MILL Q3 10Q 01.31.14

 
 
 
 
 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
 
 
 
FORM 10-Q
 
 
 

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

For the quarterly period ended January 31, 2014
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)
 
 
 
Registrant's telephone number, including area code: (865) 223-6575

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes þ    No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes þ    No o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. The number of shares of common stock issued and outstanding as of March 5, 2014 was 45,242,197.

 
 
 
 
 



TABLE OF CONTENTS

 
 
 
 
 
 
 
 
 
 
 
Page
PART I
Financial Information
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART II
Other Information
 
 
 
 
 
 
 
 


i
Table of Contents

PART I - FINANCIAL INFORMATION
 
ITEM 1.    FINANCIAL STATEMENTS.

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

 
January 31,
2014
 
April 30,
2013
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
13,184

 
$
2,551

Restricted cash
4,066

 
7,531

Accounts receivable
1,137

 
3,204

Alaska production tax credits receivable
19,763

 
12,713

Inventory
4,944

 
3,382

Prepaid expenses and other
8,371

 
1,183

Total current assets
51,465

 
30,564

OIL AND GAS PROPERTIES, NET
568,808

 
491,314

EQUIPMENT, NET
34,860

 
37,571

OTHER ASSETS:
 
 
 
Land
542

 
542

Restricted cash, non-current
12,007

 
10,207

Deferred financing costs, net
1,607

 
2,085

Other assets
1,809

 
541

Total assets
$
671,098

 
$
572,824

LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable
$
40,538

 
$
13,129

Accrued expenses
18,527

 
6,338

Short-term portion of derivative instruments
1,758

 
842

Current portion of long-term debt
—

 
6,000

Total current liabilities
60,823

 
26,309

OTHER LIABILITIES:
 
 
 
Deferred income taxes
145,890

 
157,530

Asset retirement obligation
20,967

 
19,890

Long-term portion of derivative instruments
3,152

 
—

Long-term debt, less current portion
74,268

 
48,978

Total liabilities
305,100

 
252,707

COMMITMENTS AND CONTINGENCIES (Note 14)

 

MEZZANINE EQUITY:
 
 
 
Series C Cumulative Preferred Stock, redemption amount of $78,124, 3,250,000 shares authorized, 3,069,968 and 1,454,901 shares issued and outstanding as of January 31, 2014 and April 30, 2013, respectively
67,097

 
31,236

 
 
 
 
STOCKHOLDERS' EQUITY:
 
 
 
Series D Cumulative Redeemable Preferred Stock, redemption amount of $32,342, 4,000,000 shares authorized, 1,069,031 and 0 shares issued and outstanding as of January 31, 2014 and April 30, 2013, respectively
29,885

 
—

Series D Cumulative Redeemable Preferred Stock, held in escrow (Note 10)
(5,000
)
 
—

Common stock, $0.0001 par, 500,000,000 shares authorized, 45,231,447 and 43,444,694 shares issued and outstanding as of January 31, 2014 and April 30, 2013, respectively
4

 
4

Additional paid-in capital
97,845

 
88,184

Retained earnings
176,167

 
200,693

Total stockholders' equity
298,901

 
288,881

Total liabilities and stockholders' equity
$
671,098

 
$
572,824


See accompanying notes to the condensed consolidated financial statements.

1
Table of Contents

MILLER ENERGY RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(Dollars in thousands, except share and per share data)
 
 
Three Months Ended January 31,
 
Nine Months Ended January 31,
 
2014
 
2013
 
2014
 
2013
REVENUES:
 
 
 
 
 
 
 
Oil sales
$
16,348

 
$
6,720

 
$
47,012

 
$
22,310

Natural gas sales
118

 
133

 
671

 
328

Other
162

 
1,146

 
749

 
4,433

Total revenues
16,628

 
7,999

 
48,432

 
27,071

OPERATING EXPENSES:
 

 
 

 
 

 
 

Oil and gas operating
5,821

 
4,118

 
18,249

 
12,963

Cost of other revenue
256

 
1,051

 
844

 
4,084

General and administrative
7,587

 
5,518

 
21,092

 
17,056

Exploration expense
352

 
187

 
786

 
244

Depreciation, depletion and amortization
7,642

 
3,341

 
22,352

 
9,528

Accretion of asset retirement obligation
305

 
284

 
903

 
853

Other operating expense (income), net
1,250

 
—

 
1,250

 
(65
)
Total operating expenses
23,213

 
14,499

 
65,476

 
44,663

OPERATING LOSS
(6,585
)
 
(6,500
)
 
(17,044
)
 
(17,592
)
OTHER INCOME (EXPENSE):
 

 
 

 
 

 
 

Interest expense, net
(407
)
 
(1,117
)
 
(4,051
)
 
(2,785
)
Gain (loss) on derivatives, net
1,677

 
(1,681
)
 
(5,589
)
 
5,215

Other income (expense), net
42

 
25

 
26

 
(350
)
Total other income (expense)
1,312

 
(2,773
)
 
(9,614
)
 
2,080

LOSS BEFORE INCOME TAXES
(5,273
)
 
(9,273
)
 
(26,658
)
 
(15,512
)
Income tax benefit
2,171

 
3,931

 
11,640

 
6,551

NET LOSS
(3,102
)
 
(5,342
)
 
(15,018
)
 
(8,961
)
Accretion of Series A, C and D preferred stock
(817
)
 
(145
)
 
(1,935
)
 
(2,605
)
Series C and D preferred stock cumulative dividends
(2,905
)
 
(677
)
 
(7,573
)
 
(809
)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS
$
(6,824
)
 
$
(6,164
)
 
$
(24,526
)
 
$
(12,375
)
 
 
 
 
 
 
 
 
LOSS PER COMMON SHARE:
 

 
 

 
 

 
 

Basic
$
(0.15
)
 
$
(0.14
)
 
$
(0.56
)
 
$
(0.29
)
Diluted
$
(0.15
)
 
$
(0.14
)
 
$
(0.56
)
 
$
(0.29
)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
 

 
 

 
 

 
 

Basic
44,886,838

 
43,367,781

 
44,141,222

 
42,445,223

Diluted
44,886,838

 
43,367,781

 
44,141,222

 
42,445,223


See accompanying notes to the condensed consolidated financial statements.

2
Table of Contents

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
—

 
—

 
—

 
—

 
—

 
(8,961
)
 
(8,961
)
Series C preferred dividends
—

 
—

 
—

 
—

 
—

 
(809
)
 
(809
)
Accretion of Series A and Series C Preferred Stock
—

 
—

 
—

 
—

 
—

 
(2,605
)
 
(2,605
)
Issuance of equity for services
—

 
—

 
351,477

 
—

 
2,047

 
—

 
2,047

Other equity issuances
—

 
—

 
192,800

 
—

 
1,341

 
—

 
1,341

Issuance of equity for compensation
—

 
—

 
454,665

 
—

 
8,710

 
—

 
8,710

Exercise of equity rights
—

 
—

 
1,286,001

 
—

 
3,832

 
—

 
3,832

Preferred stock redemption
—

 
—

 
—

 
—

 
2,510

 
—

 
2,510

Modification of warrants
—

 
—

 
—

 
—

 
1,840

 
—

 
1,840

Balance at January 31, 2013
—

 
—

 
43,371,694

 
4

 
85,093

 
213,813

 
298,910

Net loss
—

 
—

 
—

 
—

 
—

 
(11,459
)
 
(11,459
)
Series C preferred dividends
—

 
—

 
—

 
—

 
—

 
(1,400
)
 
(1,400
)
Accretion of Series C Preferred Stock
—

 
—

 
—

 
—

 
—

 
(261
)
 
(261
)
Issuance of equity for services
—

 
—

 
—

 
—

 
107

 
—

 
107

Issuance of equity for compensation
—

 
—

 
73,000

 
—

 
2,984

 
—

 
2,984

Balance at April 30, 2013
—

 
—

 
43,444,694

 
4

 
88,184

 
200,693

 
288,881

Net loss
—

 
—

 
—

 
—

 
—

 
(15,018
)
 
(15,018
)
Series C preferred dividends
—

 
—

 
—

 
—

 
—

 
(6,286
)
 
(6,286
)
Accretion of Series C Preferred Stock
—

 
—

 
—

 
—

 
—

 
(1,796
)
 
(1,796
)
Issuance of Series D Preferred Stock
1,282,617

 
29,746

 
—

 
—

 
—

 
—

 
29,746

Series D Preferred Stock held in escrow
(213,586
)
 
(5,000
)
 
—

 
—

 
—

 
—

 
(5,000
)
Series D preferred dividends
—

 
—

 
—

 
—

 
—

 
(1,287
)
 
(1,287
)
Accretion of Series D Preferred Stock
—

 
139

 
—

 
—

 
—

 
(139
)
 
—

Issuance of equity for services
—

 
—

 
—

 
—

 
752

 
—

 
752

Other equity issuances
—

 
—

 
—

 
—

 
3

 
—

 
3

Issuance of equity for compensation
—

 
—

 
205,099

 
—

 
4,368

 
—

 
4,368

Exercise of equity rights
—

 
—

 
1,581,654

 
—

 
4,538

 
—

 
4,538

Balance at January 31, 2014
1,069,031

 
$
24,885

 
45,231,447

 
$
4

 
$
97,845

 
$
176,167

 
$
298,901



See accompanying notes to the condensed consolidated financial statements.


3
Table of Contents

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

 
Nine Months Ended January 31,
 
2014
 
2013
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net loss
$
(15,018
)
 
$
(8,961
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 

 
 

Depreciation, depletion and amortization
22,352

 
9,528

Amortization of deferred financing fees and debt discount
1,113

 
549

Expense from issuance of equity
5,120

 
7,630

Dry hole costs, leasehold impairments and non-cash exploration expenses
157

 
—

Deferred income taxes
(11,640
)
 
(6,551
)
Derivative contracts:
 
 
 
(Gain) loss on derivatives, net
5,589

 
(5,215
)
Cash settlements
(2,765
)
 
2,276

Accretion of asset retirement obligation
903

 
853

Other
1,949

 
—

Changes in operating assets and liabilities:
 

 
 

Receivables
5,084

 
996

Inventory
372

 
(467
)
Prepaid expenses and other assets
(1,788
)
 
(1,445
)
Accounts payable, accrued expenses and other
3,849

 
6,944

NET CASH PROVIDED BY OPERATING ACTIVITIES
15,277

 
6,137

 
 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES:
 

 
 

Capital expenditures for oil and gas properties
(94,388
)
 
(23,213
)
Proceeds from Alaska production tax credits for capital expenditures
18,561

 
—

North Fork purchase deposit
(3,000
)
 
—

Prepayment of drilling costs
(2,302
)
 
—

Purchase of equipment and improvements
(986
)
 
(9,606
)
Proceeds from sale of equipment
—

 
2,000

NET CASH USED IN INVESTING ACTIVITIES
(82,115
)
 
(30,819
)
 
 
 
 
CASH FLOWS FROM FINANCING ACTIVITIES:
 

 
 

Cash dividends
(5,646
)
 
(285
)
Payments on debt
—

 
(24,130
)
Proceeds from borrowings
20,000

 
40,000

Debt acquisition costs
(1,900
)
 
(3,854
)
Redemption of preferred stock
—

 
(11,240
)
Issuance of preferred stock
62,704

 
20,448

Equity issuance costs
(3,893
)
 
(1,576
)
Exercise of equity rights
4,538

 
3,832

Restricted cash
1,665

 
(992
)
Other
3

 
—

NET CASH PROVIDED BY FINANCING ACTIVITIES
77,471

 
22,203

NET CHANGE IN CASH AND CASH EQUIVALENTS
10,633

 
(2,479
)
 
 
 
 
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
2,551

 
3,971

CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
13,184

 
$
1,492

SUPPLEMENTARY CASH FLOW DATA:
 
 
 
Cash paid for interest
$
5,805

 
$
8,895

SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
 
 
 
Capital expenditures in accounts payable and accrued expenses
$
32,572

 
$
6,702

Reduction of oil and gas properties and equipment from applications for Alaska production tax credits
$
28,906

 
$
—

Issuance of Series D Preferred Stock held in escrow
$
5,000

 
$
—

Accretion of preferred stock
$
1,935

 
$
2,605


See accompanying notes to the condensed consolidated financial statements.

4
Table of Contents

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

1.    ORGANIZATION AND BASIS OF PRESENTATION

Overview
Unless specifically set forth to the contrary, when used in this report, the terms "Miller Energy Resources, 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 Prior 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
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data 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 January 31, 2014 and April 30, 2013, current restricted cash includes $3,447 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 nine months ended January 31, 2014 or January 31, 2013.
Acquisition costs of unproved properties are assessed for impairment during the holding period and transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on our current exploration plans, and a valuation allowance is provided if impairment is indicated. Costs of expired or abandoned leases are charged to expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties are included in oil and gas operating expense and impairments of unsuccessful leases are included in exploration expense. During the nine months ended January 31, 2014 our condensed consolidated statement of operations includes $157 related to impairment of certain unproved properties and $625 in seismic and delay rentals incurred in the Cook Inlet region. We had $4 in exploration and abandonment expenses in the Appalachian region during the nine months ended January 31, 2014.

6
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data 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 at the lowest level for which identifiable cash flows are independent of cash flows from other assets. 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 January 31, 2014 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 January 31, 2014, our maximum potential undiscounted payment under this arrangement is $2,791 plus additional lender's costs.
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 January 31, 2014 our cumulative dividends were $7,573.
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
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


3.    MAJOR CUSTOMERS AND CONCENTRATIONS OF CREDIT RISK

For the three and nine months ended January 31, 2014, Tesoro Corporation accounted for 95% and 93% of our consolidated total revenues, respectively. Tesoro Corporation also accounted for 14% and 55%, of our accounts receivable as of January 31, 2014 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 nine months ended January 31, 2014 or 2013.
We maintain our cash and cash equivalents (including restricted cash), which at times may exceed federally insured amounts, in highly rated financial institutions. As of January 31, 2014, we held $15,677 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 nine months ended January 31, 2014, we paid H&H Industrial a total of $450 and $1,349, 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 nine months ended January 31, 2014, we paid Rediske Air a total of $281 and $865, 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.
The Company is required to remit payroll taxes related to certain stock-based compensation transactions. As of January 31, 2014, we had a payable of $36 and no 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, though this transaction was disclosed to the Audit Committee of our Board of Directors in connection with its evaluation of the consulting agreement with Mr. Weakley. For the three and nine months ended January 31, 2014, we paid Mr. Weakley a total of $2 and $2, respectively.
 

8
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


5.    OIL AND GAS PROPERTIES AND EQUIPMENT
 
Oil and gas properties (successful efforts method) are summarized as follows:
 
January 31,
2014
 
April 30,
2013
Property costs
 
 
 
Proved property
$
389,810

 
$
332,241

Unproved property
235,134

 
196,500

Total property costs
624,944

 
528,741

Less: Accumulated depletion
(56,136
)
 
(37,427
)
Oil and gas properties, net
$
568,808

 
$
491,314


Equipment is summarized as follows:
 
January 31,
2014
 
April 30,
2013
Machinery and equipment
$
7,748

 
$
7,413

Vehicles
1,877

 
1,851

Aircraft
476

 
476

Buildings
2,725

 
2,725

Office equipment
812

 
759

Leasehold improvements
485

 
482

Drilling rigs
30,117

 
30,117

 
44,240

 
43,823

Less: Accumulated depreciation
(9,380
)
 
(6,252
)
Equipment, net
$
34,860

 
$
37,571


Depreciation, depletion and amortization consisted of the following:
 
For the Nine Months Ended January 31,
 
2014
 
2013
Depletion of oil and gas related assets
$
19,158

 
$
7,240

Depreciation and amortization of equipment
3,194

 
2,288

Total
$
22,352

 
$
9,528



9
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data 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. In accordance with ASC 815 "Derivatives and Hedging," 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 January 31, 2014, we had the following open crude oil derivative positions. All are priced based on the Brent crude oil futures as traded on the Intercontinental Exchange.
 
 
Fixed - Price Swaps
Production Period ending April 30,
 
Bbls
 
Weighted Average Fixed Price
2014
 
191,400

 
$
102.92

2015
 
785,000

 
100.58

2016
 
787,600

 
95.75

2017
 
232,600

 
94.27


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 exists. As of January 31, 2014 and April 30, 2013, the fair market value of our derivative liabilities was as follows:
 
 
Asset Derivatives
 
Liability Derivatives
 
 
January 31, 2014
 
April 30, 2013
 
January 31, 2014
 
April 30, 2013
Derivatives not designated as hedging instruments under ASC 815
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
Commodity derivatives
 
Prepaid expenses and other
 
$
564

 
Prepaid expenses and other
 
$
—

 
Current portion of derivative instruments
 
$
(1,758
)
 
Current portion of derivative instruments
 
$
(842
)
Commodity derivatives
 
Other assets
 
680

 
Other assets
 
—

 
Long-term portion of derivative instruments
 
(3,152
)
 
Long-term portion of derivative instruments
 
—

Total derivatives not designated as hedging instruments under ASC 815
 
 
 
$
1,244

 
 
 
$
—

 
 
 
$
(4,910
)
 
 
 
$
(842
)


10
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


Offsetting of Derivative Assets and Liabilities
The following table presents our gross and net derivative assets and liabilities:
 
Gross Amount
 
Netting Adjustments (a)
 
Net Amount Presented on Balance Sheet
January 31, 2014
 
 
 
 
 
Derivative assets with right of offset or master netting agreements
$
1,244

 
$
—

 
$
1,244

Derivative liabilities with right of offset or master netting agreements
$
(4,910
)
 
$
—

 
$
(4,910
)
April 30, 2013
 
 
 
 
 
Derivative assets with right of offset or master netting agreements
$
—

 
$
—

 
$
—

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 January 31,
 
For the Nine Months Ended January 31,
 
2014
 
2013
 
2014
 
2013
Gain (loss) on derivatives, net
$
1,677

 
$
(1,681
)
 
$
(5,589
)
 
$
5,215


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
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data 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 January 31, 2014 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 January 31, 2014
Level 1
 
Level 2
 
Level 3
Commodity derivative asset
$
—

 
$
1,244

 
$
—

Commodity derivative liability
$
—

 
$
(4,910
)
 
$
—

Total
$
—

 
$
(3,666
)
 
$
—

At April 30, 2013
 

 
 

 
 

Commodity derivative asset
$
—

 
$
—

 
$
—

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 nine months ended January 31, 2014 or 2013.

7.    DEBT

As of January 31, 2014 and April 30, 2013, we had the following debt obligations reflected at their respective carrying values on our condensed consolidated balance sheets:
 
January 31,
2014
 
April 30,
2013
Apollo senior secured Credit Facility
$
75,307

 
$
55,307

Debt discount related to Apollo senior secured Credit Facility
(3,346
)
 
(2,581
)
Series B Preferred Stock
2,307

 
2,252

Total debt obligations
$
74,268

 
$
54,978


Apollo Senior Secured Credit Facility
On June 29, 2012 (the "Closing Date"), we entered into a Loan Agreement (the "Prior Loan Agreement") with Apollo Investment Corporation ("Apollo"), as administrative agent and sole initial lender. The Prior Loan Agreement provided for a $100,000 credit facility (the "Prior 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 us on the Closing Date. On February 7, 2013 and April 25, 2013, we borrowed an additional $5,000 and $10,000, respectively, under the Prior Credit Facility, exhausting the Original Availability. On August 5, 2013, the amount available to us under the Prior Credit Facility was increased by an additional $20,000, to a total of $75,000, when a second tranche of loans (the "Additional Availability") was added to the Prior Loan Agreement after negotiations with Apollo. This additional $20,000 in availability was immediately drawn by us.
As noted below, on February 3, 2014, we refinanced the Prior Credit Facility by entering into an Amended and Restated Credit Agreement (the "New Loan Agreement") among us, as a borrower, Apollo, as administrative agent (in that capacity the "Administrative Agent"), and the lenders from time to time party thereto (the "Lenders"), which amended and replaced the terms of the Prior Credit Facility.

12
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


The Prior Credit Facility was scheduled to mature on June 29, 2017 and was secured by substantially all of our assets and those of our consolidated subsidiaries (other than MEI), which subsidiaries also guaranteed the loans. Except as described below in connection with the Additional Availability, amounts outstanding under the Prior Credit Facility bore interest at a rate of 18% per annum, with interest payable on the last day of each of our fiscal quarters. We would have been 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 holding a majority of the commitments under the Prior Loan Agreement), we would have been required to repay up to $1,500 in principal quarterly. Such payments of principal would have been made, together with any interest due on such date, on the last day of our fiscal quarter. No such request to repay principal was 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 Prior Loan Agreement. In connection with the Prior Loan Agreement, we have 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 Prior Credit Facility and one year thereafter.
The Prior Loan Agreement contained interest coverage, asset coverage, minimum gross production covenants, as well as other affirmative and negative covenants. As previously reported, these covenants were 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 were 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, waived our non-compliance with the interest coverage ratio requirement as of October 31, 2013 and amended our next testing date for the interest coverage ratio to October 31, 2014. As we refinanced the Prior Credit Facility, we were not required to calculate compliance with the Prior Loan Agreement's financial covenants at January 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 had agreed to pay another $500 fee on each anniversary of the Closing Date so long as the Prior Loan Agreement remained in effect.
Additional compensation was due to Bristol Capital, LLC, a consultant to us, in connection with the closing of the Prior 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.
We used a portion of the initial $40,000 loan made available under the Prior 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 our outstanding Series A Preferred Stock; (ii) pay certain outstanding payables; and (iii) pay transaction costs associated with the closing of the Prior 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 Prior Credit Facility.
On August 5, 2013, we entered into Amendment No. 6 to the Prior Credit Facility (the “Sixth Amendment”) as modified by an Extension of Date for Prepayment of Tranche B Loan without Prepayment Premium (the "Extension Agreement"). The Amendment added the Additional Availability to the Prior Loan Agreement. This Additional Availability was drawn by us immediately and used for capital projects and working capital and was not initially subject to any pre-payment penalty, and was subject to an initial reduced interest rate of 9%. Under the terms of the Sixth Amendment as modified by the Extension Agreement, in the event that we had not repaid the entire outstanding amount of the loans made to date under the Prior Credit Facility ("Loans") on or before February 28, 2014, then the pre-payment penalty would have applied to the Additional Availability after that date and the interest rate on the Additional Availability would 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 would be applied pro rata to both the Additional 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 Prior Loan Agreement to pay interest in-kind, rather than in cash, applied to the Prior Loans only and not the Additional Availability, (ii) established separate conditions precedent to borrowings from the Additional Availability, (iii) adjusted restrictions contained in Sections 7.10

13
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


and 7.12 of the Prior 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 Prior Loan Agreement. The Seventh Amendment amended and made certain acknowledgments regarding certain provisions of the Prior 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) permitted the filing of supplementary articles amending our charter, designating the terms of the Series D Preferred Stock; (ii) clarified the treatment of the Series D Preferred Stock under the Prior Loan Agreement; (iii) so long as no default or event of default has occurred, allowed 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 Prior Loan Agreement) or during a Capital Covenant Compliance Period (as defined in the Prior Loan Agreement), provided that we are in compliance with the Capital Covenants (as defined in the Prior Loan Agreement) on a pro forma basis on the date of payment, (iv) restricted our ability to redeem the Series D Preferred Stock prior to the 30th day following Security Termination (as defined in the Prior Loan Agreement); and (v) prohibited us from modifying the terms of the Series D Preferred Stock without Apollo's prior written consent.
The Seventh Amendment also extended the date by which certain liens must be lifted, as a result of the rescheduling of the Voorhees arbitration (see Note 13 - Litigation).
As noted above, on February 3, 2014, we refinanced the Prior Credit Facility by entering into the New Loan Agreement among us, the Administrative Agent, and the Lenders. The New Loan Agreement provides for a $175,000 credit facility, which was fully drawn by us at closing, at an interest rate of LIBOR plus 9.75%, with a 2% LIBOR floor (see Note 15 - Subsequent Events).
The fair value of the outstanding balance of the Prior Credit Facility was $69,042 as of January 31, 2014, 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 January 31, 2014, the fair value of Series B Preferred Stock was $2,326, 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 Prior Credit Facility or any amendments thereto, 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 Prior Credit Facility or any amendments thereto) 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 Prior 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.
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.

14
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


On January 28, 2014, our Board approved a semiannual dividend to shareholders of record at the close of business on February 17, 2014. The semiannual payment will be approximately $5.95 per share, which is equivalent to an annualized yield of 12%. The dividend was paid on March 3, 2014 as the regularly scheduled payment date of March 1, 2014 was not a business day. The record date was February 17, 2014.

Debt Issue Costs
As of January 31, 2014 and April 30, 2013, our unamortized deferred financing costs were $1,607 and $2,085, respectively, which relates to the Prior Credit Facility and the Series B Preferred Stock. As of January 31, 2014 and April 30, 2013, our unamortized debt discount, which relates to the Prior Credit Facility, was $3,346 and $2,581, respectively. These costs are being amortized over the term of the respective debt instruments.

8.    ASSET RETIREMENT OBLIGATIONS

The following table presents changes to the Company's asset retirement obligation ("ARO") liability for the nine months ended January 31, 2014 and 2013:
 
For the Nine Months Ended January 31,
 
2014
 
2013
Asset retirement obligation, as of April 30
$
19,890

 
$
18,366

Additions
196

 
—

Settlements and adjustments
(22
)
 
—

Accretion expense
903

 
853

Asset retirement obligation, as of January 31
$
20,967

 
$
19,219

 
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 January 31, 2014 and April 30, 2013, there were no significant expenditures for abandonments.
 

15
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


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 our success. Each plan authorizes the issuance of incentive stock options, nonqualified stock options and restricted stock.  All awards issued under the share-based compensation plans must be approved by our Compensation Committee. 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"). The grant of these 7,299,996 options to purchase shares of our common stock was included in certain employment agreements between the Company and certain executive officers, Scott M. Boruff, David J. Voyticky, David M. Hall, Deloy Miller and Kurt C. Yost. On March 10, 2014, these officers entered into an amendment to their employment agreements with the Company under which the 7,299,996 options to purchase shares of our common stock will no longer be granted. 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"). On November 12, 2013, the Compensation Committee approved an option to purchase 800,000 shares of our common stock (the "Q3 Grants"). The Q1 Grants, Q2 Grants and Q3 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 January 31, 2014 and April 30, 2013, there were 77,078 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 nine months ended January 31, 2014 of approximately $1,343 and $4,368, respectively, and $2,549 and $7,077 for the three and nine months ended January 31, 2013, respectively. We also recognized non-employee expense related to warrants issued for the three and nine months ended January 31, 2014 of approximately $203 and $752, respectively, and $103 and $290 for the three and nine months ended January 31, 2013, respectively.
The following table summarizes stock options and warrants activity for the nine months ended January 31, 2014:
 
For the Nine Months Ended
 
January 31, 2014
 
Number of Options and Warrants
 
Weighted Average Exercise Price
Beginning balance at April 30
14,403,847

 
$
4.61

Granted
932,500

 
5.50

Exercised
(1,581,654
)
 
2.84

Canceled
(58,346
)
 
4.12

Ending balance
13,696,347

 
4.87

Options exercisable at January 31
10,593,495

 
$
4.70



16
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


The following table summarizes stock options and warrants outstanding, including exercisable shares at January 31, 2014:
Options and Warrants Outstanding
 
Options and Warrants
Exercisable
Range of Exercise Price
 
Number Outstanding
 
Weighted Average Remaining Contractual Life (in years)
 
Weighted Average Exercise Price
 
Number Exercisable
 
Weighted Average Exercise Price
$0.01 to $1.82
 
1,606,400

 
1.4
 
$
0.72

 
1,606,400

 
$
0.72

$2.00 to $4.99
 
1,783,000

 
5.7
 
3.55

 
1,263,485

 
3.30

$5.25 to $5.53
 
3,936,947

 
2.7
 
5.32

 
2,636,947

 
5.32

$5.89 to $5.94
 
3,295,000

 
6.6
 
5.92

 
2,936,663

 
5.93

$6.00 to $6.94
 
3,075,000

 
2.0
 
6.12

 
2,150,000

 
6.08

 
 
13,696,347

 
3.7
 
$
4.87

 
10,593,495

 
$
4.70


The following table summarizes restricted stock activity for the nine months ended January 31, 2014:
 
For the Nine Months Ended
 
January 31, 2014
Unvested at April 30
591,030

Granted
—

Vested
(220,849
)
Forfeited
(12,750
)
Unvested at January 31
357,431


10.    STOCKHOLDERS' EQUITY
 
Common Stock
At January 31, 2014, we had 45,231,447 shares of common stock outstanding. We issued 1,786,753 shares during the nine months ended January 31, 2014, of which 205,099 shares were issued to employees for compensation, and 1,581,654 shares were related to the exercise of equity rights.
At January 31, 2013, we had 43,371,694 shares of common stock outstanding. We issued 2,284,943 shares during the nine months ended January 31, 2013, of which 312,500 shares were issued to Bristol Capital, LLC as payment for fees related to the closing of our credit facility, 454,665 shares were issued to employees and non-employees for compensation, 178,800 shares 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 Stock 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 January 31, 2014, we sold 780,067 shares of Series C Preferred Stock under the Series C ATM Agreement and related prospectus

17
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


supplement at prices ranging from $21.48 per share to $26.71 per share. We received gross proceeds of $17,710 and incurred issuance costs of $620, yielding net proceeds of $17,090.
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 $1,796 during the nine months ended January 31, 2014. The fair value of the Series C Preferred Stock was $79,942 as of January 31, 2014, 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 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

18
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


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.
On January 28, 2014, our Board of Directors declared a dividend of approximately $0.67 per share on our Series C Preferred Stock which was paid on the next regularly scheduled dividend payment date of March 3, 2014, in accordance with the terms of our charter, as March 1, 2014 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 December 2014 through February 2014. The record date was February 17, 2014.
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 Stock 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, 2013 through January 31, 2014, we sold 69,031 shares of our Series D Preferred Stock under the Series D ATM Agreement and a prospectus supplement at prices ranging from $23.95 to $24.38 per share. We received gross proceeds of $1,667 and incurred issuance costs of $46, yielding net proceeds of $1,621 in connection with these sales.
On January 31, 2014, pursuant to our Purchase and Sale Agreement with 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 (collectively, the “Sellers”), we issued 213,586 shares of our Series D Preferred Stock to be held in escrow for the benefit of the Sellers, valued at approximately $5,000. For purposes of determining the number of shares of the Series D Preferred Stock, it was valued on January 31, 2014 as the average of its daily volume weighted average prices for the 10 trading days ending on and including January 31, 2014. The Series D Preferred Stock was issued in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended. The Series D Preferred Stock will be held in escrow until the transfer of the equity interests in Anchor Point Energy, LLC has been completed and certain necessary regulatory approvals have been received (see Note 15 - Subsequent Events). Pursuant to the terms of our Charter applicable to the Series D Preferred Stock, we are required to pay dividends on the Series D Preferred Stock held in escrow that are payable on any dividend payment date occurring on and after declared after March 3, 2014. The dividends are also required to be paid into escrow.
The Series D Preferred Stock is classified as permanent equity in accordance with ASC 480 and is being accreted to redemption value through the earliest redemption date of September 30, 2018, which resulted in an accretion of $139 during the

19
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


nine months ended January 31, 2014. The fair value of the Series D Preferred Stock was $30,655 as of January 31, 2014, 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, 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.
On January 28, 2014, our Board of Directors declared a dividend of approximately $0.66 per share on our Series D Preferred Stock which was paid on the next regularly scheduled dividend payment date of March 3, 2014, in accordance with the terms of our charter as March 1, 2014 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 December 2013 through February 2014. The record date was February 17, 2014.


20
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


11.    INCOME TAXES
 
We have a significant deferred income tax liability related to the excess of the book carrying value of oil and gas properties over their collective income tax bases. This difference will reverse (through lower tax depletion deductions) over the remaining recoverable life of the properties, resulting in future taxable income in excess of income for financial reporting purposes. As an independent producer of domestic oil and gas, we take advantage of certain elective provisions presently in the Internal Revenue Code allowing for expensing of specified intangible drilling and development costs that are typically capitalized for book purposes. This temporary difference also reverses over the remaining life of the properties. As a result of these elections, we presently have U.S. federal and state net operating loss carryovers that are expected to be fully utilized against future taxable income resulting solely from the reversal of the temporary differences between the book carrying value of oil and gas properties and their tax bases. We are not relying on forecasts of taxable income from other sources in concluding that no valuation allowance is needed against any of our deferred tax assets. Our provision for income taxes for the third interim reporting period in fiscal 2014 is based on the actual year-to-date effective rate, as this is our best estimate of our annual effective tax rate for the full fiscal year. The computation of the annual effective tax rate includes a forecast of our estimated "ordinary" income (loss), which is our annual income (loss) from operations before tax, excluding unusual or infrequently occurring (or discrete) items. Significant management judgment is required in the projection of ordinary income (loss) in order to determine the estimated annual effective tax rate. The level of income (or loss) projected for fiscal 2014 causes an unusual relationship between income (loss) and income tax expense (benefit), with small changes resulting in: (i) a potential significant impact on the rate and, (ii) potentially unreliable estimates. As a result, we computed the provision for income taxes for the three and nine month periods ended January 31, 2014 and January 31, 2013 by applying the actual effective tax rate to the year-to-date income (loss), as permitted by GAAP. The effective tax rate for the year-to-date period ended January 31, 2014 is a benefit of (43.7%). 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 January 31, 2014, and no significant payments are expected during the succeeding 12 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 January 31, 2014 and April 30, 2013, the Company has reduced the basis of capitalized assets by $43,218 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 January 31, 2014 and April 30, 2013, the Company had outstanding net receivables from the State of Alaska in the amount of $19,763 and $12,713, respectively.


21
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


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 reached a settlement with the Plaintiff on January 24, 2014, wherein we would pay the Plaintiff $1,250 in exchange for their agreement to dismiss the case with prejudice. The Company recorded a loss of $1,250 related to this settlement in other operating expense (income), net in its consolidated statement of operations for the three and nine months ended January 31, 2014.
On May 17, 2011, we were served with a lawsuit filed in the United States District Court for the Eastern District of Tennessee at Knoxville by Troy D. Stafford, the former Chief Financial Officer of CIE.  The suit, styled Troy D. Stafford v. Miller Petroleum, Inc., Civil Action No. 3-11CV-206, claims that we terminated Mr. Stafford's employment without cause in contravention of the terms of the Purchase and Sale Agreement between us and the sellers of CIE ("PSA"), failed or refused to pay his salary, severance, percentage of purchase price, expenses or stock 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. On February 24, 2014, we filed a Motion to Dismiss with Prejudice because Mr. Stafford has made no effort whatsoever to prosecute his case since April 2, 2013, has missed filing deadlines, and has failed to appear to give his deposition both times we have noticed it. 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. 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. In February 2014, we received notice from a third party seeking to intervene in the case in order to secure payment of a debt allegedly owed by the Plaintiff to the third party. We believe this intervention would have no effect on the outcome of the case. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.
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,

22
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


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 was denied on February 4, 2014 as to all defendants save Ford Graham. 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, which it has.
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 had been dismissed by the trial court, but that dismissal was unsuccessfully 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 the Court denied the motion on January 8, 2014.
On August 31, 2012, we terminated an agreement with Voorhees Equipment and Consulting, Inc. (“Voorhees”) for the construction and sale of the rig currently being used on the Osprey Platform, Rig 35, (the “Rig 35 Agreement”). We terminated the agreement based on our belief that Voorhees was in breach of its obligations thereunder.  Voorhees later indicated its desire to arbitrate claims it believes it has under invoices arising between May 29, 2012 and August 31, 2012.  We 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 elected to engage a private arbitrator to settle this dispute and conducted discovery.  On September 18, 2013, we received a third-party complaint from Voorhees in connection with a lawsuit by Carlile Transportation Systems, Inc., in the Superior Court for the State of Alaska. The case is styled Carlile Transportation Systems, Inc. v. Voorhees Rig International, Inc. v. Cook Inlet Energy, LLC. The dispute is over unpaid transportation fees related to the transportation of equipment for Rig 35. These amounts were already the subject of the planned arbitration with Voorhees. As all disputes under the Rig 35 contract are subject to mandatory arbitration, we filed a motion to compel arbitration, which was granted. We are currently in settlement discussions and have postponed the arbitration as we seek a settlement. We believe that any loss would be limited to the payment of the outstanding invoices of approximately $531, plus the cost of defense.
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

23
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


warranty 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 conducting discovery. 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.
On February 7, 2014, we were served with a lawsuit filed by Vulcan Capital Corporation in the District Court for the Southern District of New York styled Vulcan Capital Corp. v. Miller Energy Resources, Inc. and PlainsCapital Bank. The suit asserts various causes of action against PlainsCapital Bank, and appears to assert the following causes of action against us: (1) Breach of Fiduciary Duty and (2) Concert of Action. The case stems from an agreement Plaintiff had with PlainsCapital Bank wherein Plaintiff secured certain loans by pledging four warrants to purchase our common stock that were issued as part of the employment package of Ford F. Graham, our former President. Upon Plaintiff’s default of the loan agreement, PlainsCapital presented the warrants to us for transfer, and, after requesting certain tenders required under Tennessee law, we registered the transfer of the warrants. We have retained counsel and are preparing to file a responsive pleading. In addition, PlainsCapital Bank has agreed to indemnify us for our first $500 of expenses related to this dispute. Given the current state of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.
We are also party to various routine legal proceedings arising in the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations.

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 the Redoubt Unit and West McArthur River Unit ("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 Unit 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.
The AOA prohibited CIE from using proceeds from operations at the WMRU or Redoubt Unit for non-core oil and gas activities, or activities unrelated to the WMRU or Redoubt Unit, without the prior written approval of the Alaska DNR until the parties mutually agreed that the full dismantlement obligation under the assigned leases was funded.
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.

24
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


Failure to submit the information required by the AOA 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 January 31, 2014, $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

 

15.    SUBSEQUENT EVENTS

Repayment of MEI Loans
On February 3, 2014, we repaid all obligations under the First Secured Promissory Note dated as of November 1, 2009, a Second Secured Promissory Note dated as of December 15, 2009, a Third Secured Promissory Note dated as of May 15, 2010, and a Loan and Security Agreement dated as of March 19, 2010 (as amended, supplemented or otherwise modified prior to the date hereof, the "MEI Loan Documents"), by and among Miller Energy Income 2009-A, LP, a Delaware limited partnership ("MEI") and us. The MEI Loan Documents have terminated.

Prepayment of Prior Credit Facility
On February 3, 2014, we repaid in full the loans outstanding under the Prior Loan Agreement with Apollo, as administrative agent and lender, as amended from time to time, which provided for a credit facility of up to $100,000 (the "Prior Credit Facility") with a borrowing base of $55,000 and an Additional Availability allowing for $20,000 in loans. The availability under the Prior Credit Facility had been fully drawn by us. The terms of the Prior Credit Facility were amended and restated in their entirety in connection with New Credit Facility described below and, except to the extent incorporated into the New Credit Facility, the terms of the Prior Credit Facility are superseded and without further effect.
As a result of the prepayment of the Prior Credit Facility, we owed Apollo a prepayment and extension fee of $9,223 (the “Prepayment Fee”) in connection with the termination and early repayment of borrowings under the Prior Credit Facility. Pursuant to a letter agreement entered into by the Company and Apollo, the Prepayment Fee shall be paid to Apollo in four equal installments of approximately $2,306 on the last day of each calendar quarter, commencing June 30, 2014.

Amendment and Restatement of Prior Credit Facility
On February 3, 2014, (the "Closing Date"), we entered into New Loan Agreement, among us, as borrower, Apollo, as administrative agent and the lenders from time to time party thereto.
The New Loan Agreement provides for a $175,000 term credit facility (the "New Credit Facility"), all of which was made available to and drawn by us on the Closing Date. The amounts drawn were subject to a 2% original issue discount. Amounts outstanding under the New Credit Facility bear interest at a rate of LIBOR plus 9.75%, subject to a 2% LIBOR floor. The New Credit Facility permits us to enter into a reserve-based revolving credit facility of up to $100,000 on certain agreed terms which would be secured on a first-lien basis. Upon entering into such revolving credit facility and a related intercreditor agreement, the New Credit Facility will become a second-lien credit facility. The New Credit Facility carries a four year maturity, which may be extended by up to an additional year as necessary so that it matures at least six months after the maturity date of the first lien revolving credit facility, if put in place. The New Credit Facility contains customary second lien covenants, including a leverage ratio, interest coverage ratio, current ratio, asset coverage ratio, minimum gross production and change of management control covenants. Subject to certain conditions contained in the New Loan Agreement, the New Credit Facility also allows for us to implement a discretionary share repurchase plan on terms and conditions reasonably satisfactory to the Administrative Agent and the Lenders.

25
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


The New Loan Agreement contemplates and allows us to seek and put in place a new, first priority, credit facility ranking senior to the New Credit Facility (a "Future Credit Facility") subject to certain terms and conditions set forth in the New Loan Agreement.
We used $75,300 of the proceeds drawn under the New Credit Facility to refinance the Prior Credit Facility with Apollo and $56,975 to finance the acquisition of the North Fork Unit (as described below). In addition, $3,800 was used to retire the obligations owed under the MEI Loan Documents. The remainder of the proceeds from the New Credit Facility will be used for general corporate purposes.
On the Closing Date, in connection with the New Credit Facility, we, along with all of our consolidated subsidiaries (other than MEI), entered into an Amended and Restated Guarantee and Collateral Agreement (the "Guarantee") with Apollo, for the benefit of the lenders from time to time party to the New Loan Agreement. Under the terms of the Guarantee and related security documents each of our consolidated subsidiaries (other than MEI) have guaranteed our obligations under the New Credit Facility and we and those subsidiaries have granted a security interest in substantially all of their assets to secure the performance of the obligations arising under the New Credit Facility.
The foregoing description is qualified in its entirety by reference to the full text of the New Loan Agreement which was filed as Exhibit 10.01 to a Current Report on Form 8-K on February 6, 2014 and the Guarantee and Collateral Agreement which was filed as Exhibit 10.02 thereto.

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 acquired (i) a 100% working interest in six natural gas wells and related leases (consisting of approximately 15,465 net acres) referred to as the "North Fork Unit" in the Cook Inlet region of the State of Alaska, together with other associated rights, interests and assets (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").
The acquisition of the North Fork Properties closed on February 4, 2014 and the proposed acquisition of the Anchor Point Equity will close upon receiving approval from the Regulatory Commission of Alaska ("RCA Approval"), subject to customary closing conditions. Upon the closing of the North Fork Properties acquisition, the portion of consideration consisting of Series D Preferred Stock and assignment of Anchor Point Equity was deposited into an escrow account. These will be disbursed upon the closure of the Anchor Point Equity acquisition pursuant to the terms of the North Fork Purchase Agreement.
The purchase of both the North Fork Properties and Anchor Point Equity will be accounted for as required by ASC 850, "Business Combinations." Under ASC 805, we are required to allocate the purchase price to tangible and identifiable intangible assets acquired and liabilities assumed based on their fair values at the respective closing dates. Any excess of the purchase price over those fair values is recorded as goodwill. We are in the process of valuing the assets acquired and liabilities assumed in the North Fork Properties acquisition. Disclosures required by ASC 805 will be provided when the initial accounting for the acquisitions is complete.

Payment of Dividends
On March 3, 2014, we paid a semiannual dividend of approximately $5.95 per share on the Series B Preferred Stock. The dividend payment is equivalent to an annualized yield of 12% per share, based on the $100.00 per share stated liquidation preference, accruing from September 1, 2013 through February 28, 2014. The record date was February 17, 2014.
On March 3, 2014, we paid a quarterly dividend of approximately $0.67 per share on the Series C Preferred Stock. The dividend payment is equivalent to an annualized 10.75% per share, based on the $25.00 per share stated liquidation preference, accruing from December 1, 2013 through February 28, 2014. The record date was February 17, 2014.
On March 3, 2014, we paid a quarterly dividend of approximately $0.66 per share on the Series D Preferred Stock. The dividend payment is equivalent to an annualized 10.5% per share, based on the $25.00 per share stated liquidation preference, accruing from issuance in December 1, 2013 through February 28, 2014. The record date was February 17, 2014.


26
Table of Contents
MILLER ENERGY RESOURCES, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(Dollars in thousands, except per share data and per unit data)


Series D Preferred Stock
Pursuant to our Series D ATM Agreement with MLV, between January 31, 2014 and March 5, 2014, we offered and sold an additional 1,417 shares of our Series D Preferred Stock, at a price of $24.00 per share.  We received gross proceeds of $34 and incurred issuance costs of $1, yielding net proceeds of $33. 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. 
Appointment of John M. Brawley as Chief Financial Officer
On February 12, 2014, our Board of Directors appointed Mr. John Brawley, 31, as our Chief Financial Officer. Mr. Brawley, through his consulting company, was previously a consultant for us, starting in November 2013. From 2010 to 2013 Mr. Brawley worked for Guggenheim Partners, LLC, a diversified asset management firm, where he oversaw their mezzanine energy portfolio as the co-head of the Houston office and provided energy expertise for Guggenheim's high yield and syndicated loan portfolios. Prior to Guggenheim Partners, LLC, Mr. Brawley worked directly for the CFO of ATP Oil & Gas as a consultant from 2006 to 2010, and was a financial analyst at Lehman Brothers in their energy investment banking practice in 2006. Mr. Brawley received a B.A. in Economics and Biological Sciences and an M.B.A, with a concentration in Accounting and Finance, from Rice University.
We entered into an employment agreement with Mr. Brawley, dated as of February 12, 2014, extending until November 12, 2016, under which Mr. Brawley will receive an annual salary of $350. The Board also granted Mr. Brawley 35,000 shares of restricted stock contingent on a shareholder approval of an increase in the number of shares available under the 2011 Equity Compensation Plan (the "2011 Plan") adequate to cover this grant of restricted stock. In addition, in connection with Mr. Brawley’s engagement as a consultant on November 12, 2013, the Compensation Committee previously granted an option (the “Option”) to purchase 800,000 shares of our common stock, vesting as follows: 300,000 shares vesting on May 12, 2014, 250,000 shares vesting on November 12, 2015, and 250,000 shares vesting on November 12, 2016. This Option is also contingent upon shareholder approval of an increase in the number of shares available under the 2011 Plan adequate to cover the grant of the Option. As the Option was previously granted to Mr. Brawley’s consulting company in connection with his consulting work, that Option is being assigned with the consent of our Board of Directors and the Compensation Committee of the Board. The Option’s strike price is $6.11 per share, which was the closing price of our common stock on the New York Stock Exchange on November 12, 2013, which was when the Committee granted the Option as well as the date Mr. Brawley began rendering consulting services to us.
Also on February 12, 2014, the Company's Board of Directors approved a change in title for Mr. David J. Voyticky to President as he had previously held the title of President and Acting Chief Financial Officer.

27
Table of Contents
(Dollars in thousands, except per share data 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 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.


28
Table of Contents
(Dollars in thousands, except per share data 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 and "at-the-market" offerings of our Series D Preferred Stock, to support our capital expenditures during our third quarter of fiscal 2014. For the nine-month period ended January 31, 2014, we reported notable achievements in several key areas. Highlights for the period include:
•
Starting May 1, 2013, and periodically during the nine month period, we issued 780,067 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 $26.71 per share. We received net proceeds of $17,090 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 with Chugach Electric Association, Inc., Alaska's largest electric utility. Contractual gas sales commenced during the month of May and have continued throughout the period. We have primarily delivered gas on the new agreement with production from the RU-3 and RU-4A wells in the Redoubt Shoals field.
•
On June 19, 2013, we began drilling our Sword #1 well from our West McArthur River Production Facility in the Cook Inlet region. The Sword #1 well was completed as an extended reach well drilled directionally to approximately 19,000 feet in an adjacent fault block to the West McArthur River Field. 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 1,055 barrels of oil per day through January 31, 2014.
•
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 Prior 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 Prior 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 594 barrels of oil per day through January 31, 2014.
•
On September 30, 2013, we completed our public offering of our Series D Preferred Stock, issuing 1,000,000 shares at $25.00 per share with net proceeds of $23,125.

29
Table of Contents
(Dollars in thousands, except per share data and per unit data)

•
On September 30, 2013, we completed negotiations for a multi-year gas sales agreement with Chugach Electric Association, Inc., which expanded upon the short-term contract signed in May. 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. The rate of production has averaged 186 barrels of oil per day through January 31, 2014.
•
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 January 31, 2014, the well had produced 2,982 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. At January 31, 2014, the well was producing approximately 660 bopd.
•
On October 24, 2013, we received an 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 workover of the RU-D1 disposal well to prepare for additional drilling activity on the Osprey platform.
•
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 and requested issuance of the proposed leases in three groups. The first group of leases consisting of a total of 47,000 acres were issued with an effective date of November 1, 2013. The second and third group of leases consisting of a total of 120,900 acres were issued with an effective date of January 1, 2014. Upon award, an annual rental fee of $3.00 per acre was paid to the State of Alaska. The annual rental fee for all three groups of leases totals $504.
•
On November 22, 2013, we entered into an agreement to acquire the North Fork Properties and the Anchor Point Equity in the Cook Inlet region for $64,975, with $5,000 to be paid in our Series D Preferred Stock.
•
Beginning November 26, 2013 and periodically thereafter, we issued 69,031 shares of our Series D Preferred Stock in "at-the-market" offerings pursuant to the Series D ATM Agreement and a prospectus supplement dated October 17, 2013 (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 ranging from $24.00 to $24.38 per share. We received net proceeds of $1,621 in connection with these sales.
•
On November 28, 2013, we spudded our WMRU-8 oil well from our West McArthur River Production Facility.  WMRU-8 was drilled as a directional well into a separate fault block to the main producing structure in the West McArthur River Field.  The well reached a total depth of 15,536 feet on February 12, 2014 after successfully drilling and logging the Jurassic and West Forelands secondary targets.  The well is currently being completed in the Hemlock formation.
On February 3, 2014, we entered into a New Loan Agreement with Apollo Investment Corporation, as administrative agent. Proceeds from the new $175,000 term credit facility were used to repay the previously existing credit facility, repay all obligations to Miller Energy Income 2009-A, LP, acquire the North Fork Properties and provide working capital (see Note 15 - Subsequent Events).
On February 6, 2014, we entered into the Trans-Foreland Pipeline Development Agreement with Tesoro Alaska Company (“Tesoro”) and Trans-Foreland Pipeline Company, LLC (“TFPC”). The agreement allows for the construction of the Trans-Foreland Pipeline to connect our Kustatan Production Facility on the west side of the Cook Inlet to the Kenai Pipe Line Company tank farm of the east side. Completion of the pipeline would provide numerous advantages to us, including reduced transportation cost and delays.
On February 12, 2014, our Board of Directors appointed John M. Brawley as our Chief Financial Officer. In addition, the Board of Directors approved a change in the title of David J. Voyticky to President, as he previously held the title of President and Acting Chief Financial Officer.

Fiscal 2014 Outlook
As we head into the final 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 our WMRU-8 onshore oil well, and are 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

30
Table of Contents
(Dollars in thousands, except per share data and per unit data)

regarding the success of these development and recompletion efforts. Our current fiscal 2014 capital budget approved by our Board of Directors 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. We expect to spend approximately $200,000 of our approved capital budget during fiscal 2014. 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 nine months ended January 31, 2014 was $94.58 and $100.16, respectively, as compared to $98.77 and $101.42, 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 nine months ended January 31, 2014 was 225,377 boe and 543,717 boe as compared to 82,327 boe and 237,552 boe, respectively, for the same periods in the prior year.  
•
Capital Expenditures and Drilling Results: During the three and nine months ended January 31, 2014, we paid $28,253 and $95,374, 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.


31
Table of Contents
(Dollars in thousands, except per share data and per unit data)

Results of Operations

Three Months Ended January 31, 2014 Compared to Three Months Ended January 31, 2013
Revenues
 
For the Three Months Ended January 31,
 
 
 
 
 
2014
 
2013
 
$ Variance
 
% Variance
Oil revenues:
 
 
 
 
 
 
 
Cook Inlet
$
15,717

 
$
6,342

 
$
9,375

 
148
 %
Appalachian region
631

 
378

 
253

 
67

Total
$
16,348

 
$
6,720

 
$
9,628

 
143

Natural gas revenues:
 
 
 
 

 

Cook Inlet
$
28

 
$
13

 
$
15

 
115

Appalachian region
90

 
120

 
(30
)
 
(25
)
Total
$
118

 
$
133

 
$
(15
)
 
(11
)
Other revenues:
 
 
 
 

 

Cook Inlet
$
7

 
$
1,036

 
$
(1,029
)
 
(99
)
Appalachian region
155

 
110

 
45

 
41

Total
$
162

 
$
1,146

 
$
(984
)
 
(86
)
Total revenues
$
16,628

 
$
7,999

 
$
8,629

 
108
 %

Net Production
 
For the Three Months Ended January 31,
 
 
 
 
 
2014
 
2013
 
Variance
 
% Variance
Oil volume - bbls:
 
 
 
 
 
 
 
Cook Inlet
212,441
 
71,700
 
140,741

 
196
 %
Appalachian region
6,981
 
4,062
 
2,919

 
72

Total
219,422
 
75,762
 
143,660

 
190

Natural gas volume1- mcf:
 
 
 
 
 
 
 
Cook Inlet
5,277
 
7,588
 
(2,311
)
 
(30
)
Appalachian region
30,450
 
31,799
 
(1,349
)
 
(4
)
Total
35,727
 
39,387
 
(3,660
)
 
(9
)
Total production2 - boe:
 
 
 
 
 
 
 
Cook Inlet
213,321
 
72,965
 
140,356

 
192

Appalachian region
12,056
 
9,362
 
2,694

 
29

Total
225,377
 
82,327
 
143,050

 
174
 %
———————
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.


32
Table of Contents
(Dollars in thousands, except per share data 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 third quarter of 2014 were 4% below the same period last year. For the three months ended January 31, 2014, realized oil prices averaged $94.58 per bbl, compared with $98.77 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 third quarter of fiscal 2014 decreased over the same period last year. For the three months ended January 31, 2014, realized natural gas prices averaged $3.39 per mcf, compared with $3.86 per mcf for the same period in the prior year. The decrease in the averaged realized gas prices resulted from a decrease in gas sold in Alaska under our new natural gas sales contract in the Cook Inlet region which provides for a contract price of $6.00 per mcf.
Oil Revenues
During the third quarter of fiscal 2014 oil revenues totaled $16,348, which represents a 143% increase over the same period in the prior year. Oil revenues represented 98% of our third quarter consolidated total revenues. Net barrels sold for the current period was 172,856, which represents a 103,777 bbl, or 150%, increase as compared to the same period last year. The increase in barrels sold was partially offset by a 4% decrease in realized oil prices.
The increase in net barrels sold results from an increase in oil production for the period. Oil production increased 143,660 bbls, or 190%, to 219,422 bbls. The increase was driven by a 140,741 bbl increase in the Cook Inlet region and a 2,919 bbl increase in the Appalachian region. The production increase in the Cook Inlet region resulted from RU-1A, RU-2A and RU-5B in our Redoubt Shoals field and our new Sword #1 well being on line during the three months ended January 31, 2014. The production increase in the Appalachian region is a result of new production from our CPP H-1 and Brimstone H-1 wells.
The difference between net barrels sold and net barrels produced is approximately equal to the change in quantity of our crude oil inventory balance during the period. Although we attempt to minimize crude oil inventory balances, shipping schedules in the Cook Inlet region are beyond our control and occasionally require us to store crude oil. In addition, we are required to maintain certain inventory levels in third party pipelines and storage facilities. As noted in the following table, we experienced an above average increase in inventory levels during the third quarter of fiscal 2014, which significantly reduced the potential revenue that may have resulted from our increased oil production during the current period. The increase in our inventory balance primarily resulted from shipping schedules and a requirement to maintain increased inventory levels in third party facilities in the Cook Inlet region.

 
For the Three Months Ended January 31, 2014
 
Cook Inlet
 
Appalachian
 
Total
In barrels:
 
 
 
 
 
Beginning inventory balance
29,433

 
17,357

 
46,790

Gross production
254,211

 
14,330

 
268,541

Gross sales
(197,717
)
 
(13,734
)
 
(211,451
)
Pipeline adjustments
153

 
—

 
153

Ending inventory balance
86,080

 
17,953

 
104,033

 
 
 
 
 
 
Net change in inventory
56,647

 
596

 
57,243



33
Table of Contents
(Dollars in thousands, except per share data and per unit data)

Natural Gas Revenues
During the third quarter of fiscal 2014, natural gas revenues totaled $118, which was 11% lower than the same period in the prior year. The decline resulted from a combination of a 12% decrease in average realized prices and a 9% decrease in production. Natural gas represented 1% of our third quarter consolidated total revenues. The following summarizes our natural gas sales and production activity during the current period.
 
For the Three Months Ended January 31, 2014
 
Cook Inlet
 
Appalachian
 
Total
Natural gas production - mcf:
 
 
 
 
 
Gross gas produced
239,639

 
68,601

 
308,240

Net gas produced
238,603

 
30,450

 
269,053

Fuel gas used
233,326

 
—

 
233,326

 
 
 
 
 
 
Natural gas sales - mcf:
 
 
 
 
 
Gross gas sold
6,313

 
67,807

 
74,120

Net gas sold
5,277

 
29,656

 
34,933


Other Revenues
Other revenues primarily represent revenues generated from contracts for road building, plugging, drilling, maintenance and repair of third party wells as well as rental income we receive for services and use of facilities in the Cook Inlet region. During the third quarters of fiscal 2014 and 2013, other revenues totaled $162 and $1,146, 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. The decline is primarily a result of additional revenue in 2013 from a completed road building contract and limited activity from other projects in the current period.

Cost and Expenses
The table below presents a comparison of our expenses for the three months ended January 31, 2014 and 2013:
 
For the Three Months Ended January 31,
 
 
 
 
 
2014
 
2013
 
$ Variance
 
% Variance
Oil and gas operating costs
$
5,821

 
$
4,118

 
$
1,703

 
41
 %
Cost of other revenues
256

 
1,051

 
(795
)
 
(76
)
General and administrative
7,587

 
5,518

 
2,069

 
37

Exploration expense
352

 
187

 
165

 
88

Depreciation, depletion and amortization
7,642

 
3,341

 
4,301

 
129

Accretion of asset retirement obligation
305

 
284

 
21

 
7

Other operating expense, net
1,250

 
—

 
1,250

 
(100
)
Total costs and expenses
$
23,213

 
$
14,499

 
$
8,714

 
60
 %


34
Table of Contents
(Dollars in thousands, except per share data and per unit data)

Oil and Gas Operating Costs
The table below presents a comparison of our oil and gas operating costs for the three months ended January 31, 2014 and 2013.
 
For the Three Months Ended January 31,
 
 
 
 
 
2014
 
2013
 
$ Variance
 
% Variance
Third party transportation costs
$
1,411

 
$
563

 
$
848

 
151
%
Lease operating expense
4,410

 
3,555

 
855

 
24

Total oil and gas operating costs
$
5,821

 
$
4,118

 
$
1,703

 
41
%
 
 
 
 
 
 
 
 
Lease operating expense
$
4,410

 
$
3,555

 

 
 
Costs allocated to inventory
1,114

 
(215
)
 

 
 
Gross production costs
5,524

 
3,340

 
 
 
 
Gross oil and gas produced - boe
319,914

 
115,731

 
 
 
 
Lease operating expense per boe produced
$
17.27

 
$
28.86

 
 
 
 

Oil and gas operating costs increased $1,703 from third quarter fiscal 2013, or 41%. The increase in oil and gas operating costs is primarily attributable to increased production. The increased production creates additional labor and camp facility costs, well maintenance and transportation costs. The majority of our production costs are fixed. For the three months ended January 31, 2014 our lease operating expense per boe was $17.27 per bbl as compared to $28.86 per bbl in the same period last year. We expect our lease operating expense per boe produced to continue to decline as production increases.
Cost of Other Revenues
Our business is primarily focused on exploration and production activities. The cost of other revenues represent costs of services to third parties as a result of excess capacity and are derived from the direct labor costs of employees associated with these services, as well as costs associated with equipment, parts and repairs. During the third quarter of fiscal 2014, we experienced decreases in the cost of other revenues in the Cook Inlet region as we had limited projects during the period.
 
For the Three Months Ended January 31,
 
 
 
 
 
2014
 
2013
 
$ Variance
 
% Variance
Direct labor
$
153

 
$
466

 
$
(313
)
 
(67
)%
Equipment
24

 
397

 
(373
)
 
(94
)
Repairs
67

 
74

 
(7
)
 
(9
)
Insurance
—

 
36

 
(36
)
 
(100
)
Other
12

 
78

 
(66
)
 
(85
)
Total
$
256

 
$
1,051

 
$
(795
)
 
(76
)%


35
Table of Contents
(Dollars in thousands, except per share data and per unit data)

General and Administrative Expenses
General and administrative ("G&A") expenses include the costs of our employees, related benefits, professional fees, travel and other miscellaneous general and administrative expenses.
 
For the Three Months Ended January 31,
 
 
 
 
 
2014
 
2013
 
$ Variance
 
% Variance
Salaries
$
1,551

 
$
966

 
$
585

 
61
 %
Professional fees
2,768

 
802

 
1,966

 
245

Travel
502

 
413

 
89

 
22

Employee benefits
609

 
304

 
305

 
100

Stock-based compensation
1,440

 
2,652

 
(1,212
)
 
(46
)
Other
717

 
381

 
336

 
88

Total
$
7,587

 
$
5,518

 
$
2,069

 
37
 %

G&A expenses increased $2,069 from third quarter fiscal 2013, or 37%. Salaries increased 61% from the same period in the prior fiscal year due to 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 245% 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 46% due to the expense associated with fully vested awards exceeding the expense associated with newly granted awards. During the third quarter of fiscal 2014, our Compensation Committee approved an additional grant of 800,000 options to purchase our common stock which are contingent upon shareholder approval of an increase in the number of shares available under the 2011 share-based compensation plan. We will recognize stock-based compensation upon shareholder approval.
Exploration Expense
Exploration expense consists of abandonments of drilling locations, dry hole costs, delay rentals, geological and geophysical costs, and the impairment, amortization and abandonment associated with leases on unproved properties.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization ("DD&A") expenses include the 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 January 31,
 
 
 
 
 
2014
 
2013
 
$ Variance
 
% Variance
Depletion:
 
 
 
 
 
 
 
Cook Inlet region
$
6,411

 
$
2,141

 
$
4,270

 
199
 %
Appalachian region
215

 
199

 
16

 
8

 
6,626

 
2,340

 
4,286

 
183

Depreciation:
 
 
 
 


 


Cook Inlet region
119

 
60

 
59

 
98

Appalachian region
897

 
941

 
(44
)
 
(5
)
 
1,016

 
1,001

 
15

 
1

Total DD&A
$
7,642

 
$
3,341

 
$
4,301

 
129
 %

The increase in DD&A is primarily a result of increased production from the Cook Inlet region during the three months ended January 31, 2014.
Other Operating Expense
During the third quarter of fiscal 2014, we recorded a loss for an estimated settlement in the amount of $1,250 related to the CNX lawsuit settlement, (see Note 13 - Litigation).


36
Table of Contents
(Dollars in thousands, except per share data and per unit data)

Other Income and Expense
The following table shows the components of other income and expense for the third quarters indicated.
 
For the Three Months Ended January 31,
 
 
 
 
 
2014
 
2013
 
$ Variance
 
% Variance
Interest expense, net
$
(407
)
 
$
(1,117
)
 
$
(710
)
 
(64
)%
Gain (loss) on derivatives, net
1,677

 
(1,681
)
 
(3,358
)
 
(200
)
Other income, net
42

 
25

 
(17
)
 
(68
)
Total
$
1,312

 
$
(2,773
)
 
$
(4,085
)
 
(147
)%

Interest Expense, Net
Interest expense, net, decreased $710 from the third quarter of fiscal 2013, or 64%. The decrease in interest expense resulted from an increase in the percentage of interest expense that could be capitalized on self-constructed assets.
Gain (Loss) on Derivatives, Net
We experience earnings volatility as a result of not using hedge accounting to account for changes in commodity prices. As the positions 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 third quarter of fiscal 2014, we recorded a $1,677 gain on derivatives, as compared to a $1,681 loss on derivatives in the third quarter of fiscal 2013.

37
Table of Contents
(Dollars in thousands, except per share data and per unit data)

Results of Operations

Nine Months Ended January 31, 2014 Compared to Nine Months Ended January 31, 2013
Revenues
 
For the Nine Months Ended January 31,
 
 
 
 
 
2014
 
2013
 
$ Variance
 
% Variance
Oil revenues:
 
 
 
 
 
 
 
Cook Inlet
$
45,117

 
$
21,153

 
$
23,964

 
113
 %
Appalachian region
1,895

 
1,157

 
738

 
64

Total
$
47,012

 
$
22,310

 
$
24,702

 
111

Natural gas revenues:
 
 
 
 
 
 

Cook Inlet
$
380

 
$
41

 
$
339

 
827

Appalachian region
291

 
287

 
4

 
1

Total
$
671

 
$
328

 
$
343

 
105

Other revenues:
 
 
 
 
 
 

Cook Inlet
$
141

 
$
3,835

 
$
(3,694
)
 
(96
)
Appalachian region
608

 
598

 
10

 
2

Total
$
749

 
$
4,433

 
$
(3,684
)
 
(83
)
Total revenues
$
48,432

 
$
27,071

 
$
21,361

 
79
 %

Net Production
 
For the Nine Months Ended January 31,
 
 
 
 
 
2014
 
2013
 
Variance
 
% Variance
Oil volume - bbls:
 
 
 
 
 
 
 
Cook Inlet
496,349
 
206,290
 
290,059

 
141
 %
Appalachian region
19,789
 
12,404
 
7,385

 
60

Total
516,138
 
218,694
 
297,444

 
136

Natural gas volume1- mcf:
 
 
 
 
 
 

Cook Inlet
77,928
 
14,513
 
63,415

 
437

Appalachian region
87,547
 
98,630
 
(11,083
)
 
(11
)
Total
165,475
 
113,143
 
52,332

 
46

Total production2 - boe:
 
 
 
 
 
 

Cook Inlet
509,337
 
208,709
 
300,628

 
144

Appalachian region
34,380
 
28,843
 
5,537

 
19

Total
543,717
 
237,552
 
306,165

 
129
 %
———————
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.


38
Table of Contents
(Dollars in thousands, except per share data 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 first nine months of 2014 were 1% below the same period last year. For the nine months ended January 31, 2014, realized oil prices averaged $100.16 per bbl, compared with $101.42 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 third quarter of fiscal 2014 were substantially higher than the same period last year. For the nine months ended January 31, 2014, realized natural gas prices averaged $4.06 per mcf, compared with $3.06 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 which provides for a contract price of $6.00 per mcf.
Oil Revenues
During the first nine months of fiscal 2014, oil revenues totaled $47,012, which represents a 111% increase over the same period in the prior year. Oil revenues represented 97% of our nine month consolidated total revenues. Net barrels sold for the current period was 469,387, which represents a 260,866 bbl, or 125%, increase as compared to the same period last year. The increase in barrels sold was partially offset by a 1% decrease in realized oil prices.
The increase in net barrels sold results from an increase in oil production for the period. Oil production increased 297,444 bbls, or 136%, to 516,138 bbls. The increase was driven by a 290,059 bbls increase in the Cook Inlet region and a 7,385 bbls increase in the Appalachian region. The production increase in the Cook Inlet region resulted from RU-1A, RU-2A and RU-5B in our Redoubt Shoals field and our new Sword #1 well being on line during the nine months ended January 31, 2014. The production increase in the Appalachian region is a result of new production from our CPP H-1 and Brimstone H-1 wells.
The difference between net barrels sold and net barrels produced is approximately equal to the change in quantity of our crude oil inventory balance during the period. Although we attempt to minimize crude oil inventory balances, shipping schedules in the Cook Inlet region are beyond our control and occasionally require us to store crude oil. In addition, we are required to maintain certain inventory levels in third party pipelines and storage facilities. As noted in the following table, we experienced an above average increase in inventory levels during the first nine months of fiscal 2014, which significantly reduced the potential revenue that may have resulted from our increased oil production during the current period. The increase in our inventory balance primarily resulted from shipping schedules and a requirement to maintain increased inventory levels in third party facilities in the Cook Inlet region.

 
For the Nine Months Ended January 31, 2014
 
Cook Inlet
 
Appalachian
 
Total
In barrels:
 
 
 
 
 
Beginning inventory balance
30,130

 
24,063

 
54,193

Gross production
595,082

 
37,953

 
633,035

Gross sales
(537,782
)
 
(44,063
)
 
(581,845
)
Pipeline adjustments
(1,350
)
 
—

 
(1,350
)
Ending inventory balance
86,080

 
17,953

 
104,033

 
 
 
 
 
 
Net change in inventory
55,950

 
(6,110
)
 
49,840



39
Table of Contents
(Dollars in thousands, except per share data and per unit data)

Natural Gas Revenues
During the first nine months of fiscal 2014, natural gas revenues totaled $671, which was 105% 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 46% 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 1% of our consolidated total revenues for the nine month period. The following summarizes our natural gas sales and production activity during the current period.
 
For the Nine Months Ended January 31, 2014
 
Cook Inlet
 
Appalachian
 
Total
Natural gas production - mcf:
 
 
 
 
 
Gross gas produced
766,145

 
195,439

 
961,584

Net gas produced
750,850

 
87,547

 
838,397

Fuel gas used
672,922

 
—

 
672,922

 
 
 
 
 
 
Natural gas sales - mcf:
 
 
 
 
 
Gross gas sold
93,223

 
195,439

 
288,662

Net gas sold
77,928

 
87,547

 
165,475


Other Revenues
Other revenues primarily represent revenues generated from contracts for road building, plugging, drilling, maintenance and repair of third party wells as well as rental income we receive for services and use of facilities in the Cook Inlet region. During the first nine months of fiscal 2014 and 2013, other revenues totaled $749 and $4,433, respectively. The decline is primarily a result of additional revenue in 2013 from a completed road building contract and limited activity from other projects during the current period.

Cost and Expenses
The table below presents a comparison of our expenses for the nine months ended January 31, 2014 and 2013:
 
For the Nine Months Ended January 31,
 
 
 
 
 
2014
 
2013
 
$ Variance
 
% Variance
Oil and gas operating costs
$
18,249

 
$
12,963

 
$
5,286

 
41
 %
Cost of other revenues
844

 
4,084

 
(3,240
)
 
(79
)
General and administrative
21,092

 
17,056

 
4,036

 
24

Exploration expense
786

 
244

 
542

 
222

Depreciation, depletion and amortization
22,352

 
9,528

 
12,824

 
135

Accretion of asset retirement obligation
903

 
853

 
50

 
6

Other operating expense (income), net
1,250

 
(65
)
 
1,315

 
(2,023
)
Total costs and expenses
$
65,476

 
$
44,663

 
$
20,813

 
47
 %


40
Table of Contents
(Dollars in thousands, except per share data and per unit data)

Oil and Gas Operating Costs
The table below presents a comparison of our oil and gas operating costs for the nine months ended January 31, 2014 and 2013:
 
For the Nine Months Ended January 31,
 
 
 
 
 
2014
 
2013
 
$ Variance
 
% Variance
Third party transportation costs
$
3,023

 
$
2,011

 
$
1,012

 
50
%
Lease operating expense
15,226

 
10,952

 
4,274

 
39

Total oil and gas operating costs
$
18,249

 
$
12,963

 
$
5,286

 
41
%
 
 
 
 
 
 
 
 
Lease operating expense
$
15,226

 
$
10,952

 
 
 
 
Costs allocated to inventory
(378
)
 
114

 
 
 
 
Gross production costs
14,848

 
11,066

 
 
 
 
Gross oil and gas produced - boe
793,299

 
334,972

 
 
 
 
Lease operating expense per boe produced
$
18.72

 
$
33.04

 
 
 
 

Oil and gas operating costs increased $5,286 from the first nine months of fiscal 2013, or 41%. The increased oil and gas operating costs are primarily attributable to increased production. The increased production creates additional labor and camp facility costs, well maintenance and transportation costs. The majority of our production costs are fixed. For the nine months ended January 31, 2014 our lease operating expense per boe produced was $18.72 as compared to $33.04 in the same period last year. We expect our lease operating expense per boe produced to continue to decline as production increases.
Cost of Other Revenues
Our business is primarily focused on exploration and production activities. The cost of other revenues represent costs of services to third parties as a result of excess capacity and are derived from the direct labor costs of employees associated with these services, as well as costs associated with equipment, parts and repairs. During the first nine months of fiscal 2014, we experienced decreases in the cost of other revenues in the Cook Inlet region as we had limited projects during the period.
 
For the Nine Months Ended January 31,
 
 
 
 
 
2014
 
2013
 
$ Variance
 
% Variance
Direct labor
$
458

 
$
2,776

 
$
(2,318
)
 
(84
)%
Equipment
99

 
709

 
(610
)
 
(86
)
Repairs
253

 
402

 
(149
)
 
(37
)
Insurance
—

 
91

 
(91
)
 
(100
)
Other
34

 
106

 
(72
)
 
(68
)
Total
$
844

 
$
4,084

 
$
(3,240
)
 
(79
)%


41
Table of Contents
(Dollars in thousands, except per share data and per unit data)

General and Administrative Expenses
General and administrative ("G&A") expenses include the costs of our employees, related benefits, professional fees, travel and other miscellaneous general and administrative expenses.
 
For the Nine Months Ended January 31,
 
 
 
 
 
2014
 
2013
 
$ Variance
 
% Variance
Salaries
$
3,927

 
$
2,749

 
$
1,178

 
43
 %
Professional fees
6,920

 
3,617

 
3,303

 
91

Travel
1,488

 
1,261

 
227

 
18

Employee benefits
1,433

 
735

 
698

 
95

Stock-based compensation
4,820

 
7,367

 
(2,547
)
 
(35
)
Other
2,504

 
1,327

 
1,177

 
89

Total
$
21,092

 
$
17,056

 
$
4,036

 
24
 %

G&A expenses increased $4,036 from the first nine months of fiscal 2013, or 24%. Salaries increased 43% from the same period in the prior fiscal year due to additions to our engineering and support staff in the Cook Inlet region, and as a result of salary increases for our named executive officers effective as of July 17, 2013. Professional fees increased 91% over the same period last year due to an increase in accounting, capital-raising, legal and investor relations activities during the period. Stock-based compensation declined 35% due to the expense associated with fully vested awards exceeding the expense associated with newly granted awards. During the nine months of fiscal 2014, our Compensation Committee approved an additional grant of 391,000 shares of restricted stock and 8,129,996 options to purchase our common stock which are contingent upon shareholder approval of an increase in the number of shares available under the 2011 share-based compensation plan. We will recognize stock-based compensation upon shareholder approval. On March 10, 2014, certain officers entered into an amendment to their employment agreements with the Company under which the 7,299,996 options to purchase shares of our common stock will no longer be granted (see Note 9 - Stock-Based Compensation). 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 the Cook Inlet and Appalachian regions.
Exploration Expense
Exploration expense consists of abandonments of drilling locations, dry hole costs, delay rentals, geological and geophysical costs, and the impairment, amortization and abandonment associated with leases on unproved properties.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization ("DD&A") expenses include the 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 Nine Months Ended January 31,
 
 
 
 
 
2014
 
2013
 
$ Variance
 
% Variance
Depletion:
 
 
 
 
 
 
 
Cook Inlet region
$
18,405

 
$
6,601

 
$
11,804

 
179
%
Appalachian region
753

 
639

 
114

 
18

 
19,158

 
7,240

 
11,918

 
165

Depreciation:
 
 
 
 
 
 


Cook Inlet region
364

 
178

 
186

 
104

Appalachian region
2,830

 
2,110

 
720

 
34

 
3,194

 
2,288

 
906

 
40

Total DD&A
$
22,352

 
$
9,528

 
$
12,824

 
135
%

The increase in DD&A is primarily a result of increased production from the Cook Inlet region during the nine months ended January 31, 2014 and Rig-35 being in service during the nine months ended January 31, 2014.

42
Table of Contents
(Dollars in thousands, except per share data and per unit data)

Other Operating Expense (Income), Net
During the nine months ended January 31, 2014, we recorded a loss for an estimated settlement in the amount of $1,250 related to the CNX lawsuit settlement, (see Note 13 - Litigation).

Other Income and Expense
The following table shows the components of other income and expense for the nine months ended January 31, 2014 and 2013.
 
For the Nine Months Ended January 31,
 
 
 
 
 
2014
 
2013
 
$ Variance
 
% Variance
Interest expense, net
$
(4,051
)
 
$
(2,785
)
 
$
1,266

 
45
 %
Gain (loss) on derivatives, net
(5,589
)
 
5,215

 
10,804

 
207

Other income (expense), net
26

 
(350
)
 
(376
)
 
(107
)
Total
$
(9,614
)
 
$
2,080

 
$
11,694

 
562
 %

Interest Expense, Net
Interest expense, net, increased $1,266 from the first nine months of fiscal 2013, or 45%. The increase in interest expense resulted from a combination of higher debt balances, a reduction in the percentage of interest expense that could be capitalized on self-constructed assets and administration fees on the Prior Credit Facility.
Gain (Loss) on Derivatives, Net
We experience earnings volatility as a result of not using hedge accounting to account for changes in commodity prices. As the positions 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 first nine months of fiscal 2014, we recorded a $5,589 loss on derivatives as compared to a $5,215 gain on derivatives during the first same period of fiscal 2013.


43
Table of Contents
(Dollars in thousands, except per share data and per unit data)

Liquidity and Capital Resources

Our cash flows, both in the short-term and long-term, are impacted by highly volatile oil and natural gas prices. Significant deterioration in commodity prices negatively impacts revenues, earnings and cash flows, capital spending, and potentially our liquidity. Sales volumes and costs also impact cash flows; however, historically these have not been as volatile or as impactful as commodity prices in the short-term.
Our long-term cash flows are highly dependent on our success in efficiently developing current reserves and economically finding, developing and acquiring additional recoverable reserves. Cash investments are required continuously to fund exploration and development projects and acquisitions, which are necessary to offset the inherent declines in production and proven reserves. We may not be able to find, develop or acquire additional reserves to replace our current and future production at acceptable costs, which could materially adversely affect our future liquidity. For a discussion of risk factors related to our business and operations, please refer to the section entitled "Risk Factors" in our Annual Report on Form 10-K for the fiscal year ended April 30, 2013, as amended.
We may elect to utilize proceeds from the sales of both debt and equity in the capital markets, or proceeds from the occasional sale of nonstrategic assets to supplement our liquidity and capital resource needs.
For the three and nine months ended January 31, 2014, we experienced an operating loss. We anticipate that our operating expenses will continue to increase as we fully develop our assets in the Cook Inlet and Appalachian regions. Although we expect an increase in revenues from these development activities, we will continue depleting our cash resources to fund drilling and workover activities as well as other operating expenses until such time as we are able to significantly increase our revenues above costs.
We believe that the liquidity and capital resource alternatives available to us through the public offerings of Series C and Series D Preferred Stock, in both "at-the-market" sales in additional underwritten offerings, combined with additional debt available under any Future Credit Facility and internally generated cash flows and other potential sources of funds, will be adequate to fund our short-term and long-term operations, including our capital budget, repayment of debt maturities, and any amount that may ultimately be paid in connection with contingencies; however, the Prior Credit Facility gave Apollo control of certain operational accounts (the "Restricted Accounts").
Apollo's control notwithstanding, absent an event of default, the Prior Credit Facility required that Apollo release to us funds needed to pay for approved operational activity ("Required Releases"), subject to certain limitations on the order in which we undertake new projects, and for the payment of certain permitted expenses that arise in the ordinary course of business. The release of funds for other purposes was subject to Apollo's discretion, except that, absent an event of default and so long as at least half of these funds are spent on projects included in our plan of development, we did have the right to use 50% of all proceeds raised from sales of equity securities in excess of $20,000 on such matters as we saw fit. We reached this $20,000 threshold on October 5, 2012, the date of the initial public offering of Series C Preferred Stock. The intent of the restrictions in the Prior Credit Facility on our ability to access cash in our accounts was to require the Company allocate available cash to high-priority projects first and to control spending that is not strongly linked to the development of our existing assets. To date, the restrictions have not impeded our ability to run the business in any way, except that we have requested from time to time that Apollo agree to change the priorities of certain projects on our approved plan of development to better respond to changing market conditions in the Cook Inlet region. Periodic adjustments to our approved plan of development were contemplated by the terms of the Prior Credit Facility, and, to date, Apollo has granted our requests when made. Were an event of default to have occurred under the Prior Loan Agreement, including a failure to comply with the restrictive covenants contained in the Prior Loan Agreement, Apollo would have had the authority to prevent our accessing the Restricted Accounts. We do not anticipate that the restrictions placed on our accounts under the Prior Credit Facility will interfere with, or require any alteration of, management's overall plans in the future. On December 9, 2013, we received an amendment and waiver from Apollo ("Eighth Amendment") which, among other matters, waived our non-compliance with the interest coverage ratio requirement as of October 31, 2013 and amended our next testing date for the interest coverage ratio to October 31, 2014. Subsequent to quarter end, we refinanced the Prior Credit Facility. As we refinanced the Prior Credit Facility, we were not required to calculate compliance with the Prior Loan Agreement's financial covenants at January 31, 2014.
Pursuant to the Acknowledgment and Amendment No. 2 to the Prior Loan Agreement, upon each sale of our Series C Preferred Stock, we had previously agreed to deposit a portion of the proceeds of the sale into a separate account (the "Dividend Account") in an amount at least equal to the dividends scheduled to come due on our Series B Preferred Stock and our Series C Preferred Stock on or prior to September 3, 2013. On September 3, 2013, we paid a cash dividend on the Series B Preferred Stock and our Series C Preferred Stock of approximately $6.05 and approximately $0.67 per share, respectively, in accordance with the terms of the Series B Preferred Stock and the Series C Preferred Stock as set forth in our charter. Following this payment of dividends, the Dividend Account will remain empty.

44
Table of Contents
(Dollars in thousands, except per share data and per unit data)

Current restricted cash balances include amounts held in escrow to secure Company related credit cards. As of January 31, 2014 and April 30, 2013, current restricted cash also includes $3,447 and $7,144 of cash temporarily held in an account that is controlled by our lender and the April 30, 2013 balance is inclusive of the Dividend Account. Non-current restricted cash balances include amounts held in escrow to provide for the future plugging and abandonment of wells, the possible dismantling of our off-shore platform, performance bonds, and general liability bonds.

Sources and Uses of Cash
The following table presents the sources and uses of our cash and cash equivalents for the periods presented:
 
For the Nine Months Ended January 31,
 
2014
 
2013
Sources of cash and cash equivalents:
 
 
 
Net cash provided by operating activities
$
15,277

 
$
6,137

Proceeds from borrowings, net of debt acquisition costs
18,100

 
36,146

Proceeds from Alaska production tax credits
18,561

 
—

Proceeds from sale of equipment
—

 
2,000

Exercise of equity rights
4,538

 
3,832

Issuance of preferred stock, net of issuance costs
58,811

 
18,872

Release of restricted cash
1,665

 
—

Other proceeds
3

 
—

 
116,955

 
66,987

Uses of cash and cash equivalents:
 
 
 
Cash dividends
(5,646
)
 
(285
)
Capital expenditures for oil and gas properties
(94,388
)
 
(23,213
)
Prepayment of drilling costs
(2,302
)
 
—

Purchase of equipment and improvements
(986
)
 
(9,606
)
North Fork purchase deposit
(3,000
)
 
—

Payments on debt
—

 
(24,130
)
Redemption of preferred stock
—

 
(11,240
)
Increase in restricted cash
—

 
(992
)
 
(106,322
)
 
(69,466
)
 


 
 
Increase in cash and cash equivalents
$
10,633

 
$
(2,479
)

Net Cash Provided by Operating Activities
Our sources of capital and liquidity are partially supplemented by cash flows from operations, both in the short-term and long-term. These cash flows, however, are highly impacted by volatility in oil and natural gas prices. The factors in determining operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, asset retirement obligation ("ARO") accretion, non-cash compensation, and deferred income tax expense, which affect earnings but do not affect cash flows.
Net cash provided by operating activities for the first nine months of fiscal 2014 totaled $15,277, up $9,140 from the same period in fiscal 2013. The increase resulted primarily from a favorable shift in the timing of cash receipts and payments to vendors in the ordinary course of business and an increase in net loss excluding non-cash expenses of $7,651.
Proceeds from Credit Facilities and Other Items
During the first nine months of fiscal 2013, borrowings under our Prior Credit Facility totaled $40,000. In connection with the establishment of the new facility, we incurred approximately $3,854 in debt acquisition costs. The proceeds were used to repay our Guggenheim credit facility and redeem our outstanding Series A Cumulative Preferred Stock. During the first nine months of fiscal 2014, borrowings under our Prior Credit Facility totaled $20,000, and we incurred $1,900 in loan origination and amendment fees. For additional information on the credit facilities, please see Note 7 - Debt.

45
Table of Contents
(Dollars in thousands, except per share data and per unit data)

During the first nine months of our 2014 fiscal year, 1,581,654 stock options and warrants were exercised that provided $4,538 in proceeds from the exercise of equity rights compared to the $3,832 reflected in the same period for the prior year. The decrease was due to fewer stock options and warrants exercised in the current year as compared to the same period in the prior year.
The significant increase in net cash flows provided by financing activities was a result of $36,038 received from issuances of our Series C Preferred Stock, partially offset by issuance costs of $1,973, and $26,666 received from the issuance of our Series D Preferred Stock, partially offset by issuance costs of $1,920 during the first nine months of fiscal 2014. During the first nine months of fiscal 2013, we received $20,448 from issuances of our Series B Preferred Stock and our Series C Preferred Stock, partially offset by issuance costs of $1,576.
For the nine months ended January 31, 2014, release of restricted cash was $1,665 as compared to an increase in restricted cash of $992 in the same period last year. The classification of the net change in restricted cash is dependent on whether unrestricted cash is transferred to or from our restricted cash accounts, on a net basis.
Short-term restricted cash primarily relates to the Restricted Accounts controlled by Apollo and the Dividend Account, which is subject to contractual restriction discussed above. Apollo requires revenues and certain other items to be deposited directly into the Restricted Accounts. As Apollo controls the Restricted Accounts, it has the ability to prevent disbursements from those accounts to our unrestricted cash accounts; subject to the Required Releases discussed above. Amounts deposited into Restricted Accounts in excess of interest on the credit facility, lender fees, etcetera are generally released to us in a timely manner. Accordingly, the amount released from or transferred to our Restricted Accounts depends on hold backs and the timing of transfers at Apollo's discretion. In addition, prior to September 3, 2013, Apollo required we maintain a balance in the Dividend Account sufficient to meet certain dividend payments on our Series B and Series C Preferred Stock, and which we were, under the terms of the Prior Loan Agreement, prohibited from using for any other purpose.
Long-term restricted cash balances include amounts held in escrow to provide for the future plugging and abandonment of wells, the possible dismantling of our off-shore platform, performance bonds and general liability bonds. Amounts released from our long-term restricted cash accounts, if any, would be the result of a release from escrow by the beneficiary. Amounts transferred to our long-term restricted cash accounts result from bonding requirements for new wells and additions to our current bonding requirements.
During the nine months ended January 31, 2014, we paid $5,646 for quarterly dividends on our Series C Preferred Stock and Series D Preferred Stock. During the nine months ended January 31, 2013, we paid $285 for quarterly dividends on our Series C Preferred Stock.
Capital Expenditures and Alaska Production Tax Credits
We use a combination of operating cash flows, borrowings under credit facilities and, from time to time, issuances of debt or common stock to fund significant capital projects. Due to the volatility in oil and natural gas prices, our capital expenditure budgets, both in the short-term and long-term, are adjusted on a frequent basis to reflect changes in forecasted operating cash flows, market trends in drilling and acquisition costs, and production projections.
Total spending on capital projects increased significantly from the same period last year. For the nine months ending January 31, 2014, we incurred total capital expenditures of $127,946 which is inclusive of the increase in our capital accrual account of $32,572. Cash paid for net capital expenditures was $95,374 for the nine months ended January 31, 2014. Through the third quarter of fiscal 2014, we completed drilling of our RU-1A, RU-2A, RU-5B, RU-D1 and Sword #1 wells, and began drilling our Sword #1, WMRU-8 and Olson Creek #1 wells, all in the Cook Inlet region. During the third quarter of fiscal 2013, capital spending primarily related to the drilling of our Otter #1 well in the Cook Inlet region and the construction of Rig 35.
During the nine months ended January 31, 2014, we collected $21,578 related to our Alaska production tax credits applied for in prior periods, of which $18,561 related to expenditure and exploration based credits.
Prepayment of Drilling Costs
We occasionally are required to pay in advance for certain equipment rental and services related to our drilling activities. The advance payments are recorded in prepaid expenses at the time of payment and amortized to capital expenditures as the costs are incurred. At January 31, 2014, we had $2,302 in prepaid drilling costs and other capital related items.
North Fork Purchase Deposit    
Under the terms of the North Fork Purchase Agreement, we paid $3,000 in cash (the “Deposit”) to the North Fork Sellers during the first nine months of our 2014 fiscal year. The Deposit was applied toward the purchase price upon the closing of the acquisition of the North Fork Properties.


46
Table of Contents
(Dollars in thousands, except per share data and per unit data)

Liquidity
Cash and Cash Equivalents
As of January 31, 2014, we had $13,184 in cash and cash equivalents.
Debt and Available Credit Facilities
As of January 31, 2014, outstanding debt consisted of $71,960 under our Prior Credit Facility classified as long-term debt on the accompanying consolidated balance sheet. As of January 31, 2014 we had no additional borrowing capacity under our Prior Credit Facility.

Contractual Obligations
On June 29, 2012, we entered into a loan agreement with Apollo which provides for a $100,000 credit facility with an initial borrowing base of $55,000. In conjunction with the initiation of the Prior Credit Facility, we paid in full all outstanding principal and interest balances under the Guggenheim Credit Facility. Refer to Note 7 - Debt of the accompanying unaudited condensed consolidated financial statements for additional information regarding these credit facilities.
On September 24, 2012, we sold 25,750 shares of our Series B Preferred Stock for gross proceeds of $2,575.  We paid $167 of issuance costs which have been capitalized and are being amortized over the term of the instrument.  The outstanding Series B Preferred Stock is classified as long-term debt, in accordance with ASC 480.  See Note 7 - Debt in the Notes as set forth in the accompanying unaudited condensed consolidated financial statements.
On September 28, 2012, we sold 685,000 shares of our Series C Preferred Stock for gross proceeds of $15,755.  We incurred issuance costs of $1,335, yielding net proceeds of $14,420.  These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated September 28, 2012, and the Company's registration statement on Form S-3 (Registration No. 333-183750), which was declared effective by the SEC on September 18, 2012
The Series C Preferred Stock is classified as temporary equity in accordance with ASC 480 and is being accreted to redemption value through the earliest repayment date of November 1, 2017.  See Note 10 - Stockholders' Equity in the Notes as set forth in the accompanying unaudited condensed consolidated financial statements.
On October 12, 2012, we entered into the Series C ATM Agreement. This Series C ATM Agreement provides for the issuance by us of our common stock or Series C Preferred Stock, and for the subsequent sale of those shares into the market at the prevailing market price by MLV. These securities are registered for sale to the public pursuant to a prospectus, dated September 19, 2012, a prospectus supplement dated October 12, 2012, and our registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012. Under the Series C ATM Agreement, if and when we request MLV to engage in the sale of any or our securities, we will be obligated to pay to MLV a commission equal to 3.0% of the gross proceeds of any sale of our common stock and 3.5% of the gross proceeds of any sale of our Series C Preferred Stock. Although there are conditions on our initiating any new sale of securities and there are customary indemnities and cost reimbursement requirements, as described in the Series C ATM Agreement, there are no operational or financial covenants that restrict our operations.
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 in connection with the offering, from which MLV was paid a commission of $805. These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated May 7, 2013, and the Company's registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012.
On June 27, 2013, we entered into an Underwriting Agreement with MLV as representative for a group of underwriters for a follow-on "best efforts" offering of our Series C Preferred Stock. We sold an additional 335,000 shares of our Series C Preferred Stock, at a price of $21.50 per share. We received gross proceeds of $7,203 in connection with the offering, from which MLV was paid a commission of $547. These securities are registered for sale to the public pursuant to a prospectus, dated September

47
Table of Contents
(Dollars in thousands, except per share data and per unit data)

18, 2012, a prospectus supplement dated June 27, 2013, and the Company's registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012.
On September 25, 2013, we sold 1,000,000 shares of our Series D Preferred Stock, at a price of $25.00 per share. We incurred issuance costs of $1,875, yielding net proceeds of $23,125.  These securities are registered for sale to the public pursuant to a prospectus, dated September 18, 2012, a prospectus supplement dated September 25, 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 D Preferred Stock is classified in permanent equity in accordance with ASC 480 and is being accreted to redemption value through the earliest repayment date of September 30, 2018. See Note 10 - Stockholders' Equity in the Notes as set forth in the accompanying unaudited condensed consolidated financial statements.    
On October 17, 2013, we entered into the Series D ATM Agreement. This Series D ATM Agreement provides for the issuance by us of our Series D Preferred Stock, and for the subsequent sale of those shares into the market at the prevailing market price by MLV. These securities are registered for sale to the public pursuant to a prospectus, dated September 19, 2012, a prospectus supplement dated October 17, 2013, and our registration statement on Form S-3 (Registration No. 333-183750) which was declared effective by the SEC on September 18, 2012. Under the Series D ATM Agreement, if and when we request MLV to engage in the sale of Series D Preferred Stock, we will be obligated to pay to MLV a commission equal to 3.0% of the gross proceeds. Although there are conditions on our initiating any new sale of securities and there are customary indemnities and cost reimbursement requirements, as described in the Series D ATM Agreement, there are no operational or financial covenants that restrict our operations.
On November 22, 2013, CIE entered into a Purchase and Sale Agreement by and among Armstrong Cook Inlet, LLC, GMT Exploration Company, LLC, Dale Resources Alaska, LLC, Jonah Gas Company, LLC and Nerd Gas Company, LLC and CIE (the “Purchase Agreement”). The Purchase Agreement contemplated the acquisition by CIE of (i) a 100% working interest in oil and gas properties and related leases (consisting of approximately 15,465 net acres) in the Cook Inlet region of the State of Alaska, together with other associated rights, interests and assets and (ii) all the issued and outstanding membership interests of Anchor Point Energy, LLC, a limited liability company owning certain pipeline facilities and related assets which service the North Fork Properties, for $56,975 in cash and $5,000 of the Company’s 10.5% Fixed Rate/Floating Rate Series D Cumulative Redeemable Preferred Stock.
As of January 31, 2014 and for the third quarter of fiscal 2014, there were no additional material changes outside the ordinary course of business in our contractual obligations and commitments other than the aforementioned agreements.  For additional information regarding these obligations, please refer to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations-Contractual Cash Obligations and Commitments" contained in our Annual Report on Form 10-K for the fiscal year ended April 30, 2013, as amended, and incorporated by reference herein.

Non-GAAP Measures

Adjusted Earnings
Adjusted earnings before interest, taxes, depreciation and amortization ("EBITDA") is a significant performance metric used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts and others to assess:
•
the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
•
the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and
•
our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure.

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

•
depreciation, depletion and amortization;
•
write-off of deferred financing fees;
•
asset impairments;
•
(gain) loss on sale of assets;
•
accretion expense;
•
exploration costs;

48
Table of Contents
(Dollars in thousands, except per share data and per unit data)

•
(gain) loss from equity investment;
•
stock-based compensation expense;
•
(gain) loss from mark-to-market activities;
•
interest expense and interest (income);
•
non-recurring litigation settlements and matters

Our Adjusted EBITDA should not be considered as a substitute for net income (loss), operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
The following tables present a reconciliation of net income (loss) before income taxes to Adjusted EBITDA, our most directly comparable GAAP performance measure, for each of the periods presented:
 
For the Three Months Ended January 31,
 
For the Nine Months Ended January 31,
 
2014
 
2013
 
2014
 
2013
Loss before income taxes
$
(5,273
)
 
$
(9,273
)
 
$
(26,658
)
 
$
(15,512
)
Adjusted by:
 
 
 
 
 
 
 
Interest expense, net
407

 
1,117

 
4,051

 
2,785

Depreciation, depletion and amortization
7,642

 
3,341

 
22,352

 
9,528

Accretion of asset retirement obligation
305

 
284

 
903

 
853

Exploration costs
352

 
187

 
786

 
244

Stock-based compensation
1,546

 
2,652

 
5,120

 
7,367

Non-recurring litigation settlements and matters
1,998

 
—

 
1,998

 
—

Derivative contracts:
 
 
 
 
 
 
 
(Gain) loss on derivatives, net
(1,677
)
 
1,681

 
5,589

 
(5,215
)
Cash settlements
(983
)
 
(822
)
 
(2,765
)
 
2,276

Adjusted EBITDA
$
4,317

 
$
(833
)
 
$
11,376

 
$
2,326


Recent Accounting Pronouncements

In December 2011, the FASB issued ASU 2011-11, "Disclosures about Offsetting Assets and Liabilities," which increases disclosures about offsetting assets and liabilities. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and IFRS related to the offsetting of financial instruments. The existing GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance in ASU 2011-11 is effective for annual and interim reporting periods beginning on or after January 1, 2013. The disclosures should be applied retrospectively for all prior periods presented. We have adopted ASU 2011-11; however, it resulted in no material impact to our condensed consolidated financial statements.
There are no other recently issued accounting pronouncements that are expected to have a material impact on our financial condition, results of operations or cash flows.


49
Table of Contents
(Dollars in thousands, except per share data and per unit data)

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

Commodity Price Risk
Our major market risk exposure is in the pricing applicable to our oil production and, to some extent, our natural gas production. Our realized oil price is primarily driven by the NYMEX pricing of the West Texas Intermediate (Cushing, Oklahoma) and ANS (West Coast Alaskan North Slope) crude oil. Historically, pricing for oil and natural gas has been volatile and unpredictable and we expect this volatility to continue in the future. The prices we receive for oil and natural gas production depend on many factors outside our control, including weather, economic conditions, and the total supply of oil and natural gas available for sale in the market.
We have entered into hedging arrangements with respect to a portion of our projected future production through various derivatives that hedge the future prices received. These hedging activities are intended to support commodity sales prices at targeted levels and to manage our exposure to commodity price fluctuations. We do not hold or issue derivative instruments for speculative trading purposes. The use of hedging transactions also involves the risk that our counterparty will be unable to meet the financial terms of the transactions executed. We attempt to minimize this risk by entering into derivative transactions with a counterparty that is a creditworthy financial institution deemed by management and our lenders as a competent and competitive market maker.
The following tables summarize, for the periods indicated, our hedges currently in place through December 2016. All of these derivatives are accounted for as mark-to-market activities. All of these derivatives are variable-to-fixed price commodity swap contracts which price is based on the Brent crude oil futures as traded on the Intercontinental Exchange.
 
 
For the Quarter Ended (in barrels)
 
 
July 31,
 
October 31,
 
January 31,
 
April 30,
 
Total
Fiscal
 
Volume
 
Avg. Price
 
Volume
 
Avg. Price
 
Volume
 
Avg. Price
 
Volume
 
Avg. Price
 
Volume
 
Avg. Price
2014
 
—

 
$
—

 
—

 
$
—

 
—

 
$
—

 
191,400

 
$
102.92

 
191,400

 
$
102.92

2015
 
198,200

 
102.65

 
197,200

 
102.30

 
198,200

 
99.88

 
191,400

 
97.39

 
785,000

 
100.58

2016
 
198,200

 
97.04

 
197,200

 
96.66

 
198,200

 
95.81

 
194,000

 
93.46

 
787,600

 
95.75

2017
 
148,600

 
93.60

 
50,000

 
95.77

 
34,000

 
94.98

 
—

 
—

 
232,600

 
94.27

 
 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
1,996,600

 
$
98.16


Interest Rate Risk
We consider our interest rate risk exposure to be minimal as a result of fixing interest rates on 100% of our debt. At January 31, 2014, there was no float-rate debt that would expose us to market fluctuations in interest rates.


50
Table of Contents
(Dollars in thousands, except per share data and per unit data)

ITEM 4.    CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our CEO and our Chief Financial Officer ("CFO"), we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended, at the end of the period covered by this report (the “evaluation date”). In conducting its evaluation, management considered the material weaknesses in our disclosure controls and procedures and internal control over financial reporting described in Item 9A of our Annual Report on Form 10-K for the year ended April 30, 2013 as filed with the SEC on July 15, 2013 and as further amended on August 28, 2013.
As of the evaluation date, our CEO and CFO have concluded that we did not maintain disclosure controls and procedures that were effective in providing reasonable assurances that information required to be disclosed in our reports filed under the Securities Exchange act of 1934 was recorded, processed, summarized and reported within the time periods prescribed by SEC rules and regulations, and that such information was accumulated and communicated to our management to allow timely decisions regarding required disclosures.
Our management, including the CEO and CFO, does not expect that our disclosure controls and procedures will prevent all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system's objectives will be met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.
Changes in Internal Control over Financial Reporting
We are currently working to remediate the material weaknesses identified in our Annual Report on Form 10-K for the year ended April 30, 2013 as filed with the SEC on July 15, 2013 and as further amended on August 28, 2013. Such efforts have involved searching for additional accounting resources, engaging external accountants, and shifting the financial reporting responsibilities of certain accounting personnel to more closely align their talents with the necessary skill sets. We believe the adjustments we made to our existing accounting personnel and the use of external consultants during the nine months ended January 31, 2014 improved the quality of our financial reporting process; however, we are still searching for the appropriate accounting resources to supplement our finance and accounting department.
Other than the initiatives described above, there have been no changes in our internal control over financial reporting during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

51
Table of Contents
(Dollars in thousands, except per share data and per unit data)

PART II - OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS.

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 reached a settlement with the Plaintiff on January 24, 2014, wherein we would pay the Plaintiff $1,250 in exchange for their agreement to dismiss the case with prejudice. The Company recorded a loss of $1,250 related to this settlement in other operating expense (income), net in its consolidated statement of operations for the three and nine months ended January 31, 2014.
On May 17, 2011, we were served with a lawsuit filed in the United States District Court for the Eastern District of Tennessee at Knoxville by Troy D. Stafford, the former Chief Financial Officer of CIE.  The suit, styled Troy D. Stafford v. Miller Petroleum, Inc., Civil Action No. 3-11CV-206, claims that we terminated Mr. Stafford's employment without cause in contravention of the terms of the Purchase and Sale Agreement between us and the sellers of CIE ("PSA"), failed or refused to pay his salary, severance, percentage of purchase price, expenses or stock 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. On February 24, 2014, we filed a Motion to Dismiss with Prejudice because Mr. Stafford has made no effort whatsoever to prosecute his case since April 2, 2013, has missed filing deadlines, and has failed to appear to give his deposition both times we have noticed it. 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. 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. In February 2014, we received notice from a third party seeking to intervene in the case in order to secure payment of a debt allegedly owed by the Plaintiff to the third party. We believe this intervention would have no effect on the outcome of the case. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.
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

52
Table of Contents
(Dollars in thousands, except per share data and per unit data)

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 filed a Motion to Dismiss the case, which was denied on February 4, 2014 as to all defendants save Ford Graham. 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, which it has.
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 was unsuccessfully 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 the Court denied the motion on January 8, 2014.
On August 31, 2012, we terminated an agreement with Voorhees Equipment and Consulting, Inc. (“Voorhees”) for the construction and sale of the rig currently being used on the Osprey Platform, Rig 35, (the “Rig 35 Agreement”). We terminated the agreement based on our belief that Voorhees was in breach of its obligations thereunder.  Voorhees later indicated its desire to arbitrate claims it believes it has under invoices arising between May 29, 2012 and August 31, 2012.  We 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 elected to engage a private arbitrator to settle this dispute and have conducted discovery.  On September 18, 2013, we received a third-party complaint from Voorhees in connection with a lawsuit by Carlile Transportation Systems, Inc., in the Superior Court for the State of Alaska. The case is styled Carlile Transportation Systems, Inc. v. Voorhees Rig International, Inc. v. Cook Inlet Energy, LLC. The dispute is over unpaid transportation fees related to the transportation of equipment for Rig 35. These amounts were already the subject of the planned arbitration with Voorhees. As all disputes under the Rig 35 contract are subject to mandatory arbitration, we have filed a motion to compel arbitration, which was granted. We are currently in settlement discussions and have postponed the arbitration as we seek a settlement. We believe that any loss would be limited to the payment of the outstanding invoices of approximately $531, plus the cost of defense.
On February 7, 2014, we were served with a lawsuit filed by Vulcan Capital Corporation in the District Court for the Southern District of New York styled Vulcan Capital Corp. v. Miller Energy Resources, Inc. and PlainsCapital Bank. The suit asserts various causes of action against PlainsCapital Bank, and appears to assert the following causes of action against us: (1) Breach of Fiduciary Duty and (2) Concert of Action. The case stems from an agreement Plaintiff had with PlainsCapital Bank wherein Plaintiff secured certain loans by pledging four warrants to purchase our common stock that were issued as part of the

53
Table of Contents
(Dollars in thousands, except per share data and per unit data)

employment package of Ford F. Graham, our former President. Upon Plaintiff’s default of the loan agreement, PlainsCapital presented the warrants to us for transfer, and, after requesting certain tenders required under Tennessee law, we registered the transfer of the warrants. We have retained counsel and are preparing to file a responsive pleading. In addition, PlainsCapital Bank has agreed to indemnify us for our first $500 of expenses related to this dispute. Given the current state of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.

ITEM 1A.    RISK FACTORS.

For a detailed discussion of the risks and uncertainties associated with our business see "Risk Factors" in our 2013 Annual Report. Certain Risk Factors which have arisen as a result of our acquisition of the North Fork Unit, and those along with risk factors that apply to our newly issued Series D Preferred Stock, as well as new risks related to payments of dividends on our Series D Preferred Stock, Series C Preferred Stock and Series B Preferred Stock are set forth below. The new risk factors pertaining to our Series C and Series D Preferred stock have arisen as a result of the Series D Preferred Stock having been issued after the date of our Annual Report for fiscal 2013 and our having entered the New Loan Agreement subsequent to the date of our Annual Report.

CIE's operations are subject to oversight by the Alaska DNR and are subject to certain bonding requirements imposed by them. CIE's oil and gas leases could be terminated if it fails to uphold the terms of the Assignment Oversight Agreement. If the leases were terminated, we would be unable to continue our operations as they are presently conducted. The Assignment Oversight Agreement, along with the Performance Bond Agreement for the Redoubt Unit and Redoubt Shoal Field, also impose significant bonding requirements on us, which could adversely impact our ability to increase our revenues in future periods.
As a condition of the assignment of certain leases, CIE entered into the Assignment Oversight Agreement with the Alaska DNR effective November 5, 2009. The terms of the agreement require CIE to meet certain funding thresholds and report to the Alaska DNR regularly, until the Alaska DNR determines that CIE has completed its development and operation obligations under the leases. Should CIE fail to submit the information required under the agreement, or spend funds for items or activities that do not support core oil and gas activity as set out in the Plan of Operations or Plan of Development for the leases, the Alaska DNR could choose to terminate the leases.
Additionally, on March 11, 2011, CIE entered into a Performance Bond Agreement with the DNR concerning certain bonding requirements initially established by the Assignment Oversight Agreement. The performance bond, which is set at $18,000, is intended to ensure that CIE has sufficient funds to meet its dismantlement, removal and restoration obligations pertaining to the Redoubt Unit and Redoubt Shoal Field. The Agreement includes a funding schedule, which requires payments annually on July 1, beginning in 2013, of amounts ranging from $1,000 to $2,500 per year, and totaling $12,000, as approximately $6,800 was funded by the previous owner. If CIE is more than 10 days late with a payment to the State Trust Account or more than 10 days late providing proof of a payment into a private account, the State will assess a late payment fee of $50. Our obligation to fund the bond beginning in July 2013 will adversely impact our cash resources available to devote to the expansion of our operations. If we must pay one or more late payment fees, it will further reduce the cash resources we have available to devote to the expansion of our operations and could adversely impact our ability to increase our revenues in future periods.
The DNR could also require that additional supplemental performance bonds be provided by CIE in connection with the newly acquired North Fork Unit and/or the related pipeline which we intend to acquire upon receipt of regulatory approval.

The Series D Preferred Stock ranks junior to our Series B Preferred Stock and to all of our indebtedness and other liabilities and is effectively junior to all indebtedness and other liabilities of our subsidiaries and ranks pari passu with our existing Series C Preferred Stock.
In the event of our bankruptcy, liquidation, dissolution or winding-up of our affairs, our assets will be available to pay obligations on the Series D Preferred Stock only after all of our indebtedness and other liabilities have been paid. The rights of holders of the Series D Preferred Stock to participate in the distribution of our assets will rank junior to the prior claims of our current and future creditors, to our Series B Cumulative Redeemable Preferred Stock ("Series B Preferred Stock") and any future series or class of preferred stock we may issue that ranks senior to the Series D Preferred Stock. As of the date hereof, 25,750 shares of Series B Preferred Stock, having a liquidation value of $2,705, are outstanding. In addition, the Series D Preferred Stock effectively ranks junior to all existing and future indebtedness and other liabilities of (as well as any preferred equity interests held by others in) our existing subsidiaries and any future subsidiaries. The Series D Preferred Stock ranks pari passu with our 10.75% Series C Cumulative Redeemable Preferred Stock ("Series C Preferred Stock") in right of payments of dividends and upon the liquidation, dissolution or winding up of our affairs. As of the date hereof, 3,069,968 shares of Series C Preferred Stock, having a liquidation value of $78,124, plus accrued and unpaid dividends, are outstanding.
Our existing subsidiaries are and any future subsidiaries would be separate legal entities and have no legal obligation to pay any amounts to us in respect of dividends due on the Series D Preferred Stock. If we are forced to liquidate our assets to pay

54
Table of Contents
(Dollars in thousands, except per share data and per unit data)

our creditors, we may not have sufficient assets to pay amounts due on any or all of the Series D Preferred Stock then outstanding. We and our subsidiaries have incurred and may in the future incur substantial amounts of debt and other obligations that will rank senior to the Series D Preferred Stock. At January 31, 2014, we had approximately $71,961 of indebtedness, on a consolidated basis, ranking senior to the Series D Preferred Stock (which includes the liquidation value of our Series B Preferred Stock, referenced above). Our Prior Loan Agreement dated June 29, 2012 among us as borrower, Apollo Investment Corporation, as administrative agent and the lenders party thereto from time to time, as the same may be amended from time to time, prohibits payments of dividends on the Series D Preferred Stock if we fail to comply with certain financial covenants. Certain of our other existing or future debt instruments may restrict the authorization, payment or setting apart of dividends on the Series D Preferred Stock.
Future offerings of debt, senior equity securities, or other equity securities ranking on parity with the Series D Preferred Stock in right of payment may adversely affect the market price of the Series D Preferred Stock. If we decide to issue debt or equity securities in the future, it is possible that these securities will be governed by an indenture or other instruments containing covenants restricting our operating flexibility. Additionally, any convertible or exchangeable securities that we issue in the future may have rights, preferences and privileges more favorable than those of the Series D Preferred Stock and may result in dilution to owners of the Series D Preferred Stock. We and, indirectly, our shareholders, will bear the cost of issuing and servicing such securities. Because our decision to issue debt or equity securities in any future offering will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing or nature of our future offerings. The holders of the Series D Preferred Stock will bear the risk of our future offerings, reducing the market price of the Series D Preferred Stock and diluting the value of their holdings in us.

We may not be able to pay dividends on the Series B Preferred Stock, Series C Preferred Stock or Series D Preferred Stock.
Under Tennessee law, cash dividends on capital stock may be paid from net earnings and only if (1) we would still be able to pay our debts as they become due in the usual course of business after giving effect to the dividend payment, and (2) our total assets are not less than the sum of our total liabilities plus the amount that would be needed if we were to be dissolved at the time of the distribution, to satisfy the preferential rights upon dissolution of shareholders whose preferential rights on dissolution are superior to those receiving the distribution. Our ability to pay cash dividends on the Series B Preferred Stock, Series C Preferred Stock or Series D Preferred Stock will require us to be profitable and to have positive net assets (total assets less total liabilities) over our capital. Further, notwithstanding these factors, we may not have sufficient cash to pay dividends on the Series B Preferred Stock, Series C Preferred Stock or Series D Preferred Stock. Our ability to pay dividends may be impaired if any of the risks described in this quarterly report or in our annual report on Form 10-K were to occur. In addition, payment of our dividends depends upon our financial condition and other factors as our board of directors may deem relevant from time to time. We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us in an amount sufficient to enable us to make distributions on our common stock and preferred stock, including the Series B Preferred Stock, Series C Preferred Stock or Series D Preferred Stock, to pay our indebtedness or to fund our other liquidity needs.
In addition, the New Loan Agreement prohibits payments of dividends on the Series B Preferred Stock, Series C Preferred Stock or Series D Preferred Stock if we fail to comply with certain financial covenants. Certain of our other existing or future debt instruments may restrict the authorization, payment or setting apart of dividends on the Series B Preferred Stock, Series C Preferred Stock or Series D Preferred Stock.

The Series D Preferred Stock has not been rated.
We have not sought to obtain a rating for the Series D Preferred Stock. No assurance can be given, however, that one or more rating agencies might not independently determine to issue such a rating or that such a rating, if issued, would not adversely affect the market price of the Series D Preferred Stock. In addition, we may elect in the future to obtain a rating for the Series D Preferred Stock, which could adversely affect the market price of the Series D Preferred Stock. Ratings only reflect the views of the rating agency or agencies issuing the ratings and such ratings could be revised downward, placed on a watch list or withdrawn entirely at the discretion of the issuing rating agency if in its judgment circumstances so warrant. Any such downward revision, placing on a watch list or withdrawal of a rating could have an adverse effect on the market price of the Series D Preferred Stock.

You may not be able to exercise conversion rights upon a Change of Control, and, if exercisable, these conversion rights may not adequately compensate you.
Upon the occurrence of a Change of Control, each holder of the Series D Preferred Stock will have the right (unless, prior to the Change of Control Conversion Date, we have provided notice of our election to redeem some or all of the shares of Series D Preferred Stock held by such holder in which case such holder will have the right only with respect to shares of Series D Preferred Stock that are not called for redemption) to convert some or all of such holder’s Series D Preferred Stock into our shares of common stock (or under specified circumstances involving certain alternative consideration).

55
Table of Contents
(Dollars in thousands, except per share data and per unit data)

Although we generally may not redeem the Series D Preferred Stock prior to the fifth anniversary of the date we initially issue the Series D Preferred Stock, we have a special optional redemption right to redeem the Series D Preferred Stock in the event of a Change of Control, and holders of the Series D Preferred Stock will not have the right to convert any shares that we have elected to redeem prior to the Change of Control Conversion Date.
If we do not elect to redeem the Series D Preferred Stock prior to the Change of Control Conversion Date, then upon an exercise of the conversion rights, the holders of Series D Preferred Stock will be limited to a maximum number of shares of our common stock (or other applicable consideration) equal to 7.1225 multiplied by the number of shares of Series D Preferred Stock converted.

Change of control conversion rights may make it more difficult for a party to acquire us or discourage a party from acquiring us.
The Change of Control conversion feature of the Series D Preferred Stock may have the effect of discouraging a third party from making an acquisition proposal for us or of delaying, deferring or preventing certain of our change of control transactions under circumstances that otherwise could provide the holders of our common stock and Series D Preferred Stock with the opportunity to realize a premium over the then-current market price of such stock or that shareholders may otherwise believe is in their best interests.

The market price of the Series D Preferred Stock could be substantially affected by various factors.
The market price of the Series D Preferred Stock will depend on many factors, which may change from time to time, including:
•
prevailing interest rates, increases in which may have an adverse effect on the market price of the Series D Preferred Stock;
•
trading prices of common and preferred equity securities issued by other energy companies;
•
the annual yield from distributions on the Series D Preferred Stock as compared to yields on other financial instruments;
•
general economic and financial market conditions;
•
government action or regulation;
•
the financial condition, performance and prospects of us and our competitors;
•
changes in financial estimates or recommendations by securities analysts with respect to us, our competitors in our industry;
•
our issuance of additional preferred equity or debt securities; and
•
actual or anticipated variations in quarterly operating results of us and our competitors.
As a result of these and other factors, investors who purchase the Series D Preferred Stock may experience a decrease, which could be substantial and rapid, in the market price of the Series D Preferred Stock, including decreases unrelated to our operating performance or prospects.

We may issue additional shares of Series D Preferred Stock, Series C Preferred Stock and additional series of preferred stock that rank on parity with the Series D Preferred Stock as to dividend rights, rights upon liquidation or voting rights.
We are allowed to issue additional shares of Series D Preferred Stock, Series C Preferred Stock and additional series of preferred stock that would rank equally to the Series D Preferred Stock as to dividend payments and rights upon our liquidation, dissolution or winding up of our affairs pursuant to our amended and restated charter, as amended, and the articles of amendment for the Series D Preferred Stock without any vote of the holders of the Series D Preferred Stock. The issuance of additional shares of Series D Preferred Stock, Series C Preferred Stock and other preferred stock that would rank on parity with the Series D Preferred Stock could have the effect of reducing the amounts available to the Series D Preferred Stock issued in this offering upon our liquidation or dissolution or the winding up of our affairs. It also may reduce dividend payments on the Series D Preferred Stock issued in this offering if we do not have sufficient funds to pay dividends on all Series D Preferred Stock, Series C Preferred Stock outstanding and other classes of stock with equal priority with respect to dividends.
In addition, although holders of Series D Preferred Stock are entitled to limited voting rights with respect to such matters, the Series D Preferred Stock will vote separately as a class along with the holders of our Series C Preferred Stock and all other classes or series of our equity securities we may issue upon which similar voting rights have been conferred and are exercisable and which are entitled to vote as a class with the Series D Preferred Stock. As a result, the voting rights of holders of Series D Preferred Stock may be significantly diluted, and the holders of the Series C Preferred Stock and such other series of preferred stock that we may issue may be able to control or significantly influence the outcome of any vote.

56
Table of Contents
(Dollars in thousands, except per share data and per unit data)

Future issuances and sales of preferred stock ranking on parity with the Series D Preferred Stock, or the perception that such issuances and sales could occur, may cause prevailing market prices for the Series D Preferred Stock and our common stock to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.

As a holder of Series D Preferred Stock, you will have extremely limited voting rights.
Your voting rights as a holder of Series D Preferred Stock will be limited. Our shares of common stock are the only class of our securities that carry full voting rights. Voting rights for holders of Series D Preferred Stock exist primarily with respect to the ability to elect, voting together with the holders of our Series C Preferred Stock and any other classes or series of equity securities we may issue upon which similar voting rights have been conferred and are exercisable and which are entitled to vote as a class with the Series D Preferred Stock, two additional directors to our board of directors, subject to certain limitations, in the event that four quarterly dividends (whether or not consecutive) payable on the Series D Preferred Stock are in arrears, and with respect to voting on amendments to our amended and restated charter, as amended, or our articles of amendment relating to the Series D Preferred Stock that materially and adversely affect the rights of the holders of Series D Preferred Stock, authorize the issuance of additional Series C Preferred Stock, or authorize, increase or create additional classes or series of our shares that are senior to the Series D Preferred Stock. Other than the limited circumstances described in this prospectus supplement, holders of Series D Preferred Stock will not have any voting rights.

Disruptions in the financial markets could affect our ability to obtain financing on reasonable terms and have other adverse effects on us and the market price of the Series D Preferred Stock.
Over the last several years, the United States stock and credit markets have experienced significant price volatility, dislocations and liquidity disruptions, which have caused market prices of many stocks and debt securities to fluctuate substantially and the spreads on prospective debt financings to widen considerably. In the last few years, the financial crisis in Europe (which relates primarily to concerns that certain European countries may be unable to pay their national debt) had a similar, although less pronounced, effect. These circumstances have materially impacted liquidity in the financial markets, making terms for certain financings less attractive and in certain cases have resulted in the unavailability of certain types of financing. Unrest in certain Middle Eastern countries and the resultant increase in petroleum prices have added to the uncertainty in the capital markets. Such uncertainty will lead to continued volatility in the stock and credit markets and may negatively impact our ability to access additional financing at reasonable terms. A prolonged downturn in the stock or credit markets may cause us to seek alternative sources of potentially less attractive financing. These types of events in the stock and credit markets may make it more difficult or costly for us to raise capital through the issuance of our common stock, preferred stock or debt securities. These disruptions may have a material adverse effect on the market value of our common stock and preferred stock, including the Series D Preferred Stock offered pursuant to this prospectus supplement, the return we receive on our investments, as well as other unknown adverse effects on us or the economy in general.

The Series D Preferred Stock is a new issue of securities and does not have an established trading market, which may negatively affect its value and your ability to transfer and sell your shares.
The Series D Preferred Stock is a relatively new issue of securities with only a limited trading market. The volume of trades of shares of the Series D Preferred Stock on the NYSE is often low, and an active trading market on the NYSE for the Series D Preferred Stock may not be maintained in the future and may not provide adequate liquidity. The liquidity of any market for the Series D Preferred Stock that may exist now or in the future will depend on a number of factors, including prevailing interest rates, the dividend rate on our common stock, our financial condition and operating results, the number of holders of the Series D Preferred Stock, the market for similar securities and the interest of securities dealers in making a market in the Series D Preferred Stock. As a result, the ability to transfer or sell the Series D Preferred Stock could be adversely affected.

If our common stock is delisted, your ability to transfer or sell your shares of the Series D Preferred Stock may be limited, and the market value of the Series D Preferred Stock will likely be materially adversely affected.
Other than in connection with a Change of Control, the Series D Preferred Stock does not contain provisions that are intended to protect you if our common stock is delisted from the NYSE. Since the Series D Preferred Stock has no stated maturity date, you may be forced to hold your shares of the Series D Preferred Stock and receive stated dividends on the Series D Preferred Stock when, as and if authorized by our board of directors and paid by us with no assurance as to ever receiving the liquidation value thereof. In addition, if our common stock is delisted from the NYSE, it is likely that the Series D Preferred Stock will be delisted from the NYSE as well. Accordingly, if our common stock is delisted from the NYSE, your ability to transfer or sell your shares of the Series D Preferred Stock may be limited and the market value of the Series D Preferred Stock will likely be materially adversely affected.


57
Table of Contents

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

On January 31, 2014, pursuant to our Purchase and Sale Agreement with 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 (collectively, the “Sellers”), we issued 213,586 shares of our Series D Preferred Stock to be held in escrow for the benefit of the Sellers, valued at approximately $5,000. For purposes of determining the number of shares of the Series D Preferred Stock, it was valued on January 31, 2014 as the average of its daily volume weighted average prices for the 10 trading days ending on and including January 31, 2014. The Series D Preferred Stock was issued in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended. The Series D Preferred Stock will be held in escrow until the transfer of the equity interests in Anchor Point Energy, LLC has been completed and certain necessary regulatory approvals have been received.

ITEM 5.    OTHER INFORMATION.

None.

58
Table of Contents

ITEM 6.    EXHIBITS.

The following documents are filed as a part of this report:
EXHIBIT NO.
 
 
 
DESCRIPTION
2.1

 
–
 
Purchase and Sale Agreement, dated November 22, 2013, by and among Armstrong Cook Inlet, LLC, GMT Exploration Company, LLC, Dale Resources Alaska, LLC, Jonah Gas Company, LLC and Nerd Gas Company, LLC, as sellers and Cook Inlet Energy, LLC, as buyer (incorporated by reference to Registrant's Current Report on Form 8-K filed on November 25,2013).
3.1

 
–
 
Certificate of Incorporation (incorporated by reference to Registrant's Annual Report on Form 10-KSB (Commission file number 033-02249-FW) for the year ended December 31, 1995).
3.2

 
–
 
Certificate of Amendment of Certificate of Incorporation (incorporated by reference to Registrant's Annual Report on Form 10-KSB (Commission file number 033-02249-FW) for the year ended December 31, 1995).
3.3

 
–
 
Certificate of Amendment of Certificate of Incorporation (incorporated by reference to Registrant's Annual Report on Form 10-KSB (Commission file number 033-02249-FW) for the year ended December 31, 1995).
3.4

 
–
 
Certificate of Ownership and Merger and Articles of Merger between Triple Chip Systems, Inc. and Miller Petroleum, Inc. (incorporated by reference to Registrant's exhibits filed with the registration statement on Form SB-2, SEC File No. 333-53856, as amended).
3.5

 
–
 
Amended and Restated Charter of Miller Petroleum, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on April 29, 2010).
3.6

 
–
 
Amended and Restated Bylaws of Miller Petroleum, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on April 29, 2010).
3.7

 
–
 
Articles of Amendment to the Bylaws of Miller Petroleum, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on March 17, 2011).
3.8

 
–
 
Articles of Amendment to the Charter of Miller Petroleum, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on April 15, 2011).
3.9

 
–
 
Articles of Amendment to the Charter of Miller Energy Resources, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on April 2, 2012).
3.10

 
–
 
Articles of Amendment to the Charter of Miller Energy Resources, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on August 17, 2012).
3.11

 
–
 
Articles of Amendment to the Charter of Miller Energy Resources, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on September 4, 2012).
3.12

 
–
 
Articles of Amendment to the Charter of Miller Energy Resources, Inc. (incorporated by reference to Exhibit 3.20 to Registrant's Registration Statement on Form 8-A as filed on September 28, 2012).
3.13

 
–
 
Articles of Amendment to the Charter of Miller Energy Resources, Inc. (incorporated by reference to Exhibit 3.21 to Registrant's Registration Statement on Form 8-A as filed on September 26, 2013).
10.1

 
–
 
Waiver and Amendment No. 8 dated December 9, 2013 (incorporated by reference to Registrant's Current Report on Form 8-K filed on December 9, 2013).
10.2

 
–
 
Settlement Agreement dated January 24, 2014 between Miller Energy Resources, Inc., and CNX Gas Company, LLC (incorporated by reference to Registrant's Current Report on Form 8-K filed on January 30, 2014).
10.3

 
–
 
Extension of Date for Repayment of Tranche B Loan without Prepayment Premium dated January 30, 2014 (incorporated by reference to Registrant's Current Report on Form 8-K filed on January 31, 2014).
31.1

 
–
 
Rule 13a-14(a)/15d-14(a) certification of Chief Executive Officer *
31.2

 
–
 
Rule 13a-14(a)/15d-14(a) certification of Chief Financial Officer *
32.1

 
–
 
Section 1350 certification of Chief Executive Officer*
32.2

 
–
 
Section 1350 certification of Chief Financial Officer*
101.INS

 
–
 
XBRL Instance Document **
101.SCH

 
–
 
XBRL Taxonomy Extension Schema Document **
101.CAL

 
–
 
XBRL Taxonomy Extension Calculation Linkbase Document**
101.LAB

 
–
 
XBRL Taxonomy Extension Label Linkbase Document **
101.PRE

 
–
 
XBRL Taxonomy Extension Presentation Linkbase Document **
101.DEF

 
–
 
XBRL Taxonomy Extension Definition Linkbase Document **
———————
*    filed herewith.
**    In accordance with Regulation S-T, the XBRL-formatted interactive data files that comprise Exhibit 101 in this report on Form 10-Q shall be deemed "furnished" and not "filed".

59
Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Dated:
March 12, 2014
MILLER ENERGY RESOURCES, INC.
 
 
 
 
 
 
By:
/s/ SCOTT M. BORUFF
 
 
 
Scott M. Boruff
 
 
 
Chief Executive Officer
 
 
 
(Principal Executive Officer)
 
 
 
 
 
 
 
 
Dated:
March 12, 2014
MILLER ENERGY RESOURCES, INC.
 
 
 
 
 
 
By:
/s/ JOHN M. BRAWLEY
 
 
 
John M. Brawley
 
 
 
Chief Financial Officer
 
 
 
(Principal Financial Officer)


60