awards.





23


Exploration Expense

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

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) expenses include the depreciation, depletion and amortization of leasehold costs and equipment. Depletion is calculated on a unit-of-production basis. Depreciation is calculated on a straight line basis.
 
Three Months Ended July 31
 
2012
 
2011
 
(In thousands)
Depletion:
 
 
 
Cook Inlet region
$
2,604

 
$
2,974

Appalachian region
220

 
232

 
2,824

 
3,206

Depreciation:
 
 
 
Cook Inlet region
58

 
40

Appalachian region
243

 
127

 
301

 
167

Total DD&A
$
3,125

 
$
3,373


The decrease is primarily a result of declines in production from our Alaska West MacArthur River field and RU-1 in our Redoubt Shoals field.

Other Income and Expense

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

 
Three Months Ended July 31
 
2012
 
Increase (Decrease)
 
2011
 
(In thousands, except percentages)
Interest expense, net of interest income
$
(131
)
 
(74)%
 
$
(495
)
Gain on derivatives, net
8,941

 
138
 
3,756

Other income (expense), net
(75
)
 
(342)
 
31

Total
$
8,735

 
 
 
$
3,292


Interest Expense

Interest expense, net of interest income decreased $364 from first quarter fiscal 2012, or 74%, driven primarily by an increase in capitalized interest.

Gain on Derivatives, Net

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

    
During the first quarter of fiscal 2013, unrealized gains on commodity derivatives totaled $3,550, while realized gains on commodity derivatives totaled $4,061. Unrealized gains on warrant derivatives of $1,330 make up the remaining portion of the total net gain on derivatives of $8,941.


24


Liquidity and Capital Resources

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

Our long-term cash flows are highly dependent on our success in efficiently developing current reserves and economically finding, developing and acquiring additional recoverable reserves. Cash investments are required continuously to fund exploration and development projects and acquisitions, which are necessary to offset the inherent declines in production and proven reserves. We may not be able to find, develop or acquire additional reserves to replace our current and future production at acceptable costs, which could materially adversely affect our future liquidity. For a discussion of risk factors related to our business and operations, please see Part II, Item 1A – Risk Factors, of this Form 10-Q.

We may elect to utilize excess borrowing capacity, access to both debt and equity capital markets, or proceeds from the occasional sale of nonstrategic assets to supplement our liquidity and capital resource needs.

In the first quarter of fiscal 2013, we experienced an operating loss and had a working capital deficit as of July 31, 2012. We anticipate that our operating expenses will continue to increase as we fully develop our assets in the Cook Inlet and Appalachian regions. Although we expect an increase in our revenues to come from these development activities, we will continue depleting our cash resources to fund operating expenses until such time as we are able to significantly increase our revenues above costs.
 
We believe that the liquidity and capital resource alternatives available to us, combined with internally generated cash flows and other potential sources of funds, will be adequate to fund our short-term and long-term operations, including our capital budget, repayment of debt maturities, and any amount that may ultimately be paid in connection with contingencies; however, our new Apollo Investment Corporation credit facility restricts our access and control of certain bank accounts without compliance with certain provisions of the loan agreement.




























25


Sources and Uses of Cash

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

 
Three Months Ended July 31
 
2012
 
2011
 
(In thousands)
Sources of cash and cash equivalents:
 
 
 
Net cash provided by operating activities
$
3,608

 
$
2,803

Proceeds from borrowings, net of debt acquisition costs
36,243

 
21,165

Proceeds from sale of equipment
2,000

 

Exercise of equity rights
125

 
1,283

Release of restricted cash
640

 

 
42,616

 
25,251

Uses of cash and cash equivalents:
 
 
 
Capital expenditures for oil and gas properties
(4,714
)
 
(7,004
)
Purchase of equipment and improvements
(4,611
)
 
(12,790
)
Payments on debt
(24,130
)
 
(2,000
)
Redemption of preferred stock
(11,240
)
 

Investment in equity method investee

 
(400
)
Use of restricted cash

 
(52
)
 
(44,695
)
 
(22,246
)
 


 
 
Increase (decrease) in cash and cash equivalents
$
(2,079
)
 
$
3,005


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, asset retirement obligation ("ARO") 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 quarter of 2013 totaled $3,608, up $805 from the same period in 2012. The increase resulted primarily from the realized gain recorded for the termination of commodity derivative instruments, partially offset by an increase in prepaid expenses and other assets, and a decrease in DD&A and stock-based compensation.

Proceeds from Credit Facilities and Other Items

During the first quarter of 2013, borrowings under our new Apollo credit facility totaled $40,000. In connection with the establishment of the new facility, we incurred approximately $3,757 in deferred financing costs. The proceeds were used to repay our Guggenheim credit facility and redeem our outstanding Series A Cumulative Preferred Stock. For additional information on the credit facilities, please see Note 7 - Debt in the Notes as set forth in the accompanying unaudited Condensed Consolidated Financial Statements.

We received proceeds from the sale of a generator totaling $2,000 during the first quarter of 2013.

Capital Expenditures

We use a combination of operating cash flows, borrowings under credit facilities and, from time to time, issues 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.

26


Total spending on capital projects was down slightly from the same period last year. Capital spending on our Otter exploratory well project during the current quarter was not as high as recompletion projects involving our RU-1, RU-3 and RU-7 wells during the same period last year.

Liquidity

Cash and Cash Equivalents

As of July 31, 2012, we had $1,892 in cash and cash equivalents.

Debt

Outstanding debt consisted of $40,000 in borrowings under the Apollo credit facility, of which $1,500 is classified as current and $38,500 is classified as long-term on the accompanying unaudited Condensed Consolidated Balance Sheet of July 31, 2012.

Available Credit Facilities

We have $15,000 in additional borrowing capacity under our Apollo credit facility as of July 31, 2012, which may be made available following the satisfaction of certain conditions by the Company.

Contractual Obligations

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

As of July 31, 2012 and for the first quarter of fiscal 2013, there were no additional material changes outside the ordinary course of business in our contractual obligations and commitments.  For additional information regarding these obligations, please refer to Item 7, “Management's Discussion and Analysis of Financial Condition and Results of Operations-Contractual Cash Obligations and Commitments” contained in our Annual Report on Form 10-K for the fiscal year ended April 30, 2012, as amended, and incorporated by reference herein.  

Non-GAAP Measures

Adjusted Earnings

Adjusted EBITDA is a significant performance metric used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts and others to assess:

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and
our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure.

We define Adjusted EBITDA as net income (loss) before taxes adjusted by:
depreciation, depletion and amortization;
write-off of deferred financing fees;
asset impairments;
(gain) loss on sale of assets;
accretion expense;
exploration costs;
(gain) loss from equity investment;
stock-based compensation expense;

27


(gain) loss from mark-to-market activities;
interest expense and interest (income)

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

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

 
Three Months Ended July 31
 
2012
 
2011
 
(In thousands)
Income (loss) before income taxes
$
3,732

 
$
(430
)
Adjusted by:
 
 
 
Interest expense, net
(131
)
 
(495
)
Depreciation, depletion and amortization
3,125

 
3,373

Accretion of asset retirement obligation
284

 
269

Exploration expense
29

 
32

Stock-based compensation
2,076

 
2,716

Unrealized gain on derivatives
(4,880
)
 
(102
)
Accretion of preferred stock
2,422

 

Adjusted EBITDA
$
6,657

 
$
5,363


Recent Accounting Pronouncements

In December 2011, the FASB issued ASU 2011-11, "Disclosures about Offsetting Assets and Liabilities," which increases disclosures about offsetting assets and liabilities. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards ("IFRS") related to the offsetting of financial instruments. The existing GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance in ASU 2011-11 is effective for annual and interim reporting periods beginning on or after January 1, 2013. The disclosures should be applied retrospectively for all prior periods presented. We do not expect the adoption of this pronouncement to have a material impact to our condensed consolidated financial statements.

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

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
(dollars in thousands)

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

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil production and, to some extent, our natural gas production. Realized pricing is primarily driven by the NYMEX West Texas Intermediate (Cushing, Oklahoma) for our oil production adjusted to ANS (West Coast Alaskan North Slope) and ACI (Alaska Cook Inlet). Historically, pricing for oil and natural gas has been volatile and unpredictable and we expect this volatility to continue in the future. The prices we receive for

28


oil and natural gas production depend on many factors outside our control, including weather, economic conditions, and the total supply of oil and natural gas available for sale in the market.

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

During the first quarter of fiscal 2013, we settled three commodity derivative instruments with an average price of $94.01 per barrel of oil based on NYMEX WTI index. We also entered into two hedging agreements; one for 149,800 barrels at $97.40 per barrel and one for 219,000 at $95.30 per barrel, both prices based on the ICE Brent crude oil futures as traded on the New York Mercantile Exchange. We received $4,283 for the settlement of the hedging agreements.

The following tables summarize, for the periods indicated, our hedges currently in place through December 2013. All of these derivatives are accounted for as mark-to-market activities.
 
 
For the Quarter Ended (in Bbls)
 
 
July 31,
 
October 31,
 
January 31,
 
April 30,
 
Total
Fiscal
 
Volume
 
Avg. Price
 
Volume
 
Avg. Price
 
Volume
 
Avg. Price
 
Volume
 
Avg. Price
 
Volume
 
Avg. Price
2013
 

 
$

 
64,400

 
$
97.40

 
61,300

 
$
96.70

 
53,400

 
$
95.30

 
179,100

 
$
96.47

2014
 
55,200

 
95.30

 
55,200

 
95.30

 
36,600

 
95.30

 

 

 
147,000

 
95.30

 
 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
326,100

 
 


Interest Rate Risk

On June 29, 2012, we repaid the Guggenheim Credit Facility and initiated the Apollo Credit Facility at a fixed rate of 18% per annum. Because interest on borrowings is fixed and not subject to market fluctuations in interest rates, our interest rate risk is negligible.

ITEM 4.    CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended, at the end of the period covered by this report (the “evaluation date”). In conducting its evaluation, management considered the material weaknesses in our disclosure controls and procedures and internal control over financial reporting described in Item 9A. of our Annual Report on Form 10-K for the year ended April 30, 2012 as filed with the SEC on July 16, 2012.

We have made progress remediating the material weaknesses identified in our Annual Report on Form 10-K for the year ended April 30, 2012 as filed with the SEC on July 16, 2012. However, as of the evaluation date, our Chief Executive Officer and Chief Financial Officer 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 Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures will prevent all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system's objectives will be met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions

Changes in Internal Control over Financial Reporting. There 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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PART II - OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS.

The information set forth in Note 13 - Litigation in the accompanying unaudited Condensed Consolidated Financial Statements is incorporated herein by reference.

ITEM 1A.    RISK FACTORS.

For a detailed discussion of the risks and uncertainties associated with our business see “Risk Factors” in the Company's Annual Report on Form 10-K filed with the SEC on July 16, 2012. There have been no material changes to these risk factors since those reports.

An investment in our common shares involves various risks. When considering an investment in us, careful consideration should be given to the risk factors described in our 2012 Form 10-K. These risks and uncertainties are not the only ones facing us and there may be additional matters that are not known to us or that we currently consider immaterial. All of these risks and uncertainties could adversely affect our business, financial condition or future results and, thus, the value of an investment in us.

ITEM 6.    EXHIBITS

The following documents are filed as a part of this report:
 
EXHIBIT NO.
 
 
 
DESCRIPTION
31.1
 
 
Rule 13a-14(a)/15d-14(a) certification of Chief Executive Officer *
31.2
 
 
Rule 13a-14(a)/15d-14(a) certification of Chief Financial Officer *
32.1
 
 
Section 1350 certification of Chief Executive Officer and Chief Financial Officer*
101.INS
 
 
XBRL Instance Document **
101.SCH
 
 
XBRL Taxonomy Extension Schema Document **
101.CAL
 
 
XBRL Taxonomy Extension Calculation Linkbase Document**
101.LAB
 
 
XBRL Taxonomy Extension Label Linkbase Document **
101.PRE
 
 
XBRL Taxonomy Extension Presentation Linkbase Document **
101.DEF
 
 
XBRL Taxonomy Extension Definition Linkbase Document **
———————
*    filed herewith.
**    In accordance with Regulation S-T, the XBRL-formatted interactive data files that comprise Exhibit 101 in this report on Form 10-K shall be deemed “furnished” and not “filed”.


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SIGNATURES

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

Dated:
September 10, 2012
MILLER ENERGY RESOURCES, INC.
 
 
 
 
 
 
By:
/s/ Scott M. Boruff
 
 
 
Scott M. Boruff, Chief Executive Officer, principal executive officer
 
 
 
 
 
 
 
 
Dated:
September 10, 2012
MILLER ENERGY RESOURCES, INC.
 
 
 
 
 
 
By:
/s/ David J. Voyticky
 
 
 
David J. Voyticky, Chief Financial Officer, principal financial officer


31



EXHIBIT INDEX

EXHIBIT NO.
 
 
 
DESCRIPTION
31.1
 
 
Rule 13a-14(a)/15d-14(a) certification of Chief Executive Officer *
31.2
 
 
Rule 13a-14(a)/15d-14(a) certification of Chief Financial Officer *
32.1
 
 
Section 1350 certification of Chief Executive Officer and Chief Financial Officer*
101.INS
 
 
XBRL Instance Document **
101.SCH
 
 
XBRL Taxonomy Extension Schema Document **
101.CAL
 
 
XBRL Taxonomy Extension Calculation Linkbase Document**
101.LAB
 
 
XBRL Taxonomy Extension Label Linkbase Document **
101.PRE
 
 
XBRL Taxonomy Extension Presentation Linkbase Document **
101.DEF
 
 
XBRL Taxonomy Extension Definition Linkbase Document **
———————
*    filed herewith
**    In accordance with Regulation S-T, the XBRL-formatted interactive data files that comprise Exhibit 101 in this report on Form 10-K shall be deemed “furnished” and not “filed”.


32