MILL Q3 10Q 01.31.13

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

(Mark One)
Form 10-Q

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

For the quarterly period ended January 31, 2013
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 þ    No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes þ    No o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. The number of shares of common stock issued and outstanding as of March 5, 2013 was 43,414,694.



TABLE OF CONTENTS

 
 
 
Page
 
 
 
 
 
 
 
 
PART I
Financial Information
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART II
Other Information
 
 
 
 
 
 
 


i

Table of Contents

PART I - FINANCIAL INFORMATION
 
ITEM 1.    FINANCIAL STATEMENTS.

MILLER ENERGY RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands, except share data)

 
January 31,
2013
 
April 30,
2012
ASSETS

 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
1,492

 
$
3,971

Restricted cash
2,985

 
2,250

Accounts receivable
2,276

 
3,107

State production credits receivable
2,793

 
2,958

Inventory
2,164

 
1,835

Prepaid expenses and other
1,579

 
482

 
13,289

 
14,603

OIL AND GAS PROPERTIES, NET
490,790

 
475,802

EQUIPMENT, NET
42,028

 
33,728

OTHER ASSETS:
 
 
 
Land
542

 
542

Restricted cash, non-current
10,132

 
9,875

Deferred financing costs, net of accumulated amortization
4,945

 
1,426

Other assets
761

 
413

 
$
562,487

 
$
536,389

LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable
$
18,602

 
$
9,504

Accrued expenses
2,970

 
6,744

Short-term portion of derivative instruments
3,137

 
2,803

Current portion of long-term debt
4,500

 
24,130


29,209

 
43,181

OTHER LIABILITIES:
 
 
 
Deferred income taxes
160,768

 
167,319

Asset retirement obligation
19,219

 
18,366

Long-term portion of derivative instruments

 
7,700

Long-term debt, less current portion
37,734

 

 
246,930

 
236,566

COMMITMENTS AND CONTINGENCIES (Note 14)

 

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

 
8,818

Series C cumulative preferred stock, redemption amount of $19.9 million
16,647

 

 
 
 
 
STOCKHOLDERS' EQUITY:
 
 
 
Common stock, $0.0001 par, 500,000,000 shares authorized, 43,371,694 and 41,086,751 shares issued and outstanding, respectively
4

 
4

Additional paid-in capital
85,093

 
64,813

Retained earnings
213,813

 
226,188

 
298,910

 
291,005

 
$
562,487

 
$
536,389


See accompanying notes to the condensed consolidated financial statements.

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Table of Contents

MILLER ENERGY RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(in thousands, except share and per share data)
 
 
Three Months Ended January 31,
 
Nine Months Ended January 31,
 
2013
 
2012
 
2013
 
2012
REVENUES:
 
 
 
 
 
 
 
Oil sales
$
6,720

 
$
7,730

 
$
22,310

 
$
24,208

Natural gas sales
133

 
214

 
328

 
496

Other
1,146

 
500

 
4,433

 
1,800

 
7,999

 
8,444

 
27,071

 
26,504

OPERATING EXPENSES:
 

 
 

 
 

 
 

Oil and gas operating
4,118

 
3,770

 
12,963

 
11,941

Cost of other revenue
1,051

 
296

 
4,084

 
669

General and administrative
5,518

 
6,729

 
17,056

 
20,450

Exploration expense
187

 
395

 
244

 
574

Depreciation, depletion and amortization
3,341

 
2,826

 
9,528

 
10,437

Accretion of asset retirement obligation
284

 
268

 
853

 
805

Other operating (income) expense, net

 
255

 
(65
)
 
(642
)
 
14,499

 
14,539

 
44,663

 
44,234

OPERATING LOSS
(6,500
)
 
(6,095
)
 
(17,592
)
 
(17,730
)
OTHER INCOME (EXPENSE):
 

 
 

 
 

 
 

Interest expense, net
(1,117
)
 
(813
)
 
(2,785
)
 
(2,000
)
Gain (loss) on derivatives, net
(1,681
)
 
(3,669
)
 
5,215

 
1,593

Other income (expense), net
25

 
(8
)
 
(350
)
 
52

 
(2,773
)
 
(4,490
)
 
2,080

 
(355
)
LOSS BEFORE INCOME TAXES
(9,273
)
 
(10,585
)
 
(15,512
)
 
(18,085
)
Income tax benefit
3,931

 
4,075

 
6,551

 
6,908

NET LOSS
(5,342
)
 
(6,510
)
 
(8,961
)
 
(11,177
)
Accretion of preferred stock
(145
)
 

 
(2,605
)
 

Series C accumulated dividends
(677
)
 

 
(809
)
 

NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS
$
(6,164
)
 
$
(6,510
)
 
$
(12,375
)
 
$
(11,177
)
 
 
 
 
 
 
 
 
LOSS PER COMMON SHARE:
 

 
 

 
 

 
 

Basic
$
(0.14
)
 
$
(0.16
)
 
$
(0.29
)
 
$
(0.27
)
Diluted
$
(0.14
)
 
$
(0.16
)
 
$
(0.29
)
 
$
(0.27
)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
 

 
 

 
 

 
 

Basic
43,367,781

 
40,937,023

 
42,445,223

 
40,728,374

Diluted
43,367,781

 
40,937,023

 
42,445,223

 
40,728,374


See accompanying notes to the condensed consolidated financial statements.

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Table of Contents

MILLER ENERGY RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Unaudited)
(in thousands, except share data)


 
Common Stock
 
Additional Paid-in Capital
 
Retained Earnings
 
Total
 
Shares
 
Amount
 
 
 
Balance at April 30, 2011
39,880,251

 
$
4

 
$
49,013

 
$
245,725

 
$
294,742

Net loss

 

 

 
(11,177
)
 
(11,177
)
Issuance of equity for services
130,000

 

 
1,221

 

 
1,221

Issuance of equity for compensation
107,500

 

 
9,630

 

 
9,630

Exercise of equity rights
869,000

 

 
1,283

 

 
1,283

Balance at January 31, 2012
40,986,751

 
4

 
61,147

 
234,548

 
295,699

Net loss

 

 

 
(7,513
)
 
(7,513
)
Accretion of preferred stock

 

 

 
(847
)
 
(847
)
Issuance of equity for services

 

 
280

 

 
280

Issuance of equity for compensation

 

 
3,286

 

 
3,286

Exercise of equity rights
100,000

 

 
100

 

 
100

Balance at April 30, 2012
41,086,751

 
4

 
64,813

 
226,188

 
291,005

Net loss

 

 

 
(8,961
)
 
(8,961
)
Series C accumulated dividends

 

 

 
(809
)
 
(809
)
Accretion of preferred stock

 

 

 
(2,605
)
 
(2,605
)
Issuance of equity for services
351,477

 

 
2,047

 

 
2,047

Issuance of equity for compensation
454,665

 

 
8,710

 

 
8,710

Other equity issuances
192,800

 

 
1,341

 

 
1,341

Exercise of equity rights
1,286,001

 

 
3,832

 

 
3,832

Preferred stock redemption

 

 
2,510

 

 
2,510

Modification of warrants

 

 
1,840

 

 
1,840

Balance at January 31, 2013
43,371,694

 
$
4

 
$
85,093

 
$
213,813

 
$
298,910



See accompanying notes to the condensed consolidated financial statements.


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Table of Contents

MILLER ENERGY RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 (in thousands)

 
Nine Months Ended January 31,
 
2013
 
2012
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net loss
$
(8,961
)
 
$
(11,177
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 

 
 

Depreciation, depletion and amortization
9,528

 
10,437

Amortization of deferred financing fees
549

 
887

Expense from issuance of equity
7,630

 
10,506

Deferred income taxes
(6,551
)
 
(6,908
)
Loss on derivative instruments, net
(2,939
)
 
(786
)
Accretion of asset retirement obligation
853

 
805

Changes in operating assets and liabilities:
 

 
 

Receivables
996

 
1,472

Inventory
(467
)
 
(90
)
Prepaid expenses and other assets
(1,445
)
 
(744
)
Accounts payable and accrued expenses
6,944

 
4,933

NET CASH PROVIDED BY OPERATING ACTIVITIES
6,137

 
9,335

 
 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES:
 

 
 

Capital expenditures for oil and gas properties
(23,213
)
 
(9,472
)
Purchase of equipment and improvements
(9,606
)
 
(24,388
)
Proceeds from sale of equipment
2,000

 

NET CASH USED IN INVESTING ACTIVITIES
(30,819
)
 
(33,860
)
 
 
 
 
CASH FLOWS FROM FINANCING ACTIVITIES:
 

 
 

Cash dividends
(285
)
 

Payments on debt
(24,130
)
 

Debt acquisition costs
(3,854
)
 
(2,140
)
Proceeds from borrowings
40,000

 
26,895

Redemption of preferred stock
(11,240
)
 

Issuance of preferred stock
20,448

 

Equity issuance costs
(1,576
)
 

Exercise of equity rights
3,832

 
1,283

Restricted cash
(992
)
 
57

NET CASH PROVIDED BY FINANCING ACTIVITIES
22,203

 
26,095

NET CHANGE IN CASH AND CASH EQUIVALENTS
(2,479
)
 
1,570

 
 
 
 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
3,971

 
1,559

CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
1,492

 
$
3,129

SUPPLEMENTARY CASH FLOW DATA:
 
 
 
Cash paid for interest
$
8,895

 
$
1,366


See accompanying notes to the condensed consolidated financial statements.

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Table of Contents

MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(in thousands of U.S. dollars, except share and per share data)

1.    ORGANIZATION AND BASIS OF PRESENTATION

Overview
Unless specifically set forth to the contrary, when used in this report, the terms "Miller Energy Resources, Inc.," the "Company," "we," "us," "ours," "MER," "Miller," and similar terms refer to our Tennessee corporation Miller Energy Resources, Inc., formerly known as Miller Petroleum, Inc., and our subsidiaries, Miller Rig & Equipment, LLC, Miller Drilling TN, LLC and Miller Energy Services, LLC, East Tennessee Consultants, Inc., East Tennessee Consultants II, LLC, Miller Energy GP, LLC, and Cook Inlet Energy, LLC ("CIE"), collectively.
We are an independent exploration and production company that utilizes seismic data and other technologies for the geophysical exploration, development and production of oil and natural gas wells in the Cook Inlet Basin of southcentral Alaska and the Appalachian region of eastern Tennessee. The accounting policies used by us and our subsidiaries reflect industry practices and conform to U.S. generally accepted accounting principles ("GAAP"). Significant policies are discussed below.
Basis of Presentation
The accompanying condensed consolidated financial statements are presented in accordance with GAAP and, in the opinion of management, include all adjustments (consisting only of normal recurring adjustments) necessary for a fair statement of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted under Securities and Exchange Commission ("SEC") rules and regulations. The results reported in these condensed consolidated financial statements are not necessarily indicative of the financial position or operating results that may be expected for the entire year.
The financial information included herein should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto included in Item 8 of Part II of the Company's Annual Report on Form 10-K for the year ended April 30, 2012, which was filed with the SEC on July 16, 2012, amended on August 28, 2012 and further amended on September 6, 2012. Certain amounts in the condensed consolidated financial statements and notes thereto have been reclassified to conform to current period presentation.
Principles of Consolidation
The accompanying condensed consolidated financial statements include our consolidated accounts, including the accounts of the Company, after elimination of intercompany balances and transactions. The condensed consolidated financial statements also include the accounts of all investments in which we, either through direct or indirect ownership, have more than a 50% interest or significant influence over the management of those entities.

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.
Restricted Cash
As of January 31, 2013 and April 30, 2012, current restricted cash includes $605 and $2,045 of cash temporarily held in an account that is controlled by our lender. Current restricted cash balances include amounts held in escrow to secure company related credit cards. Non-current restricted cash balances include amounts held in escrow to provide for the future plugging and abandonment of wells, including the possible dismantling of our off-shore platform, and general liability bonds.
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 condensed consolidated balance sheets.


5

Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(in thousands of U.S. dollars, except share and per share data)


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 was recorded at the estimated fair value of $250, and is being amortized over the life of the guarantee. It is included in accrued expenses on our condensed consolidated balance sheet as of January 31, 2013. 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 January 31, 2013.
Income (Loss) Per Share
We determine basic income (loss) per share and diluted income (loss) per share in accordance with the provisions of ASC 260, “Earnings Per Share.” Basic income (loss) per share excludes dilution and is computed by dividing earnings available to common stockholders by the weighted-average number of common shares outstanding for the period. The calculation of diluted earnings (loss) per share is similar to that of basic earnings per share, except that the denominator is increased, if net income is positive, to include the number of additional common shares that would have been outstanding if all potentially dilutive common shares, such as those issuable upon the exercise of stock options and warrants, had been exercised. We compute the numerator for basic income (loss) by subtracting accretion of preferred stock and cumulative preferred stock dividends from net income (loss) to arrive at net income (loss) attributable to common stockholders. Preferred stock dividends include dividends declared on preferred stock (regardless of whether the dividends have been paid) and dividends accumulated for the period on cumulative preferred stock (regardless of whether the dividends have been declared).
New Accounting Pronouncements Issued But Not Yet Adopted
In December 2011, the FASB issued Accounting Standards Update ("ASU") 2011-11, "Disclosures about Offsetting Assets and Liabilities," which increases disclosures about offsetting assets and liabilities. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards ("IFRS") related to the offsetting of financial instruments. The existing GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance in ASU 2011-11 is effective for annual and interim reporting periods beginning on or after January 1, 2013. The disclosures should be applied retrospectively for all prior periods presented. We have evaluated the new pronouncement and have determined that there is no material impact to our condensed consolidated financial statements.
There are no other recently issued accounting pronouncements that are expected to have a material impact on our financial condition, results of operations or cash flows.

3.    MAJOR CUSTOMERS AND CONCENTRATIONS OF CREDIT RISK

For the three and nine months ended January 31, 2013, Tesoro Corporation accounted for $6,343, or 79%, and $21,153, or 78%, of our consolidated total revenues, respectively. Tesoro Corporation also accounted for $62, or 3%, and $2,581, or 83%, of our accounts receivable as of January 31, 2013 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 and nine months ended January 31, 2013 and 2012.
We maintain our cash and cash equivalents (including restricted cash), which at times may exceed federally insured amounts, in highly rated financial institutions. As of January 31, 2013, we held $3,182 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, Chief Executive Officer ("CEO") of CIE and member of our Board of Directors. The audit committee of our Board of Directors determined that the amounts paid

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Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(in thousands of U.S. dollars, except share and per share data)


by us for the services performed were fair to and in the best interests of the Company. For the three and nine months ended January 31, 2013, we recorded expenses of $276 and $867, respectively, for services rendered by H&H Industrial, Inc. and $170 and $510 for the same periods in the prior year.
From time to time the Company provides support and services to Mr. Gettelfinger (and family) and Mr. Miller, members of the Board of Directors, and Mr. Boruff, our CEO. As of January 31, 2013 and April 30, 2012, Mr. Gettelfinger owed us $12 and $17, respectively. As of January 31, 2013 and April 30, 2012, Mr. Miller owed us $270 and $0, respectively As of January 31, 2013 and April 30, 2012, Mr. Boruff owed us $26 and $0, 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 Financial Industry Regulatory Authority ("FINRA"). Mr. Boruff, our 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 Miller Energy Income ("MEI") offering. The terms of the agreement 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 contained customary indemnification, non-circumvention and confidentiality clauses. For the three and nine months ended January 31, 2013, we recorded expenses related to The Dimirak Companies and their affiliates of ($3) and $49, respectively. For the three and nine months ended January 31, 2012, we recorded expenses related to The Dimirak Companies and their affiliates of $27 and $63, respectively. Effective July 24, 2012, Mr. Boruff sold his interest in Dimirak Securities Corporation and we terminated our agreements with it.
 
5.    OIL AND GAS PROPERTIES AND EQUIPMENT
 
Oil and gas properties (successful efforts method) are summarized as follows:
 
January 31,
2013
 
April 30,
2012
Property costs
 
 
 
Proved property
$
342,824

 
$
321,066

Unproved property
183,035

 
182,704

Total property costs
525,859

 
503,770

Less: Accumulated depletion
(35,069
)
 
(27,968
)
Oil and gas properties, net
$
490,790

 
$
475,802


As of January 31, 2013, we have capitalized $4,423 related to the cost incurred to repair and restore production of the RU-1 well.  We currently anticipate that the cost incurred will result in the addition of incremental proved reserves, which is necessary in order for these costs to remain capitalized.  If we determine that proved reserves did not increase as a result of the cost incurred on the RU-1 well, such costs will be released from work in progress and charged to expense at the time that determination is made.  


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MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(in thousands of U.S. dollars, except share and per share data)


Equipment is summarized as follows:
 
January 31,
2013
 
April 30,
2012
Machinery and equipment
$
6,605

 
$
5,595

Vehicles
1,855

 
1,689

Aircraft
460

 
460

Buildings
2,725

 
2,683

Office equipment
671

 
533

Leasehold improvements
463

 
423

Drilling rigs
30,912

 
3,714

Construction in progress
3,567

 
21,589

 
47,258

 
36,686

Less: Accumulated depreciation
(5,230
)
 
(2,958
)
Equipment, net
$
42,028

 
$
33,728


Depreciation, depletion and amortization consisted of the following:
 
For the Nine Months Ended January 31,
 
2013
 
2012
Depletion of oil and gas related assets
$
7,240

 
$
9,913

Depreciation and amortization of equipment
2,288

 
524

Total
$
9,528

 
$
10,437


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 January 31, 2013, we had the following open crude oil derivative positions:
 
 
Fixed - Price Swaps
Production Period:
 
Bbls
 
Weighted Average Fixed Price
2013
 
53,400

 
$
95.30

2014
 
147,000

 
95.30



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MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(in thousands of U.S. dollars, except share and per share data)


Warrant Derivatives
Series A Cumulative Preferred Stock. In April 2012, purchasers of our Series A Cumulative Preferred Stock (the "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 mark-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 was required if, at any time after issuance, we issue warrants at an exercise price lower than $5.28.
On September 21, 2012, the Company entered into a Special Warrant Exercise Agreement with warrant holders, pursuant to which, warrant holders agreed to exercise 586,001 warrants immediately for $4.00 per share and waived their right to a cashless exercise.  In addition, 42,857 warrants were cancelled in exchange for a settlement payment of $75.  These modifications resulted in a loss of $210, which is included in other income (expense), net on our consolidated statement of operations for the nine months ended January 31, 2013. 
The term for the remaining 138,197 warrants outstanding was extended for one year in exchange for the removal of the exercise price reset provision.  The mark-to-market adjustment from May 1, 2012 to September 21, 2012 was recorded to gain (loss) on derivatives, net, and the remaining liability was reclassified to additional paid-in capital.

Fair Value Measurements
As of January 31, 2013 and April 30, 2012, the fair market value of our derivative liabilities is as follows:
 
January 31,
2013
 
April 30,
2012
Current liabilities:
 
 
 
Commodity derivatives
$
3,137

 
$
2,803

Current portion of derivative instruments
3,137

 
2,803

Long-term liabilities:
 
 
 
Commodity derivatives

 
2,551

Warrant derivatives

 
5,149

Long-term portion of derivative instruments

 
7,700

Total derivative liability
$
3,137

 
$
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 Standard & Poor's ("S&P") default rating for small, independent exploration and production companies to assess the impact of non-performance credit risk when evaluating our net obligations to the counterparty. As of January 31, 2013 and April 30, 2012, the effect of non-performance risk on our commodity derivatives was negligible.

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MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(in thousands of U.S. dollars, except share and per share data)


Warrant Derivatives
Prior to the September 21, 2012 modification described above, certain of our warrants contained an exercise price reset provision and were considered freestanding derivative instruments which required liability classification 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 April 30, 2012, the warrants had an aggregate fair value of and $2,953. On June 29, 2012, the exercise price of the warrants became fixed and had a fair value of $2,510 which was reclassified to additional paid-in capital.
Warrants Issued in Connection with Other Equity Transactions. At April 30, 2012, we had 767,055 warrants outstanding that were issued in connection with our March 26, 2010 equity transaction. These warrants contained 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 were considered freestanding derivative instruments and were classified as liabilities with fair value measured on a recurring basis in accordance with GAAP. On September 21, 2012, the exercise price reset provision was eliminated for the remaining warrants that were not exercised or canceled pursuant to the Special Warrant Exercise Agreement. We utilized the Black-Scholes model to determine fair value at April 30, 2012 with the following weighted average assumptions: risk-free rate of 0.4%, an expected term of 2.90 years, expected volatility of 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 January 31, 2013 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 January 31, 2013
Level 1
 
Level 2
 
Level 3
Commodity derivative liability
$

 
$
3,137

 
$

Total
$

 
$
3,137

 
$

At April 30, 2012
 

 
 

 
 

Warrant derivative liability
$

 
$
5,354

 
$

Commodity derivative liability

 
5,149

 

Total
$

 
$
10,503

 
$


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MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(in thousands of U.S. dollars, except share and per share data)



Derivative Activities Reflected on Condensed Consolidated Statements of Operations
Changes in the fair value of our derivative liabilities are recorded in gain (loss) on derivatives, net on our condensed consolidated statements of operations.
 
For the Three Months Ended January 31,
 
For the Nine Months Ended January 31,
 
2013
 
2012
 
2013
 
2012
Realized gain (loss) recognized in earnings
$
(822
)
 
$
(71
)
 
$
2,276

 
$
807

Unrealized gain (loss) recognized in earnings
(859
)
 
(3,598
)
 
2,939

 
786

Gain (loss) on derivatives, net
$
(1,681
)
 
$
(3,669
)
 
$
5,215

 
$
1,593


On June 6, 2012, the Company terminated the commodity derivative contracts in place on 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 $2,007 in realized losses during the nine months ended January 31, 2013 to arrive at the realized net gain of $2,276.

7.    DEBT

As of January 31, 2013 and April 30, 2012, we had the following debt obligations reflected at their respective carrying values on our condensed consolidated balance sheets:
 
January 31,
2013
 
April 30,
2012
Guggenheim senior secured Credit Facility
$

 
$
24,130

Apollo senior secured Credit Facility
40,000

 

Series B Preferred Stock
2,234

 

Total debt obligations
$
42,234

 
$
24,130


Apollo Senior Secured Credit Facility
On June 29, 2012 (the "Closing Date"), the Company entered into a Loan Agreement (the "Loan Agreement") with Apollo Investment Corporation ("Apollo"), as administrative agent and sole initial lender.
The Loan Agreement provides for a $100,000 credit facility (the "Apollo Credit Facility") with an initial borrowing base of $55,000. Of that initial $55,000, $40,000 was made available to, and was drawn by, Miller on the Closing Date. On February 7, 2013, we borrowed an additional $5,000 (the "February Loan") under the Apollo Credit Facility. The remaining $10,000 of the initial borrowing base is currently available to be drawn, but has not been requested by us at this time. Pursuant to a Waiver and Amendment No. 4 to the Loan Agreement, dated February 7, 2013 (the "February Amendment"), we have agreed that unless we request a drawdown of the remaining $10,000 remaining under the borrowing base on or before June 29, 2013, we will pay an "unused" fee of $2,000. The Apollo Credit Facility matures on June 29, 2017 and is secured by substantially all the assets of Miller and its' consolidated subsidiaries (other than MEI), which subsidiaries also guarantee the loans. Amounts outstanding under the Apollo Credit Facility bear interest at a rate of 18% per annum, with interest payable on the last day of each of Miller's fiscal quarters. Miller will be required to pay the outstanding balance of the loan in full on the maturity date; however, beginning with the fiscal quarter ending on July 31, 2013, if requested by Apollo (at the direction of lenders holding a majority of the commitments under the Loan Agreement), Miller would be required to repay up to $1,500 in principal quarterly. Such payments of principal would be made, together with any interest due on such date, on the last day of Miller's fiscal quarter.
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. As previously reported by the Company, the financial and production covenants in the Apollo Credit Facility were amended on September 25, 2012 (the "September Amendment"), to delay the date on which compliance with those covenants would be measured from October 31, 2012 to January

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MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(in thousands of U.S. dollars, except share and per share data)


31, 2013, and to adjust the covenant levels to be met on that date. The financial and production covenants were further amended in the February Amendment to delay the date on which compliance with those covenants would be measured from January 31, 2013 to April 30, 2013, and to adjust the covenant levels to be met on the testing dates, as well as to include our Tennessee production in the minimum production covenant.
On the Closing Date, we paid Apollo a non-refundable structuring fee of $2,750, payable for the account of the lenders, and we have agreed to pay an additional 5% fee to Apollo for the benefit of the lenders on the amount of every additional borrowing over and above the $55,000 amount of the borrowing base at the date of closing. In addition, we paid Apollo a supplemental fee of $500 on the Closing Date, and have agreed to pay another $500 fee on each anniversary of the Closing Date so long as the Loan Agreement remains in effect.
Additional compensation was due to Bristol Capital, LLC, a consultant to us, in connection with the closing of the Loan Agreement. This fee was paid by issuing 312,500 shares of the Company's restricted common stock.
The Company has used a portion of the initial $40,000 loan made available under the Apollo Credit Facility to repay in full the amounts outstanding under the Guggenheim Senior Secured Credit Facility ("Guggenheim Credit Facility") of approximately $26,200. The remaining $13,800 was used to (i) redeem the Company's outstanding Series A Preferred Stock; (ii) pay certain outstanding payables of the Company; and (iii) pay transaction costs associated with the closing of the Apollo Credit Facility, such as attorneys' fees. The February Loan, in the net cash amount of $4,800, was used to pay outstanding operational and general and administrative expenses otherwise permitted under the Apollo Credit Facility.
The fair value of the January 31, 2013 outstanding balance of the Apollo Credit Facility was $41,361 as calculated using the discounted cash flows method.

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 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.

Series B Preferred Stock
On September 24, 2012, we sold 25,750 shares of our Series B Cumulative Redeemable Preferred Stock (the "Series B Preferred Stock") to 10 accredited investors and issued those investors warrants to purchase 128,750 shares of common stock in a private offering exempt from registration under the Securities Act of 1933, as amended. We received gross proceeds of $2,575. We paid issuance costs of $167, which have been capitalized and are being amortized over the term of the instrument. The outstanding Series B Preferred Stock is classified as long-term debt, in accordance with ASC 480, "Distinguishing Liabilities from Equity." As of January 31, 2013, the fair value of Series B Preferred Stock is $2,587.
The designations, rights and preferences of the Series B Preferred Stock, include:
a stated value of one hundred dollars per share and a liquidation preference equal to the stated value;
the holders are not entitled to any voting rights and the shares of Series B Preferred Stock are not convertible into any other security;
the holders are entitled to receive annual cumulative dividends at the rate of 12% per annum, payable in arrears semi-annually, beginning on March 1, 2013;
dividends will be paid in cash on each relevant dividend date provided that (i) we are in compliance with certain financial covenants (designated the "Capital Covenants") under the Apollo Credit Facility, with compliance to be determined as of the most recent reporting date and, on a pro forma basis, on the dividend date, and (ii) no "Default" or "Event of Default" (as defined in the Apollo Credit Facility) has occurred or is continuing on the dividend date;
the shares may not be redeemed until 30 days after "Security Termination" (as defined in the Apollo Credit Facility), but otherwise may be redeemed at any time by the Company, with a required redemption on the fifth anniversary of issuance or, if later, on the 30th day after Security Termination.


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MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(in thousands of U.S. dollars, except share and per share data)


Debt Issue Costs
As of January 31, 2013, our unamortized debt issue costs were $4,945, which relate to the Apollo Credit Facility and the Series B Preferred Stock. These costs are being amortized over the term of the respective debt instruments.
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
As described above in connection with the September Amendment and the February Amendment, the date on which compliance with the financial and production covenants will be measured has been changed to April 30, 2013 under the Apollo Credit Facility. Based on current production levels, we would not be in compliance with these covenants.

8.    ASSET RETIREMENT OBLIGATIONS

The following table presents changes to the Company's asset retirement obligation liability for the nine months ended January 31, 2013 and 2012:
 
For the Nine Months Ended January 31,
 
2013
 
2012
Asset retirement obligation, as of April 30
$
18,366

 
$
17,294

Accretion expense
853

 
805

Asset retirement obligation, as of January 31
$
19,219

 
$
18,099

 
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 January 31, 2013 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 share-based compensation plans authorizing 3,000,000 and 8,250,000 shares of common stock under each plan, respectively. The share-based compensation plans allow us to offer our employees, officers, directors and others an opportunity to acquire a proprietary interest in the Company and enable us to attract, retain, motivate and reward such persons in order to promote the success of the Company. Each plan authorizes the issuance of incentive stock options, nonqualified stock options and restricted stock.  All awards issued under the share-based compensation plans must be approved by our Compensation Committee. At January 31, 2013 and April 30, 2012, there were 247,828 and 1,250,000 additional shares available under the compensation plans. 
Included in general and administrative expenses within the condensed consolidated statements of operations is stock-based compensation expenses for the three months ended January 31, 2013 and 2012 of approximately $2,549 and $3,421, respectively, and for the nine months ended January 31, 2013 and 2012 of approximately $7,077 and $9,396, respectively. We also recognized non-employee expenses related to warrants issued for the three months ended January 31, 2013 and 2012 of approximately $103 and $611, respectively, and for the nine months ended January 31, 2013 and 2012 of approximately $290 and $1,110, respectively.

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MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(in thousands of U.S. dollars, except share and per share data)


The following table summarizes our stock-based compensation activities for the nine months ended January 31, 2013 and 2012:
 
For the Nine Months Ended January 31, 2013
 
For the Nine Months Ended January 31, 2012
 
Number of Options and Warrants
 
Weighted Average Exercise Price
 
Number of Options and Warrants
 
Weighted Average Exercise Price
Beginning balance at April 30
15,405,955

 
$
4.60

 
11,079,955

 
$
3.98

Granted
928,750

 
4.36

 
4,345,000

 
5.16

Exercised
(1,286,001
)
 
2.98

 
(869,000
)
 
1.48

Canceled
(482,857
)
 
5.09

 
(50,000
)
 
5.94

Ending balance
14,565,847

 
4.63

 
14,505,955

 
4.53

Options exercisable at January 31
9,163,073

 
$
4.13

 
6,543,456

 
$
3.23


The following table summarizes our stock options and warrants outstanding, including exercisable shares at January 31, 2013:
Options and Warrants Outstanding
 
Options and Warrants
Exercisable
Range of Exercise Price
 
Number Outstanding
 
Weighted Average Remaining Contractual Life (in years)
 
Weighted Average Exercise Price
 
Number Exercisable
 
Weighted Average Exercise Price
$0.01 to $1.82
 
1,818,900

 
1.8
 
$
0.75

 
1,818,900

 
$
0.75

$2.00 to $4.99
 
2,445,000

 
4.8
 
2.99

 
1,700,558

 
2.56

$5.25 to $5.53
 
4,166,947

 
3.6
 
5.32

 
2,308,613

 
5.31

$5.89 to $5.94
 
3,510,000

 
7.6
 
5.92

 
2,001,668

 
5.93

$6.00 to $6.94
 
2,625,000

 
2.9
 
6.03

 
1,333,334

 
6.04

 
 
14,565,847

 
4.4
 
$
4.63

 
9,163,073

 
$
4.13


10.    STOCKHOLDERS' EQUITY
 
At January 31, 2013, we had 43,371,694 shares of common stock outstanding. We issued 2,284,943 shares during the nine months ended January 31, 2013, of which 351,477 shares were issued for services, 454,665 shares were issued to employees for compensation, 1,286,001 shares were related to the exercise of equity rights, and 192,800 shares for other equity issuances.
On September 28, 2012, we sold 685,000 shares of the Company's newly designated 10.75% Series C Cumulative Redeemable Preferred Stock (the "Series C Preferred Stock") pursuant to the Company's shelf registration statement on Form S-3, which became effective on September 28, 2012.  The shares were offered to the public at $23.00 per share for gross proceeds of $15,755.  We incurred issuance costs of $1,335, yielding net proceeds of $14,420.  Subsequent to the initial offering on September 28, 2012 through January 31, 2013, we sold an additional 95,048 shares of Series C Preferred Stock to the public with prices ranging from $22.00 per share to $23.00 per share. We received gross proceeds of $2,118 and incurred issuance costs of $74, yielding net proceeds of $2,044. The Series C Preferred Stock is classified as temporary equity in accordance with ASC 480 and is being accreted to redemption value through the earliest repayment date of November 1, 2017, which resulted in accretion of $112 and $145 during the three and nine months ended January 31, 2013, respectively. The fair value of the Series C Preferred Stock was $17,723 based on the closing price at January 31, 2013.
The holders are entitled to receive a 10.75% per annum cumulative quarterly dividend, on March 1, June 1, September 1, and December 1, payable in cash on each dividend date unless the Company is prohibited by making such payment pursuant to the terms of any agreement of the Company (including any other class or series of equity securities or any agreement related to indebtedness);
The dividend may increase to a penalty rate of 12.75% if we fail to (A) pay dividends for four or more quarterly dividend periods, whether or not consecutive, or (B) maintain the listing of our Series C Preferred Stock on a national securities exchange (the events listed in clauses (A) and (B) being "Penalty Events");

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MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(in thousands of U.S. dollars, except share and per share data)


There is no mandatory redemption or stated maturity with respect to the Series C Preferred Stock, and it is not redeemable prior to November 1, 2017 unless: (A) there is a change in control and redemption occurs pursuant to a special right of redemption related to that change in control or (B) the Closing Bid Price of our common stock has equaled or exceeded the conversion price initially set at $10.00 per share by 150% for at least 20 days trading days in any 30 consecutive trading day period (a "Market Trigger");
The redemption price is $25.00 per share plus any accrued and unpaid dividends;
Liquidation preference is $25.00 per share plus any accrued and unpaid dividends;
The Series C Preferred Stock is senior to all our other securities except our Series B Redeemable Preferred Stock, which is senior to the Series C Preferred Stock;
There is a general conversion right with respect to the Series C Preferred Stock with an initial conversion price of $10.00 per share, a special conversion right upon a change in control, and a market trigger conversion at our option in the event of a Market Trigger;
The Series C Preferred Stock has been listed on the NYSE and is registered under our universal shelf; and
Holders of the Series C Preferred Stock have no voting rights, except: 1) as otherwise required by law; 2) with respect to any proposal to (A) create, authorize or increase the authorized or issued amount of any class or series of our equity securities which rank senior to the Series C Preferred Stock or (B) amend, alter or repeal any provision of our charter, as amended, in a manner which materially and adversely affects any right, preference, privilege or voting power of the holders of the Series C Preferred Stock; and 3) the holders of the Series C Preferred Stock will have the right to elect two directors to our board of directors upon the occurrence of a Penalty Event.

At January 31, 2012, we had 40,986,751 shares of common stock outstanding. We issued 1,106,500 shares during the nine months ended January 31, 2012, of which 130,000 shares were issued for services, 107,500 shares were issued to employees for compensation, and 869,000 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 third interim 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 January 31, 2013 and January 31, 2012 by applying the actual effective tax rate to the year-to-date income (loss), as permitted by GAAP. The effective tax rate for the year-to-date period ended January 31, 2013 is a benefit of (42.23%). The principal differences in our effective tax rate (benefit) for this period and the federal statutory rate of 35% are state income taxes, a favorable permanent difference related to mark-to-market accounting for Company warrants, and and unfavorable permanent difference related to incentive stock options.  No valuation allowance was deemed necessary in order to fully benefit the Company's year-to-date loss due to the presence of sufficient future taxable income related to the excess of book carrying value in oil and gas properties over their corresponding tax bases.  No other sources of taxable income were considered by Management in reaching this conclusion. No cash payments of income taxes were made during the year-to-date period ended January 31, 2013, and no significant payments are expected during the succeeding 12 months.
 

15

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MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(in thousands of U.S. dollars, except share and per share data)


12.    ALASKA PRODUCTION TAX CREDITS

Upon qualifying, the Company can apply for several credits under Alaska Statutes 43.55.023 and 43.55.025:
43.55.023(a)(1) Qualified capital expenditure credit (20%)
43.55.023(l)(1) Well lease expenditure credit (effective June 30, 2010) (40%)
43.55.023(a)(2) Qualified capital exploration expenditure credit (20%)
43.55.023(l)(2) Well lease exploration expenditure credit (effective June 30, 2010) (40%)
43.55.023(b) Carried-forward annual loss credit (25%)
43.55.025 Seismic exploration credits (40%)

We recognize a receivable when the amount of the credit is reasonably estimable and receipt is probable. For expenditure and exploration based credits, the credit is recorded as a reduction to the related assets. For carried-forward annual loss credits, the credit is recorded as a reduction to the Alaska production tax. To the extent the credit amount exceeds the Alaska production tax, the credit is recorded as a reduction to general and administrative expenses.
As of January 31, 2013 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 condensed consolidated balance sheets in "oil and gas properties." As of January 31, 2013 and April 30, 2012, the Company had outstanding receivables from the State of Alaska in the amount of $2,793 and $2,958, respectively.

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 the oil and gas lease owned by us is still in full force and effect. The defendant filed an Answer and Counterclaim, seeking in the Counterclaim a declaration that the oil and gas lease has expired. The parties reached a mutual settlement of this matter, effective as of November 9, 2012. Under the terms of this settlement, the related lease is still in full force and effect. An Order of Dismissal was filed on January 11, 2013, dismissing the case with full prejudice.
On May 11, 2011, the Court of Appeals of Tennessee at Knoxville returned its opinion in the case styled CNX Gas Company, LLC v. Miller Petroleum, Inc., et al.  As previously reported, CNX Gas Company, LLC ("CNX") commenced litigation on June 11, 2008 in the Chancery Court of Campbell County, State of Tennessee to enjoin us from assigning or conveying certain leases described in the Letter of Intent signed by CNX and our company on May 30, 2008, to compel us to specifically perform the assignments as described in the Letter of Intent, and for damages. After the trial court granted the motion for summary judgment of the company and other party defendants and dismissed the case, finding that there were no genuine issues of material fact and that we were entitled to judgment as a matter of law, CNX appealed.  All parties filed briefs and the Court of Appeals heard oral arguments on May 18, 2010.  In its May 11, 2011 opinion, the Court of Appeals reversed the trial court's grant of summary judgment in favor of our company and the other party defendants, and remanded the case back to the trial court for further proceedings.  On July 28, 2011, the case was dismissed without prejudice on the motion of CNX.
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 tortiously interfered with, or induced the breach of, the letter of intent between us and the Plaintiff.  We have filed our Answer and intend to vigorously defend this suit. We are presently conducting discovery, and trial is scheduled to begin on November 18, 2013. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.
On May 17, 2011, we were served with a lawsuit filed in the United States District Court for the Eastern District of Tennessee at Knoxville by Troy D. Stafford, the former Chief Financial Officer of our wholly owned subsidiary, Cook Inlet Energy, LLC.  The suit, styled Troy D. Stafford v. Miller Petroleum, Inc., Civil Action No. 3-11CV-206, claims that we terminated Mr. Stafford's employment without cause in contravention of the terms of the Purchase and Sale Agreement between us and the sellers of CIE ("PSA"), failed or refused to pay his salary, severance, percentage of purchase price, expenses or stock warrant and violated

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(in thousands of U.S. dollars, except share and per share data)


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 filed a Motion to Dismiss for lack of personal jurisdiction, but this motion was not granted by the court. We filed an Answer to the complaint in this case on October 10, 2012, and we are currently conducting discovery. Trial is set for November 4, 2013. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.
In August 2011, several purported class action lawsuits were filed against us in the United States District Court for the Eastern District of Tennessee.  The lawsuits made similar claims and have been consolidated into one case, styled In re Miller Energy Resources, Inc. Securities Litigation. The suit names us, along with several of our current and former executive officers, Scott Boruff, Paul Boyd, Ford Graham, David Hall, and Deloy Miller, as defendants. The Plaintiffs allege two causes of action against the defendants: (1) violation of Section 10(b) and Rule 10b-5 of the Exchange Act, (2) violation of Section 20(a) of the Exchange Act.  The case seeks money damages against us and the other defendants, and payment of the Plaintiffs' attorney's fees. We have filed a Motion to Dismiss the case. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.
On August 23, 2011, a derivative action was filed against us in Knox County Chancery Court.  The case is styled Marco Valdez, derivatively on behalf Miller Energy Resources, Inc. v. Deloy Miller, Scott M. Boruff, Jonathan S. Gross, Herman Gettelfinger, David Hall, Merrill A. McPeak, Charles M. Stivers, Don A. Turkleson, and David J. Voyticky, and Miller Energy Resources, Inc., nominal defendant.  The suit alleges the following causes of action: (1) Breach of Fiduciary Duty for disseminating false and misleading information; (2) Breach of Fiduciary Duty for failure to maintain internal controls; (3) Breach of Fiduciary Duty for failing to properly oversee and manage the company; (4) Unjust Enrichment; (5) Abuse of Control; Gross Mismanagement, and; (6) Waste of Corporate Assets.  The Plaintiff seeks unspecified money damages from the individual defendants, that we take certain actions with respect to our management, restitution to us, and the Plaintiff's attorney fees and costs. We have filed a Motion to Dismiss and, in the alternative, a Motion to Stay pending the outcome of the Class Action. The Plaintiff has agreed to stay this case awaiting a ruling on the plaintiff's appeal in the federal derivatives case in Lukas v. Miller Energy Resources, Inc., et al, as described in the next paragraph. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.
On August 25, 2011, and August 31, 2011, two derivative actions were filed against us and our Board of Directors and former Chief Financial Officer in the United States District Court for the Eastern District of Tennessee. These cases were consolidated into Patrick P. Lukas, derivatively on behalf Miller Energy Resources, Inc. v. Merrill A. McPeak, Scott M. Boruff, Deloy Miller, Jonathan S. Gross, Herman Gettelfinger, David Hall, Charles M. Stivers, Don A. Turkleson, and David J. Voyticky, and Miller Energy Resources, Inc., nominal defendant. As noted below, this case has been dismissed by the trial court, but that dismissal is being appealed by the plaintiffs. It contained substantially similar claims as Valdez. The suit alleged the following causes of action: (1) Breach of Fiduciary Duty for disseminating false and misleading information; (2) Breach of Fiduciary Duty for failing to properly oversee and manage the company; (3) Unjust Enrichment; (4) Abuse of Control; (5) Gross Mismanagement, and; (5) Waste of Corporate Assets.  The Plaintiffs sought unspecified money damages from the individual defendants, to have us take certain actions with respect to our management, restitution to us, and the Plaintiffs' attorney fees and costs. We filed a Motion to Dismiss, which was granted on September 21, 2012. On October 16, 2012, a notice of appeal of this dismissal was filed by the Plaintiffs with the Sixth Circuit Court of Appeals. The Plaintiffs filed their brief in support of this appeal and we are presently preparing our reply brief in answer to it. Given the current stage of the proceedings with respect to this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.
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.


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(in thousands of U.S. dollars, except share and per share data)


14.     COMMITMENTS AND CONTINGENCIES

On November 5, 2009, CIE entered into an Assignment Oversight Agreement ("AOA") with the Alaska Department of Natural Resources ("Alaska DNR") which set out certain terms under which the Alaska DNR would approve the transfer of oil and gas leases owned by the State of Alaska from Pacific Energy to CIE. This agreement remains in place following our acquisition of CIE in December 2009. Generally, the agreement requires CIE to provide the Alaska DNR with additional information and oversight authority to ensure that CIE is acting diligently to develop the oil and gas from Redoubt and West McArthur River units ("WMRU"). Under the terms of the AOA, until the Alaska DNR determines that CIE has completed certain development and operational commitments relating to the WMRU and Redoubt Units, CIE must do the following, in addition to the normal requirements under the terms of the leases:
file a quarterly summary of expenditures by oil and gas field, tied to objectives in CIE's business plan and plan of development previously presented to the Alaska DNR,
meet monthly with the Alaska DNR to provide an update on operations and progress towards meeting these objectives,
notify the Alaska DNR 10 days prior to commitment when CIE is preparing to spend funds on a purchase, project or item relating to the WMRU or Redoubt Leases of more than $5,000,
annually submit a new plan of development and plan of operations for the Alaska DNR's approval.

The AOA required CIE to demonstrate funding commitments of $5,150 to support the redevelopment of the WMRU and an estimated $31,000 to support the development of the Redoubt Unit. The Company believes it has adequately fulfilled these commitments.
On March 11, 2011, the Company entered into a Performance Bond Agreement under its AOA with the state of Alaska. Under the Performance Bond Agreement, the Company is required to post a total bond of $18,000 for the dismantling and abandonment of the properties. As agreed with the state of Alaska, the Performance Bond Agreement fulfills our commitment under the AOA to fund the full dismantlement costs with respect to our onshore and offshore assets. The Performance Bond Agreement also stipulated that $6,628 held by the state in an escrow account will be credited towards the $18,000. As a result, the Company recorded a $6,910 gain on acquisition during the year ended April 30, 2011.
The AOA also prohibits CIE from using proceeds from operation at WMRU or Redoubt for non-core oil and gas activities, or activities unrelated to WMRU or Redoubt, without the prior written approval of the Alaska DNR until the parties mutually agree that the full dismantlement obligation under the assigned leases is funded.
Failure to submit the information required by the AOA or expenditure of proceeds from WMRU or Redoubt for items or activities unrelated to core oil and gas activities at WMRU or Redoubt would constitute a default under the AOA. If the default could not be cured within 30 days, the leases would be subject to termination by the Alaska DNR.
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

 


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MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(in thousands of U.S. dollars, except share and per share data)


15.    SUBSEQUENT EVENTS

Series B Preferred Stock
On January 31, 2013, our Board of Directors declared a dividend of $5.16 per share on our Series B Preferred Stock paid on the next regularly scheduled dividend payment date of March 1, 2013, in accordance with the terms of our charter. The dividend payment is equivalent to an annualized 12% per share, based on the $100.00 per share stated liquidation preference for the Series B Preferred Stock, accruing from the date the Series B Preferred Stock was first issued on September 24, 2012 through February 28, 2013. The record date, as required in accordance with our charter, was February 15, 2013.

Series C Preferred Stock
Pursuant to our At Market Issuance Sales Agreement, dated October 12, 2012 ("ATM Agreement") with MLV & Co. LLC ("MLV"), between February 1 and March 1 of 2013, we offered and sold an additional 7,828 shares of our Series C Preferred Stock, at prices ranging from $22.00 and $23.51 per share.  The Company received $179 in gross proceeds as a result of these sales, from which MLV was paid a commission of $6. These securities are registered for sale to the public pursuant to a prospectus, dated September 19, 2012, a prospectus supplement dated October 12, 2012, a prospectus supplement dated February and the Company's registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012. 
Pursuant to an Underwriting Agreement, dated February 12, 2013, with MLV, for itself and as representative of the underwriters listed on Schedule I to that agreement, on February 13, 2013, we offered and sold an additional 625,000 shares of our Series C Preferred Stock, at a price of $22.90 per share. The Company received $14,312 in gross proceeds as a result of these sales, from which MLV was paid a commission of $987. These securities are registered for sale to the public pursuant to a prospectus, dated September 19, 2012, a prospectus supplement dated February 13, 2013, and the Company's registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012.
On January 31, 2013, our Board of Directors declared a dividend of approximately $0.67 per share on our Series C Preferred Stock paid on the next regularly scheduled dividend payment date of March 1, 2013, in accordance with the terms of our charter. The dividend payment is equivalent to an annualized 10.75% per share, based on the $25.00 per share stated liquidation preference for the Series C Preferred Stock, accruing December 2012 through February 2013. The record date, as required in accordance with our charter, was February 15, 2013.

Apollo Credit Facility Waiver and Amendment
On February 7, 2013, we entered into the February Amendment with Apollo under the Apollo Credit Facility. The fee for the Amendment was $200. The Amendment: (i) includes a request to draw an additional $5,000 under the Apollo Credit Facility and adds an unused facility fee of $2,000 that will be payable to Apollo should we fail to request a draw of the remaining $10,000 in available funds on or prior to June 29, 2013; (ii) waives any defaults or events of default which may exist as of February 7, 2013, under the interest coverage, minimum production and maximum consolidated general and administrative expense covenants; (iii) clarifies that the Series B Preferred Stock and Series C Preferred Stock are not intended to be classified as "Indebtedness" for purposes of certain covenants under the Loan Agreement, regardless of the accounting treatment of these series of stock; (iv) amends and adds certain definitions; (v) modifies certain financial and production covenants and definitions, referred to in the Loan Agreement as the "Maintenance Covenants" and "Capital Covenants," by moving the initial testing dates from January 31, 2013 to April 30, 2013 and by adjusting the covenant compliance levels on the testing dates, as well as including our Tennessee production in the minimum production covenant; (vi) allows certain filings made by Voorhees Equipment and Consulting, Inc. will be treated as permitted liens, subject to their being lifted by July 31, 2013; (vii) adds as a condition to additional loans the requirement that we raise an additional $15,000 in offerings of preferred equity; (viii) amends Section 7.24(c) and Section 7.26 of the Loan Agreement to allow us to pay for certain consolidated general and administrative expenses using certain proceeds of preferred equity in excess of that $15 million; and (ix) amends the Approved Plan of Development.


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

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

Forward Looking Statements

We have made forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company's operations, economic performance and financial condition in this report, our Annual Report on Form 10-K 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.
See the discussion in the "Risk Factors" and "Caution Concerning Forward-Looking Statements" sections of the Company's Annual Report on Form 10-K filed with the SEC on July 16, 2012, as amended. All written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements contained in the section entitled "Risk Factors" included in such Annual Report as well as other cautionary statements that are made from time to time in our other SEC filings and public communications. You should evaluate all forward-looking statements made in this report in the context of these risks and uncertainties.

Executive Overview

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

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


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

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

On June 29, 2012, we fully redeemed the outstanding Series A Preferred Stock.
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 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. Our engineering team is currently finalizing plans to deepen the Otter well #1 a minimum of 900' and a maximum of 1,300'. Another 900' will fully penetrate the Beluga formation leading us immediately into the Tyonek formation.
On August 21, 2012, we gained approval from state regulators to commence drilling with Rig 35 on the Osprey offshore platform. The rig has been used on workovers for RU-1, RU-3 and RU-7 and sidetracking a new RU-2A. With subsequent work, RU-3 and RU-4 are now fulfilling 100% of our current fuel gas demand with a combined flow rate around 1.6 mmcfd. RU-1 is producing oil again, and with subsequent work we anticipate RU-7 being back on line as an oil producer as well.
On September 21, 2012, we entered into a Special Warrant Exercise Agreement with warrant holders, pursuant to which, warrant holders agreed to exercise 586,001 warrants immediately for $4.00 per share and waived their right to a cashless exercise. We received net proceeds of $2,291 upon exercise of these warrants.
Also on September 21, 2012, we entered into a Bristol Warrant Exercise Agreement with Bristol Capital, LLC, pursuant to which, Bristol Capital, LLC, agreed to exercise 300,000 warrants immediately for $4.00 per share and for cash. We received net proceeds of $1,200 upon exercise of these warrants.
On September 24, 2012, we issued 25,750 shares of a new class of Series B Preferred Stock to 10 accredited investors in a private offering exempt from registration under the Securities Act of 1933, as amended. We received net proceeds of $2,408 in connection with this sale. For additional information refer to Note 7 - Debt, in the condensed consolidated financial statements.
On October 5, 2012, we issued 685,000 shares of a new class of Series C Preferred Stock in a public sale pursuant to a prospectus supplement date September 18, 2012 (issued under our existing S-3 registration statement, filed with the SEC as file number 333-183750). This new series of stock is listed for trading on the New York Stock Exchange under the ticker symbol MILLprC. We received net proceeds of $14,420 in connection with this sale.
On October 12, 2012, we entered into the ATM Agreement with MLV for the placement and sale of our common stock and Series C Preferred Stock in one or more "at the market" public offerings from time to time. The first sale made pursuant to this Agreement occurred on November 1, 2012, as discussed below.
On October 26, 2012, we completed a workover on the RU-1 well in the Redoubt Shoals field in Alaska. The workover involved replacing a failed electric submersible pump as well as removing other downhole obstructions. The workover was successful and we improved our access to the proved reserves.
Starting on November 1, 2012, and periodically during the quarter, we issued 95,048 shares of our Series C Preferred Stock in "at-the-market" offerings pursuant to the ATM Agreement and a prospectus supplement dated October 12, 2012 (issued under our existing S-3 registration statement, filed with the SEC as file number 333-183750). These sales were made at an average price on the date of such sale ranging from $22.00 to $23.00 per share. We received net proceeds of $2,044 in connection with these sales.


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On November 26, 2012, we applied for a right-of-permits necessary for construction of the Trans Foreland pipeline. When completed, this undersea pipeline will move our crude from the west side of the Cook Inlet where we have several producing units to the east side where the nearest refinery is located. Transporting the crude this way will be cheaper and safer than using tankers which is our only current option.
On January 11, 2013, we completed the first horizontal well in the Mississippian Lime in Tennessee, CPP-H-1. The well was drilled into the Fort Payne Formation to a true vertical depth of approximately 1,600 feet on our Cumberland Plateau Partners LLC lease in Scott County, Tennessee, and it exposed a pay section of approximately 2,300 feet in the horizontal section of the well.
On January 26, 2013, we brought a new gas well, RU-4A, into production on the Osprey platform. The workover consisted of re-completing the well to access a behind pipe gas accumulation in the Lower Tyonek gas sands at a measured depth of approximately 9,200 feet.
 
2013 Outlook
As we head into the final quarter of fiscal 2013, we believe our inventory of recompletion, workovers, and exploration and development projects offers numerous growth opportunities. Our current 2013 capital budget is $50,000 to $100,000. The majority of this budget is expected to be spent on projects in Alaska, with the remaining amount allocated to our Appalachian region. Due to the uncertainty associated with changes in commodity prices, we closely monitor our cost levels and revise our capital budgets based on changes in forecasted cash flows. This means our plan for capital expenditures may change as a result of anticipated changes in the market place. Further, our ability to fully utilize the budget will be dependent on a number of factors including, but not limited to, access to capital, weather and regulatory approval.     
We note that, although we expect to continue to sell our Series C Preferred stock in additional “at-the-market” offerings in the final quarter of fiscal 2013, we cannot guarantee that market conditions will continue to permit such sales at prices we would find acceptable. If that occurred, cash generated from those offerings would cease.        
We expect to fund our remaining 2013 capital budget with funds borrowed under the Apollo Credit Facility and proceeds received from additional sales of our Series C Preferred Stock, both in “at-the-market” offerings and in one or more underwritten “best efforts” offerings, one of which we closed on February 15, 2013, having sold an additional 625,000 shares of Series C Preferred Stock and raised $13,260 in net proceeds, after payment of the underwriters' commissions and legal expenses. 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 and nine months ended January 31, 2013 was $98.77 and $101.42, respectively, as compared to $101.05 and $91.24, respectively, for the same periods in the prior year. These results exclude the impact of commodity derivative settlements.
Production: Our net production for the three and nine months ended January 31, 2013 was 82,327 boe and 237,552 boe, respectively, as compared to 82,820 boe and 286,469 boe, respectively, for the same periods in the prior year.  The decrease in production is attributable to RU-1 and RU-7 in our Redoubt Shoals field being off-line for a portion of the periods, a normal decline curve, and fluctuation and shipping schedules.
Capital Expenditures and Drilling Results: During the three and nine months ended January 31, 2013, we spent $13,872 and $32,819, respectively, 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, which are 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 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.


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(in thousands of U.S. dollars, except share and per share data)

Results of Operations

Three Months Ended January 31, 2013 Compared to Three Months Ended January 31, 2012
Revenues
 
For the Three Months Ended January 31,
 
2013
 
Increase (Decrease)
 
2012
Oil revenues:
 
 
 
 
 
Cook Inlet
$
6,342

 
(15)%
 
$
7,422

Appalachian region
378

 
23
 
308

Total
$
6,720

 
(13)
 
$
7,730

Natural gas revenues:
 
 
 
 
 
Cook Inlet
$
13

 
(46)
 
$
24

Appalachian region
120

 
(37)
 
190

Total
$
133

 
(38)
 
$
214

Other revenues:
 
 
 
 
 
Cook Inlet
$
1,036

 
64
 
$
632

Appalachian region
110

 
183
 
(132
)
Total
1,146

 
129
 
500

Total revenues
$
7,999

 
(5)
 
$
8,444


Net Production
 
For the Three Months Ended January 31,
 
2013
 
Increase (Decrease)
 
2012
Oil volume - bbls:
 
 
 
 
 
Cook Inlet
71,700
 
(1)%
 
72,259
Appalachian region
4,062
 
4
 
3,922
Total
75,762
 
(1)
 
76,181
Natural gas volume1- mcf:
 
 
 
 
 
Cook Inlet
7,588
 
(21)
 
9,639
Appalachian region
31,799
 
5
 
30,194
Total
39,387
 
(1)
 
39,833
Total production2 - boe:
 
 
 
 
 
Cook Inlet
72,965
 
(1)
 
73,866
Appalachian region
9,362
 
5
 
8,954
Total
82,327
 
(1)
 
82,820
———————
1 
Cook Inlet natural gas volume excludes natural gas produced and used as fuel gas.
2 
These figures show production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the current price ratio between the two products.




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Pricing
Oil Prices
All of our oil production is sold at prevailing market prices, which are subject to fluctuations driven by market factors outside of our control. As volatility increases in response to the rise in global demand for oil combined with economic uncertainty, prices will continue to experience volatility at unpredictable levels. Prices received for crude oil in the third quarter of 2013 were 2% below the same period last year. For the three months ended January 31, 2013, realized oil prices averaged $98.77 per bbl, compared with $101.05 per bbl for the same period in the prior year.
Natural Gas Prices
Natural gas is subject to price variances based on local supply and demand conditions. The majority of our natural gas sales contracts are indexed to prevailing local market prices. Prices received for natural gas in the third quarter of 2013 were 34% below the same period last year. For the three months ended January 31, 2013, realized natural gas prices averaged $3.86 per mcf, compared with $5.84 per mcf for the same period in the prior year.
Oil Revenues
During the third quarter of fiscal 2013, oil revenues totaled $6,720, 13% lower than the same period in the prior year. The decline resulted from a 1% decrease in production and a 2% decrease in realized oil prices. Oil sales represented 84% of our third quarter consolidated total revenues.
Oil production decreased 419 bbls, driven by an 559 bbls decrease in the Cook Inlet region offset by an increase in the Appalachian region. The production decrease in the Cook Inlet region resulted from RU-7 in our Redoubt Shoals field being off-line for the majority of the quarter, a normal decline cure and fluctuations in shipping schedules.
Natural Gas Revenues
During the third quarter of fiscal 2013, natural gas revenues totaled $133, 38% lower than the same period in the prior year. The decline resulted from a combination of a 34% decrease in average realized prices and a 1% decrease in production. Natural gas represented 2% of our third quarter consolidated total revenues.
Other Revenues
Other revenues primarily represent revenues generated from contracts for road building, plugging, drilling, maintenance and repair of third party wells as well as rental income we receive for services and use of facilities in the Cook Inlet region. During the third quarters of fiscal 2013 and 2012, other revenues totaled $1,146, or 14%, and $500, or 6%, respectively, of our consolidated total revenues. The increase in other revenues resulted from our grind and inject facility, which allows for the processing and safe disposal of solid material that is extracted as a byproduct of drilling wells.

Cost and Expenses
The table below presents a comparison of our expenses for the three months ended January 31, 2013 and 2012:
 
For the Three Months Ended January 31,
 
 
 
 
 
2013
 
2012
 
$ Variance
 
% Variance
Oil and gas operating costs
$
4,118

 
$
3,770

 
$
348

 
9
 %
Cost of other revenues
1,051

 
296

 
755

 
255

General and administrative
5,518

 
6,729

 
(1,211
)
 
(18
)
Exploration expense
187

 
395

 
(208
)
 
(53
)
Depreciation, depletion, and amortization
3,341

 
2,826

 
515

 
18

Accretion of asset retirement obligation
284

 
268

 
16

 
6

Other operating expense, net

 
255

 
(255
)
 
(100
)
Total costs and expenses
$
14,499

 
$
14,539

 
$
(40
)
 



Oil and Gas Operating Costs
Oil and gas operating costs increased $348 from third quarter fiscal 2012, or 9%. 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. Increased drilling activities and rental of camp facilities and equipment in the Cook Inlet region require additional personnel in our camps, which increase the cost of support services.

24

Table of Contents
(in thousands of U.S. dollars, except share and per share data)

Cost of Other Revenues
Our business is primarily focused on exploration and production activities. The cost of other revenues represent costs of services to third parties as a result of excess capacity, and are derived from the direct labor costs of employees associated with these services, as well as costs associated with equipment, parts and repairs. During the third quarter of fiscal 2013, we experienced increases in cost of other revenues in the Cook Inlet region as we continued our grind and inject operations.
 
For the Three Months Ended January 31,
 
2013
 
Increase (Decrease)
 
2012
Direct labor
$
466

 
162%
 
$
178

Equipment
397

 
10,025
 
(4
)
Repairs
74

 
(39)
 
122

Insurance
36

 
 

Other
78

 
 

Total
$
1,051

 
255%
 
$
296


During third quarter fiscal of 2013, cost of other revenues increased 255% to $1,051. A substantial portion of this increase is related to direct labor and equipment costs incurred as a result of the road building contract and the grind and inject facility.
General and Administrative Expenses
General and administrative ("G&A") expenses include the costs of our employees, related benefits, professional fees, travel and other miscellaneous general and administrative expenses.
 
For the Three Months Ended January 31,
 
2013
 
Increase (Decrease)
 
2012
Salaries
$
966

 
19%
 
$
813

Professional fees
802

 
14
 
704

Travel
413

 
(21)
 
526

Employee benefits
304

 
(16)
 
362

Stock-based compensation
2,652

 
(34)
 
4,032

Other
381

 
30
 
292

Total
$
5,518

 
(18)%
 
$
6,729


G&A expenses decreased $1,211 from third quarter fiscal 2012, or 18%. Salaries increased 19% from the same period in the prior fiscal year as we significantly expanded our corporate accounting and legal staff from the prior period. Professional fees increased 14% over the same period last year due to an increase in litigation related expenses and employee recruitment during the quarter. Stock-based compensation declined 34% due to the expense associated with awards that became fully vested exceeding the expense associated with newly granted awards.
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.

25

Table of Contents
(in thousands of U.S. dollars, except share and per share data)

Depreciation, Depletion and Amortization
Depreciation, depletion and amortization (“DD&A”) expenses include the depreciation, depletion and amortization of leasehold costs and equipment. Depletion is calculated on a unit-of-production basis. Depreciation is calculated on a straight-line basis.
 
For the Three Months Ended January 31,
 
2013
 
2012
Depletion:
 
 
 
Cook Inlet region
$
2,141

 
$
2,476

Appalachian region
199

 
161

 
2,340

 
2,637

Depreciation:
 
 
 
Cook Inlet region
60

 
41

Appalachian region
941

 
148

 
1,001

 
189

Total DD&A
$
3,341

 
$
2,826


The increase in DD&A is primarily a result of Rig-34 and Rig-35 being placed in service during the period.

Other Income and Expense
The following table shows the components of other income and expense for the third quarters indicated.
 
For the Three Months Ended January 31,
 
2013
 
Increase (Decrease)
 
2012
Interest expense, net
$
(1,117
)
 
37%
 
$
(813
)
Loss on derivatives, net
(1,681
)
 
(54)
 
(3,669
)
Other income (expense), net
25

 
(413)
 
(8
)
Total
$
(2,773
)
 
(38)%
 
$
(4,490
)

Interest Expense, Net
Interest expense, net, increased $304 from the third quarter of fiscal 2012, or 37%, driven primarily by a reduction in the percentage of interest expense that was capitalized during the period.
Loss on Derivatives, Net
We experience earnings volatility as a result of not using hedge accounting to account for changes in commodity prices. As the positions of future oil production are marked-to-market, both realized and unrealized gains or losses are included on our condensed consolidated statements of operations. We do not engage in speculative trading and utilize commodity derivatives only as a mechanism to lock in future prices for a portion of our expected crude oil production.
During the third quarter of fiscal 2013, unrealized losses on commodity derivatives totaled $859, while realized losses on commodity derivatives totaled $822.

26

Table of Contents
(in thousands of U.S. dollars, except share and per share data)

Results of Operations

Nine Months Ended January 31, 2013 Compared to Nine Months Ended January 31, 2012
Revenues
 
For the Nine Months Ended January 31,
 
2013
 
Increase (Decrease)
 
2012
Oil revenues:
 
 
 
 
 
Cook Inlet
$
21,153

 
(8)%
 
$
22,871

Appalachian region
1,157

 
(13)
 
1,337

Total
$
22,310

 
(8)
 
$
24,208

Natural gas revenues:
 
 
 
 
 
Cook Inlet
$
41

 
(64)
 
$
113

Appalachian region
287

 
(25)
 
383

Total
$
328

 
(34)
 
$
496

Other revenues:
 
 
 
 
 
Cook Inlet
$
3,835

 
347
 
$
858

Appalachian region
598

 
(37)
 
942

Total
4,433

 
146
 
1,800

Total revenues
$
27,071

 
2
 
$
26,504


Net Production
 
For the Nine Months Ended January 31,
 
2013
 
Increase
(Decrease)
 
2012
Oil volume - bbls:
 
 
 
 
 
Cook Inlet
206,290
 
(18)%
 
251,562
Appalachian region
12,404
 
(1)
 
12,497
Total
218,694
 
(17)
 
264,059
Natural gas volume1- mcf:
 
 
 
 
 
Cook Inlet
14,513
 
(58)
 
34,527
Appalachian region
98,630
 
(1)
 
99,940
Total
113,143
 
(16)
 
134,467
Total production2 - boe:
 
 
 
 
 
Cook Inlet
208,709
 
(19)
 
257,316
Appalachian region
28,843
 
(1)
 
29,153
Total
237,552
 
(17)
 
286,469
———————
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.





27

Table of Contents
(in thousands of U.S. dollars, except share and per share data)

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 nine months of fiscal 2013 were 11% above the same period last year. For the nine months ended January 31, 2013, realized oil prices averaged $101.42 per bbl, compared with $91.24 per bbl for the same period in the prior year.
Natural Gas Prices
Natural gas is subject to price variances based on local supply and demand conditions. The majority of our natural gas sales contracts are indexed to prevailing local market prices. Average realized natural gas prices decreased 19% in the first nine months of fiscal 2013 compared to the same period in the prior year. For the nine months ended January 31, 2013, realized natural gas prices averaged $3.06 per mcf, compared to $3.78 per mcf for the same period in the prior year.
Oil Revenues
During the first nine months of fiscal 2013, oil revenues totaled $22,310, 8% lower than the same period in the prior year. The decline resulted from a 17% decrease in production partially offset by a 11% increase in realized oil prices. Oil sales represented 82% of our consolidated total revenues for the nine month period.
Oil production decreased 45,365 bbls, driven by a 45,272 bbls decrease in the Cook Inlet region. The production decrease in the Cook Inlet region resulted from declines in production from RU-1 and RU-7 in our Redoubt Shoals field being off-line during portions of the period, a normal decline curve and fluctuations in shipping schedules.
Natural Gas Revenues
During the first nine months of 2013, natural gas revenues totaled $328, 34% lower than the same period in the prior year. The decline resulted from a combination of a 19% decrease in average realized prices and a 16% decrease in production. Natural gas represented 1% of our consolidated total revenues for the nine month period.
Other Revenues
Other revenues primarily represent revenues generated from contracts for road building, plugging, drilling, maintenance and repair of third party wells as well as rental income we receive for services and use of facilities in the Cook Inlet region. During the first nine months of fiscal 2013 and 2012, other revenues totaled $4,433 and $1,800, respectively, which represented 16% and 7%, respectively, of our consolidated total revenues. The increase in other revenues resulted from our grind and inject facility and a road building contract in the Cook Inlet region that was completed during the period.

Cost and Expenses
The table below presents a comparison of our expenses for the nine months ended January 31, 2013 and 2012:
 
For the Nine Months Ended January 31,
 
 
 
 
 
2013
 
2012
 
$ Variance
 
% Variance
Oil and gas operating costs
$
12,963

 
$
11,941

 
$
1,022

 
9
 %
Cost of other revenues
4,084

 
669

 
3,415

 
510

General and administrative
17,056

 
20,450

 
(3,394
)
 
(17
)
Exploration expense
244

 
574

 
(330
)
 
(57
)
Depreciation, depletion, and amortization
9,528

 
10,437

 
(909
)
 
(9
)
Accretion of asset retirement obligation
853

 
805

 
48

 
6

Other operating income, net
(65
)
 
(642
)
 
577

 
(90
)
Total costs and expenses
$
44,663

 
$
44,234

 
$
429

 



Oil and Gas Operating Costs
Oil and gas operating costs increased $1,022 from the first nine months of fiscal 2012, or 9%. 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. Increased drilling activities and rental of camp facilities and equipment in the Cook Inlet region require additional personnel in our camp facilities, which increase the cost of support services.

28

Table of Contents
(in thousands of U.S. dollars, except share and per share data)

Cost of Other Revenues
Our business is primarily focused on exploration and production activities. The cost of other revenues represent costs of services to third parties as a result of excess capacity, and are derived from the direct labor costs of employees associated with these services, as well as costs associated with equipment, parts and repairs. During the third quarter of fiscal 2013, we experienced increases in the cost of other revenues in the Cook Inlet region as we continued our grind and inject operations.
 
For the Nine Months Ended January 31,
 
2013
 
Increase (Decrease)
 
2012
Direct labor
$
2,776

 
428%
 
$
526

Equipment
709

 
 

Repairs
402

 
181
 
143

Insurance
91

 
 

Other
106

 
 

Total
$
4,084

 
510%
 
$
669


During the first nine months of fiscal 2013, cost of other revenues increased 510% to $4,084. A substantial portion of this increase is related to direct labor and equipment costs associated with a road and pad building project and cost associated with the operations of our new grind and inject facility in the Cook Inlet region.
General and Administrative Expenses
G&A expenses include the costs of our employees, related benefits, professional fees, travel and other miscellaneous general and administrative expenses.
 
For the Nine Months Ended January 31,
 
2013
 
Increase (Decrease)
 
2012
Salaries
$
2,749

 
8%
 
$
2,541

Professional fees
3,617

 
12
 
3,242

Travel
1,261

 
(6)
 
1,348

Employee benefits
735

 
(49)
 
1,430

Stock-based compensation
7,367

 
(30)
 
10,506

Other
1,327

 
(4)
 
1,383

Total
$
17,056

 
(17)%
 
$
20,450


G&A expenses decreased $3,394 from the first nine months of fiscal 2012, or 17%. The decrease was significantly driven by decreases in employee benefit and stock-based compensation. Stock-based compensation declined 30% due to the expense associated with awards that became fully vested exceeding the expense associated with newly granted awards.
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.

29

Table of Contents
(in thousands of U.S. dollars, except share and per share data)

Depreciation, Depletion and Amortization
DD&A expenses include the depreciation, depletion and amortization of leasehold costs and equipment. Depletion is calculated on a unit-of-production basis. Depreciation is calculated on a straight-line basis.
 
For the Nine Months Ended January 31,
 
2013
 
2012
Depletion:
 
 
 
Cook Inlet region
$
6,601

 
$
9,337

Appalachian region
639

 
576

 
7,240

 
9,913

Depreciation:
 
 
 
Cook Inlet region
178

 
121

Appalachian region
2,110

 
403

 
2,288

 
524

Total DD&A
$
9,528

 
$
10,437


The decrease is primarily a result of declines in production due to RU-1 and RU-7 in our Redoubt Shoals field being off-line for a portion of the period and from our Alaska West MacArthur River field.

Other Income and Expense
The following table shows the components of other income and expense for the nine months ended January 31, 2013 and 2012.
 
For the Nine Months Ended January 31,
 
2013
 
Increase (Decrease)
 
2012
Interest expense, net
$
(2,785
)
 
39%
 
$
(2,000
)
Gain on derivatives, net
5,215

 
227
 
1,593

Other income (expense), net
(350
)
 
(773)
 
52

Total
$
2,080

 
(686)%
 
$
(355
)

Interest Expense, Net
Interest expense, net increased $785 from the first nine months of fiscal 2012, or 39%, driven primarily by a reduction in the percentage of interest expense that was capitalized during the period.
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 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 nine months of fiscal 2013, unrealized gains on commodity derivatives totaled $2,216, while realized gains on commodity derivatives totaled $2,276. Unrealized gains on warrant derivatives of $723 make up the remaining portion of the total net gain on derivatives of $5,215.

30

Table of Contents
(in thousands of U.S. dollars, except share and per share data)

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 "Risk Factors" in our Annual Report on Form 10-K for the year ended April 30, 2012, filed on July 16, 2012 (the "2012 Annual Report").
We may elect to utilize excess borrowing capacity, proceeds from the sales of both debt and equity in the capital markets, or proceeds from the occasional sale of nonstrategic assets to supplement our liquidity and capital resource needs.
For the three and nine months ended January 31, 2013, we experienced an operating loss and had a working capital deficit as of January 31, 2013. We anticipate that our operating expenses will continue to increase as we fully develop our assets in the Cook Inlet and Appalachian regions. Although we expect an increase in revenues from these development activities, we will continue depleting our cash resources to fund drilling and workover activities as well as other operating expenses until such time as we are able to significantly increase our revenues above costs.
We believe that the liquidity and capital resource alternatives available to us under the Apollo Credit Facility and through the public offerings of additional Series C Preferred Stock, in both “at-the-market” sales in additional underwritten offerings, 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 Credit Facility restricts our access to and control of certain bank accounts without compliance with certain provisions of the loan agreement.
These restrictions notwithstanding, absent an event of default, the Apollo Credit Facility does require that Apollo release to us funds needed to pay for approved operational activity, subject to certain limitations on the order in which we undertake new projects, and for the payment of certain permitted expenses that arise in the ordinary course of business. The release of funds for other purposes is subject to Apollo's discretion, except that, absent an event of default and so long as least half these funds are spent on projects included in our plan of development, we do have the right to use 50% of all proceeds raised from sales of equity securities in excess of $20,000 on such matters as we see fit. We reached this $20,000 threshold on October 5, 2012, the date of the initial public offering of Series C Preferred Stock. The intent of the restrictions in the Apollo Credit Facility on our ability to access cash in our accounts is to require that Company allocate available cash to high-priority projects first and to control spending that is not strongly linked to the development of our existing assets. To date, the restrictions have not impeded our ability to run the business in any way, except that we did request that Apollo agree to change the priorities of certain projects on our approved plan of development, due to the higher than anticipated demand for natural gas in the Cook Inlet region. Periodic adjustments to our approved plan of development were contemplated by the terms of the Apollo Credit Facility, and, to date, Apollo has granted our requests when made. We do not anticipate that the restrictions placed on our accounts under the Apollo Credit Facility will interfere with or require any alteration of management's overall plans in the future, subject to the need to make additional adjustments to the approved plan of development as market conditions change.
Under the February Amendment to the Apollo Credit Facility, we have agreed that, unless we make a request to draw at least the remaining $10,000 in availability under the loan agreement on or before June 29, 2013, that we would pay an unused fee of $2,000. Under the terms of the February Amendment, the conditions to making such a loan to us need not be satisfied at the time of such request, and if the lenders and administrative agent should decline to waive any such conditions, then no unused fee would be payable even though the loan would not then be made to us.
Pursuant to the September Amendment to the Apollo Credit Facility, upon each sale of our Series C Preferred Stock, we have agreed to deposit a portion of the proceeds of the sale into a separate account in an amount at least equal to the dividends scheduled to come due on our Series B Preferred Stock and our Series C Preferred Stock on or prior to September 25, 2013. As of January 31, 2013, the balance in this account was $1,861. Although we presently have the right to direct disbursements from this account without Apollo's consent, Apollo has taken a security interest in this account, and the terms of the Apollo Credit Facility state that we may only disburse funds from this account as needed to pay dividends on the Series B Preferred Stock and Series C Preferred Stock. If an event of default were to occur under the Apollo Credit Facility, Apollo would have the right to take control over this account. On December 3, 2012, we paid a cash dividend on the Series C Preferred Stock of approximately $0.41 per share in accordance with the terms of the Series C Preferred Stock as set forth in our Charter.

31

Table of Contents
(in thousands of U.S. dollars, except share and per share data)

Current restricted cash balances include amounts held in escrow to secure company related credit cards. As of January 31, 2013 and April 30, 2012, current restricted cash also includes $605 and $2,045 of cash temporarily held in an account that is controlled by our lender. Non-current restricted cash balances include amounts held in escrow to provide for the future plugging and abandonment of wells, including the possible dismantling of our off-shore platform, and general liability bonds.
Sources and Uses of Cash
The following table presents the sources and uses of our cash and cash equivalents for the periods presented:
 
For the Nine Months Ended January 31,
 
2013
 
2012
Sources of cash and cash equivalents:
 
 
 
Net cash provided by operating activities
$
6,137

 
$
9,335

Proceeds from borrowings, net of debt acquisition costs
36,146

 
24,755

Proceeds from sale of equipment
2,000

 

Exercise of equity rights
3,832

 
1,283

Issuance of preferred stock, net of issuance costs
18,872

 

Release of restricted cash

 
57

 
66,987

 
35,430

Uses of cash and cash equivalents:
 
 
 
Cash dividends
(285
)
 

Capital expenditures for oil and gas properties
(23,213
)
 
(9,472
)
Purchase of equipment and improvements
(9,606
)
 
(24,388
)
Payments on debt
(24,130
)
 

Redemption of preferred stock
(11,240
)
 

Increase in restricted cash
(992
)