10-Q 1 millq210q103113.htm FORM 10-Q MILL Q2 10Q 10.31.13

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 October 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 December 2, 2013 was 44,524,779.



TABLE OF CONTENTS

 
 
 
 
 
 
 
 
 
 
 
Page
PART I
Financial Information
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART II
Other Information
 
 
 
 
 
 
 
 


i


PART I - FINANCIAL INFORMATION
 
ITEM 1.    FINANCIAL STATEMENTS.

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

 
October 31,
2013
 
April 30,
2013
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
21,885

 
$
2,551

Restricted cash
733

 
7,531

Accounts receivable
5,838

 
3,204

Alaska production tax credits receivable
5,448

 
12,713

Inventory
2,191

 
3,382

Prepaid expenses and other
5,020

 
1,183

 
41,115

 
30,564

OIL AND GAS PROPERTIES, NET
554,683

 
491,314

EQUIPMENT, NET
35,838

 
37,571

OTHER ASSETS:
 
 
 
Land
542

 
542

Restricted cash, non-current
11,978

 
10,207

Deferred financing costs, net
1,723

 
2,085

Other assets
564

 
541

 
$
646,443

 
$
572,824

LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable
$
21,314

 
$
13,129

Accrued expenses
14,221

 
6,338

Short-term portion of derivative instruments
2,863

 
842

Current portion of long-term debt
6,000

 
6,000

 
44,398

 
26,309

OTHER LIABILITIES:
 
 
 
Deferred income taxes
147,974

 
157,530

Asset retirement obligation
20,472

 
19,890

Long-term portion of derivative instruments
3,463

 

Long-term debt, less current portion
68,006

 
48,978

 
284,313

 
252,707

COMMITMENTS AND CONTINGENCIES (Note 14)

 

MEZZANINE EQUITY:
 
 
 
Series C Cumulative Preferred Stock, redemption amount of $73,593, 3,250,000 shares authorized, 2,892,201 and 1,454,901 shares issued and outstanding as of October 31, 2013 and April 30, 2013, respectively
61,879

 
31,236

 
 
 
 
STOCKHOLDERS' EQUITY:
 
 
 
Series D Fixed Rate/Floating Rate Cumulative Redeemable Preferred Stock, cumulative dividend rate 10.5% per annum, 4,000,000 shares authorized, 1,000,000 and 0 shares issued and outstanding as of October 31, 2013 and April 30, 2013, respectively, with liquidation preference of $25.00 per share
23,125

 

Common stock, $0.0001 par, 500,000,000 shares authorized, 44,447,279 and 43,444,694 shares issued and outstanding as of October 31, 2013 and April 30, 2013, respectively
4

 
4

Additional paid-in capital
94,131

 
88,184

Retained earnings
182,991

 
200,693

 
300,251

 
288,881

 
$
646,443

 
$
572,824


See accompanying notes to the condensed consolidated financial statements.

1


MILLER ENERGY RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(dollars in thousands, except share and per share data)
 
 
Three Months Ended October 31,
 
Six Months Ended October 31,
 
2013
 
2012
 
2013
 
2012
REVENUES:
 
 
 
 
 
 
 
Oil sales
$
18,406

 
$
7,944

 
$
30,664

 
$
15,590

Natural gas sales
283

 
112

 
553

 
195

Other
107

 
2,754

 
587

 
3,287

 
18,796

 
10,810

 
31,804

 
19,072

OPERATING EXPENSES:
 

 
 

 
 

 
 

Oil and gas operating
6,163

 
4,871

 
12,428

 
8,845

Cost of other revenue
304

 
2,485

 
588

 
3,033

General and administrative
7,145

 
6,208

 
13,505

 
11,538

Exploration expense
148

 
28

 
434

 
57

Depreciation, depletion and amortization
9,018

 
3,062

 
14,710

 
6,187

Accretion of asset retirement obligation
301

 
285

 
598

 
569

Other operating income, net

 
(40
)
 

 
(65
)
 
23,079

 
16,899

 
42,263

 
30,164

OPERATING LOSS
(4,283
)
 
(6,089
)
 
(10,459
)
 
(11,092
)
OTHER INCOME (EXPENSE):
 

 
 

 
 

 
 

Interest expense, net
(1,363
)
 
(1,537
)
 
(3,644
)
 
(1,668
)
Gain (loss) on derivatives, net
(4,190
)
 
(2,045
)
 
(7,266
)
 
6,896

Other expense, net
(2
)
 
(300
)
 
(16
)
 
(375
)
 
(5,555
)
 
(3,882
)
 
(10,926
)
 
4,853

LOSS BEFORE INCOME TAXES
(9,838
)
 
(9,971
)
 
(21,385
)
 
(6,239
)
Income tax benefit
4,850

 
3,741

 
9,469

 
2,620

NET LOSS
(4,988
)
 
(6,230
)
 
(11,916
)
 
(3,619
)
Accretion of Series A and C preferred stock
(665
)
 
(38
)
 
(1,118
)
 
(2,460
)
Series C and D preferred stock accumulated dividends
(2,632
)
 
(131
)
 
(4,668
)
 
(131
)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS
$
(8,285
)
 
$
(6,399
)
 
$
(17,702
)
 
$
(6,210
)
 
 
 
 
 
 
 
 
LOSS PER COMMON SHARE:
 

 
 

 
 

 
 

Basic
$
(0.19
)
 
$
(0.15
)
 
$
(0.40
)
 
$
(0.15
)
Diluted
$
(0.19
)
 
$
(0.15
)
 
$
(0.40
)
 
$
(0.15
)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
 

 
 

 
 

 
 

Basic
44,081,775

 
42,542,242

 
43,768,414

 
41,984,283

Diluted
44,081,775

 
42,542,242

 
43,768,414

 
41,984,283


See accompanying notes to the condensed consolidated financial statements.

2


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


 
Series D Preferred Stock
 
Common Stock
 
Additional Paid-in Capital
 
Retained Earnings
 
Total
 
Shares
 
Amount
 
Shares
 
Amount
 
 
 
Balance at April 30, 2012

 
$

 
41,086,751

 
$
4

 
$
64,813

 
$
226,188

 
$
291,005

Net loss

 

 

 

 

 
(3,619
)
 
(3,619
)
Accretion of preferred stock

 

 

 

 

 
(2,460
)
 
(2,460
)
Issuance of equity for services

 

 
351,477

 

 
1,944

 

 
1,944

Other equity issuances

 

 
192,800

 

 
1,341

 

 
1,341

Issuance of equity for compensation

 

 
444,665

 

 
6,161

 

 
6,161

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 October 31, 2012

 

 
43,361,694

 
4

 
82,441

 
220,109

 
302,554

Net loss

 

 

 

 

 
(16,801
)
 
(16,801
)
Series C preferred dividends

 

 

 

 

 
251

 
251

Accretion of preferred stock

 

 

 

 

 
(2,866
)
 
(2,866
)
Issuance of equity for services

 

 

 

 
210

 

 
210

Issuance of equity for compensation

 

 
83,000

 

 
5,533

 

 
5,533

Balance at April 30, 2013

 

 
43,444,694

 
4

 
88,184

 
200,693

 
288,881

Net loss

 

 

 

 

 
(11,916
)
 
(11,916
)
Series C preferred dividends

 

 

 

 

 
(4,223
)
 
(4,223
)
Issuance of Series D Preferred Stock
1,000,000

 
23,125

 

 

 

 

 
23,125

Series D preferred dividends

 

 

 

 

 
(445
)
 
(445
)
Accretion of preferred stock

 

 

 

 

 
(1,118
)
 
(1,118
)
Issuance of equity for services

 

 

 

 
549

 

 
549

Other equity issuances

 

 

 

 
3

 

 
3

Issuance of equity for compensation

 

 
165,765

 

 
3,025

 

 
3,025

Excess tax benefits from share-based compensation

 

 

 

 
87

 

 
87

Exercise of equity rights

 

 
836,820

 

 
2,283

 

 
2,283

Balance at October 31, 2013
1,000,000

 
$
23,125

 
44,447,279

 
$
4

 
$
94,131

 
$
182,991

 
$
300,251



See accompanying notes to the condensed consolidated financial statements.


3


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

 
Six Months Ended October 31,
 
2013
 
2012
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net loss
$
(11,916
)
 
$
(3,619
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 

 
 

Depreciation, depletion and amortization
14,710

 
6,187

Amortization of deferred financing fees and debt discount
754

 
269

Expense from issuance of equity
3,574

 
4,978

Dry hole costs, leasehold impairments and non-cash exploration expenses
193

 

Deferred income taxes
(9,556
)
 
(2,620
)
Excess tax benefits from share-based compensation
87

 

Derivative contracts:
 
 
 
(Gain) loss on derivatives, net
7,266

 
(6,896
)
Cash settlements
(1,782
)
 
3,098

Accretion of asset retirement obligation
598

 
569

Other
843

 

Changes in operating assets and liabilities:
 

 
 

Receivables
383

 
1,207

Inventory
1,487

 
(242
)
Prepaid expenses and other assets
(1,420
)
 
(1,393
)
Accounts payable, accrued expenses and other
(1,047
)
 
5,119

NET CASH PROVIDED BY OPERATING ACTIVITIES
4,174

 
6,657

 
 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES:
 

 
 

Capital expenditures for oil and gas properties
(66,171
)
 
(11,228
)
Proceeds from Alaska production tax credits
9,668

 
64

Prepayment of drilling costs
(2,192
)
 

Purchase of equipment and improvements
(950
)
 
(7,719
)
Proceeds from sale of equipment

 
2,000

NET CASH USED IN INVESTING ACTIVITIES
(59,645
)
 
(16,883
)
 
 
 
 
CASH FLOWS FROM FINANCING ACTIVITIES:
 

 
 

Cash dividends
(3,258
)
 

Payments on debt

 
(24,130
)
Proceeds from borrowings
20,000

 
40,000

Debt acquisition costs
(1,900
)
 
(3,799
)
Redemption of preferred stock

 
(11,240
)
Issuance of preferred stock
56,333

 
18,330

Equity issuance costs
(3,683
)
 
(1,502
)
Exercise of equity rights
2,283

 
3,831

Restricted cash
5,027

 
(10,892
)
Other
3

 

NET CASH PROVIDED BY FINANCING ACTIVITIES
74,805

 
10,598

NET CHANGE IN CASH AND CASH EQUIVALENTS
19,334

 
372

 
 
 
 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
2,551

 
3,971

CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
21,885

 
$
4,343

SUPPLEMENTARY CASH FLOW DATA:
 
 
 
Cash paid for interest
$
5,712

 
$
5,429

SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
 
 
 
Capital expenditures in accounts payable and accrued expenses
$
15,325

 
$
1,463

Reduction of oil and gas properties and equipment from applications for Alaska production tax credits
$
5,642

 
$

Accretion of preferred stock
$
1,118

 
$
2,460


See accompanying notes to the condensed consolidated financial statements.

4


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

1.    ORGANIZATION AND BASIS OF PRESENTATION

Overview
Unless specifically set forth to the contrary, when used in this report, the terms "Miller Energy Resources, Inc.," the "Company," "we," "us," "ours," "MER," "Miller," and similar terms refer to our Tennessee corporation Miller Energy Resources, Inc., formerly known as Miller Petroleum, Inc., and our subsidiaries, Miller Rig & Equipment, LLC, Miller Drilling TN, LLC, 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 east Tennessee. The accounting policies used by us and our subsidiaries reflect industry practices and conform to U.S. generally accepted accounting principles ("GAAP"). Significant policies are discussed below.
Basis of Presentation
The accompanying condensed consolidated financial statements are presented in accordance with GAAP and, in the opinion of management, include all adjustments (consisting only of normal recurring adjustments) necessary for a fair statement of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted under Securities and Exchange Commission ("SEC") rules and regulations. The results reported in these condensed consolidated financial statements are not necessarily indicative of the financial position or operating results that may be expected for the entire year.
The financial information included herein should be read in conjunction with the audited consolidated financial statements and notes thereto included in Item 8 of Part II of the Company's Annual Report on Form 10-K for the year ended April 30, 2013, which was filed with the SEC on July 15, 2013 and was amended on August 28, 2013. Certain amounts in the condensed consolidated financial statements and notes thereto have been reclassified to conform to current period presentation.
Immaterial Reclassifications to Prior Period Consolidated Balance Sheets
We reclassified a $5,305 contra asset related to Alaska production tax credits from oil and gas properties to equipment. The credits that resulted in the recognition of the contra asset related to our drilling rigs, the costs of which are classified in equipment. We have determined the reclassification to be immaterial to the prior period consolidated balance sheet taken as a whole. This error did not have an impact on the prior period consolidated statements of operations, equity or cash flows.
 
As Presented
 
 
 
As Adjusted
 
April 30, 2013
 
Reclassifications
 
April 30, 2013
Oil and gas properties, net
$
486,009

 
$
5,305

 
$
491,314

 
 
 
 
 
 
Equipment, net
$
42,876

 
$
(5,305
)
 
$
37,571


In addition, we reclassified certain costs related to the issuance of debt under our Apollo Credit Facility that were paid to our lender. The costs were initially recorded and reflected as deferred financing costs on our condensed consolidated balance sheet and have been reclassified as a debt discount. We have determined the reclassification to be immaterial to the prior period consolidated balance sheet taken as a whole. This error did not have an impact on the prior period consolidated statements of operations, equity or cash flows.
 
As Presented
 
 
 
As Adjusted
 
April 30, 2013
 
Reclassifications
 
April 30, 2013
Deferred financing costs, net
$
4,666

 
$
(2,581
)
 
$
2,085

 
 
 
 
 
 
Long-term debt, less current portion
$
51,559

 
$
(2,581
)
 
$
48,978



5

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


2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our significant accounting policies are consistent with those disclosed in our Annual Report on Form 10-K for the year ended April 30, 2013, as amended.
Principles of Consolidation
The accompanying condensed consolidated financial statements include our consolidated accounts, including the accounts of the Company, after elimination of intercompany balances and transactions. The condensed consolidated financial statements also include the accounts of all investments in which we, either through direct or indirect ownership, have more than a 50% interest or significant influence over the management of those entities.
Use of Estimates
The preparation of financial statements requires us to utilize estimates and make judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. These estimates are based on historical experience and on various other assumptions that we believe to be reasonable under the circumstances. The estimates are evaluated by management on an ongoing basis and the results of these evaluations form a basis for making decisions about the carrying value of assets and liabilities that are not readily apparent from other sources. Although actual results may differ from these estimates under different assumptions or conditions, we believe that the estimates used in the preparation of our financial statements are reasonable.
Restricted Cash
As of October 31, 2013 and April 30, 2013, current restricted cash includes $149 and $7,144, respectively, of cash temporarily held in an account that is controlled by our lender. Current restricted cash balances also include amounts held in escrow to secure company related credit cards and certain amounts held for and to be paid out to working interest owners. Non-current restricted cash balances include amounts held in escrow to provide for the future plugging and abandonment of wells, the possible dismantling of our off-shore platform, performance bonds and general liability bonds.
Oil and Gas Properties
We follow the successful efforts method of accounting for oil and gas properties. Under this method, exploration costs, such as exploratory geological and geophysical costs, delay rentals and exploration overhead, are charged against earnings as incurred. Acquisition costs and costs of drilling exploratory wells are capitalized pending determination of whether proved reserves can be attributed to the area as a result of drilling the well. If management determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are charged to exploration expense.
Costs of drilling and equipping successful wells, costs to construct or acquire facilities, and associated asset retirement costs are depleted using the unit-of-production method based on total estimated proved developed reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties and costs to construct or acquire offshore platforms, and associated asset retirement costs are depleted using the unit-of-production method based on total estimated proved reserves.
When circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future net cash flows, calculated using the Company's estimate of future oil and natural gas prices, operating expenses and production, to the net book value of the proved properties on a field by field basis. If the sum of the expected undiscounted future net cash flows is less than the net book value of the proved properties, an impairment loss is recognized for the excess, if any, of the net book value over its estimated fair value. No impairment of proved properties was recognized during the six months ended October 31, 2013 or October 31, 2012.
Acquisition costs of unproved properties are assessed for impairment during the holding period and transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on our current exploration plans, and a valuation allowance is provided if impairment is indicated. Costs of expired or abandoned leases are charged to expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties are included in oil and gas operating expense and impairments of unsuccessful leases are included in exploration expense. During the six months ended October 31, 2013 our condensed consolidated statement of operations includes $157 related to impairment of certain unproved properties and $277 in seismic and delay rentals incurred in the Cook Inlet region. We had no exploration or abandonment expenses in the Appalachian region during the six months ended October 31, 2013.

6

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


Equipment
Equipment includes drilling rigs, automobiles, trucks, an airplane, office furniture, computer equipment, and buildings. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets or group of assets, which range from five to forty years.
Equipment is reviewed for impairment when facts and circumstances indicate that book values may not be recoverable. In performing this review, an undiscounted cash flow test is performed on the impairment unit. If the sum of the undiscounted estimated future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property's net book value over its estimated fair value.
Investments
On June 24, 2011, we acquired a 48% minority interest in Pellissippi Pointe I, LLC and Pellissippi Pointe II, LLC (the "Pellissippi Pointe" entities or "investee") for total cash consideration of $400. In connection with the transaction, we executed a five-year lease agreement with the investee and relocated our corporate offices to the new facility on November 7, 2011. Since we do not exercise control over the financial and operating decisions made by the investee, we have accounted for these investments using the equity method. These investments are reflected in other assets in the accompanying condensed consolidated balance sheets.
Guarantees
On July 12, 2012, we signed a direct guarantee for 55% of the $5,074 outstanding loan obligations with FSG Bank for the Pellissippi Pointe equity investment. The Company's guarantee is included within the scope of Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 460, "Guarantees" and was recorded at the estimated fair value of $250; such amount is included in accrued expenses on our condensed consolidated balance sheet as of October 31, 2013 and is being amortized over the five-year life of the guarantee. The fair value was calculated using the income approach and the estimated default rate was determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of Pellissippi Pointe and the term of the underlying loan obligations. The default rates are published by Moody's Investors Service. To the extent we are required to make payments under the guarantee, we will record the differences between the liability and the associated payments in earnings. At October 31, 2013, our maximum potential undiscounted payment under this arrangement is $2,791 plus additional lender's costs.
Income (Loss) Per Share
We determine basic income (loss) per share and diluted income (loss) per share in accordance with the provisions of ASC 260, “Earnings Per Share.” Basic income (loss) per share excludes dilution and is computed by dividing earnings available to common stockholders by the weighted-average number of common shares outstanding for the period. The calculation of diluted earnings (loss) per share is similar to that of basic earnings per share, except that the denominator is increased, if net income is positive, to include the number of additional common shares that would have been outstanding if all potentially dilutive common shares, such as those issuable upon the exercise of stock options and warrants, had been exercised. We compute the numerator for basic income (loss) by subtracting accretion of preferred stock and cumulative preferred stock dividends from net income (loss) to arrive at net income (loss) attributable to common stockholders. Preferred stock dividends include dividends declared on preferred stock (regardless of whether the dividends have been paid) and dividends accumulated for the period on cumulative preferred stock (regardless of whether the dividends have been declared). As of October 31, 2013 our accumulated dividends were $4,668.
New Accounting Pronouncements
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. The 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 was 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 adopted ASU 2011-11; however, it did not have a material impact to our condensed consolidated financial statements
There are no other recently issued accounting pronouncements that are expected to have a material impact on our financial condition, results of operations or cash flows.


7

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


3.    MAJOR CUSTOMERS AND CONCENTRATIONS OF CREDIT RISK

For the three and six months ended October 31, 2013, Tesoro Corporation accounted for 95% and 92% of our consolidated total revenues, respectively. Tesoro Corporation also accounted for 89% and 55%, of our accounts receivable as of October 31, 2013 and April 30, 2013, respectively.
Credit is extended to customers based on an evaluation of their credit worthiness and collateral is generally not required. We experienced no credit losses of significance during the three and six months ended October 31, 2013 or 2012.
We maintain our cash and cash equivalents (including restricted cash), which at times may exceed federally insured amounts, in highly rated financial institutions. As of October 31, 2013, we held $21,180 in excess of the $250 limit insured by the Federal Deposit Insurance Corporation.

4.    RELATED PARTY TRANSACTIONS

We use a number of contract labor companies to provide on demand labor at our Alaska operations. H&H Industrial, Inc. ("H&H Industrial") is an entity contracted by CIE, a wholly-owned subsidiary of the Company, to provide services related to the exploration and production of oil and natural gas. H&H Industrial is owned by the sister and father of David Hall, who is a member of our Board of Directors and Chief Operating Officer ("COO") of Miller, as well as the Chief Executive Officer ("CEO") of CIE. For the three and six months ended October 31, 2013, we paid H&H Industrial, Inc. a total of $799 and $899, respectively. We have used Rediske Air, Inc. ("Rediske Air") to provide transportation to our facilities. Rediske Air was owned by David Hall's brother-in-law, who passed away on July 7, 2013. Rediske Air is no longer owned by a related party. For the three and six months ended October 31, 2013, we paid Rediske Air a total of $482 and $584, respectively. The audit committee of our Board of Directors determined that the amounts paid by us for the services performed were fair and in the best interest of the Company.
From time to time the Company provides service work on oil and gas wells owned by Mr. Herman Gettelfinger (and family), a member of the Board of Directors. As of October 31, 2013 and April 30, 2013, Mr. Gettelfinger (and family) owed us $5 and $11, respectively. The audit committee of our Board of Directors determined that the amounts paid to us for the services performed were fair and in the best interest of the Company.
During the three months ended October 31, 2013, Mr. Gettelfinger paid the Company $3 for the profit he made from the purchase and sale of our common stock within a six month period. The $3 proceeds are presented in other cash flows from financing activities in our condensed consolidated statements of cash flows.
The Company is required to remit payroll taxes related to certain stock-based compensation transactions. As of October 31, 2013, we had no related payables or receivable. At April 30, 2013, we had a payable of $620 and a corresponding receivable from the respective employees of $593, which was collected subsequent to April 30, 2013.
In 2009, we formed both Miller Energy GP and Miller Energy Income 2009-A, LP ("MEI") to raise capital necessary to support strategic business initiatives. From November 2009 to May 2010 we entered into three secured promissory notes with MEI to borrow $3,071 with maturity dates ranging from November 2013 to May 2014. On June 29, 2012, the maturity dates on the promissory notes were amended to reflect the later of (i) 91 days after the date on which the Apollo Credit Facility is extinguished, or (ii) July 31, 2017. Our wholly owned subsidiary, Miller Energy GP, owns 1% of MEI; however, due to the shared management of our company and MEI, we consolidate this entity. We have not presented non-controlling interest on our condensed consolidated balance sheets or our condensed consolidated statements of operations since these amounts are immaterial.
On September 18, 2013, the Company entered into a one-year consulting agreement with William R. Weakley under which he agreed to assist us with investor relations and outreach, including advising the company on its communications with high net-worth individuals, helping to further the Company’s related business goals, assisting with our strategic planning, providing management and business advice, and other consulting services we may reasonably request.  Mr. Weakley is a related party to the Company as a result of aggregating his personal holdings in our stock with those of his brother, son-in-law and other of his relatives which, taken together, exceed 5% of the outstanding common stock of the Company.  As compensation for these services, we granted Mr. Weakley a warrant to purchase 300,000 shares of our common stock at an exercise price of $6.63 per share.  So long as the warrant has not otherwise terminated prior to that date, this warrant will vest in full and be exercisable on September 18, 2014.  The warrant will terminate if the related consulting agreement is terminated prior to the end of its one-year term.  The warrant will otherwise terminate on the earlier of the one year anniversary of the death or disability of Mr. Weakley or September 18, 2016. The audit committee of our Board of Directors determined that the consideration given by us for the services to be performed was fair and in the best interest of the Company.  We further note that in an unrelated transaction, Mr. Weakley’s son-in-law extended a personal loan to our CEO, Scott M. Boruff.  The Company is not a party to or otherwise involved in this loan,

8

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


though this transaction was disclosed to the audit committee in connection with its evaluation of the consulting agreement with Mr. Weakley.
 
5.    OIL AND GAS PROPERTIES AND EQUIPMENT
 
Oil and gas properties (successful efforts method) are summarized as follows:
 
October 31,
2013
 
April 30,
2013
Property costs
 
 
 
Proved property
$
362,224

 
$
332,241

Unproved property
242,714

 
196,500

Total property costs
604,938

 
528,741

Less: Accumulated depletion
(50,255
)
 
(37,427
)
Oil and gas properties, net
$
554,683

 
$
491,314


Equipment is summarized as follows:
 
October 31,
2013
 
April 30,
2013
Machinery and equipment
$
7,738

 
$
7,413

Vehicles
1,849

 
1,851

Aircraft
476

 
476

Buildings
2,725

 
2,725

Office equipment
812

 
759

Leasehold improvements
485

 
482

Drilling rigs
30,117

 
30,117

 
44,202

 
43,823

Less: Accumulated depreciation
(8,364
)
 
(6,252
)
Equipment, net
$
35,838

 
$
37,571


Depreciation, depletion and amortization consisted of the following:
 
For the Six Months Ended October 31,
 
2013
 
2012
Depletion of oil and gas related assets
$
12,532

 
$
4,900

Depreciation and amortization of equipment
2,178

 
1,287

Total
$
14,710

 
$
6,187



9

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


6.    DERIVATIVE INSTRUMENTS AND FAIR VALUE MEASUREMENTS

Derivative Instruments
Commodity Derivatives
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 over-the-counter variable-to-fixed price commodity swap contracts to manage fluctuations in cash flows resulting from changes in commodity prices. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the condensed consolidated statement of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.
As of October 31, 2013, we had the following open crude oil derivative positions. All are priced based on the ICE Brent crude oil futures as traded on the New York Mercantile Exchange.
 
 
Fixed - Price Swaps
Production Period:
 
Bbls
 
Weighted Average Fixed Price
2014
 
289,600

 
$
101.42

2015
 
584,000

 
99.21

2016
 
585,600

 
94.23

2017
 
97,600

 
91.95


Warrants Issued in Connection with Other Equity Transactions
From time to time we issue warrants to third parties in exchange for services. Certain warrants that we issued contained exercise reset provisions, which were considered freestanding derivatives, and were accounted for as liabilities measured at fair value in accordance with ASC 815, "Derivatives and Hedging."
On September 21, 2012, the Company entered into a Special Warrant Exercise Agreement with warrant holders, pursuant to which warrant holders agreed to exercise 586,001 warrants immediately for $4.00 per share and waived their right to a cashless exercise.  In addition, 42,857 warrants were cancelled in exchange for a settlement payment of $75.  These modifications resulted in a loss of $210, which was included in other income (expense), net on our consolidated statement of operations.
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 of $260 was recorded to gain (loss) on derivatives, net, and the remaining liability of $1,840 was reclassified to additional paid-in capital.
Derivative Activities Reflected on Condensed Consolidated Balance Sheets
The Company reports the fair value of derivatives on the condensed consolidated balance sheets in derivative instrument assets and derivative instrument liabilities as either current or noncurrent. The Company determines the current and noncurrent classification based on the timing of the expected future cash flows of individual trades. The Company reports these amounts on a net basis by counterparty where right of offset or master netting agreements exist. As of October 31, 2013 and April 30, 2013, the fair market value of our derivative liabilities was as follows:
 
October 31,
2013
 
April 30,
2013
Current liabilities:
 
 
 
Commodity derivatives
$
2,863

 
$
842

Current portion of derivative instruments
2,863

 
842

Long-term liabilities:
 
 
 
Commodity derivatives
3,463

 

Long-term portion of derivative instruments
3,463

 

Total derivative liability
$
6,326

 
$
842


10

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



Offsetting of Derivative Assets and Liabilities
The following table presents our gross and net derivative assets and liabilities:
 
Gross Amount Presented on Balance Sheet
 
Netting Adjustments (a)
 
Net Amount
October 31, 2013
 
 
 
 
 
Derivative liabilities with right of offset or master netting agreements
$
6,326

 
$

 
$
6,326

April 30, 2013
 
 
 
 
 
Derivative liabilities with right of offset or master netting agreements
$
842

 
$

 
$
842

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

Derivative Activities Reflected on Condensed Consolidated Statements of Operations
Gains and losses on derivatives are reported in the condensed consolidated statements of operations. The following represents the Company’s reported gains and losses on derivative instruments for the periods presented:
 
For the Three Months Ended October 31,
 
For the Six Months Ended October 31,
 
2013
 
2012
 
2013
 
2012
Gain (loss) on derivatives, net
$
(4,190
)
 
$
(2,045
)
 
$
(7,266
)
 
$
6,896


Fair Value Measurements
Fair Value Hierarchy
ASC 820, "Fair Value Measurements and Disclosures," 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. A cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

11

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


Fair Value Measurement on a Recurring Basis
The following table presents, by level within the fair value hierarchy, the Company's assets and liabilities that are measured at fair value on a recurring basis as of October 31, 2013 and April 30, 2013. The carrying amounts reported in the condensed consolidated balance sheets for cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
 
Fair Value Measurements
At October 31, 2013
Level 1
 
Level 2
 
Level 3
Commodity derivative liability
$

 
$
6,326

 
$

Total
$

 
$
6,326

 
$

At April 30, 2013
 

 
 

 
 

Commodity derivative liability
$

 
$
842

 
$

Total
$

 
$
842

 
$


Our commodity derivatives consist of over-the-counter 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. Significant level 2 assumptions used to measure the fair value of the commodity derivatives include current market and contractual crude oil prices, appropriate risk adjusted discount rates, and other relevant data.
Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. There were no transfers between Level 1, Level 2 or Level 3 during the six months ended October 31, 2013 or 2012.

7.    DEBT

As of October 31, 2013 and April 30, 2013, we had the following debt obligations reflected at their respective carrying values on our condensed consolidated balance sheets:
 
October 31,
2013
 
April 30,
2013
Apollo senior secured Credit Facility
$
75,307

 
$
55,307

Debt discount related to Apollo senior secured Credit Facility
$
(3,589
)
 
$
(2,581
)
Series B Preferred Stock
2,288

 
2,252

Total debt obligations
$
74,006

 
$
54,978


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 (the "Original Availability"). Of that initial $55,000, $40,000 was made available to, and was drawn by, Miller on the Closing Date. On February 7, 2013 and April 25, 2013, we borrowed an additional $5,000 and $10,000, respectively, under the Apollo Credit Facility, exhausting the Original Availability. On August 5, 2013, the amount available to the Company under the Apollo Credit Facility was increased by an additional $20,000, to a total of $75,000, when a second tranche of loans (the "New Availability") was added to the Loan Agreement after negotiations with Apollo. This additional $20,000 in availability was immediately drawn by the Company.
The Apollo Credit Facility matures on June 29, 2017 and is secured by substantially all of our assets and those of our consolidated subsidiaries (other than MEI), which subsidiaries also guarantee the loans. Except as described below in connection with New Availability, 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 our fiscal quarters. We will be required to pay the outstanding balance of the loan in full on the maturity date; however, beginning with the fiscal quarter ending July 31, 2013, if requested by Apollo (at the direction of lenders

12

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


holding a majority of the commitments under the Loan Agreement), we 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 our fiscal quarter. No such request to repay principal has been made by Apollo.
In addition, the outstanding debt includes paid in kind interest of $307 added to the principal amount as a part of the “PIK Election” as defined in the Loan Agreement. In connection with the Loan Agreement, the Company has granted Apollo a right of first refusal to provide debt financing for the acquisition, development, exploration or operation of any oil and gas related properties, including wells, during the term of the Apollo Credit Facility and one year thereafter.
The Loan Agreement contains interest coverage, asset coverage, minimum gross production covenants, as well as other affirmative and negative covenants. As previously reported by the Company, these covenants have been amended several times to adjust the covenant levels and the date on which compliance with the covenants would be measured, and to include our Tennessee production in the minimum production covenant. As of April 30, 2013, we were not in compliance with such covenants; however, we received a waiver of such violations from Apollo on July 11, 2013. Under the terms of the waiver, we will be required to maintain compliance with the financial and production covenants on a quarterly basis commencing with the quarter ending October 31, 2013. As of October 31, 2013, we were in compliance with the asset coverage and minimum gross production covenants, but not the interest coverage ratio covenant. On December 9, 2013, we received an amendment and waiver from Apollo ("Eighth Amendment") which, among other matters (see Note 15 - Subsequent Events), waived our non-compliance with that interest coverage ratio requirement as of October 31, 2013 and amended our next testing date for the interest coverage ratio to October 31, 2014.
On the Closing Date, we paid Apollo a non-refundable structuring fee of $2,750, payable for the benefit 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 Original Availability. 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 based on the amount of the Original Availability.
The Company has used a portion of the initial $40,000 loan made available under the Apollo Credit Facility to repay in full the amounts outstanding under the Guggenheim Senior Secured Credit Facility ("Guggenheim Credit Facility") of approximately $26,200. The remaining $13,800 was used to (i) redeem the Company's outstanding Series A Preferred Stock; (ii) pay certain outstanding payables of the Company; and (iii) pay transaction costs associated with the closing of the Apollo Credit Facility, such as attorneys' fees. The February and April 2013 borrowings were used to fund our drilling projects and pay outstanding operational and general and administrative expenses otherwise permitted under the Apollo Credit Facility.
On August 5, 2013, we entered into Amendment No. 6 to the Apollo Credit Facility (the “Sixth Amendment”). The Amendment added the New Availability to the Loan Agreement. This New Availability was drawn by us immediately, is not initially subject to any pre-payment penalty, and will be subject to an initial reduced interest rate of 9%. In the event that we do not repay the entire outstanding amount of the loans made to date under the Apollo Credit Facility (“Loans”) on or before January 31, 2014, then the pre-payment penalty will apply to the New Availability after that date and the interest rate on the New Availability will increase to 18%. The Sixth Amendment clarified that when and if any prepayment of the Loans is made from the proceeds of tax credits received by us under Alaska's Clear and Equitable Share program, that pre-payment will be applied pro rata to both the New Availability and previously drawn Loans (the “Prior Loans”).
In addition to the increase in the amounts available to be borrowed and the adjustment to the interest rate and prepayment penalties on those amounts, among other things, the Sixth Amendment: (i) clarified that the option under the Loan Agreement to pay interest in-kind, rather than in cash, applies to the Prior Loans only and not the New Availability, (ii) established separate conditions precedent to borrowings from the New Availability, (iii) adjusted restrictions contained in Sections 7.10 and 7.12 of the Loan Agreement, and (iv) established interpretive rules related to the repayment and pre-payment of the Loans.
On September 20, 2013, we entered into Revised and Restated Consent and Amendment No. 7 (the “Seventh Amendment”) with Apollo under the Loan Agreement. The Seventh Amendment amends and makes certain acknowledgments regarding certain provisions of the Loan Agreement allowing for our issuance of our Series D Preferred Stock and the payment of dividends on the series. Among other things, the Seventh Amendment: (i) permits the filing of supplementary articles amending our charter, designating the terms of the Series D Preferred Stock; (ii) clarifies the treatment of the Series D Preferred Stock under the Loan Agreement; (iii) so long as no default or event of default has occurred, allows payment of dividends on our Series D Preferred Stock, our Series B Preferred Stock and our Series C Preferred Stock either out of Excluded Equity Proceeds (as defined in the

13

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


Loan Agreement) or during a Capital Covenant Compliance Period (as defined in the Loan Agreement), provided that we are in compliance with the Capital Covenants (as defined in the Loan Agreement) on a pro forma basis on the date of payment, (iv) restricts our ability to redeem the Series D Preferred Stock prior to the 30th day following Security Termination (as defined in the Loan Agreement); and (v) prohibits us from modifying the terms of the Series D Preferred Stock without Apollo’s prior written consent.
The Seventh Amendment also extends the date by which certain liens must be lifted, as a result of the rescheduling of the Voorhees arbitration (see Note 13 - Litigation).
The fair value of the outstanding balance of the Apollo Credit Facility was $71,724 as of October 31, 2013, as calculated using the discounted cash flows method.

Series B Preferred Stock
On September 24, 2012, we sold 25,750 shares of our Series B Cumulative Redeemable Preferred Stock (the "Series B Preferred Stock") to 10 accredited investors and issued those investors warrants to purchase 128,750 shares of common stock in a private offering exempt from registration under the Securities Act of 1933, as amended. We received gross proceeds of $2,575. We paid issuance costs of $167, which have been capitalized and are being amortized over the term of the instrument. The outstanding Series B Preferred Stock is classified as long-term debt, in accordance with ASC 480, "Distinguishing Liabilities from Equity." As of October 31, 2013, the fair value of Series B Preferred Stock is $2,462, as calculated using the discounted cash flow method.
The designations, rights and preferences of the Series B Preferred Stock, include:
a stated value of $100 per share and a liquidation preference equal to the stated value;
the holders are not entitled to any voting rights and the shares of Series B Preferred Stock are not convertible into any other security;
the holders are entitled to receive annual cumulative dividends at the rate of 12% per annum, payable in arrears semi-annually, which began on March 1, 2013;
dividends will be paid in cash on each relevant dividend date provided that (i) we are in compliance with certain financial covenants (designated the "Capital Covenants") under the Apollo Credit Facility, with compliance to be determined as of the most recent reporting date and, on a pro forma basis, on the dividend date, and (ii) no "Default" or "Event of Default" (as defined in the Apollo Credit Facility) has occurred or is continuing on the dividend date;
the shares may not be redeemed until 30 days after "Security Termination" (as defined in the Apollo Credit Facility), but otherwise may be redeemed at any time by the Company, with a required redemption on the fifth anniversary of issuance or, if later, on the 30th day after Security Termination.
On March 1, 2013, in accordance with our charter and the designations for the Series B Preferred Stock, we paid a semiannual dividend of approximately $5.16 per share on the Series B Preferred Stock. In addition, on July 18, 2013, our Board approved the payment of a semiannual dividend, of approximately $6.05 per share, which was paid on September 3, 2013 as the regularly scheduled payment date of September 1, 2013 was not a business day. The record date was August 15, 2013.

Debt Issue Costs
As of October 31, 2013 and April 30, 2013, our unamortized deferred financing costs were $1,723, and $2,085, respectively, which relates to the Apollo Credit Facility and the Series B Preferred Stock. As of October 31, 2013 and April 30, 2013, our unamortized debt discount, which relates to the Apollo Credit Facility, was $3,589 and $2,581, respectively. These costs are being amortized over the term of the respective debt instruments.


14

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


8.    ASSET RETIREMENT OBLIGATIONS

The following table presents changes to the Company's asset retirement obligation ("ARO") liability for the six months ended October 31, 2013 and 2012:
 
2013
 
2012
Asset retirement obligation, as of April 30
$
19,890

 
$
18,366

Settlements and adjustments
(16
)
 

Accretion expense
598

 
569

Asset retirement obligation, as of October 31
$
20,472

 
$
18,935

 
The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with the Company's oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.
Any additional retirement obligations will increase the liability associated with new oil and natural gas wells and other facilities. Actual expenditures for abandonments of oil and natural gas wells and other facilities reduce the liability for asset retirement obligations. At October 31, 2013 and April 30, 2013, there were no significant expenditures for abandonments.
 
9.    STOCK-BASED COMPENSATION
 
During fiscal years 2010 and 2011, our Compensation Committee and Board of Directors adopted share-based compensation plans authorizing 3,000,000 and 8,250,000 shares of common stock under each plan, respectively. The share-based compensation plans allow us to offer our employees, officers, directors and others an opportunity to acquire a proprietary interest in the Company and enable us to attract, retain, motivate and reward such persons in order to promote the success of the Company. Each plan authorizes the issuance of incentive stock options, nonqualified stock options and restricted stock.  All awards issued under the share-based compensation plans must be approved by our Compensation Committee. On June 21, 2013 and July 29, 2013, our Compensation Committee approved additional grants of 350,000 shares of restricted stock and 7,299,996 options to purchase our common stock (the "Q1 Grants"). On October 11, 2013, the Compensation Committee approved an additional grant of 41,000 shares of restricted stock and an option to purchase 30,000 shares of our common stock (the "Q2 Grants"). The Q1 Grants and Q2 Grants are contingent upon shareholder approval of an increase in the number of shares available under the 2011 share-based compensation plan and have not been included in our calculation of available shares. At October 31, 2013 and April 30, 2013, there were 72,828 and 329,328 additional shares available under the compensation plans, respectively. 
Allocated between general and administrative expenses and cost of oil and gas sales within the condensed consolidated statements of operations is stock-based compensation expense for the three and six months ended October 31, 2013 of approximately $1,469 and $3,025, respectively, and $2,538 and $4,528 for the three and six months ended October 31, 2012, respectively. We also recognized non-employee expense related to warrants issued for the three and six months ended October 31, 2013 of approximately $439 and $549, respectively, and $365 and $450 for the three and six months ended October 31, 2012, respectively.

15

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


The following table summarizes stock options and warrants activity for the six months ended October 31, 2013:
 
For the Six Months Ended
 
October 31, 2013
 
Number of Options and Warrants
 
Weighted Average Exercise Price
Beginning balance at April 30
14,403,847

 
$
4.25

Granted
932,500

 
5.50

Exercised
(836,820
)
 
2.74

Canceled
(58,346
)
 
4.12

Ending balance
14,441,181

 
4.77

Options exercisable at October 31
10,373,076

 
$
4.49


The following table summarizes stock options and warrants outstanding, including exercisable shares at October 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
 
1,656,400

 
1.0
 
$
0.75

 
1,656,400

 
$
0.73

$2.00 to $4.99
 
2,248,834

 
4.6
 
3.17

 
1,591,400

 
2.94

$5.25 to $5.53
 
4,150,947

 
3.0
 
5.32

 
2,798,613

 
5.32

$5.89 to $5.94
 
3,310,000

 
6.9
 
5.92

 
2,951,663

 
5.92

$6.00 to $6.94
 
3,075,000

 
2.3
 
6.12

 
1,375,000

 
6.06

 
 
14,441,181

 
3.7
 
$
4.67

 
10,373,076

 
$
4.49


The following table summarizes restricted stock activity for the six months ended October 31, 2013:
 
For the Six Months Ended
 
October 31, 2013
Unvested at April 30
591,030

Granted

Vested
(174,265
)
Forfeited
(8,500
)
Unvested at October 31
408,265


10.    STOCKHOLDERS' EQUITY
 
Common Stock
At October 31, 2013, we had 44,447,279 shares of common stock outstanding. We issued 1,002,585 shares during the six months ended October 31, 2013, of which 165,765 shares were issued to employees for compensation, and 836,820 shares were related to the exercise of equity rights.
At October 31, 2012, we had 43,361,694 shares of common stock outstanding. We issued 2,274,943 shares during the six months ended October 31, 2012, of which 312,500 shares were issued to Bristol Capital, LLC as payment for fees related to the closing of our credit facility, 483,642 shares were issued to employees and non-employees for compensation, 178,800 shares

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


were issued for the settlement of an obligation, 14,000 shares were issued for oil and gas leases, and 1,286,001 shares were related to the exercise of equity rights.
Series C Preferred Stock
On September 28, 2012, we sold 685,000 shares of the Company's newly designated 10.75% Series C Cumulative Redeemable Preferred Stock (the "Series C Preferred Stock"). These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated September 28, 2012, and the Company's registration statement on Form S-3 (Registration No. 333-183750), which was declared effective by the SEC on September 18, 2012.  The shares were offered to the public at $23.00 per share for gross proceeds of $15,755.  We incurred issuance costs of $1,335, yielding net proceeds of $14,420
On October 12, 2012, we entered into an At Market Issuance Sales Agreement ("Series C ATM Agreement") with MLV & Co. LLC ("MLV"). The Series C ATM Agreement contemplates periodic sales by MLV of our Series C Preferred as and when directed by the Company. These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated October 12, 2012, and the Company's registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012. On and after October 12, 2012 and through October 31, 2013, we sold 747,201 shares of Series C Preferred Stock under the Series C ATM Agreement and related prospectus supplement at prices ranging from $21.48 per share to $23.51 per share. We received gross proceeds of $16,230 and incurred issuance costs of $569, yielding net proceeds of $15,661.
On February 12, 2013, we entered into an Underwriting Agreement with MLV as representative for a group of underwriters for a follow-on "best efforts" offering of our Series C Preferred Stock. We sold an additional 625,000 shares of the Series C Preferred Stock in this offering at a price of $22.90 per share. We received gross proceeds of $14,312 and incurred issuance costs of $1,052, yielding net proceeds of $13,260 in connection with the offering. These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated February 13, 2013, and the Company's registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012.
On May 7, 2013, we entered into an Underwriting Agreement with MLV as representative for a group of underwriters for a follow-on "best efforts" offering of our Series C Preferred Stock. We sold an additional 500,000 shares of our Series C Preferred Stock, at a price of $22.25 per share. We received gross proceeds of $11,125 and incurred issuance costs of $805, yielding net proceeds of $10,320. These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated May 7, 2013, and the Company's registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012.
On June 27, 2013, we entered into an Underwriting Agreement with MLV as representative for a group of underwriters for a follow-on "best efforts" offering of our Series C Preferred Stock. We sold an additional 335,000 shares of our Series C Preferred Stock, at a price of $21.50 per share. We received gross proceeds of $7,203 and incurred issuance costs of $547, yielding net proceeds of $6,656. These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated June 28, 2013, and the Company's registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012.
The Series C Preferred Stock is classified as temporary equity in accordance with ASC 480 and is being accreted to redemption value through the earliest repayment date of November 1, 2017, which resulted in accretion of $1,118 during the six months ended October 31, 2013. The fair value of the Series C Preferred Stock was $76,036 as of October 31, 2013, based on the closing price on that date. The designations, rights and preferences of the Series C Preferred Stock include:
The holders are entitled to receive a 10.75% per annum cumulative quarterly dividend, on March 1, June 1, September 1, and December 1, payable in cash on each dividend date unless the Company is prohibited by making such payment pursuant to the terms of any agreement of the Company (including any other class or series of equity securities or any agreement related to indebtedness);
The dividend may increase to a penalty rate of 12.75% if we fail to (A) pay dividends for four or more quarterly dividend periods, whether or not consecutive, or (B) maintain the listing of our Series C Preferred Stock on a national securities exchange (the events listed in clauses (A) and (B) being "Penalty Events");
There is no mandatory redemption or stated maturity with respect to the Series C Preferred Stock, and it is not redeemable prior to November 1, 2017 unless: (A) there is a change in control and redemption occurs pursuant to a special right of redemption related to that change in control or (B) the Closing Bid Price of our common

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


stock has equaled or exceeded the conversion price initially set at $10.00 per share by 150% for at least 20 trading days in any 30 consecutive trading day period (a "Market Trigger");
The redemption price is $25.00 per share plus any accrued and unpaid dividends;
Liquidation preference is $25.00 per share plus any accrued and unpaid dividends;
The Series C Preferred Stock is senior to all our other securities except our Series B Preferred Stock, which is senior to the Series C Preferred Stock, and ranks on parity with our Series D Preferred Stock (as defined below);
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.
On April 30, 2013, our Board of Directors declared a dividend of approximately $0.67 per share on our Series C Preferred Stock which was paid on the next regularly scheduled dividend payment date of June 3, 2013, in accordance with the terms of our charter, as June 1, 2013 was not a business day. The dividend payment is equivalent to an annualized 10.75% per share, based on the $25.00 per share stated liquidation preference for the Series C Preferred Stock, accruing from March 2013 through May 2013. The record date was May 15, 2013.
On July 18, 2013, our Board of Directors declared a dividend of approximately $0.67 per share on our Series C Preferred Stock which was paid on the next regularly scheduled dividend payment date of September 3, 2013, in accordance with the terms of our charter, as September 1, 2013 was not a business day. The dividend payment is equivalent to an annualized 10.75% per share, based on the $25.00 per share stated liquidation preference for the Series C Preferred Stock, accruing from June 2013 through August 2013. The record date was August 16, 2013.
On October 17, 2013, our Board of Directors declared a dividend of approximately $0.67 per share on our Series C Preferred Stock which was paid on the next regularly scheduled dividend payment date of December 2, 2013, in accordance with the terms of our charter, as December 1, 2013 was not a business day. The dividend payment is equivalent to an annualized 10.75% per share, based on the $25.00 per share stated liquidation preference for the Series C Preferred Stock, accruing from September 2013 through November 2013. The record date was November 15, 2013.
Series D Preferred Stock
On September 30, 2013, we sold 1,000,000 shares of the Company's newly designated 10.5% Series D Fixed Rate/Floating Rate Cumulative Redeemable Preferred Stock (the "Series D Preferred Stock"). These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated September 26, 2013, and the Company's registration statement on Form S-3 (Registration No. 333-183750), which was declared effective by the SEC on September 18, 2012.  The shares were offered to the public at $25.00 per share for gross proceeds of $25,000.  We incurred issuance costs of $1,875, yielding net proceeds of $23,125
On October 17, 2013, we entered into an At Market Issuance Sales Agreement ("Series D ATM Agreement") with MLV. The Series D ATM Agreement contemplates periodic sales by MLV of our Series D Preferred as and when directed by the Company. These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated October 17, 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 and after October 17, 2012 through October 31, 2013, we have not offered or sold any additional shares of Series D Preferred Stock under the Series D ATM Agreement and related prospectus supplement.
The Series D Preferred Stock is classified as permanent equity in accordance with ASC 480. The fair value of the Series D Preferred Stock was $24,390 as of October 31, 2013, based on the closing price at that date. The designations, rights and preferences of the Series D Preferred Stock include:
From the date of original issuance to (but not including) December 1, 2018 the holders are entitled to receive a 10.5% per annum cumulative quarterly dividend based on the $25.00 per share liquidation preference per annum,

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


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);
After (and including) December 1, 2018, the holders are entitled to receive a cumulative quarterly dividend at an annual rate equal to the sum of (a) Three-Month LIBOR (as defined below) as calculated on each applicable date of determination and (b) 9.073%, based on the $25.00 per share liquidation preference per annum, 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);
With respect to the Series D Preferred Stock, “Three-Month LIBOR” means: on any date of determination, the rate (expressed as a percentage per year) for deposits in U.S. dollars for a three-month period as appears on Bloomberg, L.P. page US0003M, as set by the British Bankers Association at 11:00 am (London time) on such date of determination.
The dividend may increase by 2% to a penalty rate of (a) 12.5% (before December 1, 2018) or (b) an annual rate equal to the sum of (i) Three-Month LIBOR as calculated on each applicable date of determination and (ii) 11.073%, based on the $25.00 per share liquidation preference per annum (after and including December 1, 2018) 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 D Preferred Stock on a national securities exchange (the events listed in clauses (A) and (B) being "Penalty Events");
There is no mandatory redemption or stated maturity with respect to the Series D Preferred Stock, and it is not redeemable prior to September 30, 2018 unless there is a change in control and redemption occurs pursuant to a special right of redemption related to that change in control;
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 D Preferred Stock is senior to all our other securities except our Series B Preferred Stock, which is senior to the Series D Preferred Stock, and ranks on parity with our Series C Preferred Stock;
The Series D Preferred Stock has been listed on the NYSE and is registered under our universal shelf; and
Holders of the Series D 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 D 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 D Preferred Stock; and 3) the holders of the Series D Preferred Stock will have the right to elect two directors to our board of directors upon the occurrence of a Penalty Event.
On October 17, 2013, our Board of Directors declared a dividend of approximately $0.44 per share on our Series D Preferred Stock which was paid on the next regularly scheduled dividend payment date of December 2, 2013, in accordance with the terms of our charter as December 1, 2013 was not a business day. The dividend payment is equivalent to an annualized 10.5% per share, based on the $25.00 per share stated liquidation preference for the Series D Preferred Stock, accruing from issuance in September 2013 through November 2013. The record date was November 15, 2013.

11.    INCOME TAXES
 
We have a significant deferred income tax liability related to the excess of the book carrying value of oil and gas properties over their collective income tax bases. This difference will reverse (through lower tax depletion deductions) over the remaining recoverable life of the properties, resulting in future taxable income in excess of income for financial reporting purposes. As an independent producer of domestic oil and gas, we take advantage of certain elective provisions presently in the Internal Revenue Code allowing for expensing of specified intangible drilling and development costs that are typically capitalized for book purposes. This temporary difference also reverses over the remaining life of the properties. As a result of these elections, we presently have U.S. federal and state net operating loss carryovers that are expected to be fully utilized against future taxable income resulting solely from the reversal of the temporary differences between the book carrying value of oil and gas properties and their tax bases. We are not relying on forecasts of taxable income from other sources in concluding that no valuation allowance is needed against any of our deferred tax assets. Our provision for income taxes for the second interim reporting period in fiscal 2014 is based on the actual year-to-date effective rate, as this is our best estimate of our annual effective tax rate for the full fiscal year. The

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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(dollars in thousands, except share and per share data and unit and per unit data)


computation of the annual effective tax rate includes a forecast of our estimated “ordinary” income (loss), which is our annual income (loss) from operations before tax, excluding unusual or infrequently occurring (or discrete) items. Significant management judgment is required in the projection of ordinary income (loss) in order to determine the estimated annual effective tax rate. The level of income (or loss) projected for fiscal 2014 causes an unusual relationship between income (loss) and income tax expense (benefit), with small changes resulting in: (i) a potential significant impact on the rate and, (ii) potentially unreliable estimates. As a result, we computed the provision for income taxes for the three and six month periods ended October 31, 2013 and October 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 October 31, 2013 is a benefit of (44%). 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 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 significant cash payments of income taxes were made during the year-to-date period ended October 31, 2013, and no significant payments are expected during the succeeding nine months.
 
12.    ALASKA PRODUCTION TAX CREDITS

Upon qualifying, the Company can apply for several credits under Alaska Statutes 43.55.023 and 43.55.025:
43.55.023(a)(1) Qualified capital expenditure credit (20%)
43.55.023(l)(1) Well lease expenditure credit (effective June 30, 2010) (40%)
43.55.023(a)(2) Qualified capital exploration expenditure credit (20%)
43.55.023(l)(2) Well lease exploration expenditure credit (effective June 30, 2010) (40%)
43.55.023(b) Carried-forward annual loss credit (25%)
43.55.025 Seismic exploration credits (40%)
We recognize a receivable when the amount of the credit is reasonably estimable and receipt is probable. For expenditure and exploration based credits, the credit is recorded as a reduction to the related assets. For carried-forward annual loss credits, the credit is recorded as a reduction to the Alaska production tax. To the extent the credit amount exceeds the Alaska production tax, the credit is recorded as a reduction to general and administrative expenses.
As of October 31, 2013 and April 30, 2013, the Company has reduced the basis of capitalized assets by $19,964 and $14,547 for expenditure and exploration credits, respectively. The reductions are recorded on our condensed consolidated balance sheets in oil and gas properties and equipment. As of October 31, 2013 and April 30, 2013, the Company had outstanding net receivables from the State of Alaska in the amount of $5,448 and $12,713, respectively.

13.    LITIGATION

On May 11, 2011, the Court of Appeals of Tennessee at Knoxville returned its opinion in the case styled CNX Gas Company, LLC v. Miller Petroleum, Inc., et al.  As previously reported, CNX Gas Company, LLC ("CNX") commenced litigation on June 11, 2008 in the Chancery Court of Campbell County, State of Tennessee to enjoin us from assigning or conveying certain leases described in the Letter of Intent signed by CNX and our Company on May 30, 2008, to compel us to specifically perform the assignments as described in the Letter of Intent, and for damages. After the trial court granted the motion for summary judgment of the Company and other party defendants and dismissed the case, finding that there were no genuine issues of material fact and that we were entitled to judgment as a matter of law, CNX appealed.  All parties filed briefs and the Court of Appeals heard oral arguments on May 18, 2010.  In its May 11, 2011 opinion, the Court of Appeals reversed the trial court's grant of summary judgment in favor of our Company and the other party defendants, and remanded the case back to the trial court for further proceedings.  On July 28, 2011, the case was dismissed without prejudice on the motion of CNX.
This action was revived on August 4, 2011, when a breach of contract case was filed against us in the United States District Court for the Eastern District of Tennessee.  The case, styled CNX Gas Company, LLC v. Miller Energy Resources, Inc., Chevron Appalachia, LLC as successor in interest to Atlas America, LLC, Cresta Capital Strategies, LLC and Scott Boruff, arises from the same allegations as the previous action in the state court.  The federal case seeks money damages from us for breach of contract; however, unlike the previous action, it does not seek specific performance of the assignments at issue.  The Plaintiff claims that the other defendants tortiously interfered with, or induced the breach of, the letter of intent between us and the Plaintiff.  We have

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


filed our Answer and intend to vigorously defend this suit.  Discovery is complete, and trial is scheduled to begin on February 10, 2014.  Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.
On May 17, 2011, we were served with a lawsuit filed in the United States District Court for the Eastern District of Tennessee at Knoxville by Troy D. Stafford, the former Chief Financial Officer of our wholly owned subsidiary, Cook Inlet Energy, LLC.  The suit, styled Troy D. Stafford v. Miller Petroleum, Inc., Civil Action No. 3-11CV-206, claims that we terminated Mr. Stafford's employment without cause in contravention of the terms of the Purchase and Sale Agreement between us and the sellers of CIE ("PSA"), failed or refused to pay his salary, severance, percentage of purchase price, expenses or stock warrant and violated a duty of good faith and fair dealing. The suit seeks damages in excess of $3,000, which includes $2,687 of damages for loss of vested warrants. We believe that all of the asserted claims are baseless, particularly in view of the fact that we issued the warrants in accordance with the terms of the PSA.  We believe that we had appropriate cause to dismiss Mr. Stafford's employment after discovering that he had breached certain representations and warranties in the PSA, and had acted in violation of our Code of Conduct. We have filed our Answer, conducted discovery and are presently awaiting further action by the plaintiff. On January 21, 2013, Mr. Stafford's attorney filed a motion to withdraw as counsel, and on April 2, 2013, Mr. Stafford filed a motion to proceed pro se. We do not yet know how this will affect the timing of this matter. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.
On June 15, 2011, a breach of contract lawsuit was filed against us and CIE in the United States District Court for the Eastern District of Pennsylvania styled VAI, Inc. v. Miller Energy Resources, Inc., f/k/a Miller Petroleum, Inc. and Cook Inlet Energy, LLC. The Plaintiff alleges three causes of action: (1) breach of contract, (2) unjust enrichment, and (3) breach of the implied covenant of good faith and fair dealing. The case seeks damages in warrants to purchase our common stock and monetary damages for certain fees and expenses. The Sale Agreement with David Hall, Walter "JR" Wilcox, and Troy Stafford dated December 10, 2009 contains indemnification provisions relevant to this claim. We filed a Motion to Dismiss for lack of personal jurisdiction, but this motion was not granted by the court. We filed an Answer to the complaint in this case on October 10, 2012, and we have conducted discovery. We have filed a motion for summary judgment. Trial was set for November 4, 2013. On October 21, 2013, the trial was postponed with no new trial date having been set. On October 31, 2013, the judge ruled on our outstanding Motion for Summary Judgment, granting it as to the unjust enrichment claim and breach of the implied covenant of good faith and fair dealing claim, and denying it as to the breach of contract claim. We expect to proceed to trial on the breach of contract claim once a new trial date is set. 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, which is pending before the court. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.
On August 23, 2011, a derivative action was filed against us in Knox County Chancery Court.  The case is styled Marco Valdez, derivatively on behalf Miller Energy Resources, Inc. v. Deloy Miller, Scott M. Boruff, Jonathan S. Gross, Herman Gettelfinger, David Hall, Merrill A. McPeak, Charles M. Stivers, Don A. Turkleson, and David J. Voyticky, and Miller Energy Resources, Inc., nominal defendant.  The suit alleges the following causes of action: (1) Breach of Fiduciary Duty for disseminating false and misleading information; (2) Breach of Fiduciary Duty for failure to maintain internal controls; (3) Breach of Fiduciary Duty for failing to properly oversee and manage the company; (4) Unjust Enrichment; (5) Abuse of Control; Gross Mismanagement, and; (6) Waste of Corporate Assets.  The Plaintiff seeks unspecified money damages from the individual defendants, that we take certain actions with respect to our management, restitution to us, and the Plaintiff's attorney fees and costs. We have filed a Motion to Dismiss and, in the alternative, a Motion to Stay pending the outcome of the Class Action. The Plaintiff has agreed to stay this case awaiting a ruling on the plaintiff's appeal in the federal derivatives case in Lukas v. Miller Energy Resources, Inc., et al, as described in the next paragraph. The Plaintiff has also agreed to voluntarily dismiss the case in the event the plaintiff's appeal in Lukas is denied. On October 1, 2013, the Court entered an Order dismissing the case without prejudice on the motion of the Plaintiff. On October 24, 2013, we filed a Motion to Amend the Order of Dismissal as the agreement with the Plaintiff was that the case would be dismissed with prejudice if the Sixth Circuit Court of Appeals affirmed the dismissal of the Lukas case. 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.

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


On August 25, 2011, and August 31, 2011, two derivative actions were filed against us and our Board of Directors and former Chief Financial Officer in the United States District Court for the Eastern District of Tennessee. These cases were consolidated into Patrick P. Lukas, derivatively on behalf Miller Energy Resources, Inc. v. Merrill A. McPeak, Scott M. Boruff, Deloy Miller, Jonathan S. Gross, Herman Gettelfinger, David Hall, Charles M. Stivers, Don A. Turkleson, and David J. Voyticky, and Miller Energy Resources, Inc., nominal defendant. As noted below, this case has been dismissed by the trial court, but that dismissal is being appealed by the plaintiffs. It contained substantially similar claims as Valdez. The suit alleged the following causes of action: (1) Breach of Fiduciary Duty for disseminating false and misleading information; (2) Breach of Fiduciary Duty for failing to properly oversee and manage the company; (3) Unjust Enrichment; (4) Abuse of Control; (5) Gross Mismanagement, and; (5) Waste of Corporate Assets.  The Plaintiffs sought unspecified money damages from the individual defendants, to have us take certain actions with respect to our management, restitution to us, and the Plaintiffs' attorney fees and costs. We filed a Motion to Dismiss, which was granted on September 21, 2012. On October 16, 2012, a notice of appeal of this dismissal was filed by the Plaintiffs with the Sixth Circuit Court of Appeals. The appeal has been fully briefed, and the Court heard oral arguments on July 24, 2013. On September 19, 2013, the Court of Appeals affirmed the judgment of the District Court dismissing the case. On October 3, 2013, the Plaintiff filed a Motion for Rehearing En Banc. We filed our response to that motion on October 21, 2013, and we are currently awaiting a ruling. Given the current stage of the proceedings with respect to this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.
On August 31, 2012, we terminated an agreement with Voorhees Equipment and Consulting, Inc. (“Voorhees”) for the construction and sale of the rig currently being used on the Osprey Platform, Rig 35. We terminated the agreement based on our belief that Voorhees was in breach of its obligations thereunder.  Although no action has been filed in connection with that termination, Voorhees has indicated its desire to arbitrate claims it believes it has under invoices arising between May 29, 2012 and August 31, 2012.  We believe we have grounds to dispute liability with respect to some or all of these outstanding invoices. In addition, we expect to assert counterclaims against Voorhees for damages exceeding the amounts Voorhees claims are owed to it, for breach of the relevant contract by Voorhees.  The parties have elected to engage a private arbitrator to settle this dispute and are currently conducting discovery.  The date of the arbitration has been postponed, but we expect that arbitration to begin on or about January 7, 2014.  Given the current stage of the proceedings with respect to this matter, we believe that any loss would be limited to the payment of the outstanding invoices of approximately $531, plus the cost of defense. Based on the information currently available, we have accrued our best estimate of the potential loss on our consolidated balance sheet. On September 18, 2013, we received a third-party complaint from Voorhees in connection with a lawsuit by Carlile Transportation Systems, Inc., in the Superior Court for the State of Alaska. The case is styled Carlile Transportation Systems, Inc. v. Voorhees Rig International, Inc. v. Cook Inlet Energy, LLC. The dispute is over unpaid transportation fees related to the transportation of equipment for Rig 35. These amounts are already the subject of the planned arbitration scheduled for January of 2014. As all disputes under the Rig 35 contract are subject to mandatory arbitration, we have filed a motion to compel arbitration.
On April 4, 2013, we filed suit against a former contractor of CIE and its parent company (collectively “Cudd”) in the United States District Court for the District of Alaska at Anchorage. This case is styled Cook Inlet Energy, LLC v. Cudd Pressure Control Inc. and RPC, Inc. In our suit we are seeking declaratory relief and damages for breach of contract, breach of implied warrant of merchantability, breach of implied covenant of fitness for a particular purpose and breach of the implied covenant of good faith and fair dealing arising out of a dispute regarding certain equipment and services provided by Cudd on the Osprey Platform that did not meet our needs or expectations as promised. We have not yet determined the full amount of damages claimed. On May 29, 2013, Cudd filed its Answer denying our claims and including a counterclaim for equipment and services, totaling approximately $1,889, plus the costs of defense. We have filed our counteranswer and denied that these amounts are owed, in whole or in part. We are presently beginning the discovery process. Given the current stage of the proceedings with respect to this case, we believe that any loss would be limited to $1,889 plus the cost of defense, related to this matter. Based on the information currently available, we have accrued our best estimate of the potential loss on our consolidated balance sheet.
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)
(dollars in thousands, except share and per share data and unit and per unit 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 for the Alaska DNR's approval.

The AOA required CIE to demonstrate funding commitments of $5,150 to support the redevelopment of the WMRU and an estimated $31,000 to support the development of the Redoubt Unit. The Company believes it has adequately fulfilled these commitments.
On March 11, 2011, the Company entered into a Performance Bond Agreement under its AOA with the state of Alaska. Under the Performance Bond Agreement, the Company is required to post a total bond of $18,000 for the dismantling and abandonment of the properties. As agreed with the state of Alaska, the Performance Bond Agreement fulfills our commitment under the AOA to fund the full dismantlement costs with respect to our onshore and offshore assets. The Performance Bond Agreement also stipulated that funds held by the state in an escrow account will be credited towards the $18,000. As a result, the Company recorded a $6,910 gain on acquisition during the year ended April 30, 2011.
The AOA also prohibits CIE from using proceeds from operation at WMRU or Redoubt for non-core oil and gas activities, or activities unrelated to WMRU or Redoubt, without the prior written approval of the Alaska DNR until the parties mutually agree that the full dismantlement obligation under the assigned leases is funded.
Failure to submit the information required by the AOA or expenditure of proceeds from WMRU or Redoubt for items or activities unrelated to core oil and gas activities at WMRU or Redoubt would constitute a default under the AOA. If the default could not be cured within 30 days, the leases would be subject to termination by the Alaska DNR.
Under the terms of the Performance Bond Agreement, the Company is obligated to fund an additional $12,000 towards the bond in addition to the amount held by the state in the escrow account. As of October 31, 2013, $1,000 of this amount has been funded. The remaining $11,000 (subject to annual inflation adjustments) will be funded through annual payments as follows:
July 1, 2014
 
$
1,500

 
July 1, 2015
 
2,000

 
July 1, 2016
 
2,500

 
July 1, 2017
 
2,000

 
July 1, 2018
 
1,500

 
July 1, 2019
 
1,500

 
 
 
$
11,000

 


23

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


15.    SUBSEQUENT EVENTS

North Fork Unit Acquisition Agreement
On November 22, 2013, CIE entered into a purchase and sale agreement by and among Armstrong Cook Inlet, LLC (“Armstrong”), GMT Exploration Company, LLC, Dale Resources Alaska, LLC, Jonah Gas Company, LLC and Nerd Gas Company, LLC (together, the “North Fork Sellers”) and CIE (the “North Fork Purchase Agreement”). Pursuant to the North Fork Purchase Agreement, CIE will acquire (i) a 100% working interest in six natural gas wells and related leases (consisting of approximately 16,465 net acres) referred to as the “North Fork Unit” in the Cook Inlet region of the State of Alaska, together with other associated rights, interests and assets (collectively, the “North Fork Properties”) and (ii) all the issued and outstanding membership interests (the “Anchor Point Equity”) of Anchor Point Energy, LLC, a limited liability company owning certain pipeline facilities and related assets which service the North Fork Properties, for $59,975 in cash, subject to certain adjustments described below and $5,000 of the Company’s Series D Preferred Stock (collectively, the “North Fork Acquisition”).
Under the terms of the North Fork Purchase Agreement, CIE is required to pay $3,000 in cash (the “Deposit”) to the North Fork Sellers. The Deposit will be applied toward the purchase price upon the closing of the acquisition of the North Fork Properties. If, prior to closing of the proposed acquisition of the North Fork Properties, CIE terminates the North Fork Purchase Agreement because closing has not occurred on or before March 1, 2014 as a result of certain conditions to CIE’s obligation to close (the “CIE Closing Conditions”) not having been met on before February 28, 2014, CIE will be entitled to be refunded the Deposit. If, prior to closing of the proposed acquisition of the North Fork Properties, (a) CIE and Armstrong agree to terminate the North Fork Purchase Agreement, (b) Armstrong elects to terminate the North Fork Purchase Agreement as a result of certain conditions to Armstrong’s obligation to close not having been met; or (c) either Armstrong or CIE elects to terminate the North Fork Purchase Agreement as a result of the closing not having occurred on or before February 28, 2014 for any reason (except where CIE’s performance has been excused because the CIE Closing Conditions have not seen satisfied), the North Fork Sellers will be entitled to retain the Deposit and, in the event of any termination pursuant to (ii)(b) or (c) above, receive an additional $10,000 payment from CIE as liquidated damages.
The North Fork Purchase Agreement contains customary representations and warranties and covenants, including provisions for indemnification, subject to the limitations described in the North Fork Purchase Agreement.
Under the terms of the North Fork Purchase Agreement, the purchase price will be adjusted in accordance with certain adjustment mechanisms contained in the North Fork Purchase Agreement, which includes an adjustment to provide CIE with the net proceeds from the North Fork Properties at all times after the closing. In addition, prior to the receipt of approval from the Regulatory Commission of Alaska of the proposed transfer of the Anchor Point Equity (the “RCA Approval”), CIE will pay Armstrong $25 per month as an overhead fee for its continued operation of Anchor Point Energy, LLC. Between the signing of the North Fork Purchase Agreement and the receipt of RCA Approval, the Anchor Point Energy, LLC will retain at least 60% of its estimated net income in its banks accounts, though the remaining 40% may be distributed to the North Fork Sellers. After the proposed acquisition of the Anchor Point Equity closes, the purchase price will be adjusted to reflect any difference in this amount retained by Anchor Point Energy, LLC based on any difference between the estimated net income of the entity as compared to its actual net income.
The closing of the proposed acquisition of the North Fork Properties is subject to satisfaction of customary closing conditions and is expected to occur on or before February 28, 2014. The closing of the proposed acquisition of the Anchor Point Equity is subject to customary closing conditions and the receipt of RCA Approval. Upon the closing of the acquisition of the North Fork Properties, the portion of the consideration consisting of Series D Preferred Stock and an assignment of Anchor Point Equity will be deposited into an escrow account and disbursed upon the closing of the acquisition of the Anchor Point Equity pursuant to the terms of the North Fork Purchase Agreement.

Series C Preferred Stock
Pursuant to our ATM Agreement with MLV, between October 31 and December 4 of 2013, we offered and sold an additional 116,092 shares of our Series C Preferred Stock, at prices ranging from $26.50 and $26.71 per share.  The Company received $3,082 in gross proceeds as a result of these sales, from which MLV was paid a commission of $108. These securities are registered for sale to the public pursuant to a prospectus, dated September 19, 2012, a prospectus supplement dated October 12, 2012, and the Company's registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012. 


24

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


Series D Preferred Stock
Pursuant to our Series D ATM Agreement with MLV, between October 31 and December 4 of 2013, we offered and sold an additional 32,781 shares of our Series D Preferred Stock, at prices ranging from $24.22 and $24.38 per share.  The Company received $796 in gross proceeds as a result of these sales, from which MLV was paid a commission of $24. These securities are registered for sale to the public pursuant to a prospectus, dated September 19, 2012, a prospectus supplement dated October 17, 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. 

Eighth Amendment to Apollo Loan Agreement
On December 9, 2013, we received the Eighth Amendment to the Loan Agreement. The Eighth Amendment granted a waiver from Apollo of a default under the interest coverage ratio covenant contained in the Loan Agreement. In addition, the Eighth Amendment amended the Loan Agreement to: (i) permit the North Fork Acquisition and the issuance of a corporate guaranty of certain obligations related to the North Fork Acquisition, (ii) delay the requirement that we maintain compliance with the interest coverage ratio covenant until the fiscal quarter ending October 31, 2014, and (iii) increase the covenant levels of the minimum daily gross production covenant in the Loan Agreement.

Expiration of Susitna Basin Exploration License #2 and Conversion of Some Acreage to Leases
On November 1, 2013, the Susitna Basin Exploration License #2 (“Susitna #2 License”) expired. Prior to expiration, we received confirmation from the State of Alaska that we had met our work commitment under the Susitna #2 License and were eligible to convert acreage under the license to leases. We applied for conversion of a total of 167,905 acres, and requested issuance of the proposed leases in three groups. The first group of leases consists of a total of 47,000 acres (the “Group 1 Leases”), which were issued with an effective date of November 1, 2013. The second group of leases consists of a total of 53,451 acres (the “Group 2 Leases”), and the third group of leases consists of a total of 67,454 leases (the “Group 3 Leases”). The State of Alaska has not yet issued the Group 2 Leases or the Group 3 Leases.
Upon award, an annual rental fee of $3.00 per acre was or will be due to the State of Alaska. The annual rental fee for all three groups of leases totals $504.

Payment of Dividends
On December 2, 2013, we paid a quarterly dividend of approximately $0.67 per share on the Series C Preferred Stock. The dividend payment is equivalent to an annualized 10.75% per share, based on the $25.00 per share stated liquidation preference, accruing from September 2013 through November 2013. The record date was November 15, 2013.
On December 2, 2013, we paid a quarterly dividend of approximately $0.44 per share on the Series D Preferred Stock. The dividend payment is equivalent to an annualized 10.5% per share, based on the $25.00 per share stated liquidation preference, accruing from issuance in September 2013 through November 2013. The record date was November 15, 2013.

25

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

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

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

Forward Looking Statements

We have made forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company's operations, economic performance and financial condition in this report, and our Annual Report on Form 10-K, as amended, for the year ended April 30, 2013, and may make other forward-looking statements from time to time in other public filings, press releases and discussions with our management. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include those statements preceded by, followed by or that otherwise include the words "may," "could," "believes," "expects," "anticipates," "intends," "estimates," "projects," "target," "goal," "plans," "objective," "should" or similar expressions or variations on such expressions. For these statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that our expectations will prove to be correct. We undertake no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise.
See the discussion in the "Risk Factors" and "Caution Concerning Forward-Looking Statements" sections of the Company's Annual Report on Form 10-K filed with the SEC on July 15, 2013 and was further amended on August 28, 2013. All written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements contained in the section entitled "Risk Factors" included in such Annual Report as well as other cautionary statements that are made from time to time in our other SEC filings and public communications. You should evaluate all forward-looking statements made in this report in the context of these risks and uncertainties.

Executive Overview

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

Strategy
Our mission is to grow a profitable exploration and production company for the long-term benefit of our shareholders by focusing on the development of our reserves, continued expansion of our oil and natural gas properties and increasing our production and related cash flow. We intend to accomplish these objectives through the execution of our core strategies, which include:
Develop Acquired Acreage. We are focused on organically growing production through drilling for our own benefit on existing leases and acreage in the exploration licenses with a view towards retaining the majority of working interest in the new wells. This strategy allows us to maintain operational control, which we believe will translate to long-term benefits;
Increase Production. We are increasing oil and gas production through the maintenance, repair and optimization of wells located in the Cook Inlet region and development of wells in the Appalachian region of east Tennessee. Our operational team employs a combination of the latest available technologies along with tried and true technologies to restore as well as explore and develop our properties;
Expand Our Revenue Stream. We intend to fully exploit our mid-stream facilities, such as our injection wells and the Kustatan Production Facility, our ability to engage in the commercial disposal of waste generated by oil and gas operations, 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 continues to seek opportunities that meet our criteria for risk, reward, rate of return and growth potential. We pursue value-creating acquisitions when the opportunities arise, subject to the availability of sufficient capital.


26

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

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

Financial and Operating Results
We continued to utilize operational cash flow along with funds raised from sales of our Series C Preferred Stock made in "at-the-market" and "follow-on" public offerings, along with the initial public offering of our Series D Preferred Stock, to support our capital expenditures during our second quarter of fiscal 2014. For the six-month period ended October 31, 2013, we reported notable achievements in several key areas. Highlights for the period include:
Starting May 1, 2013, and periodically during the six month period, we issued 602,300 shares of our Series C Preferred Stock in "at-the-market" offerings pursuant to the Series C ATM Agreement and a prospectus supplement dated October 12, 2012 (issued under our existing S-3 registration statement, filed with the SEC as file number 333-183750). These sales were made at an average price on the date of such sale ranging from $21.48 to $22.35 per share. We received net proceeds of $12,550 in connection with these sales.
On May 10, 2013, we issued 500,000 shares of our Series C Preferred Stock in a "follow-on" best efforts public offering. The shares were registered in the prospectus supplement dated May 7, 2013 and we received net proceeds of $10,320.
Effective May 15, 2013, we entered into a new commercial gas sales agreement in the Cook Inlet region. We will primarily deliver gas on the new agreement with production from the RU-3 and RU-4A wells in the Redoubt Shoals field. Contractual gas sales commenced during the month of May and continued throughout the period.
On June 19, 2013, we began drilling our Sword #1 well located near our West McArthur River Unit ("WMRU") in the Cook Inlet region. The Sword #1 well has been planned as an extended reach well intended to be drilled directionally to approximately 19,000 feet in an adjacent fault block to the WMRU. The 3D seismic data shows a faulted four-way closure and an estimated 240-acre structure with an estimated ultimate recovery ("EUR") of approximately 800,000 barrels of oil from the Sword #1 well.
On June 20, 2013, we brought a new oil well, RU-2A, into production. This well is a sidetrack of a previously producing oil well, RU-2. After clearing the well of drilling fluids from the sidetrack, a subsequent well test showed an initial production of 1,281 barrels of oil per day with a water cut of 19%. The rate of production has averaged 1,146 barrels of oil per day through October 31, 2013.
On July 2, 2013, we issued 335,000 shares of our Series C Preferred Stock in a "follow-on" best efforts public offering. The shares were registered in the prospectus supplement dated June 27, 2013 and we received net proceeds of $6,655.
On July 22, 2013, we announced that our Board of Directors appointed David M. Hall to Chief Operating Officer ("COO"). Mr. Hall has been the Chief Executive Officer of our wholly-owned Alaskan operating subsidiary, Cook Inlet Energy, since 2009 and will continue in that capacity. In his new role as COO, Mr. Hall will oversee our drilling operations in both Alaska and Tennessee.
On July 25, 2013, we elected Marceau Schlumberger to our board of Directors. Mr. Schlumberger is Miller's sixth independent director. Mr. Schlumberger has nearly twenty years of investment banking experience, including international and domestic mergers and acquisitions, restructuring, strategic analysis, and financial experience.
On August 5, 2013, we entered into the Sixth Amendment to our Apollo Credit Facility which allowed us to borrow an additional $20,000 at a temporarily reduced interest rate of 9%. For additional information on the Sixth Amendment and the Apollo Credit Facility, refer to Note 7 - Debt.
On August 17, 2013, we successfully brought our RU-1A oil well online. The well is a sidetrack of a previously producing oil well, RU-1. The newly completed well displayed an initial production rate of 700 barrels of oil per day and an approximate water cut of 5%. The rate of production has averaged 671 barrels of oil per day through October 31, 2013.
On September 30, 2013, we completed our initial public offering of our Series D Preferred Stock, issuing 1,000,000 shares at $25.00 per share with net proceeds of $23,125.

27

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

On September 30, 2013, we completed negotiations for a multi-year gas sales agreement with Chugach Electric Association, Inc., the largest electric utility in Alaska. The contract was submitted to the Regulatory Commission of Alaska and was approved on November 25, 2013.
On October 12, 2013, we brought our RU-5B oil well online. At October 31, 2013, the well was producing approximately 250 bopd.
On October 15, 2013, we brought our Brimstone H-1 well online in Tennessee. Similar to our other horizontal wells, this well requires additional testing. At October 31, 2013, the well had produced 670 bbls of oil.
On October 23, 2013, we reached total depth on our Sword #1 well. On November 20, 2013, we brought the well online. Its initial production rate was 883 bopd.
On October 24, 2013, we received our Underground Injection Control ("UIC") permit from the Environmental Protection Agency ("EPA"). We intend to re-inject gas into a vertical well adjacent to our CPP H-1 horizontal well in Tennessee to maintain reservoir pressure and hopefully increase production.
On October 31, 2013, we completed our rework of our RU-D1 disposal well to prepare for additional drilling activity on the Osprey platform.
Subsequent to the end of the second quarter of fiscal 2014, we spudded our WMRU-8 oil well on November 28, 2013, and we expect to reach total depth on this well within 90 days.
 
Fiscal 2014 Outlook
As we head into the third quarter of fiscal 2014, we believe our inventory of recompletion, workovers, exploration and development projects and newly acquired assets offer numerous growth opportunities. We are in the process of drilling two wells in Alaska, our Otter gas well and our WMRU-8 oil well, and completing preparatory work to begin drilling our RU-9 offshore oil well. We continue to work on proving the horizontal well concept in Tennessee and expect to make significant progress now that we have received a gas reinjection permit from the EPA, which is crucial to our plans to optimize our CPP H-1 well. We have several additional development projects planned, which we expect will contribute to our production in fiscal 2014. No assurance can be made regarding the success of these development and recompletion efforts. Our current fiscal 2014 capital budget is $297,000. The majority of this budget is expected to be spent on projects in Alaska, with the remaining amount allocated to our Appalachian region. Due to the uncertainty associated with changes in commodity prices, we closely monitor our cost levels and revise our capital budgets based on changes in forecasted cash flows. This means our plan for capital expenditures may change as a result of anticipated changes in the market place. Further, our ability to fully utilize the budget will be dependent on a number of factors including, but not limited to, access to capital, favorable weather and regulatory approval.     
Although we expect to sell our Series C and Series D Preferred Stock in “at-the-market” offerings during fiscal 2014, we cannot guarantee that market conditions will continue to permit such sales at prices we would find acceptable. If market conditions are unfavorable, cash generated from those offerings would not be available to us.        
    
Significant Operational Factors
Realized Prices: Our average realized oil price for the three and six months ended October 31, 2013 was $102.65 and $103.41, respectively, as compared to $105.68 and $102.60, respectively, for the same periods in the prior year. These results exclude the impact of commodity derivative settlements.
Production: Our net production, excluding fuel gas, for the three and six months ended October 31, 2013 was 193,261 boe and 318,340 boe as compared to 78,145 boe and 155,040 boe, respectively, for the same periods in the prior year.  
Capital Expenditures and Drilling Results: During the three and six months ended October 31, 2013, we paid $51,147 and $67,121, respectively, in capital expenditures.

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


28

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

Results of Operations

Three Months Ended October 31, 2013 Compared to Three Months Ended October 31, 2012
Revenues
 
For the Three Months Ended October 31,
 
2013
 
Increase (Decrease)
 
2012
Oil revenues:
 
 
 
 
 
Cook Inlet
$
17,767

 
135%
 
$
7,568

Appalachian region
639

 
70
 
376

Total
$
18,406

 
132
 
$
7,944

Natural gas revenues:
 
 
 
 
 
Cook Inlet
$
197

 
795
 
$
22

Appalachian region
86

 
(4)
 
90

Total
$
283

 
153
 
$
112

Other revenues:
 
 
 
 
 
Cook Inlet
$
(113
)
 
(104)
 
$
2,526

Appalachian region
220

 
(4)
 
228

Total
107

 
(96)
 
2,754

Total revenues
$
18,796

 
74%
 
$
10,810


Net Production
 
For the Three Months Ended October 31,
 
2013
 
Increase (Decrease)
 
2012
Oil volume - bbls:
 
 
 
 
 
Cook Inlet
175,474
 
159%
 
67,832
Appalachian region
5,832
 
46
 
3,997
Total
181,306
 
152
 
71,829
Natural gas volume1- mcf:
 
 
 
 
 
Cook Inlet
44,478
 
860
 
4,632
Appalachian region
27,249
 
(18)
 
33,265
Total
71,727
 
89
 
37,897
Total production2 - boe:
 
 
 
 
 
Cook Inlet
182,887
 
167
 
68,604
Appalachian region
10,374
 
9
 
9,541
Total
193,261
 
147%
 
78,145
———————
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.


29

(dollars in thousands, except share and per share data and unit and per unit 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 second quarter of 2014 were 3% below the same period last year. For the three months ended October 31, 2013, realized oil prices averaged $102.65 per bbl, compared with $105.68 per bbl for the same period in the prior year.
Natural Gas Prices
Natural gas is subject to price variances based on local supply and demand conditions. Prices received for natural gas in the second quarter of fiscal 2014 increased over the same period last year. For the three months ended October 31, 2013, realized natural gas prices averaged $3.91 per mcf, compared with $2.95 per mcf for the same period in the prior year. The increase in the averaged realized gas prices resulted from our new natural gas sales contract in the Cook Inlet region.
Oil Revenues
During the second quarter of fiscal 2014, oil revenues totaled $18,406, 132% higher than the same period in the prior year. The increase resulted from a 152% increase in production partially offset by a 3% decrease in realized oil prices. Oil sales represented 98% of our second quarter consolidated total revenues. Oil production increased 109,477 bbls, driven by a 107,642 bbls increase in the Cook Inlet region and a 1,835 bbls increase in the Appalachian region. The production increase in the Cook Inlet region resulted from RU-1A and RU-2A in our Redoubt Shoals field being on line during the three months ended October 31, 2013. The production increase in the Appalachian region is a result of new production from our CPP H-1 well.
Natural Gas Revenues
During the second quarter of fiscal 2014, natural gas revenues totaled $283, 153% higher than the same period in the prior year. The increase resulted from a combination of a 33% increase in average realized prices and a 89% increase in production. The increase in the averaged realized gas prices resulted from our new natural gas sales contract in the Cook Inlet region. The increase in natural gas production resulted from selling natural gas in excess of our fuel gas needs from our RU-3 and RU-4A wells in the Cook Inlet region. Natural gas represented 2% of our second 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 second quarters of fiscal 2014 and 2013, other revenues totaled $107 and $2,754, respectively. The decrease resulted from lower revenue 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, coupled with having revenue from a road building contract in the same period last year.

Cost and Expenses
The table below presents a comparison of our expenses for the three months ended October 31, 2013 and 2012:
 
For the Three Months Ended October 31,
 
 
 
 
 
2013
 
2012
 
$ Variance
 
% Variance
Oil and gas operating costs
$
6,163

 
$
4,871

 
$
1,292

 
27
 %
Cost of other revenues
304

 
2,485

 
(2,181
)
 
(88
)
General and administrative
7,145

 
6,208

 
937

 
15

Exploration expense
148

 
28

 
120

 
429

Depreciation, depletion and amortization
9,018

 
3,062

 
5,956

 
195

Accretion of asset retirement obligation
301

 
285

 
16

 
6

Other operating expense, net

 
(40
)
 
40

 
100

Total costs and expenses
$
23,079

 
$
16,899

 
$
6,180

 
37
 %

Oil and Gas Operating Costs
Oil and gas operating costs increased $1,292 from second quarter fiscal 2013, or 27%. The increase in production and oil and gas operating costs are directly attributable to increased production and drilling activity. The increased production creates

30

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

additional labor and camp facility costs, well maintenance and transportation costs. The addition of new producing wells and increased drilling activity substantially increases the cost of control of well insurance.
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 second quarter of fiscal 2014, we experienced decreases in cost of other revenues in the Cook Inlet region as we had limited projects during the period.
 
For the Three Months Ended October 31,
 
2013
 
Increase (Decrease)
 
2012
Direct labor
$
140

 
(93)%
 
$
2,022

Equipment
36

 
(84)
 
220

Repairs
115

 
(44)
 
207

Insurance

 
(100)
 
17

Other
13

 
(32)
 
19

Total
$
304

 
(88)%
 
$
2,485


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 October 31,
 
2013
 
Increase (Decrease)
 
2012
Salaries
$
1,453

 
59%
 
$
911

Professional fees
1,991

 
39
 
1,431

Travel
533

 
12
 
477

Employee benefits
411

 
86
 
221

Stock-based compensation
1,781

 
(33)
 
2,639

Other
976

 
84
 
529

Total
$
7,145

 
15%
 
$
6,208


G&A expenses increased $937 from second quarter fiscal 2013, or 15%. Salaries increased 59% from the same period in the prior fiscal year due to an increase in our corporate accounting staff from the prior period, additions to our engineering and support staff in the Cook Inlet region, and as a result of salary increases of our named executive officers effective as of July 17, 2013. Professional fees increased 39% over the same period last year due to an increase in accounting, capital-raising, legal and investor relations activities during the quarter. Stock-based compensation declined 33% due to the expense associated with awards that became fully vested exceeding the expense associated with newly granted awards. The increase in other expense resulted from an increase in liability insurance premiums due to our increased drilling activities and an increase in office rent related to the addition of office space in both Tennessee and Alaska.
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.

31

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

Depreciation, Depletion and Amortization
Depreciation, depletion and amortization (“DD&A”) expenses include the DD&A of leasehold costs and equipment. Depletion is calculated on a unit-of-production basis. Depreciation is calculated on a straight-line basis.
 
For the Three Months Ended October 31,
 
2013
 
Increase (Decrease)
 
2012
Depletion:
 
 
 
 
 
Cook Inlet region
$
7,802

 
318%
 
$
1,865

Appalachian region
193

 
(12)
 
220

 
7,995

 
283
 
2,085

Depreciation:
 
 
 
 
 
Cook Inlet region
127

 
112
 
60

Appalachian region
896

 
(3)
 
926

 
1,023

 
4
 
986

Total DD&A
$
9,018

 
194%
 
$
3,071


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

Other Income and Expense
The following table shows the components of other income and expense for the second quarters indicated.
 
For the Three Months Ended October 31,
 
2013
 
Increase (Decrease)
 
2012
Interest expense, net
$
(1,363
)
 
(11)%
 
$
(1,537
)
Loss on derivatives, net
(4,190
)
 
105
 
(2,045
)
Other expense, net
(2
)
 
(99)
 
(300
)
Total
$
(5,555
)
 
43%
 
$
(3,882
)

Interest Expense, Net
Interest expense, net, decreased $174 from the second quarter of fiscal 2013, or 11%.
Loss on Derivatives, Net
We experience earnings volatility as a result of not using hedge accounting to account for changes in commodity prices. As the positions used to hedge future oil production are marked-to-market, both realized and unrealized gains or losses are included on our condensed consolidated statements of operations. We do not engage in speculative trading and utilize commodity derivatives only as a mechanism to lock in future prices for a portion of our expected crude oil production.
During the second quarter of fiscal 2014, we recorded a $4,190 loss on derivatives, as compared to a $2,045 loss on derivatives in the second quarter of fiscal 2013.

32

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

Results of Operations

Six Months Ended October 31, 2013 Compared to Six Months Ended October 31, 2012
Revenues
 
For the Six Months Ended October 31,
 
2013
 
Increase (Decrease)
 
2012
Oil revenues:
 
 
 
 
 
Cook Inlet
$
29,401

 
99%
 
$
14,810

Appalachian region
1,263

 
62
 
780

Total
$
30,664

 
97
 
$
15,590

Natural gas revenues:
 
 
 
 
 
Cook Inlet
$
353

 
1,161
 
$
28

Appalachian region
200

 
20
 
167

Total
$
553

 
184
 
$
195

Other revenues:
 
 
 
 
 
Cook Inlet
$
134

 
(95)
 
$
2,799

Appalachian region
453

 
(7)
 
488

Total
587

 
(82)
 
3,287

Total revenues
$
31,804

 
67%
 
$
19,072


Net Production
 
For the Six Months Ended October 31,
 
2013
 
Increase (Decrease)
 
2012
Oil volume - bbls:
 
 
 
 
 
Cook Inlet
283,908
 
111%
 
134,590
Appalachian region
12,807
 
54
 
8,342
Total
296,715
 
108
 
142,932
Natural gas volume1- mcf:
 
 
 
 
 
Cook Inlet
72,651
 
1,148
 
5,823
Appalachian region
57,097
 
(15)
 
66,830
Total
129,748
 
79
 
72,653
Total production2 - boe: