Edgar Filing: MILLER ENERGY RESOURCES, INC.

MILL 10K 04.30.13

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10-K

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(Mark One)

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

For the fiscal year ended: April 30, 2013

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

For the transition period from __________________ to __________________________

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MILLER ENERGY RESOURCES, INC.

(Exact name of registrant as specified in its charter)

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Tennessee	001-34732	62-1028629
(State or Other Jurisdiction	(Commission	(I.R.S. Employer
of Incorporation or Organization)	File Number)	Identification No.)

9721 Cogdill Road, Suite 302, Knoxville, TN 37932

(Address of Principal Executive Office) (Zip Code)

(865) 223-6575

(Registrant’s telephone number, including area code)

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Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common Stock, par value $0.0001 per share		New York Stock Exchange

10.75% Series C Cumulative Redeemable Preferred Stock, par value $0.0001 per share		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

	None
	(Title of Class)

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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
	¨	Yes	þ	No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
	¨	Yes	þ	No

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.
	þ	Yes	¨	No

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 (§229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
	þ	Yes	¨	No



Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
						¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.

Large accelerated filer	¨	Accelerated filer				þ
Non-accelerated filer	¨	Smaller reporting company				¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).			¨	Yes	þ	No

The aggregate market value of the outstanding common stock, other than shares held by persons who may be deemed affiliates of the registrant, computed by reference to the closing sales price for the registrant’s common stock on October 31, 2012 (the last business day of the registrant’s most recently completed second quarter), as reported on the New York Stock Exchange-Composite Index, was approximately $159,097,613. As of July 5, 2013, there were 43,446,694 shares of common stock of the registrant outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of registrant’s proxy statement relating to registrant’s 2013 annual meeting of stockholders have been incorporated by reference in Part II and Part III of this annual report on Form 10-K.

MILLER ENERGY RESOURCES, INC.

ANNUAL REPORT ON FORM 10-K

FOR THE YEAR ENDED APRIL 30, 2013

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			Page

FORWARD-LOOKING STATEMENTS			ii
GLOSSARY OF TERMS			ii

PART I
	Item 1 and 2.	Business and Properties	1
	Item 1A.	Risk Factors	16
	Item 1B.	Unresolved Staff Comments	29
	Item 3.	Legal Proceedings	29
	Item 4.	Mine Safety Disclosures	29

PART II
	Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities	30
	Item 6.	Selected Financial Data	32
	Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	33
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	48
	Item 8.	Financial Statements and Supplementary Data	48
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	49
	Item 9A.	Controls and Procedures	49
	Item 9B.	Other Information	50

PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	51
	Item 11.	Executive Compensation	51
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	51
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	51
	Item 14.	Principal Accounting Fees and Services	51

PART IV
	Item 15.	Exhibits, Financial Statement Schedules	52

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

We have made forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company's operations, economic performance and financial condition in this report, our Annual Report on Form 10-K for the year ended April 30, 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.

These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:


•	the potential for us to experience additional operating losses;


•	material weaknesses in our internal control over financial reporting and our need to enhance our management, systems, accounting, controls and reporting performance;


•	high debt costs under our existing senior credit facility;


•	potential limitations imposed by debt covenants under our senior credit facility on our growth and our ability to meet our business objectives;


•	our ability to meet the financial and production covenants contained in the Apollo Credit Facility;


•	whether we are able to complete or commence our drilling projects within our expected time frame;


•	litigation risks;


•	our ability to perform under the terms of our oil and gas leases, and exploration licenses with the Alaska DNR, including meeting the funding or work commitments of those agreements;


•	uncertainties related to deficiencies identified by the SEC in our Form 10-K for 2011;


•	our ability to successfully acquire, integrate and exploit new productive assets in the future;


•	whether we can establish production on certain leases in a timely manner before expiration;


•	our ability to complete the work commitments required as terms of our Susitna Basin Exploration Licenses;


•	our ability to recover proved undeveloped reserves and convert probable and possible reserves to proved reserves;


•	our experience with horizontal drilling;


•	risks associated with the hedging of commodity prices;


•	our dependence on third party transportation facilities;


•	concentration risk in the market for the oil we produce in Alaska;


•	the impact of natural disasters on our Cook Inlet Basin operations;


•	the effect of global market conditions on our ability to obtain reasonable financing and on the prices of our common and Series C Preferred Stock;


•	the imprecise nature of our reserve estimates;


•	risks related to drilling dry holes or wells without commercial quantities of hydrocarbons;


•	fluctuating oil and gas prices and the impact on our results from operations;


•	the need to discover or acquire new reserves in the future to avoid declines in production;


•	differences between the present value of cash flows from proved reserves and the market value of those reserves;


•	the existence within the industry of risks that may be uninsurable;


•	strong industry competition;


•	constraints on production and costs of compliance that may arise from current and future environmental, FERC and other statutes, rules and regulations at the state and federal level;


•	new regulation on derivative instruments used by us to manage our risk against fluctuating commodity prices;


•	the impact that future legislation could have on access to tax incentives currently enjoyed by us;


•	that no dividends may be paid on our common stock for some time;

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•	cashless exercise provisions of outstanding warrants;


•	market overhang related to restricted securities and outstanding options, and warrants;


•	the impact of non-cash gains and losses from derivative accounting on future financial results;


•	risks to non-affiliate shareholders arising from the substantial ownership positions of affiliates;


•	the junior ranking of our Series C Preferred Stock to our Series B Preferred Stock and all of our indebtedness;


•	our ability to pay dividends on the Series C Preferred Stock;


•	whether our Series C Preferred Stock is rated;


•	the ability of our Series C Preferred Stockholders to exercise conversion rights upon a Change of Control;


•	fluctuations in the market price of our Series C Preferred Stock;


•	whether we issue additional shares of Series C Preferred Stock or additional series of preferred stock that rank on parity with the Series C Preferred Stock;


•	the very limited voting rights held by our Series C Preferred Stockholders;


•	the newness of the Series C Preferred Stock and its limited trading market;


•	risks related to our continued listing of the Series C Preferred Stock on the NYSE; and


•	the effect of the change of control conversion feature of our Series C Preferred Stock on a potential change in control.

Most of these factors are difficult to predict accurately and are generally beyond our control. You should consider the areas of risk described in connection with any forward-looking statements that may be made herein. Readers are cautioned not to place undue reliance on these forward-looking statements, and readers should carefully review this annual report in its entirety, including the risks described in Item 1A. Risk Factors. Except for our ongoing obligations to disclose material information under the Federal securities laws, we undertake no obligation to release publicly any revisions to any forward-looking statements, to report events or to report the occurrence of unanticipated events. These forward-looking statements speak only as of the date of this annual report, and you should not rely on these statements without also considering the risks and uncertainties associated with these statements and our business.

OTHER PERTINENT INFORMATION

We maintain our web site at www.millerenergyresources.com. On our website, you will find detailed information regarding our company, our locations and our leadership team, as well as information for shareholders and investors on our media and investor pages. Information on this web site is not a part of this annual report.

Unless specifically set forth to the contrary, when used in this annual report on Form 10-K, the terms “Miller Energy Resources,” "Miller," the "Company," "we," "us," "ours," and similar terms refers to our Tennessee corporation Miller Energy Resources, Inc., formerly known as Miller Petroleum, Inc., and our subsidiaries, Miller Rig & Equipment, LLC, Miller Drilling, TN LLC, Miller Energy Services, LLC, East Tennessee Consultants, Inc. ("ETC"), East Tennessee Consultants II, LLC ("ETCII"), Miller Energy GP, LLC, and Cook Inlet Energy, LLC ("CIE").

Our fiscal year end is April 30. The year ended April 30, 2013 is referred to as “fiscal 2013” or "2013," the year ended April 30, 2012 is referred to as “fiscal 2012” or "2012," the year ended April 30, 2011 is referred to as “fiscal 2011” or "2011" and the year ending April 30, 2014 is referred to as “fiscal 2014” or "2014."

GLOSSARY OF OIL AND NATURAL GAS TERMS

We are engaged in the business of exploring and producing oil and natural gas as well as exploiting our mid-stream assets that could entail electrical power sales, processing third party fluids and natural gas and waste disposal. Many of the terms used to describe our business are unique to the oil and gas industry. The definitions set forth below apply to the indicated terms as used in this annual report on Form 10-K.

3-D seismic. The method by which a three dimensional image of the earth's subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, exploitation and production.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bcf. Billion cubic feet of natural gas corrected to standard temperature and pressure.

Bopd. Barrels of oil per day.

Boe. Barrels of oil equivalent in which six Mcf of natural gas equals one Bbl of oil.

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Boe/d. Boe per day.

Mcf. One thousand cubic feet of natural gas corrected to standard temperature and pressure.

Mcfd. One thousand cubic feet of natural gas per day.

MMBbls. Million barrels of oil.

MMcf. Million cubic feet of natural gas corrected to standard temperature and pressure.

Completion. The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Development well. A well drilled within the proved areas of oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Downstream. Refers to oil and gas infrastructure or operations relating to the refining, manufacturing, or sales of sales-quality crude oil or natural gas. This term is used in contrast to upstream (exploration and production) or midstream (transportation and ancillary services).

Dry hole or dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Midstream. Refers to oil and gas infrastructure or operations relating to the transportation of sales-quality crude oil and gas production facilities to market. Used to contrast to upstream (exploration & production) or downstream (refining, manufacturing and sales).

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

Oil and gas lease or lease. An agreement between a mineral owner, the lessor, and a lessee which conveys the right to the lessee to explore for and produce oil and gas from the leased lands. Oil and gas leases usually have a primary term during which the lessee must establish production of oil and or gas. If production is established within the primary term, the term of the lease generally continues in effect so long as production occurs on the lease. Leases generally provide for a royalty to be paid to the lessor from the gross proceeds from the sale of production.

Proved developed non-producing reserves ("PDNP"). Proved crude oil and natural gas reserves that are developed behind pipe, shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.

Proved developed producing reserves ("PDP"). Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. The quantities of oil and gas that, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible. We provide information on two types of proved reserves - developed and undeveloped.

Proved undeveloped reserves ("PUD"). Reasonably certain reserves in drilling units immediately adjacent to the drilling unit containing a producing well as well as areas beyond one offsetting drilling unit from a producing well.

Reservoir. A porous or permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty interest. A right to oil, gas, or other minerals that is not burdened by the costs to develop or operate the related property.

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Upstream. Refers to oil and gas infrastructure or operations relating to the exploration and production of crude oil and gas and its processing into sales-quality crude or gas. Used to contrast to midstream (transportation and ancillary services) or downstream (refining, manufacturing and sales).

Working interest. An interest in an oil and gas property that is burdened with the costs of development and operation of the property.

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

PART I

ITEM 1 AND 2. BUSINESS AND PROPERTIES.

Overview

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

During fiscal 2013, we continued to develop our oil and gas operations acquired from Pacific Energy Resources ("Pacific Energy") in December 2009 through a bankruptcy proceeding, including onshore and offshore production and processing facilities, the offshore Osprey platform, and approximately 700,000 lease or exploration license acres of land, along with hundreds of miles of 2-D and 3-D geologic seismic data, miscellaneous roads, pads, pipelines and facilities. Our mission is to grow a profitable exploration and production company for the long-term benefit of our shareholders by focusing on the development of our reserves, continued expansion of our oil and natural gas properties and increase in our production and related cash flow. We intend to accomplish these objectives through the execution of the following core strategies:


•	Develop Acquired Acreage. We will focus on organically growing production through drilling for our own benefit on existing leases and acreage in the exploration licenses with a view towards retaining the majority of the working interest in the new wells. This strategy will allow us to maintain operational control, which we believe will translate to long-term benefits;

•

Increase Production. We plan on increasing oil and gas production through the maintenance, repair and optimization of wells located in the Cook Inlet region and development of wells in the Appalachian region of east Tennessee. Our operational team will employ a combination of the latest available technologies along with tried and true technologies to restore as well as explore and develop our properties;


•	Expand Our Revenue Stream. We intend on fully exploiting our mid-stream facilities, such as our injection wells and the Kustatan Production Facility, our ability to engage in the commercial disposal of waste generated by oil and gas operations, and our capacity to process third party fluids and natural gas and to offer excess electrical power to net users in the Cook Inlet region; and

•

Pursue Strategic Acquisitions. We have significantly increased our oil and gas properties through strategic low-cost / high-value acquisitions. Under the same strategy, our management team will continue to seek opportunities that meet our criteria for risk, reward, rate of return, and growth potential. We plan to leverage our management team's expertise to pursue value-creating acquisitions when the opportunities arise, subject to the availability of sufficient capital.

For a more in-depth discussion of our fiscal 2013 results and our capital resources and liquidity, please see Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.

Recent Developments

Drilling Activities

On June 20, 2013, the RU-2 Sidetrack ("RU-2A") well was completed and was successfully brought online. After clearing the well of drilling fluids from the sidetrack, a subsequent well test showed an initial daily production rate (IP) of 1,281 barrels of oil per day (bopd) and a water cut of 19%. RU-2A is one of five planned sidetracks to be completed on the Osprey Platform.

The original RU-2 well, drilled by a previous operator, produced approximately 500,000 barrels before it suffered casing damage caused by a poor completion design. After assessing the deficiencies that resulted in the sub-optimal production and eventful catastrophic well failure, we re-engineered the drilling and completion to achieve optimal oil recovery on re-entry. RU-2A was sidetracked from the original RU-2 well starting at a depth of approximately 8,500 feet and drilled to a measured depth of 15,265 feet. The completed well has a new bottom hole located 46 feet higher on structure than the original RU-2 well.

We are currently drilling Olson Creek with Rig 34. Upon completion, we plan to move Rig 34 to deepen the Otter #1 prospect, which discovered the presence of reservoir quality sands and strong gas shows earlier this year.

Series C Preferred Stock

Pursuant to our At Market Issuance Sales Agreement, dated October 12, 2012 ("ATM Agreement") with MLV & Co. LLC ("MLV"), between May 1, 2013 and July 5, 2013, we offered and sold an additional 43,180 shares of our Series C Preferred Stock, at prices ranging from $22.01 and $22.35 per share. The Company received $953 in gross proceeds as a result of these sales, from which MLV was paid a commission of $33. These securities are registered for sale to the public pursuant to a prospectus

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supplement, dated September 19, 2012, and 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.

Pursuant to an Underwriting Agreement, dated May 7, 2013, with MLV, for itself and as representative of the underwriters listed on Schedule I to that agreement, on May 10, 2013, we offered and 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 $765. These securities are registered for sale to the public pursuant to a prospectus, dated September 19, 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.

Pursuant to an Underwriting Agreement, dated June 27, 2013, with MLV, for itself and as representative of the underwriters listed on Schedule I to that agreement, on July 2, 2013, we offered and 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 $7,200 in connection with the offering from which MLV was paid a commission of $504. These securities are registered for sale to the public pursuant to a prospectus, dated September 19, 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.

Apollo Credit Facility Waiver and Amendment

On July 11, 2013, we entered into an Amendment (the “July 2013 Amendment”) with Apollo Investment Corporation ("Apollo") under the Apollo Credit Facility. The fee for the Amendment was $100. The Amendment makes the following changes to the Apollo Credit Facility among others: (i) changes the initial testing date for those financial and production covenants referred to as the "maintenance covenants" to October 31, 2013; (ii) allows transfers of working interests by the Company to the Tennessee Oil and Gas Association; (iii) reduces the restrictions on the transfer of the Company's stock by senior management; and (iv) allows for a later delivery date for certain routine deliverables otherwise called for under the related loan agreement with Apollo.

Geographic Area Overview

We currently focus our efforts on activities in the Cook Inlet and Susitna Basins of Alaska as well as the Appalachian region of east Tennessee.

The following table sets forth certain key information for each of our operating areas. Additional data and discussion is provided in Part II, Item 7 of this Form 10-K.



	2013 Production	Percentage of Total 2013 Production	2013 Oil and Gas Revenues		4/30/2013 Estimated Proved Reserves	Percentage of Total Estimated Proved Reserves
	(In Boe)				(In MBoe)
Cook Inlet ¹	276,908	87%	$	27,932	8,445	98%
Appalachian region	40,698	13%	1,983		166	2%
Total	317,606	100%	$	29,915	8,611	100%

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1	Cook Inlet production excludes 57,123 boe of natural gas produced and used as fuel gas.

Alaska Region

Overview

The Cook Inlet Basin contains large oil and gas deposits including multiple offshore fields. In 2013 there were 16 platforms in the Cook Inlet, the oldest of which is the XTO A platform first installed by Royal Dutch Shell plc in 1964, and the newest of which is the Osprey platform installed by Forest Oil Corporation in 2000 and acquired by us in December 2009. Southcentral Alaska has a well-developed oil and gas pipeline infrastructure to bring Cook Inlet oil and gas to market. This system is isolated from the main North American gas pipeline system. Much of the value-added hydrocarbon processing occurs on the east side of Cook Inlet in an industrial cluster located in Nikiski, which is the northern part of the city of Kenai. The Tesoro refinery, ConocoPhillips LNG plant, BP GTL plant, Agrium, Inc. fertilizer plant, and numerous docks, tanks and pipelines are all located in Nikiski. The Susitna Basin is a large area to the north of Anchorage in southcentral Alaska. It is perhaps best known for its coal seams in the sedimentary basin that lies underneath the basin and could become a new source of much-needed natural gas.

Cook Inlet and Susitna Basins

The Cook Inlet is a vast estuary stretching 180 miles from the Gulf of Alaska to Anchorage in southcentral Alaska. The Inlet separates the Kenai Peninsula in the east from the Alaska Peninsula in the west. The Cook Inlet Basin underlying this region contains large oil and gas deposits including several offshore fields. There are also numerous oil and gas pipelines located in and

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under the Cook Inlet. The Cook Inlet Basin has produced approximately 1.3 billion barrels of oil and 7.8 trillion cubic feet ("tcf") of natural gas.

The Susitna Basin underlies the sprawling Susitna River valley to the north of Anchorage. The Susitna Basin lies directly north of the Cook Inlet Basin, separated by the Castle Mountain Fault, and has similar geology. While the Cook Inlet Basin is a historic region of oil and gas production, there is not currently commercial production of oil or gas from the Susitna Basin.

In its 2011 Assessment of Undiscovered Oil and Gas Resources of the Cook Inlet Region, the United States Geologic Survey ("USGS") estimated mean undiscovered technically recoverable reserves of 599 million bbls of oil and 19 tcf of natural gas. All of the undiscovered oil and 13.7 tcf of the undiscovered gas are conventional resources, and 5.3 tcf of natural gas was estimated to be technically recoverable as coal bed methane. This report considered the full oil and gas potential of the Cook Inlet Basin, but only the coal-bed methane potential of the Susitna Basin. These numbers do not include oil and gas remaining to be produced in currently producing fields.

As of April 30, 2013 and 2012, we owned approximately 100,099 and 105,713 gross acres of leasehold interests, the exploration license rights to an additional 580,147 acres and interests in 10 crude oil and five natural gas wells. The reduction in leased acreage from April 30, 2012 is a result of the expiration of three leases.

At the time we acquired the Alaskan operations, all ten oil wells, four of five gas wells and four injection wells were shut-in. As of April 30, 2013, four oil wells and five gas wells are producing. In addition, we own a 30% working interest in two gas wells operated by Aurora Gas, which have been operated continuously.

Oil wells drilled in this area range from 9,000 feet to 10,000 feet in vertical depth while gas wells have a vertical depth of 3,000 feet to 9,000 feet. Wells that are deviated (continue on from the vertical depth either diagonally or horizontally) will have a longer measured depth of approximately 5,000 feet to 9,000 feet or more giving measured depth of up to 19,000 feet or more. Well spacing is quite variable, as there are large parts of Cook Inlet which are completely undeveloped and others that are more mature. Our fields have approximately 60 acre spacing. The Cook Inlet Basin contains a thick section of terrestrial tertiary rocks which includes shale, sandstone, and coal. The primary targets in the area are crude oil reserves, but prolific gas fields are increasingly attractive due to the rising price of gas in the Alaska market and liquefied natural gas ("LNG"). Cook Inlet natural gas is strategically situated to provide LNG to Asian markets where the LNG price is high and rising.

Osprey Platform and Redoubt Shoals Field

The Osprey platform is located in the Redoubt Unit approximately 1.8 miles southeast of West Foreland in central Cook Inlet at a water depth of approximately 45 feet. The Osprey platform, which produces from the Redoubt Shoals Field is connected to our Kustatan Production Facility. It relies on our Kustatan Production Facility and our West McArthur River Unit Production Facility to provide all of its electricity and gas, and on the Kustatan Production Facility to process all of Osprey's produced fluids. The platform has 21 available slots, eight of which are currently used, and an attached 48 man camp. After a period of inactivity, we started work to re-commission Osprey in February 2011 and restored production in May 2011.

The Osprey platform was placed on site in June 2000 and initially used to conduct exploration drilling operations between January 2001 and July 2002. Eight wells were drilled, which in their present configuration consist of one water flood well, one Class I injection well, and six oil wells. The oil wells were equipped with electrical submersible pumps (“ESPs”) which were necessary to bring the oil to the surface. In 2005, the third-party drilling rig was removed from the platform after a contract dispute. The removal of the rig delayed the ability to maintain and repair the platform's wells or to expand production, and the Osprey platform was shut-in in the spring of 2009.

In order to restore production from the Redoubt Unit, it was necessary to mobilize a drilling rig to the Osprey platform to repair the shut-in wells. Two of the wells required replacement of the ESPs, and the other four wells required re-drilling in sections. Due to significant drilling rig rental cost and delays associated with mobilization and availability of a drilling rig sufficient in size and power to repair the wells, we determined it was most effective to permanently locate a drilling rig on the Osprey platform. In March 2011, we transitioned the Osprey platform out of lighthouse mode and successfully repaired the first of the two wells needing ESP replacement, of which one later failed in September 2011 as a result of successive pump failure. In June 2011, we contracted with Voorhees Equipment and Consulting, Inc. for the custom construction and purchase of Rig 35 for $17,900.

We successfully mobilized all components of the custom rig to the Osprey platform in late December 2011. Assembly of the rig began as parts were delivered to the platform. In January 2012, the region experienced prolonged, near-record cold weather, which caused us to temporarily delay rig assembly efforts due to safety concerns. The cold weather also led to significant generation of ice volume in the Cook Inlet and made shipping and the operation of work-boats very limited. As warmer temperatures moderated the region and rig contractor and supplies were in order, we resumed work on the assembly of Rig 35, which was brought online in August 2012. Rig 35 has since replaced pumps in oil wells RU-1 and RU-7, sidetracked oil well RU-2A and completed the reworking of the RU-3 and the RU-4 gas wells. We were unable to optimize the performance of RU-1 due to obstructions which were stuck in the lower part of the well bore. We are currently performing a side track on this well bore.

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Kustatan Production Facility

The Kustatan Production Facility was constructed in 2002 by Forest Oil Corporation to process an estimated 25,000 bopd. Processing capabilities are expandable to 50,000 bopd. The facility provides power and processes hydrocarbons produced from our offshore Osprey platform.

West McArthur River Field and Production Facility

The West McArthur River Facility processes oil and gas from the West McArthur River Field and has the ability to process gas from the West Foreland Field. Currently, there are three producing wells in the field. The facility was built in 1990s to process approximately 5,000 bopd.

West Foreland Field and Production Facility

The West Foreland Field is produced through the West Foreland Facility but can be processed through the West McArthur River Facility. Currently, there are three wells in the field, one of which is off-line. The West Foreland Facility is tied into the gas pipeline network including sales gas pipelines.

Three Mile Creek Field

The three Mile Creek Field is operated by Aurora Gas. There are two gas wells in which we own a 30% working interest in this field.

Susitna Basin

Included in the Alaskan operations we acquired is a 100% interest in Susitna Basin Exploration License No. 2, granted by the State of Alaska in October 2005 covering approximately 471,474 acres in the Susitna basin area north of Anchorage. Under the terms of the Exploration License, the licensee was granted a seven-year exclusive license to explore for oil and gas on the specified lands, and upon fulfillment of the work commitment, the license for all or any part of the land could be converted into oil and gas leases. The original work commitment of approximately $3,000 was fulfilled. In an effort to control the timing of the development of this acreage, in April 2010 we requested a three-year extension of the exploration license for a work commitment of $750. The State granted the extension in October 2010. We will have the right to convert all or any portion of the licensed acreage into oil and gas leases upon completion of the new work commitment. We currently have a performance bond of $415 toward fulfilling its work commitment, and will need to post additional bonds annually if no work is carried out in the licensed area. The Susitna Basin Exploration License No. 2 is set to expire on October 31, 2013 and we expect to have fulfilled our work commitment obligation by such date. We will evaluate whether to convert all or any part of the license to leases at such time.

On April 1, 2011, we were awarded Susitna Basin Exploration License No. 4, which consists of 62,909 acres. It granted us an exclusive ten-year license to explore for oil and gas on the specified lands. Upon fulfillment of a $2,250 work commitment, we will gain the option to convert any part of the licensed area into oil and gas leases. We currently have a performance bond of $281 toward fulfilling its work commitment, and will need to post additional bonds annually if no work is carried out in the licensed area.

On April 1, 2012, we were awarded Susitna Basin Exploration License No. 5, which consists of 45,764 acres. It granted us an exclusive five-year license to explore for oil and gas on the specified lands. Upon fulfillment of a $250 work commitment, we will gain the option to convert any part of the licensed area into oil and gas leases. We currently have a performance bond of $63 toward fulfilling its work commitment, and will need to post additional bonds annually if no work is carried out in the licensed area.

Assignment Oversight Agreement

On November 5, 2009, CIE entered into an Assignment Oversight Agreement ("AOA") with the Alaska Department of Natural Resources ("Alaska DNR") which set out certain terms under which the Alaska DNR would approve the transfer of oil and gas leases owned by the State of Alaska from Pacific Energy to CIE. This agreement remains in place following our acquisition of CIE in December 2009. Generally, the agreement requires CIE to provide the Alaska DNR with additional information and oversight authority to ensure that CIE is acting diligently to develop the oil and gas from Redoubt and West McArthur River units ("WMRU"). Under the terms of the AOA, until the Alaska DNR determines that CIE has completed certain development and operational commitments relating to the WMRU and Redoubt Units, CIE must do the following, in addition to the normal requirements under the terms of the leases:


•	file a monthly 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,


•	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,

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•	notify the Alaska DNR 10 days prior to commitment when CIE is preparing to spend funds on a purchase, project or item relating to the WMRU or Redoubt Leases of more than $5,000,


•	annually submit a new plan of development for the Alaska DNR's approval.

The AOA required CIE to demonstrate funding commitments of $5,150 to support the redevelopment of the WMRU and an estimated $31,000 to support the development of the Redoubt Unit. The Company believes it has adequately fulfilled these commitments.

On March 11, 2011, the Company entered into a Performance Bond Agreement under its AOA with the state of Alaska. Under the Performance Bond Agreement, the Company is required to post a total bond of $18,000 for the dismantling and abandonment of the properties. As agreed with the state of Alaska, the Performance Bond Agreement fulfills our commitment under the AOA to fund the full dismantlement costs with respect to our onshore and offshore assets. The Performance Bond Agreement also stipulated that $6,628 held by the state in an escrow account will be credited towards the $18,000. As a result, the Company recorded a $6,910 gain on acquisition (inclusive of accrued interest) during the year ended April 30, 2011.

The AOA also prohibits CIE from using proceeds from operation at WMRU or Redoubt for non-core oil and gas activities, or activities unrelated to WMRU or Redoubt, without the prior written approval of the Alaska DNR until the parties mutually agree that the full dismantlement obligation under the assigned leases is funded.

Failure to submit the information required by the AOA or expenditure of proceeds from WMRU or Redoubt for items or activities unrelated to core oil and gas activities at WMRU or Redoubt would constitute a default under the AOA. If the default could not be cured within 30 days, the leases would be subject to termination by the Alaska DNR.

Membership in Cook Inlet Spill Prevention and Response, Inc. ("CISPRI")

CIE is a member of the CISPRI. CISPRI is a non-profit corporation formed in 1990 to provide oil spill prevention and response capabilities in Cook Inlet. CISPRI has been designated as a Class "E" Oil Spill Removal Organization by the U.S. Coast Guard, which is the highest level of designation based on spill containment and removal equipment requirements for offshore/ocean response. CISPRI's response zone includes the entire Cook Inlet region. At each annual meeting of CISPRI members adopt a budget for the coming year which includes funds for day to day operational activities of CISPRI, investments in capital equipment and materials to be used in connection with the cleanup activities and research and development and training. The budget is funded though payment of dues by the members and the amount of dues is calculated in accordance with a participation formula. We pay an annual fee of $50 together with additional fees based upon the amount of oil we transport.

If a spill of crude oil/synthetic crude oil or refined petroleum products is identified as originating from facilities owned or operations conducted by one or more of the members, CISPRI will act to control and clean up the spill without any further action by the members. Any member that utilizes or receives the benefit of these activities must reimburse CISPRI for all expenses of control and clean up, including costs of equipment, materials and personnel. Each member is required to execute a response action contract providing terms and conditions under which response and cleanup activities will be undertaken. CIE is a party to such an agreement which, in part, requires CIE to maintain worker's compensation insurance, employers' liability insurance, comprehensive general and automotive liability insurance covering injury or death or persons and property damage of at least $10,000. CIE is in compliance with these insurance requirements. All members accept responsibility for spills which result from their operations or facilities and have indemnified CISPRI and all other members for all liabilities arising for a spill. This indemnification is not limited by the amount of insurance coverage.

CIE may resign its membership in CISPRI upon 30 days written notice. At the effective date of the resignation, CIE is obligated to pay all unpaid dues and assessments levied prior to the notice of resignation. CIE's membership may be terminated by the Board of Directors of CISPRI upon 60 days notice if it is determined CIE is no longer eligible for membership. CIE would not be entitled to a refund of any monies paid to CISPRI.

Appalachian Region

We are the largest owner/operator of oil and natural gas wells in Tennessee. As of April 30, 2013, we owned approximately 50,260 gross acres of leasehold interests with 193 producing oil wells and 191 producing gas wells in which we own an interest. This is an increase of 1,000 gross acres, 10 oil wells and 10 gas wells from April 30, 2012. Wells drilled within our acreage range from approximately 1,500 to 4,200 feet in depth with major targets in descending order being: the Mississippian age Monteagle Limestone and Fort Payne Limestone, and the Devonian age Chattanooga Shale, with the Fort Payne Limestone being the primary oil target.

During fiscal 2013, Miller focused its emphasis on continuing the purchase of working interests in wells in order to increase the number of wells in which we own an interest, thus increasing production. In addition we focused on reworks of older producing wells, and drilling horizontal wells in the Mississippian age Fort Payne Limestone. With the strategic purchases of

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working interests, reworks, and drilling new wells; net oil production in Tennessee increased from 46 bbls per day at April 30, 2012 to 55 bbls per day at April 30, 2013. Gas production has stayed flat due to restrictions on gas sales in the area.

In January 2013, we drilled and completed the first successful horizontal oil well in the Fort Payne Limestone in Tennessee. This well has confirmed the viability of this type of drilling technique in the Mississippian age limestone formations in Tennessee. We are presently producing from this well, and since the well is a first of its kind we are experimenting with various production techniques. Miller drilled a second horizontal well in the Fort Payne Limestone and we are still in the completion phase of this well.

This drilling and production method, along with gas pressure maintenance, will enable us to maximize the oil potential in Tennessee. We have acreage in and around previously producing fields and plan to utilize our expertise to enhance present production and extract additional oil from areas previously overlooked. Currently, within the acreage controlled by us, there are numerous potential well locations that can be drilled and produced. In addition, we will continue to pursue a pressure maintenance program and natural gas storage within the Mississippian age Fort Payne Limestone.

Miller has millions of cubic feet of gas shut-in and behind pipe in Tennessee. With the price of natural gas moving upward, we plan on moving forward to secure markets for this gas. In addition to the gas shut-in and behind pipe, the Devonian age Chattanooga Shale underlies acreage controlled by us and is a candidate for horizontal gas wells in the future.

Principal Markets and Customers

The existing markets for natural gas production in southcentral Alaska are the Tesoro Nikiski Refinery, utility companies, petrochemical manufacturing, the production of LNG for export to Asian markets, and the production of synthetic crude oil (“syncrude”). Presently, our sole market for crude oil produced from our Alaskan operations is the Tesoro Nikiski Refinery. Crude oil is shipped by pipeline and tanker vessel to the Tesoro Nikiski Refinery, operated by Tesoro Alaska Petroleum Company ("Tesoro").

Under the terms of the Alaska crude oil sales contract, Tesoro has agreed to purchase all crude oil produced by us, subject to a minimum of 200 bbls/day and a maximum of 24,000 bbls/day. Should the quantity of oil produced by us fall below the minimum or rise above the maximum, the contract would be open for renegotiation.

The price for each delivery of oil shall be equal to the simple arithmetic average of the published daily NYMEX WTI for the applicable front month NYMEX Contract published each business day in the calendar month of delivery, subject to certain adjustments: (i) If the ANS Index Midpoint Price is at least $2.285/bbl greater than the WTI Index Price, then the price shall be equal to the ANS Index Midpoint Price less $4.00/bbl; (ii) If the ANS Index Midpoint Price is equal to or less than the sum of the WTI Index Price plus $2.285/bbl, then the price shall be equal to the WTI Index Price less $1.715/bbl; (iii) less a deduction for the CISPRI; (iv) less a deduction for transportation through the Kenai Pipeline; (v) less a deduction for transportation and shipping, and; (vi) less a deduction adjusting for Redoubt Shoal quality. Non-Redoubt Shoal oil will have an additional quality adjustment.

We are also responsible for paying taxes on the sale, production or handling of the oil prior to delivery. The contract may be opened for renegotiation if the quality of the oil changes, certain volume reductions or increases, changes to the CISPRI charges, or closure of the company's Alaska Refinery. In fiscal 2013, 2012 and 2011, purchases by Tesoro accounted for 100%, 100%, and 99%, respectively, of our total Alaska oil and gas production revenues.

Currently, approximately 1.5 MMcfd to 3.0 MMcfd of natural gas produced by our Alaskan operations is used to generate heat and power at our production facilities. In the near future, gas production in excess of our internal needs will be sold to third parties, as all of our gas wells are connected to the Southcentral Alaska Railbelt pipeline network through the Cook Inlet Gas Gathering System and/or the Beluga Pipeline, both of which are operated by Hilcorp Alaska, LLC and its affiliates.

The principal markets for our crude oil and natural gas produced in the Appalachian region are refining companies, utility companies and private industry end users. Crude oil is stored in tanks at the well site until the purchaser retrieves it by tank truck. Direct purchases of our crude oil are made by Barrett Oil Purchasing Company, Sunoco, and Kentucky Oil and Refining Company. Our natural gas has multiple markets throughout the eastern United States through gas transmission lines. Access to these markets is presently provided by three companies in northeastern Tennessee: Cumberland Valley Resources, NAMI Resources Company, and Tengasco. Local markets in Tennessee are served by Citizens Gas Utility District and the Powell Clinch Utility District. Natural gas is delivered to the purchaser via gathering lines into the main gas transmission line. Surplus gas is placed in storage facilities or transported to East Tennessee Natural Gas which serves Tennessee and Virginia. In fiscal 2013, 2012 and 2011, sales to Barrett Oil Purchasing and Sunoco, collectively, represented approximately 81%, 35%, and 2%, respectively, of our total Tennessee oil and gas revenues.

Drilling Statistics

Historically, our drilling activities have generally concentrated on the recompletion of wells in the Cook Inlet region and the exploitation and extension of existing producing fields in the Appalachian region. In fiscal 2012, we transitioned our efforts

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to the construction of a custom rig for the Osprey platform, Rig 35, with the anticipation that it will restore all previously producing wells on the platform. During fiscal 2013 and early fiscal 2014, we have used Rig 35 to restore or commence production from oil wells RU-1, RU-7 and RU-2A and gas wells RU-3 and RU-4. Rig 35 is currently being used to sidetrack the RU-1 oil well.

We also made significant improvements and modifications to one of our rigs, Rig 34, to enable onshore drilling in winter conditions while complying with Alaska regulations. Upon certification from the Alaska Oil and Gas Conservation Commission ("AOGCC") in March 2012, we mobilized Rig 34 to the Kustatan gas field to workover the KF-1 well, a previously producing gas well, and to the Otter Prospect in April 2012 to begin drilling the Otter 1 well. Rig 34 is currently working on the Olson Creek #1 well, which was spudded on June 25, 2013.

In 2013, we incurred dry hole costs on one well in Tennessee. In Tennessee, we drilled two new development wells; one well that is producing and one well that is classified non-producing as of the year end. In 2012, we explored two new zones in our KF-1 well in Alaska that were unproductive. The cost of exploring the two new zones was expensed in 2012.

The following table shows the results of the oil and gas wells drilled and completed for each of the last three fiscal years:



	Drilling Activities
	2013		2012		2011
	Gross	Net	Gross	Net	Gross	Net
Development:
Producing
Cook Inlet	—	—	—	—	—	—
Appalachian region	1	1	—	—	—	—
Total producing	1	1	—	—	—	—
Non-Producing
Cook Inlet	—	—	—	—	—	—
Appalachian region	1	1	—	—	—	—
Total non-producing	1	1	—	—	—	—
Injection
Cook Inlet	—	—	—	—	—	—
Appalachian region	—	—	—	—	—	—
Total injection	—	—	—	—	—	—
Dry
Cook Inlet	—	—	—	—	—	—
Appalachian region	—	—	2	2	—	—
Total dry	—	—	2	2	—	—
Total development	2	2	2	2	—	—
Exploratory:
Productive
Cook Inlet	—	—	—	—	—	—
Appalachian region	—	—	—	—	3	3
Total productive	—	—	—	—	3	3
Dry
Cook Inlet	—	—	1	1	—	—
Appalachian region	1	1	—	—	—	—
Total dry	1	1	1	1	—	—
Pending determination	—	—	—	—	—	—
Total exploratory	1	1	1	1	3	3
Total drilling activity	3	3	3	3	3	3

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Productive Oil and Gas Wells

The number of productive oil and gas wells, operated and non-operated, in which we had an interest as of April 30, 2013 is set forth below:



	Producing Wells
	Gross^(a)			Net^(b)
	Oil	Gas	Total	Oil	Gas	Total
Cook Inlet	5	9	14	4	6	10
Appalachian region	193	191	384	132	128	260
Total	198	200	398	136	134	270

———————


(a)	The number of gross wells is the total number of wells in which an interest is owned.


(b)	The number of net wells is the sum of fractional interests we own in gross wells expressed as whole numbers and fractions thereof.

Production, Pricing, and Lease Operating Cost Data

The following table describes, for each of the last three fiscal years, net oil and gas production volumes, average sales prices, and average production cost per boe after deducting royalties and interests of others, with respect to oil and gas production attributable to our interest. Average production cost presented within the table are costs incurred to operate, to maintain the wells and equipment, and to pay the production costs, which does not include transportation, ad valorem and severance taxes per unit of production.



	For the Year Ended April 30,
	2013		2012		2011
Net production - boe¹	374,729		405,799		327,712
Average oil price - per bbl	$	101.53	$	93.10	$	75.75
Average natural gas price - per mcf	$	3.52	$	3.47	$	4.77
Average lease operating expenses - per boe²	$	59.48	$	27.86	$	24.93

———————


1	Net production for fiscal 2013, 2012 and 2011 includes 57,123, 33,956 and 34,987 boe of fuel gas, respectively, which is considered in the calculation of average production cost but excluded from the calculation of average sales prices.


2	Fiscal 2013 average lease operating expenses per boe includes $7,462 in workover expenses.

Gross and Net Undeveloped and Developed Acreage

Our staff of professional geologists utilizes results from logs, seismic data and other tools to evaluate existing wells and to predict the location of economically attractive new natural gas and oil reserves. To further this process, we have collected and continue to collect logs, core data, production information and other raw data available from state and private agencies and other companies and individuals actively drilling in the regions being evaluated. From this information, the geologists develop models of the subsurface structures and formations that are used to predict areas for prospective economic development.

On the basis of these models, we obtain available natural gas and oil leaseholds, farm-outs and other development rights in these prospective areas. In most cases, to secure a lease, we pay a lease bonus and an annual rental payment, converting to a royalty upon initial production. In addition, overriding royalty payments may be granted to third parties in conjunction with the acquisition of drilling rights initially leased by others.

We believe that we hold good and defensible title to our developed properties, in accordance with standards generally accepted in the industry. As is customary in the industry, a preliminary title examination is conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial work is performed with respect to discovered defects which we deem to be significant. Title examinations have been performed with respect to substantially all of our producing properties.

Certain of the properties we own are subject to royalty, overriding royalty and other outstanding interests customary to the industry. The properties may also be subject to additional burdens, liens or encumbrances customary to the industry, including items such as operating agreements, current taxes, development obligations under natural gas and oil leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with the use of the properties.

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The following table presents our gross and net acreage position in each region where we have operations as of April 30, 2013:



	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Cook Inlet	39,153	32,106	641,093	623,244	680,246	655,350
Appalachian region	11,500	7,760	38,760	32,117	50,260	39,877
Total acreage	50,653	39,866	679,853	655,361	730,506	695,227

The following table presents the net undeveloped acres that we control under fee leases and exploration licenses and the period the leases and exploration license are scheduled to expire, absent pre-expiration drilling or production which extends the term of the lease(s) or the fulfillment of the exploration license terms which permits us to convert all or any portion of the exploration license into oil and gas leases. The expiration dates of the leases are subject to one year automatic renewals so long as we are producing oil and/or gas on the lease. In Alaska, three leases (Gross & Net 12,553 acres) expired May 31, 2012, the State of Alaska issued ADL 391877 (Gross & Net 160 acres), and acreage was added to one of the Olson Creek Mental Health Trust leases (Gross & Net 1,660 acres).

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	Net Undeveloped Acres
Lease/Exploration License	Fiscal Year of Expiration	Total Acres
Cook Inlet
MHT 9300062 - Olson Creek	2014	5,483
MHT 9300063 - Olson Creek	2014	5,566
ADL 391613 - Olson Creek	2018	107
ADL 391614 - Olson Creek	2018	35
ADL 391615 - Olson Creek	2018	570
ADL 391623 - N Alexander	2018	5,513
ADL 391877 - N Alexander	2020	160
ADL 390749 - Otter	2014	2,522
ADL 390579 - Otter	2012, Held by Drilling	5,760
ADL 391621 - Otter	2018	2,528
ADL 391624 - Otter	2018	2,514
ADL 390078 - Susitna Basin #2 Exploration License	2013	471,474
ADL 391628 - Susitna Basin #4 Exploration License	2021	62,909
ADL 391794 - Susitna Basin #5 Exploration License	2017	45,764
ADL 390735 - Stingray	2013	2,047
ADL 391608 - Tazlina	2018	5,760
ADL 17602 - Sabre/Sword	1967, Held by Unit	896
ADL 18758 - Sabre	1967, Held by Unit	280
ADL 17594	1967, Held by Unit	80
ADL 17597	1967, Held by Unit	1,280
ADL 18730	1967, Held by Unit	480
ADL 18777	1967, Held by Unit	553
ADL 390368 - Kustatan	2010, Held by Well	963
Total		623,244

Appalachian region
Lindsay	Held by production	1,439
Edwards-Fowler	Held by production	55
Gunsight	Held by production	1,468
Phillips et al from Gunsight acreage	Held by production	1,031
KTO acreage	Held by production	24,586
Baker-Senior lease farm out	Held by production	1,590
Other Undeveloped, net	2014	1,948
Total		32,117

Total acreage		655,361

Oil and Natural Gas Reserves

“Proved reserves” are the quantities of oil and gas that, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible. We provide information on two types of proved reserves - developed and undeveloped. “Proved developed reserves” are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods and “proved undeveloped reserves” are reasonably certain reserves in drilling units immediately adjacent to the drilling unit containing a producing well, as well as areas beyond one offsetting drilling unit from a producing well.

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“Unproved reserves” are based on geological and/or engineering data similar to that used in estimates of proved reserves, but technical, contractual, or regulatory uncertainties preclude such reserves being classified as proved. They are sub-classified as probable and possible. Probable reserves are attributed to known accumulations and usually claim a 50% confidence level of recovery. Possible reserves are attributed to known accumulations that have a less likely chance of being recovered than probable reserves. This term is often used for reserves which are claimed to have at least a 10% certainty of being produced. Reasons for classifying reserves as possible include varying interpretations of geology, reserves not producible at commercial rates, uncertainty due to reserve infill, and projected reserves based on future recovery methods.

The following table shows proved oil and gas reserves as of April 30, 2013, based on average commodity prices in effect on the first day of each month in fiscal 2013, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms. This table shows reserves 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. All of our proved reserves are located in the United States.



	Net Reserves at April 30, 2013
Reserves category:	Oil (MBbls)	Natural Gas (MMcf)	MBoe	Reserve %
PROVED
Developed
Cook Inlet	1,576	244	1,617	19%
Appalachian region	121	269	166	2
Undeveloped
Cook Inlet	6,257	3,427	6,828	79
Appalachian region	—	—	—	—
Total Proved	7,954	3,940	8,611	100%

Our estimates of proved reserves, proved developed reserves and proved undeveloped ("PUD") reserves as of April 30, 2013, 2012 and 2011, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Supplemental Oil and Gas Disclosures (Unaudited) set forth in Part IV, Item 15 of this Form 10-K. Estimated future net cash flows were calculated using a discount rate of 10% per annum, end of period costs, and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.

In fiscal 2013, we did not develop any PUDs. We anticipate developing four of our offshore PUDs in Alaska's Redoubt Unit during fiscal 2014, including Redoubt 2A, 5B, 9 and 4A. Depending on the availability of an onshore drilling rig, we also plan on developing two PUDs in Alaska's West MacArthur River Field in fiscal 2014 including WMRU 8 and 9.

Preparation of Oil and Gas Reserve Information

Our reserve estimates for oil and natural gas as of April 30, 2013 for our Cook Inlet and Appalachian region assets were prepared by Ralph E. Davis Associates, Inc., an independent engineering firm. Our reserve reports, which are filed as exhibits to this annual report, were prepared using engineering and geological methods widely accepted in the industry. All reserve definitions comply with the applicable definitions of the rules of the SEC. The accuracy of the reserve estimates is dependent upon the quality of available data and upon independent geological and engineering interpretation of that data. For the proved developed producing reserves, the estimates were made when considered to be definitive, using performance methods that utilize extrapolations of various historical data including, but not limited to, oil, gas and water production and pressure history. For the other proved producing, proved behind pipe reserves, proved undeveloped reserves, and probable and possible reserves estimates were made using volumetric methods.

Our reserve estimates for oil and natural gas as of April 30, 2012 and 2011 for our Cook Inlet assets were prepared by Ralph E. Davis Associates, Inc. Our reserve estimates for oil and natural gas at April 30, 2012 for our Appalachian region assets were prepared by Ralph E. Davis Associates, Inc., and by Lee Keeling and Associates, Inc., as of April 30, 2011.

Internal Controls over Reserves Estimate

Our reserve estimates are in compliance with the SEC definitions and guidance and were prepared by an independent engineering firm. Our Chief Executive Officer of CIE and Acting Chief Financial Officer are primarily responsible for the engagement and oversight of our independent engineering firms. We provide the engineering firms with estimate preparation material such as property interests, production, current operation costs, current production prices and other information. This

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information is reviewed by the Chief Executive Officer of CIE and our Acting Chief Financial Officer prior to submission to our third party engineering firm. Letters which identify the professional qualifications of each of the independent engineering firms who prepared the reserve reports are included in those reserve reports which are filed as exhibits to this annual report. There was no conversion of unproved reserves to proved reserves during the fiscal year ended April 30, 2013.

Other Ancillary Services

We also generate ancillary revenues from facility rentals, services and drilling activities. While the facilities, equipment and personnel on hand are for the benefit of servicing and drilling our own properties, from time to time we optimize unused capacity by renting space and performing services and drilling on behalf of third parties. In fiscal 2013, 51% of our other revenues related to a road and pad building project in Alaska. In fiscal 2012 and 2011, 29% and 35%, respectively, of our other revenue related to a plugging project for the U.S. Department of Interior in Tennessee.

Competitive Conditions

Our oil and gas exploration activities in Alaska and Tennessee are undertaken in a highly competitive and speculative business environment. In seeking any other suitable oil and gas properties for acquisition, we compete with a number of other companies doing business in Alaska, Tennessee and elsewhere, including large oil and gas companies and other independent operators, many with greater financial resources than we have.

At the local level, as we seek to expand our lease holdings, we compete with several companies who are also seeking to acquire leases in the areas of the acreage which we have under lease. In Alaska, we have nine significant competitors consisting of Apache Corporation, Aurora Gas, Buccaneer Alaska, Hilcorp, ConocoPhillips, Furie, XTO, Linc Energy, and NordAq. However, we believe we can effectively compete because we already have existing oil and gas production, facilities, infrastructure, and pipelines that connect us to the oil and gas markets. We believe that our existing Alaska oil and gas reserves and current leases with large acreage positions enhance our competitive position within the area and will enable us to compete effectively for additional lease acreage with our competitors. In the Appalachian region, we have five significant competitors consisting of Atlas Energy Resources, LLC, Consol Energy, Inc., Can Argo Energy Corporation, Champ Oil, and Tengasco, Inc. These companies are in competition with us for oil and gas leases in known producing areas in which we currently operate, as well as other potential areas of interest. We have more than 40 years of experience in the Appalachian region and are the largest operator of oil and gas wells in Tennessee.

Government Regulation

While the prices of oil and natural gas are set by the market, other aspects of our business and the industry in general are heavily regulated. The availability of a ready market for oil production and natural gas depends on several factors beyond our control. These factors include regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to protect consumers from unfair treatment and oppressive control, to reduce the risk to the public and workers from the drilling, completion, production and transportation of oil and natural gas, to prevent waste of oil and natural gas, to protect rights among owners in a common reservoir and to control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies.

Our exploration and production business is subject to various federal, state and local laws and regulations on the taxation of natural gas and oil, the development, production and marketing of natural gas and oil and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, water discharge, prevention of waste and other matters. Prior to commencing drilling activities for a well, we must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies in the state in which the area to be drilled is located. The permits and approvals include those for the drilling of wells. Additionally, other regulated matters include the following:


•	bond requirements in order to drill or operate wells;


•	the location of wells;


•	the method of drilling and casing wells;


•	the surface use and restoration of well properties;


•	the plugging and abandoning of wells; and


•	the disposal of fluids.

The Regulatory Commission of Alaska regulates the intrastate pipeline tariffs and encompasses all pipelines CIE ships through including the Cook Inlet Pipeline Company ("CIPL"), CIGGS, and Beluga lines. The Regulatory Commission of Alaska must also review and approve most major long-term gas sales contracts to public utilities, and through this mechanism plays the

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dominant role in determining gas pricing, since Alaska has no spot market for gas. Southcentral Alaska gas is typically sold under long or short term contracts as opposed to a spot market. For the purposes of reasonably valuing gas reserves, therefore, future gas production is assumed to be sold at contract terms comparable to similarly situated producers.

CIE has posted $800 in Alaska and federal bonds. The Alaska DNR requires $600 in bonding to operate oil and gas leases on state lands, and the AOGCC requires a $200 bond to drill wells in the state. These bonds are fully funded and are held by the First National Bank of Alaska in certificates of deposit for benefit of the various beneficiaries.

CIE has a total of $909 in designated accounts to satisfy future abandonment obligations. A $324 letter of credit is established for two Class 1 non-hazardous injection wells for benefit of the United States Environmental Protection Agency (“EPA”). This letter of credit is backed by an account which must maintain a minimum value of $324. Under the terms of the bankruptcy sale of the Pacific Energy assets, CIE was obligated to establish accounts to cover abandonment obligations to Cook Inlet Region, Inc. (“CIRI”), Salamatof Native Association (“Salamatof”), and the State of Alaska; $585 was required to cover future abandonment expenses related to the three West Foreland gas wells for benefit of CIRI, all of which has been funded. An additional $750 is for future abandonment expenses associated with surface facilities and pipelines for benefit of CIRI and Salamatof, none of which has yet been funded.

In March 2011, CIE entered into a Performance Bond Agreement that set the bond for the Osprey platform at an inflation-adjusted $18,000. The agreement sets a payment schedule totaling $12,000 in annual payments between July 2013 and July 2019. An existing interest bearing account containing approximately $7,011 as of April 30, 2013 is to be credited against the inflation-adjusted $18,000 liability. Annual payments will be made after 2019 as necessary to the degree that inflation has caused the liability to increase over the amount contained in the funded accounts.

Under the Oil Pollution Act of 1990, CIE is required to fund a citizens advisory group, the Cook Inlet Regional Citizen's Advisory Council, under which its commitment is approximately $60 per year.

Tennessee law requires that we obtain state permits for the drilling of oil and gas wells and to post a bond with the Tennessee Oil and Gas Board to ensure that each well is reclaimed and properly plugged when it is abandoned. The reclamation bonds cost $1,500 per well. The cost for the plugging bonds range from $2,000 to $3,000 per well depending on depth or $20,000 for ten wells. Currently, we have several old $10 blanket plugging bonds which covers up to 10 wells. For most of the reclamation bonds, we have deposited a $2 certificate of deposit with the Tennessee Oil and Gas Board.

Sales of natural gas in Tennessee are affected by intrastate and interstate gas transportation regulation. Beginning in 1985, the Federal Energy Regulatory Commission ("FERC"), which sets the rates and charges for transportation and sale of natural gas, adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. The stated purpose of FERC's changes is to promote competition among the various sectors of the natural gas industry. In 1995, FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas by pipeline. Every five years, FERC will examine the relationship between the change in the applicable index and the actual cost changes experienced by the industry. We are not able to predict with certainty what effect, if any, these regulations will have on us.

The state and regulatory burden on the oil and natural gas industry generally increases our cost of doing business and affects our profitability. While we believe we are presently in compliance with all applicable federal, state and local laws, rules and regulations, continued compliance (or failure to comply) and future legislation may have an adverse impact on our present and contemplated business operations. Because such federal and state regulations are amended or reinterpreted frequently, we are unable to predict with certainty the future cost or impact of complying with these laws.

We are subject to various federal, state and local laws and regulations governing the protection of the environment, such as the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act, and the Federal Water Pollution Control Act of 1972 (the "Clean Water Act"), which affect our operations and costs. In particular, our exploration, development and production operations, our activities in connection with storage and transportation of oil and other hydrocarbons and our use of facilities for treating, processing or otherwise handling hydrocarbons and related wastes may be subject to regulation under these and similar state legislation. These laws and regulations:


•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;


•	limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and


•	impose substantial liabilities for pollution resulting from our operations.

CERCLA, also known as "Superfund," imposes liability for response costs and damages to natural resources, without regard to fault or the legality of the original act, on some classes of persons that contributed to the release of a "hazardous substance"

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into the environment. These persons include the "owner" or "operator" of a disposal site and entities that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our ordinary operations, we may generate waste that may fall within CERCLA's definition of a "hazardous substance." We may be jointly and severally liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these wastes have been disposed.

We currently lease properties that for many years have been used for the exploration and production of oil and natural gas. Although we have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed or released on, under or from the properties owned or leased by us or on, under or from other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose actions with respect to the treatment and disposal or release of hydrocarbons or other wastes were not under our control. These properties and wastes disposed on these properties may be subject to CERCLA and analogous state laws. Under these laws, we could be required to do the following:


•	remove or remediate previously disposed wastes, including wastes disposed or released by prior owners or operators, and/or


•	clean up contaminated property, including contaminated groundwater; or to perform remedial operations to prevent future contamination.

At this time, we do not believe that we are associated with any Superfund site and we have not been notified of any claim, liability or damages under CERCLA.

The RCRA is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements and liability for failure to meet such requirements on a person who is either a "generator" or "transporter" of hazardous waste or an "owner" or "operator" of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA's requirements because our operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.

The Clean Water Act imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. The Clean Water Act requires us to construct a fresh water containment barrier between the surface of each drilling site and the underlying water table. This involves constructing pit(s) and inserting heavy gauge plastic in the pit(s) in order to keep any drilling fluids and/or oil from escaping the drill site and contaminating the ground water and/or any navigable waters. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans.

The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

Our operations are also subject to laws and regulations requiring removal and cleanup of environmental damages under certain circumstances. Laws and regulations protecting the environment have generally become more stringent in recent years, and may in certain circumstances impose "strict liability," rendering a corporation liable for environmental damages without regard to negligence or fault on the part of such corporation. Such laws and regulations may expose us to liability for the conduct of operations or conditions caused by others, or for acts which may have been in compliance with all applicable laws at the time such acts were performed. The modification of existing laws or regulations or the adoption of new laws or regulations relating to environmental matters could have a material adverse effect on our operations.

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In addition, our existing and proposed operations could result in liability for fires, blowouts, oil spills, discharge of hazardous materials into surface and subsurface aquifers and other environmental damage, any one of which could result in personal injury, loss of life, property damage or destruction or suspension of operations. We have an Emergency Action and Environmental Response Policy Program in place. This program details the appropriate response to any emergency that management believes to be possible in our area of operations. We believe we are presently in compliance with all applicable federal and state environmental laws, rules and regulations; however, continued compliance (or failure to comply) and future legislation may have an adverse impact on our present and contemplated business operations.

Employees

On April 30, 2013, we had 79 employees.

Offices

Our principal executive offices are located at 9721 Cogdill Road, Suite 302, Knoxville, Tennessee. At April 30, 2013, we maintained regional exploration and/or production offices in Huntsville and Sunbright, Tennessee and Anchorage, Alaska. We lease all of our primary administrative offices in Knoxville, Tennessee and Anchorage, Alaska. The current lease on our principal executive office runs through 2016. For more information regarding our obligations under office leases, please see Management's Discussion and Analysis of Financial Condition and Results of Operations under the caption "Contractual Obligations" set forth in Part II, Item 7 of this Form 10-K.

Our History

We were formed in Delaware in November 1985. In January 1997, we acquired Miller Petroleum, Inc., a privately-held company controlled by Mr. Deloy Miller, our Chairman, in a reverse merger in which Miller Petroleum, Inc. was the accounting survivor. In conjunction with this transaction, we changed our name to Miller Petroleum, Inc. and re-domesticated to the State of Tennessee.

From 1997 to 2008, we focused our operations on our existing acreage in the State of Tennessee. During this time, we participated in a joint venture with Wind City Oil & Gas, LLC (“Wind City”), which resulted in the drilling of ten successful natural gas wells on our Koppers, Lindsay, and Harriman acreage. However, a dispute arose between Wind City and us as to the winding up of the joint venture, and it was ultimately resolved after we were able to sell some of the acreage to Atlas Energy Resources, LLC (“Atlas”), in 2008. The Atlas transaction was subject to unwinding pursuant to a pending litigation between our company and CNX Gas Company, LLC as disclosed in Item 3. Legal Proceedings.

In August 2008, we hired Scott M. Boruff as our Chief Executive Officer, and began to look for opportunities to expand our acreage and operations by acquiring other businesses and forming strategic partnerships with other exploration and production companies. During Mr. Boruff's tenure as CEO, we have acquired the assets of one company, and acquired sole ownership of three companies.

The first acquisition under Mr. Boruff's leadership was the KTO transaction in which we acquired certain oil and gas properties in exchange for 1,000,000 shares of our common stock valued at $320.

Shortly thereafter, we acquired ETC, in exchange for an aggregate of 1,000,000 shares of our common stock valued at $250. In March 2009, we formed Miller Energy GP and in April 2009 we formed Miller Energy Income 2009-A, LP (“MEI”). MEI was organized to provide the capital required to invest in various types of oil and gas ventures including the acquisition of oil and gas leases, royalty interests, overriding royalty interests, working interests, mineral interests, real estate, producing and non-producing wells, reserves, oil and gas related equipment including transportation lines and potential investments in entities that invest in such assets (except for other investment partnerships sponsored by affiliates of MEI). Through a subsidiary we own 1% of MEI, however due to the shared management of our company and MEI, we consolidate this entity.

The third acquisition significantly expanded our operations, assets, and reserves, and took us into a new geographic area. On December 10, 2009, we acquired 100% of the membership interests in CIE in exchange for four year stock warrants to purchase 3,500,000 shares of our common stock at exercise prices ranging from $0.01 to $2.00 per share and $250 in cash to satisfy certain expenses as well as reimbursement for reasonable out of pocket expenses. Following the transaction, Mr. David Hall was appointed as a member of our Board of Directors and as Chief Executive Officer of CIE.

Immediately prior to our acquisition of CIE, CIE acquired, through a Delaware Chapter 11 bankruptcy proceeding, the former Alaskan operations of Pacific Energy. The purchased operations included the West McArthur River oil field, the West Foreland natural gas field, the Redoubt field and related Osprey offshore platform and Kustatan Production Facility. All of these assets are located along the west side of the Cook Inlet. We also acquired 602,000 acres of oil and gas leases, including 471,474 acres under the Susitna Basin Exploration License as well as completed 3D seismic geology and other production facilities. At

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closing we paid Pacific Energy $2,250 and provided $2,220 for bonds, contract cure payments and other federal and State of Alaska requirements to operate the facilities.

In April 2011, we changed our name to Miller Energy Resources, Inc.

On June 24, 2011, we acquired a 48% minority interest in each of two limited liability companies, Pellissippi Pointe, LLC and Pellissippi Pointe II, LLC for total cash consideration of $400. We have also agreed to indemnify the sellers of the membership interests with respect to their guaranties of the construction loans held by the Pellissippi Pointe entities. On July 12, 2012, we signed a direct guarantee for 55% of the loan obligation outstanding of $5,074 with FSG Bank. As of April 30, 2013, the loan obligation is $4,970 and the liability recorded for the guarantee is $207. The Pellissippi Pointe entities own two office buildings in west Knoxville, Tennessee. In November, 2011, we moved our corporate headquarters into one of these buildings, located at 9721 Cogdill Road, Knoxville, Tennessee. We executed a five-year lease for the space, and with the addition of us, the building is fully occupied by tenants.

ITEM 1A. RISK FACTORS.

In addition to the other information set forth elsewhere in the Form 10-K, you should carefully consider the following known, material risk factors associated with our business, the oil and gas industry in which we operate, and the ownership of our securities. If any of the events described below occur, our business, financial condition, results of operations, liquidity or access to the capital markets could be materially adversely affected, and holders or purchasers of our securities could lose part or all of their investments. There may be additional risks that are not presently material or known. We may include additional risk factors in the prospectuses for securities we issue in the future.

Risks Related to Our Business

We have a history of operating losses and incurred a net loss in fiscal 2013, 2012 and fiscal 2011. Our revenues are not currently sufficient to fund our operating expenses and there are no assurances we will develop profitable operations.

We reported operating losses of $32,349 in fiscal 2013, $25,085 in fiscal 2012 and $14,592 in fiscal 2011. As a result of the continued expansion of our business during fiscal 2013, our operating expenses presently exceed our revenues. We anticipate that our operating expenses will continue to increase as we continue to develop our operations in both Tennessee and Alaska. We will continue depleting our cash resources to fund operating expenses until such time as we are able to significantly increase our revenues. We have had to borrow money and raise money through issuances of equity in order to fund our operations in the past, resulting in debt costs, interest, and dilution of our existing shareholders' equity. We may have to reduce our expansion efforts if we have not seen an increase in revenues in the next fiscal year, which could also lead to a loss of properties or reserves. There are no assurances that we will be able to significantly increase our revenues or develop profitable operations.

In preparing our consolidated financial statements for the fiscal years 2013, 2012, and 2011, we and our independent public accounting firms identified material weaknesses in our internal control over financial reporting. If we fail to achieve or maintain effective internal control over financial reporting, we may be unable to accurately and timely report our financial results or prevent fraud, and our business, investor confidence and the market price of our shares may be adversely impacted.

In the course of the preparation and audit of our consolidated financial statements for the fiscal years 2013, 2012, and 2011 we and our independent registered public accounting firms identified a number of deficiencies in our internal control over financial reporting, including “material weaknesses” as defined in the standards established by the U.S. Public Company Accounting Oversight Board Standard. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis, and a significant deficiency is a deficiency, or a combination of deficiencies, in internal control over financial reporting that is less severe than a material weakness, but important enough to merit attention by those responsible for oversight of the company's financial reporting.

The material weaknesses identified for the fiscal years 2013, 2012 and 2011 related to a lack of human resources in our accounting and finance departments. In the audit of our consolidated financial statements for fiscal 2013, we and our independent registered public accounting firm determined that enough time had not lapsed since the hiring of additional accounting personnel to provide assurance that the material weakness has been remediated. In remediating the material weakness, we may experience difficulties in integrating new personnel into the accounting department and may identify areas where additional personnel may be required. In an effort to meet the demands of our planned activities in fiscal 2014 and thereafter, we may be required to supplement our staff with more expensive contract and consultant personnel until we are able to hire new employees, if necessary. We further may not be successful in our efforts to enhance our systems, accounting, controls and reporting performance. All of this may have a material adverse effect on our business, results of operations, cash flows and growth plans, on our regulatory and listing status, and on our stock price.

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We are subject to debt costs under the terms of our Credit Facility with Apollo Investment Corporation. Monies borrowed are subject to an interest rate of 18% per annum.

As described later in this Annual Report, in June 2012 we entered into a Loan Agreement with Apollo Investment Corporation, under which a credit facility of up to $100,000 (the “Apollo Credit Facility”) was made available to us. At closing, we drew $40,000 under the Apollo Credit Facility, and have drawn $15,000 in subsequent borrowings and $307 in paid-in-kind interest, for a total indebtedness under our Apollo Credit Facility of approximately $55,307. That amount and any other monies borrowed by us bear interest at mezzanine rates and are subject to a make whole premium and prepayment penalties if any prepayments are made prior to June 29, 2016. These debt costs may be substantial, and will adversely impact our results until the facility has been repaid.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions, and engage in other business activities that may be in our best interests.

The Apollo Credit Facility contains a number of significant covenants that, among other things, restrict our ability to:


•	pay for general and administrative expenses;


•	deviate from the Approved Plan of Development ("APOD");


•	dispose of assets;


•	incur or guarantee additional indebtedness and issue certain types of preferred stock;


•	pay dividends on our capital stock;


•	create liens on our assets;


•	enter into sale or leaseback transactions;


•	enter into specified investments or acquisitions;


•	repurchase, redeem or retire our capital stock or subordinated debt;


•	merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;


•	engage in specified transactions with subsidiaries and affiliates; or


•	pursue other corporate activities.

Because we are limited in the total amount we may spend on general and administrative expenses, we may need to make reductions in general and administrative expenses in future periods, which could impact our ability to operate our business and achieve our aggressive plan for development.

The Apollo Credit Facility further establishes priorities among the projects we may choose to fund using either loan proceeds or our ordinary collections in the APOD. This may constrain management's ability to pursue projects in their optimal order, or require us to obtain waivers or consents from our lenders in order to deviate from the APOD.

We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under the Apollo Credit Facility.

If we fail to meet financial and production covenants contained in the Apollo Credit Facility, we may be limited in our ability to make additional borrowings under the Apollo Credit Facility, obtain additional funds on favorable terms, make capital expenditures, withstand a downturn in our business or the economy, or pay dividends on our Series B and Series C Preferred Stock. If the failure to meet these covenants results in a default, we could face the acceleration of our indebtedness under the Apollo Credit Facility which would become immediately due and payable.

The Apollo Credit Facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition and oil and gas production-level tests. Our ability to comply with these ratios and financial condition and production-level tests may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition and production-level tests. These financial ratio restrictions and financial condition and production-level tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. A decline in oil and natural gas prices, a prolonged period of oil and natural gas prices at lower levels, or any event which limits our ability to meet oil and gas production requirements specified in the Apollo Credit Facility could eventually result in our failing to meet one or more of the financial and production-level covenants required by the Apollo Credit Facility, which could require us to raise additional capital at an inopportune time or on terms not favorable to us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition or production-level tests could result in a default under the Apollo Credit Facility. A default under that facility, if not cured or waived, could result in acceleration of all indebtedness outstanding under our credit agreement. The accelerated debt would become

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immediately due and payable. If that should occur, we may be unable to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us.

During fiscal 2013, we sought amendments to the Apollo Credit Facility to revise the dates on which the covenant tests would commence, and paid waiver fees up to $200. If, in the future, we are required to obtain similar amendments as a result of our inability to meet the required financial ratios, there can be no assurance that those amendments will be available on commercially reasonable terms or at all.

Based on our production levels existing at April 30, 2013, we would not achieve compliance with the production covenant under the Apollo Credit Facility as of October 31, 2013, the next relevant testing date. Our ability to meet this covenant by that date will depend on new sources of production coming online subsequent to April 30, 2013, including production from RU-2A, which was brought online in June 2013. No assurance can be made regarding RU-2A's continued output in the future or the success of our efforts to increase production from other wells.

Material differences between the estimated and actual timing of critical events may affect the completion and commencement of production from our projects.

We have identified and budgeted for numerous drilling locations, but we may not be able to drill those locations within our expected time frame or at all. Our projects may be delayed by the availability of third-party rigs, project approvals from joint venture partners, timely issuances of permits and licenses by governmental agencies, weather conditions, manufacturing and delivery schedules of critical equipment, equipment repairs, the availability of sufficient capital resources, and other unforeseen events. Delays and differences between estimated and actual timing of critical events may adversely affect our production and our projected cash flows from operations.

We are party to several lawsuits seeking millions of dollars in damages against us. An adverse decision in any of these lawsuits could result in our being forced to pay the prevailing plaintiff substantial amounts of money that would adversely impact our ability to continue with our development plans and/or operate our business.

As described later in this Annual Report, we are subject to lawsuits seeking millions of dollars in damages against us. While we believe these suits to be of an essentially frivolous nature, litigation is inherently unpredictable, and any damages that could ultimately be paid by us in relation to any of these lawsuits are subject to significant uncertainty. The timing and progression of each case is also unpredictable; it may take years for the case to make its way to trial and through various appeals. The total amounts that will ultimately be paid by us in relation to all obligations relating to these lawsuits are subject to significant uncertainty and the ultimate exposure and cost to us will be dependent on many factors, including the time spent litigating each case and the attorneys' fees incurred by us in defending the cases, and whether our insurance provides coverage for the claims asserted in each case. Our consolidated financial statements contained herein do not contain any reserves for any potential damages associated with this pending litigation. If we should not be successful in our defense of this pending litigation, our results of operations in future periods could be materially adversely impacted.

CIE's operations are subject to oversight by the Alaska DNR. 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.

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We may be subject to regulatory actions surrounding the filing of the 2011 Form 10-K

On July 30, 2011, the Audit Committee of our Board of Directors determined that our consolidated balance sheet at April 30, 2011, and our consolidated statements of operations, stockholders' equity and cash flows for the year then ended (collectively, the “2011 Financial Statements”), as well as the report of KPMG LLP dated July 29, 2011 on such statements, all as included in our 2011 Form 10-K, should not be relied upon. The 2011 Form 10-K was filed with the SEC on July 29, 2011 prior to KPMG LLP completing its audit of the 2011 consolidated financial statements and issuing their independent accountants' report thereon, or issuing its consent to the use of their report. We received a request from the SEC for a more detailed explanation regarding the specific circumstances that led to the filing of the 2011 Form 10-K that included the audit report and consent from KPMG LLP prior to the completion of their audit. In September 2011, we provided the requested explanation to the SEC and are fully cooperating with the staff. We cannot predict the nature of any additional responses or actions that may be required of us surrounding the filing of the 2011 Form 10-K. Such responses could divert management's time and attention from the operation of our business and could result in increased legal fees and fines.

We may fail to fully identify potential problems related to acquired businesses or assets, or obtain protection from the sellers, and the integration of significant acquisitions may be difficult.

Our business plan contemplates significant acquisitions of reserves, properties, prospects, and leaseholds and other strategic transactions that appear to fit within our overall business strategy, which may include the acquisition of asset packages of producing properties or existing companies or businesses operating in our industry. The successful acquisition of producing properties requires an assessment of several factors, including:


•	recoverable reserves;


•	future oil and natural gas prices and their appropriate differentials;


•	development and operating costs; and


•	potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We are not entitled to contractual indemnification for environmental liabilities and acquired properties on an “as is” basis.

Significant acquisitions of existing companies or businesses and other strategic transactions may involve additional risks, including:


•	diversion of our management's attention to evaluating, negotiating, and integrating significant acquisitions and strategic transactions;


•	our ability to meet the reporting requirements under federal securities laws due to the condition or availability of the target's financial records;


•	the challenge and cost of integrating acquired operations, accounting, internal controls, human resources, information management, administrative, and other technology systems, and business cultures with our own while carrying on our ongoing business;


•	the adjustment to operating a larger combined organization once integrations are complete;


•	failure to realize expected synergies and cost savings;


•	difficulty associated with coordinating geographically separate organizations; and


•	the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to manage the integration process effectively, or if any significant business activities are interrupted as a result of the integration process, our business could be materially adversely affected.

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Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on the acreage.

A sizeable portion of our acreage is currently undeveloped. Unless production is established on these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.

Our Susitna Basin Exploration Licenses require us to fulfill certain work commitments and convert acreage to leases in order to retain the acreage after the term of the license.

Over 580,000 acres of our total acreage consists of the three Susitna Basin Exploration Licenses in Cook Inlet, Alaska. These three licenses require us to spend a total of $3,250 in work commitments before we may convert the licenses into leases. We may not be able to complete our work commitments in a timely manner, or if we do complete them, we may not identify any acreage that we would convert to leases. This could result in a substantial decrease in our total acreage in the Cook Inlet Basin.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Approximately 79% of our total estimated proved reserves at April 30, 2013 were proved undeveloped reserves. In addition, there are no assurances that probable and possible reserves will be converted to proved reserves.

Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in our reserve engineer reports assumes that substantial capital expenditures are required to develop such reserves, and we typically hold most or all of the working interests in our wells, so must bear most or all of the costs of development ourselves. Although cost and reserve estimates attributable to our natural gas and crude oil reserves have been prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate, that development will occur as scheduled or that the results of such development will be as estimated. We also have a significant amount of unproved reserves at April 30, 2013. There is significant uncertainty attached to unproved reserve estimates, which include probable and possible reserves. Proved reserves are more likely to be produced than probable reserves and probable reserves are more likely to be produced than possible reserves. There are no assurances that we can develop probable or possible reserves into proved reserves, or that if developed, these reserves will become producing reserves to the level of the estimates.

The results of our use of horizontal drilling in Tennessee using long laterals and modern completion techniques are subject to more uncertainties than our vertical drilling programs and may not meet our expectations for reserves or production.

During fiscal 2013, we believe we became the first company to drill horizontal oil wells in the Fort Payne formation in Tennessee. Part of our drilling strategy in formations where we have drilled horizontal wells involves the drilling of long horizontal laterals and the use of modern completion techniques of multi-stage fracture stimulations that have been used in other basins by other operators. Our experience with horizontal drilling and multi-stage fracture stimulations of these formations to date is relatively limited and there is no way at this time to determine whether the use of these techniques will prove to be commercially successful in the formations of interest in Tennessee.

Our commodity price risk management and trading activities may prevent us from benefiting fully from price increases and may expose us to the risk of financial loss.

To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which:


•	our production falls short of the hedged volumes;


•	there is a widening of price-basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;


•	the counterparties to our hedging or other price risk management contracts fail to perform under those arrangements; or


•	a sudden unexpected event materially impacts oil and natural gas prices.

Our business depends on oil and natural gas transportation facilities, most of which are owned by others.

The marketability of our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems owned by third parties. The lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. The lack of availability of these facilities for an extended period of time could negatively affect our revenues. Federal and state regulation of oil and natural gas production and

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transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

The majority of our oil production is dedicated to one customer and as a result, our credit exposure to this customer is significant.

We have entered into an oil marketing agreement with Tesoro Refining and Marketing Company under which Tesoro purchases all of our oil production in Alaska. We generally do not require letters of credit or collateral to support these trade receivables. Accordingly, a material adverse change in their financial condition could adversely impact our ability to collect the applicable receivables, and thereby affect our financial condition.

The majority of our reserves and assets, including our Cook Inlet Basin leases and our Osprey Platform, are located in a region of active volcanoes and we could be subject to the adverse impacts of natural disasters or other regional events.

The Cook Inlet region contains active volcanoes, including Augustine Volcano, Mount Spurr and Mount Redoubt, and volcanic eruptions in this region have been associated with earthquakes and tsunamis. Debris avalanches have also resulted in tsunamis. In 2009, the CIPL suspended operations on several occasions as a result of the spring 2009 major eruption of Mount Redoubt which also resulted in a shutdown of the Drift River Oil Terminal. Our operations in this area are subject to all of the inherent risks associated with operations in a geographical region which is subject to natural disasters and we are susceptible to the risk of damage to our operations and assets located in the Cook Inlet Basin. While our facilities are engineered to withstand seismic activity, and the current tight line configuration should allow us to continue shipments through an active volcanic period without much interruption, we do not maintain business interruption insurance which could adversely impact our results of operations as the result of lost revenues in future periods.

The majority of our oil and gas reserves are located in the Cook Inlet Basin. Any regional events, including price fluctuations, the natural disasters mentioned above, restrictive laws or regulations that increase costs, reduce availability of equipment or supplies, reduce demand or limit our production may impact our operations more than if our reserves were more geographically diversified.

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 C 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. More recently, the financial crisis in Europe (which relates primarily to concerns that certain European countries may be unable to pay their national debt) has 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 C Preferred Stock, the return we receive on our investments, as well as other unknown adverse effects on us or the economy in general.

Risks Related to the Oil and Natural Gas Industry

Estimates of oil and natural gas reserves are inherently imprecise. Any material inaccuracies in these reserve estimates or underlying assumptions will affect materially the quantities and present value of our reserves.

Estimates of proved oil and natural gas reserves and the future net cash flows attributable to those reserves are prepared by independent petroleum engineers and geologists. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and cash flows attributable to such reserves, including factors beyond our control and that of our engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Different reserve engineers may make different estimates of reserves and cash flows based on the same available data. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future oil and natural gas prices and expenditures for future development drilling and exploration activities, and of engineering and geological interpretation and judgment. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based upon production history, development drilling and exploration activities and prices of oil and natural gas. Actual future production, revenue, taxes, development drilling expenditures, operating expenses, underlying information, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and underlying information set forth herein.

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We may not realize an adequate return on wells that we drill.

Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The wells we drill or participate in may not be productive, and we may not recover all or any portion of our investment in those wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that crude oil or natural gas is present or may be produced economically. The costs of drilling, completing, and operating wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors including, without limitation:


•	unexpected drilling conditions;


•	pressure or irregularities in formations;


•	equipment failures or accidents;


•	fires, explosions, blowouts, and surface cratering;


•	marine risks such as capsizing, collisions, or adverse weather conditions; and


•	increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment.

Future drilling activities may not be successful, and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.

Oil and gas prices fluctuate due to a number of uncontrollable factors, creating a component of uncertainty in our development plans and overall operations. Declines in prices adversely affect our financial results and rate of growth in proved reserves and production.

Oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production depend on numerous factors beyond our control. These factors include, but are not limited to, changes in global supply and demand for oil and gas, the actions of the Organization of Petroleum Exporting Countries, the level of global oil and gas exploration and production activity, weather conditions, technological advances affecting energy consumption, domestic and foreign governmental regulations and tax policies, proximity and capacity of oil and gas pipelines and other transportation facilities.

Additionally, a decline in future oil and natural gas prices and the related reduction in revenues could precipitate a breach in the interest coverage ratio covenant contained in our Loan Agreement with Apollo.

Discoveries or acquisitions of additional reserves are needed to avoid a material decline in reserves and production.

The production rate from oil and gas properties generally declines as reserves are depleted, while related per-unit production costs generally increase as a result of decreasing reservoir pressures and other factors. Therefore, unless we add reserves through exploration and development activities or, through engineering studies, identify additional behind-pipe zones, secondary recovery reserves, or tertiary recovery reserves, or acquire additional properties containing proved reserves, our estimated proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves on an economic basis. Furthermore, if oil or gas prices increase, our cost for additional reserves could also increase.

The present value of future net cash flows from our proved reserves will not necessarily be the same as the current market value of our estimated natural gas, crude oil and natural gas liquids reserves.

You should not assume that the present value of future net revenues from our proved reserves referred to in this Annual Report is the current market value of our estimated natural gas, crude oil and natural gas liquids reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from our proved reserves are based on prices and costs on the date of the estimate, held constant for the life of the properties. Actual future prices and costs may differ materially from those used in the present value estimate. Actual future net cash flows will also be affected by increases or decreases in consumption by oil and gas purchasers and changes in governmental regulations or taxation. The timing of both the production and the incurrence of expenses in connection with the development and production of oil and gas properties affects the timing of actual future net cash flows from proved reserves. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily an appropriate discount factor for determining a market valuation. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the relevance of the 10% discount factor.

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Our business involves a high degree of operational risk, particularly risk of personal injury, damage, or loss of equipment, and environmental accidents that may result in substantial losses for which insurance may be unavailable or inadequate.

Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, formations with abnormal pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures or cement failures, and environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases. Any of these risks can cause substantial losses resulting from injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution and other environmental damages, regulatory investigations and penalties, suspension of our operations and repair and remediation costs. In addition, our liability for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease. We maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations.

We face strong industry competition that may have a significant negative impact on our results of operations.

Strong competition exists in all sectors of the oil and gas exploration and production industry. We compete with major integrated and other independent oil and gas companies for acquisition of oil and gas leases, properties, and reserves, equipment, and labor required to explore, develop, and operate those properties, and marketing of oil and natural gas production. Crude oil and natural gas prices impact the costs of properties available for acquisition and the number of companies with the financial resources to pursue acquisition opportunities. Many of our competitors have financial and other resources substantially larger than we possess and have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as fluctuating worldwide commodity prices and levels of production, the cost and availability of alternative fuels, and the application of government regulations. We also compete in attracting and retaining personnel, including geologists, geophysicists, engineers, and other specialists. These competitive pressures may have a significant negative impact on our results of operations.

Our industry is subject to extensive environmental regulation that may limit our operations and negatively impact our production. As a result of increased enforcement of existing regulations and potential new regulations following the Gulf of Mexico oil spill, the costs for complying with government regulation could increase.

Extensive federal, state, and local environmental laws and regulations in the United States affect all of our operations. Environmental laws to which we are subject in the U.S. include, but are not limited to, the Clean Air Act and comparable state laws that impose obligations related to air emissions, the RCRA, and comparable state laws that impose requirements for the handling, storage, treatment or disposal of solid and hazardous waste from our facilities, the CERCLA and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which our hazardous substances have been transported for disposal, and the Clean Water Act, and comparable state laws that regulate discharges of wastewater from our facilities to state and federal waters. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental laws, including CERCLA and analogous state laws, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Environmental legislation may require that we do the following:


•	acquire permits before commencing drilling;


•	restrict spills, releases or emissions of various substances produced in association with our operations;


•	limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas;


•	take reclamation measures to prevent pollution from former operations;


•	take remedial measures to mitigate pollution from former operations, such as plugging abandoned wells and remedying contaminated soil and groundwater; and


•	take remedial measures with respect to property designated as a contaminated site.

There is inherent risk of incurring environmental costs and liabilities in connection with our operations due to our handling of natural gas and other petroleum products, air emissions and water discharges related to our operations, and historical industry

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operations and waste disposal practices. The costs of any of these liabilities are presently unknown but could be significant. We may not be able to recover all or any of these costs from insurance. In addition, we are unable to predict what impact the Gulf oil spill will have on independent oil and gas companies such as our company. For instance, companies such as ours currently pay an $0.08 per barrel tax on all oil produced in the U.S. which is contributed to the Oil Spill Liability Trust Fund. There are pending proposals to raise this tax to $0.18 to $0.25 per barrel. It is also probable that there will be increased enforcement of existing regulations and adoption of new regulations which will also increase our cost of doing business which would reduce our operating profits in future periods.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005, FERC has authority to impose penalties for violations of the Natural Gas Act, up to $1 per day for each violation and disgorgement of profits associated with any violation. FERC has recently proposed and adopted regulations that may subject our facilities to reporting and posting requirements. Additional rules and legislation pertaining to these and other matters may be considered or adopted by FERC from time to time. Failure to comply with FERC regulations could subject us to civil penalties.

Derivatives regulation included in current or proposed financial legislation and rulemaking could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.

The Dodd-Frank Act, which was signed into law in July 2010, contains significant derivatives regulation, including a requirement that certain transactions be cleared on exchanges and a requirement to post collateral (commonly referred to as “margin”) for such transactions. The Act provides for a potential exception from these clearing and collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions. We expect to qualify as a commercial end-user. As required by the Dodd-Frank Act, the Commodities Futures and Trading Commission ("CFTC") has promulgated numerous rules to define these terms. In addition, it is possible that the CFTC, in conjunction with prudential regulators, may mandate that financial counterparties entering into swap transactions with end-users must do so with credit support agreements in place, which could result in negotiated credit thresholds above which an end-user must post collateral.

We use derivative instruments with respect to a portion of our expected crude oil and natural gas production in order to reduce the impact of commodity price fluctuations and enhance the stability of cash flows to support our capital investment programs and acquisitions. Our current derivative contracts do not require the posting of margin up to $15,000.

Depending on the rules and definitions adopted by the CFTC and prudential regulators, we could be required to post significant amounts of collateral with our dealer counterparties for derivative transactions. Requirements to post cash collateral could result in negative impacts on our liquidity and financial flexibility and also cause us to incur additional debt and/or reduce capital investment. In addition, the final CFTC rules may also require the counterparties to our derivative instruments to move some of their derivative activities to a separate entity, which may not be as creditworthy as the current counterparty.

Proposed federal, state, or local regulation regarding hydraulic fracturing could increase our operating and capital costs.

Several proposals are before the U.S. Congress that, if implemented, would either prohibit or restrict the practice of hydraulic fracturing or subject the process to regulation under the Safe Drinking Water Act. Several states are considering legislation to regulate hydraulic fracturing practices that could impose more stringent permitting, transparency, and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In addition, some municipalities have significantly limited or prohibited drilling activities and/or hydraulic fracturing, or are considering doing so. We routinely use fracturing techniques in the U.S. and other regions to expand the available space for natural gas and oil to migrate toward the wellbore. It is typically done at substantial depths in very tight formations.

Although it is not possible at this time to predict the final outcome of the legislation regarding hydraulic fracturing, any new federal, state, or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions in the U.S.

The effects of future environmental legislation on our business are unknown but could be substantial.

Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. Changes in, or enforcement of, environmental laws may result in a curtailment of our production activities, or a material increase in the costs of production, development drilling or exploration, any of which could have a material adverse effect on our financial condition and results of operations or prospects. In addition, many countries, as well as several states in the United States have agreed to regulate emissions of “greenhouse gases.”

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Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning natural gas, are greenhouse gases. Regulation of greenhouse gases could adversely impact some of our operations and demand for products in the future.

The proposed U.S. federal budget for fiscal year 2014 includes certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.

On April 10, 2013, the Office of Management and Budget released a summary of the proposed U.S. federal budget for fiscal year 2014. The proposed budget repeals many tax incentives and deductions that are currently used by U.S. oil and gas companies and imposes new taxes. The provisions eliminate of the ability to fully deduct intangible drilling costs in the year incurred, repeal percentage depletion for oil and natural gas wells, repeal the domestic manufacturing deduction for oil and natural gas companies, increase the geological and geophysical amortization period for independent producers to seven years, repeal the exception to passive loss limitations for working interests in oil and natural gas properties, repeal the enhanced oil recovery credit, and repeal the credit for oil and gas produced from marginal wells. Should some or all of these provisions become law, our taxes will increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also cause us to reduce our drilling activities. As none of these proposals have yet been voted on or become law, we do not know the ultimate impact these proposed changes may have on our business.

Risks Related to the Ownership of Our Securities

We do not currently pay dividends on our common stock and do not anticipate doing so in the future.

We intend to retain any future earnings to fund our operations; therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. Also, our credit agreement does not permit us to pay dividends on our common stock. We are prohibited by Tennessee law from paying dividends, if after the payment of the dividend we are unable to pay our debts as they come due in the ordinary course of business, or if our total assets would be 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 dividend, to satisfy any preferential liquidation rights to those of our common stock.

Certain of our outstanding warrants contain cashless exercise provisions; which means we will not receive any cash proceeds upon their exercise.

At April 30, 2013, we have common stock warrants outstanding to purchase an aggregate of 1,376,650 shares of our common stock with an average exercise price of $5.04 per share which are exercisable on a cashless basis. This means that the holders, rather than paying the exercise price in cash, may surrender a number of warrants equal to the exercise price of the warrants being exercised. It is possible that the warrant holders will utilize the cashless exercise feature which will deprive us of additional capital which might otherwise be obtained if the warrants did not contain a cashless feature.

A large portion of our outstanding common shares are “restricted securities” and we have outstanding options, warrants and purchase rights to purchase approximately 16% of our currently outstanding common stock. The exercise of these options, warrants and purchase rights would be dilutive to our current shareholders, and could adversely affect our stock price.

We may, in the future, issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present shareholders. We are currently authorized to issue 500,000,000 shares of common stock and 150,000 shares of preferred stock with such designations, preferences and rights as determined by our Board of Directors. At July 5, 2013 we had 43,446,694 shares of common stock outstanding together with outstanding options and warrants to purchase an aggregate of 14,503,847 shares of common stock at exercise prices of between $0.01 and $6.94 per share. Of our outstanding shares of common stock at July 5, 2013, approximately 8,169,107 shares are "restricted securities." Future sales of restricted common stock under Rule 144 or otherwise could negatively impact the market price of our common stock. In addition, in the event of the exercise of the warrants and options, the number of our outstanding common stock will increase by approximately 14,503,847, which will have a dilutive effect on our existing shareholders.

The impacts of non-cash gains and losses from derivative accounting in future periods could materially impact our financial results.

To manage variability in cash flows resulting from fluctuation in oil prices, we occasionally enter into commodity derivatives to hedge a portion of our crude oil production. These instruments are marked-to-market on a periodic basis with changes in the estimated fair value recorded to our consolidated statement of operations. As of April 30, 2013, we have a derivative liability of $842. We recognized a non-cash loss on derivatives of $5,235 in fiscal 2013, $3,436 in fiscal 2012 and $1,008 in fiscal 2011. The amount of quarterly non-cash gains or losses we will record in future periods is unknown at this time as the measurement is based upon the fair market value of oil on the measurement date. It is likely, however, that these non-cash gains or losses will continue to have a material impact on our financial results in future periods.

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Substantial stock ownership by our affiliates may limit the ability of our non-affiliate stockholders to influence the outcome of director elections and other matters requiring shareholder approval.

As of April 30, 2013, management and members of the Board of Directors own approximately 30% of our outstanding common stock. Accordingly, they have significant influence in the election of our directors and, therefore, our policies and direction. This concentration of voting power could have the effect of delaying or preventing a change in control or discouraging a potential acquirer from attempting to obtain control of us, which in turn could have a material adverse effect on the market price of our common stock or prevent our shareholders from realizing a premium over the market price for their shares of common stock.

The Change of Control conversion feature of our Series C Preferred Stock may prevent a change in control, or discourage a third party from acquiring us

The Change of Control conversion feature of the Series C 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 C 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.

Risks Related to the Ownership of our Series C Preferred Stock

The Series C 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.

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 C Preferred Stock only after all of our indebtedness and other liabilities have been paid. The rights of holders of the Series C 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 Preferred Stock and any future series or class of preferred stock we may issue that ranks senior to the Series C Preferred Stock. As of the date hereof, 25,750 shares of Series B Preferred Stock, having a liquidation value of $2,575, are outstanding. In addition, the Series C 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. 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 C Preferred Stock. If we are forced to liquidate our assets to pay our creditors, we may not have sufficient assets to pay amounts due on any or all of the Series C 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 C Preferred Stock. At April 30, 2013, we had approximately $57,559 of indebtedness, on a consolidated basis (including obligations arising under our Series B Preferred Stock), ranking senior to the Series C Preferred Stock. Our Loan Agreement with Apollo prohibits payments of dividends on the Series C Preferred Stock if we fail to comply with certain financial covenants or, at certain times, if a default or event of default has occurred. Certain of our other existing or future debt instruments may restrict the authorization, payment or setting apart of dividends on the Series C Preferred Stock.

Future offerings of debt or senior equity securities may adversely affect the market price of the Series C Preferred Stock. If we decide to issue debt or senior 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 C Preferred Stock and may result in dilution to owners of the Series C 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 C Preferred Stock will bear the risk of our future offerings, reducing the market price of the Series C Preferred Stock and diluting the value of their holdings in us.

We may not be able to pay dividends on the Series C Preferred Stock.

Under Tennessee law, cash dividends may be paid from net earnings 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 C 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 C Preferred Stock. Our ability to pay dividends may be impaired if any of the risks described in this Annual Report, 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 make assurances 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

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us to make distributions on our common stock and preferred stock, including the Series C Preferred Stock, to pay our indebtedness or to fund our other liquidity needs.

The Series C Preferred Stock has not been rated.

We have not sought to obtain a rating for the Series C 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 C Preferred Stock. In addition, we may elect in the future to obtain a rating for the Series C Preferred Stock, which could adversely affect the market price of the Series C 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 C Preferred Stock.

Series C Preferred Stock holders 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 C 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 C Preferred Stock held by such holder, in which case such holder will have the right only with respect to shares of Series C Preferred Stock that are not called for redemption) to convert some or all of such holder's Series C Preferred Stock into shares of our common stock (or under specified circumstances involving certain alternative consideration).

Although we generally may not redeem the Series C Preferred Stock prior to November 1, 2017, we have a special optional redemption right to redeem the Series C Preferred Stock in the event of a Change of Control, and holders of the Series C 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 C Preferred Stock prior to the Change of Control Conversion Date, then upon an exercise of the applicable conversion rights, the holders of Series C Preferred Stock will be limited to a maximum number of shares of our common stock or other applicable consideration equal to 9.51 multiplied by the number of shares of Series C Preferred Stock converted.

The market price of the Series C Preferred Stock could be substantially affected by various factors.

The market price of the Series C 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 C Preferred Stock;


•	trading prices of common and preferred equity securities issued by other energy companies;


•	the annual yield from distributions on the Series C 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, or 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 C Preferred Stock may experience a decrease, which could be substantial and rapid, in the market price of the Series C Preferred Stock, including decreases unrelated to our operating performance or prospects.

We may issue additional shares of Series C Preferred Stock and additional series of preferred stock that rank on parity with the Series C Preferred Stock as to dividend rights, rights upon liquidation or voting rights.

We are allowed to issue additional shares of Series C Preferred Stock and additional series of preferred stock that would rank equally to the Series C 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 C Preferred Stock without any vote of the holders of the Series C Preferred Stock. The issuance of additional shares of Series C Preferred Stock and preferred stock that would rank on parity with the Series C Preferred Stock could have the effect of reducing the amounts

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available to the current holders of our Series C Preferred Stock upon our liquidation or dissolution or the winding up of our affairs. It also may reduce dividend payments to the current holders of the Series C Preferred Stock if we do not have sufficient funds to pay dividends on all Series C Preferred Stock outstanding and other classes of stock with equal priority with respect to dividends.

In addition, although holders of Series C Preferred Stock are entitled to limited voting rights, with respect to such matters, the Series C Preferred Stock will vote separately as a class along with the holders of 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 C Preferred Stock. As a result, the voting rights of holders of Series C Preferred Stock may be significantly diluted, and the holders of such other series of preferred stock that we may issue may be able to control or significantly influence the outcome of any vote.

Future issuances and sales of preferred stock ranking on parity with the Series C Preferred Stock, or the perception that such issuances and sales could occur, may cause prevailing market prices for the Series C 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.

Holders of Series C Preferred Stock have extremely limited voting rights.

Voting rights as a holder of Series C Preferred Stock are limited. Our shares of common stock are the only class of our securities that carry full voting rights. Voting rights for holders of Series C Preferred Stock exist primarily with respect to the ability to elect, voting together with the holders of any 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 C 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 C Preferred Stock are in arrears, and with respect to voting on amendments to our amended and restated charter, as amended, or articles of amendment relating to the Series C Preferred Stock that materially and adversely affect the rights of the holders of Series C Preferred Stock or authorize, increase or create additional classes or series of our shares that are senior to the Series C Preferred Stock. Other than the limited circumstances described in this Annual Report, holders of Series C Preferred Stock will not have any voting rights.

The Series C Preferred Stock is a relatively new issue of securities and has only a limited trading market, which may negatively affect its value and the ability to transfer and sell shares.

The Series C Preferred Stock is a relatively new issue of securities with only a limited trading market. The volume of trades of shares of the Series C Preferred Stock on the New York Stock Exchange ("NYSE") is often low, and an active trading market on the NYSE for the Series C Preferred Stock may not be maintained in the future and may not provide adequate liquidity. The liquidity of any market for the Series C 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 C Preferred Stock, the market for similar securities and the interest of securities dealers in making a market in the Series C Preferred Stock. As a result, the ability to transfer or sell the Series C Preferred Stock could be adversely affected.

If the Series C Preferred Stock or our common stock is delisted, the ability to transfer or sell shares of the Series C Preferred Stock may be limited, and the market value of the Series C Preferred Stock will likely be materially adversely affected.

Other than in connection with a Change of Control, the Series C Preferred Stock does not contain provisions that are intended to protect stockholders if our common stock is delisted from the NYSE. Since the Series C Preferred Stock has no stated maturity date, stockholders may be forced to hold their shares of the Series C Preferred Stock and receive stated dividends on the Series C Preferred Stock when, 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 C Preferred Stock will be delisted from the NYSE as well. Accordingly, if the Series C Preferred Stock or our common stock is delisted from the NYSE, the ability to transfer or sell shares of the Series C Preferred Stock may be limited and the market value of the Series C Preferred Stock will likely be materially adversely affected.

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ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 3. LEGAL PROCEEDINGS.

The information set forth in Note 9 - Litigation in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K is incorporated herein by reference.

ITEM 4. MINE SAFETY DISCLOSURES.

Not applicable to our operations.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

During fiscal 2013, our common stock, par value $0.0001 per share, was listed on the NYSE under the symbol “MILL.” From May 6, 2010 to April 11, 2011, our common stock was listed on the NASDAQ Global Market. Previously, our common stock was quoted on the OTC Bulletin Board and in the over the counter market on the Pink Sheets. The table below provides certain information regarding our common stock for fiscal 2013 and 2012. Prices were obtained from The New York Stock Exchange, Inc. Composite Transactions Reporting System. The quotations reflect inter-dealer prices, without retail mark-up, markdown or commission, and may not represent actual transactions. Per-share prices shown below have been rounded to the indicated decimal place.



	2013				2012
	High		Low		High		Low
First quarter	$	5.29	$	3.75	$	8.02	$	4.41
Second quarter	5.26		3.79		3.95		2.16
Third quarter	5.01		3.38		4.04		2.63
Fourth quarter	4.23		3.50		5.47		3.90

The closing price of our common stock, as reported on the New York Stock Exchange for July 5, 2013, was $4.02 per share. As of July 5, 2013, there were 43,446,694 shares of our common stock outstanding held by approximately 341 stockholders of record and approximately 11 beneficial owners.

We have never paid cash dividends on our common stock and we do not anticipate that we will declare or pay dividends in the foreseeable future. Payment of dividends, if any, is within the sole discretion of our Board of Directors and will depend, among other factors, upon our earnings, capital requirements and our operating and financial condition. In addition under Tennessee law, we may not pay a dividend if, after giving effect, we would be unable to pay our debts as they become due in the usual course of business or if our total assets would be 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 payment of the dividend to satisfy the preferential rights upon dissolution of shareholders whose preferential rights were superior to those receiving the dividend. In addition, our credit facility with Apollo does not permit us to pay dividends on our common stock.

Information concerning securities authorized for issuance under equity compensation plans is set forth in the proxy statement relating to our fiscal 2013 annual meeting of stockholders, which is incorporated herein by reference.

Stockholder Return Performance Presentation

The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the appreciation of our common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company's common stock with the cumulative total return of the Standard & Poor's Composite 500 Stock Index and of the Dow Jones U.S. Exploration & Production Index (formerly Dow Jones Secondary Oil Stock Index) from April 30, 2009, through April 30, 2013. The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.

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COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*

Among Miller Energy Resources, Inc., S&P 500 Index

and the Dow Jones US Exploration & Production Index



	2008		2009		2010		2011		2012		2013
Miller Energy Resources, Inc.	$	100	$	330	$	5,780	$	5,770	$	5,430	$	3,800
S&P's Composite 500 Stock Index	100		63		86		98		101		115
Dow Jones US Exploration & Production Index	100		52		76		100		86		94

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ITEM 6. SELECTED FINANCIAL DATA.

The following table sets forth selected financial data of our company over the five-year period ended April 30, 2013, which information has been derived from our audited financial statements. This information should be read in connection with, and is qualified in its entirety by, the more detailed information in the Company's financial statements set forth in Part IV, Item 15 of this Form 10-K.



	As of or for the Year Ended April 30,
	2013			2012			2011			2010		2009
Income Statement Data:
Total revenues	$	34,801		$	35,402		$	22,842		$	5,867	$	1,567
Net income (loss) attributable to common stockholders	(25,495		)	(19,537		)	(3,880		)	250,941		8,356
Net income (loss) per common share:
Basic	(0.60		)	(0.48		)	(0.11		)	11.65		0.56
Diluted	(0.60		)	(0.48		)	(0.11		)	8.34		0.56

Balance Sheet Data:
Total assets	$	575,405		$	536,389		$	509,081		$	500,342	$	9,942
Total debt	57,559			24,130			2,000			1,239		1,959
Weighted average common shares outstanding:
Basic	42,682,685			40,811,308			36,112,286			21,537,677		14,827,877
Diluted	42,682,685			40,811,308			36,112,286			30,092,017		14,827,877

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

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

Executive Overview

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

Strategy

Our mission is to grow a profitable exploration and production company for the long-term benefit of our shareholders by focusing on the development of our reserves, continued expansion of our oil and natural gas properties and increasing our production and related cash flow. We intend to accomplish these objectives through the execution of our core strategies, which include:


•	Develop Acquired Acreage. We will focus on organically growing production through drilling for our own benefit on existing leases and acreage in the exploration licenses with a view towards retaining the majority of working interest in the new wells. This strategy will allow us to maintain operational control, which we believe will translate to long-term benefits;

•


•	Expand Our Revenue Stream. We intend to fully exploit our mid-stream facilities, such as our injection wells and the Kustatan Production Facility, our ability to engage in the commercial disposal of waste generated by oil and gas operations, our capacity to process third party fluids and natural gas and to offer excess electrical power to net users in the Cook Inlet region; and

•

Our management team is focused on maintaining the financial flexibility required to successfully execute these core strategies.

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

Financial and Operating Results

We continued to utilize operational cash flow along with funds from our credit facility and funds raised from sales of our Series C Preferred Stock made in two "best efforts" public offerings and in "at-the-market" public offerings to support our capital expenditures during fiscal 2013. For the fiscal year ended April 30, 2013, we reported notable achievements in several key areas. Highlights for the period include:


•	On June 29, 2012, we fully redeemed the outstanding Series A Preferred Stock.


•	On June 29, 2012, we closed our new credit facility with Apollo Investment Corporation and repaid our Guggenheim Credit Facility. For additional information refer to Note 3 - Debt, in the consolidated financial statements.

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•

Rig 34 was mobilized to the Otter natural gas prospect and the drilling phase was completed at a depth of 5,680 feet in the Beluga formation. Mud logs have reported two significant hydrocarbon gas shows in the zone of interest. Additional work is now needed to fully evaluate the Beluga formation. Our engineering team is currently finalizing plans to deepen the Otter well #1 a minimum of 900 feet and a maximum of 1,300 feet. Another 900 feet will fully penetrate the Beluga formation leading us immediately into the Tyonek formation.


•	On August 21, 2012, we gained approval from state regulators to commence drilling with Rig 35 on the Osprey offshore platform. The rig has been used on workovers for RU-1, RU-3 and RU-7 and sidetracking a new RU-2A. With subsequent work, RU-3 and RU-4 are now fulfilling 100% of our current fuel gas demand with a combined flow rate around 2.5 MMcfd.


•	On September 21, 2012, we entered into a Special Warrant Exercise Agreement with warrant holders, pursuant to which warrant holders agreed to exercise 586,001 warrants immediately for $4.00 per share and waived their right to a cashless exercise. We received net proceeds of $2,291 upon exercise of these warrants.


•	Also on September 21, 2012, we entered into a Bristol Warrant Exercise Agreement with Bristol Capital, LLC, pursuant to which Bristol Capital, LLC agreed to exercise 300,000 warrants immediately for $4.00 per share and for cash. We received net proceeds of $1,200 upon exercise of these warrants.


•	On September 24, 2012, we issued 25,750 shares of a new class of Series B Preferred Stock to 10 accredited investors in a private offering exempt from registration under the Securities Act of 1933, as amended. We received net proceeds of $2,408 in connection with this sale. For additional information refer to Note 3 - Debt, in the consolidated financial statements.

•

On October 5, 2012, we issued 685,000 shares of a new class of Series C Preferred Stock in a public sale pursuant to a prospectus supplement date September 18, 2012 (issued under our existing S-3 registration statement, filed with the SEC as file number 333-183750). This new series of stock is listed for trading on the NYSE under the ticker symbol MILLprC. We received net proceeds of $14,420 in connection with this sale.


•	On October 12, 2012, we entered into the ATM Agreement with MLV for the placement and sale of our common stock and Series C Preferred Stock in one or more "at the market" public offerings from time to time. The first sale made pursuant to this agreement occurred on November 1, 2012, as discussed below.

•

On October 26, 2012, we completed a workover on the RU-1 well in the Redoubt Shoals field in Alaska. The workover involved replacing a failed electric submersible pump as well as removing other downhole obstructions. We initially capitalized the cost of the workover as we believed the workover would significantly increase our access to proved reserves. We ultimately concluded it should be expensed as the workover did not significantly increase our access to proved reserves. The costs of the workover were written off during the fourth quarter.

•

Starting on November 1, 2012, and periodically during the quarter, we issued 95,048 shares of our Series C Preferred Stock in "at-the-market" offerings pursuant to the ATM Agreement and a prospectus supplement dated October 12, 2012 (issued under our existing S-3 registration statement, filed with the SEC as file number 333-183750). These sales were made at an average price on the date of such sale ranging from $22.00 to $23.00 per share. We received net proceeds of $2,044 in connection with these sales.

•

On November 26, 2012, we applied for a right-of-permits necessary for construction of the Trans Foreland pipeline. When completed, this undersea pipeline will move our crude from the west side of the Cook Inlet where we have several producing units to the east side where the nearest refinery is located. Transporting the crude this way will be cheaper and safer than using tankers which is our only current option.


•	On January 11, 2013, we completed the first horizontal well in the Mississippian Lime in Tennessee, CPP-H-1. The well was drilled into the Fort Payne Formation to a true vertical depth of approximately 1,600 feet on our Cumberland Plateau Partners LLC lease in Scott County, Tennessee, and it exposed a pay section of approximately 2,300 feet in the horizontal section of the well.


•	On January 26, 2013, we brought a new gas well, RU-4A, into production on the Osprey platform. The workover consisted of re-completing the well to access a behind pipe gas accumulation in the Lower Tyonek gas sands at a measured depth of approximately 9,200 feet.


•	On February 7, 2013, we borrowed an additional $5,000 under our new credit facility with Apollo Investment Corporation. For additional information refer to Note 3 - Debt, in the consolidated financial statements.


•	On February 15, 2013, we issued 625,000 shares of our Series C Preferred Stock in a "follow-on" best efforts public offering. The shares were registered in the prospectus supplement date February 13, 2013 and we received net proceeds of $13,325 in connection with the issuance.


•	On February 25, 2013, we brought a new gas well, RU-3, into production on the Osprey platform. The workover consisted of re-completing the well to access a behind pipe gas accumulation in the Lower Tyonek gas sands at a measured depth of approximately 14,800 feet.

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•	On April 17, 2013, we borrowed an additional $10,000 under our new credit facility with Apollo Investment Corporation. For additional information refer to Note 3 - Debt, in the consolidated financial statements.

Fiscal 2014 Outlook

As we head into fiscal 2014, we believe our inventory of recompletion, workovers, and exploration and development projects offers numerous growth opportunities. Subsequent to April 30, 2013, we brought RU-2A online after using Rig 35 to complete a sidetrack. We are currently using Rig 35 to work on a sidetrack at RU-1 and expect to complete the sidetrack during the summer of 2013. Upon completion of the sidetrack, we will work on recompletion of RU-5. We also have several development projects onshore, which we expect will also contribute to production in fiscal 2014, along with the offshore wells brought online subsequent to April 30, 2013. No assurance can be made regarding the success of these development and recompletion efforts. Our current 2014 capital budget is $125,000. The majority of this budget is expected to be spent on projects in Alaska, with the remaining amount allocated to our Appalachian region. Due to the uncertainty associated with changes in commodity prices, we closely monitor our cost levels and revise our capital budgets based on changes in forecasted cash flows. This means our plan for capital expenditures may change as a result of anticipated changes in the market place. Further, our ability to fully utilize the budget will be dependent on a number of factors including, but not limited to, access to capital, weather and regulatory approval.

We note that, although we expect to continue to sell our Series C Preferred Stock in additional “at-the-market” offerings during fiscal 2014, we cannot guarantee that market conditions will continue to permit such sales at prices we would find acceptable. If that occurred, cash generated from those offerings would cease.

We expect to fund a portion of our remaining 2014 capital budget with free cash flow from operations, state of Alaska tax credits, potential joint ventures, and through debt, equity and preferred equity capital markets. On May 10, 2013 and on July 2, 2013, we closed two other offerings of our Series C Preferred Stock. For additional information on these offerings, refer to Note 15 - Subsequent Events, in the consolidated financial statements. In the event we are unable to raise additional capital on acceptable terms, we may reduce our capital spending.

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Results of Operations

Revenues



	For the Year Ended April 30,
	2013		Increase (Decrease)	2012		Increase (Decrease)	2011
Oil revenues:
Cook Inlet	$	27,891	(9)%	$	30,566	57%	$	19,459
Appalachian region	1,556		18	1,314		46	901
Total	$	29,447	(8)	$	31,880	57	$	20,360
Natural gas revenues:
Cook Inlet	$	41	(69)	$	134	(53)	$	286
Appalachian region	427		(11)	479		9	440
Total	$	468	(24)	$	613	(16)	$	726
Other revenues:
Cook Inlet	$	3,950	226	$	1,212	61	$	753
Appalachian region	936		45	1,697		69	1,003
Total	4,886		68	2,909		66	1,756
Total revenues	$	34,801	(2)	$	35,402	55	$	22,842

Net Production



	For the Year Ended April 30,
	2013	Increase (Decrease)	2012	Increase (Decrease)	2011
Oil volume - bbls:
Cook Inlet	275,658	(15)%	325,756	28%	254,504
Appalachian region	19,825	19	16,655	17	14,292
Total	295,483	(14)	342,411	27	268,796
Natural gas volume¹- mcf:
Cook Inlet	7,500	(84)	45,985	8	42,480
Appalachian region	125,238	(4)	130,609	19	109,683
Total	132,738	(25)	176,594	16	152,163
Total production² - boe:
Cook Inlet	276,908	(17)	333,420	27	261,584
Appalachian region	40,698	6	38,423	18	32,573
Total	317,606	(15)	371,843	26	294,157

———————


1	Cook Inlet natural gas volume excludes natural gas produced and used as fuel gas.


2	These figures show production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the current price ratio between the two products.

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Pricing



	For the Year Ended April 30,
	2013		Increase (Decrease)	2012		Increase (Decrease)	2011
Average oil sales price - per barrel:
Cook Inlet	$	102.74	9%	$	93.83	23%	$	76.46
Appalachian region	83.92		6	78.89		25	63.04
Total	101.53		9	93.10		23	75.75
Average natural gas sales price - per mcf:
Cook Inlet	3.99		37	2.92		(57)	6.73
Appalachian region	3.41		(7)	3.66		(9)	4.01
Total	3.52		1	3.47		(27)	4.77

Crude 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 fiscal 2013 were 9% above fiscal 2012, increasing from an average of $93.10 per bbl in 2012 to $101.53 per bbl in 2013.

Natural Gas Prices

Natural gas is subject to price variances based on local supply and demand conditions. The majority of our natural gas sales contracts are indexed to prevailing local market prices. Average realized prices increased 1% in 2013 compared to 2012.

Crude Oil Revenues

2013 vs. 2012. During 2013, oil revenues totaled $29,447, 8% lower than 2012. The decrease resulted from a 14% decrease in production partially offset by a 9% increase in realized oil prices. Oil revenues represented 85% of our consolidated total revenues in 2013 and 93% of our equivalent production.

Oil production decreased 46,928 bbls, driven by a 50,098 bbls decrease in the Cook Inlet region partially offset by a small increase in the Appalachian region. The production decrease in the Cook Inlet region resulted from wells being off-line during certain portions of the year, a normal decline curve and fluctuations in shipping schedules.

2012 vs. 2011. During 2012, oil revenues totaled $31,880, 57% higher than 2011, driven by a 23% increase in average realized prices and a 27% increase in production. Oil revenues represented 90% of our consolidated total revenue and 92% of our equivalent production in 2012, compared to 89% and 91%, respectively, in the prior year.

Oil production increased 73,615 bbls, driven by a 71,252 bbls increase in the Cook Inlet region, with the Appalachian region contributing an additional 2,363 bbls to the increase in total production for the year. The significant production increase in the Cook Inlet region resulted from bringing wells at our Redoubt Unit online.

Natural Gas Revenues

2013 vs. 2012. During 2013, natural gas revenues totaled $468, 24% lower than 2012. The decrease resulted from a 25% decrease in production. Natural gas represented 1% of our consolidated total revenues and 7% of our equivalent production.

2012 vs. 2011. During 2012, natural gas revenues totaled $613, $113 lower than the 2011 natural gas revenues of $726, driven by a 27% decrease in average realized prices, partially offset by a 16% increase in production. Natural gas represented 2% of our consolidated total revenues and 8% of our equivalent production in 2012, compared to 3% and 9%, respectively, in the prior year.

Other Revenues

2013 vs. 2012. Other revenues primarily represent revenues generated from contracts for road building, plugging, drilling and 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 2013 and 2012, other revenues totaled $4,886, or 14%, and $2,909, or 8%, respectively, of our consolidated total revenues. The increase in other revenues primarily resulted from a road and pad building project in the Cook Inlet region.

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2012 vs. 2011. Other revenues primarily represent revenues generated from contracts for plugging, drilling and maintenance and repair of third party wells as well as rental income we received for use of facilities in the Cook Inlet region. During 2012 and 2011, other revenues totaled $2,909, or 8%, and $1,756, or 8%, respectively, of our consolidated total revenues. The increase in other revenues primarily resulted from an increase in plugging activities in the Appalachian region and a 61% increase in facility rentals and other miscellaneous income in the Cook Inlet region.

Cost and Expenses

The table below presents a comparison of our expenses on an absolute dollar basis and an equivalent unit of production (boe) basis where meaningful.



	For the Year Ended April 30,								For the Year Ended April 30,
	2013			2012			2011		2013		2012		2011
									(Per boe)
Oil and gas operating costs	$	24,698		$	14,861		$	9,703	$	65.91	$	36.62	$	29.61
Cost of other revenues	4,189			926			808		NM		NM		NM
General and administrative	22,799			29,718			14,555		NM		NM		NM
Exploration expense	1,458			1,241			—		NM		NM		—
Depreciation, depletion, and amortization	13,170			13,310			10,961		35.15		32.80		33.45
Accretion of asset retirement obligation	900			1,072			1,407		NM		NM		NM
Other operating expense, net	(64		)	(641		)	—		NM		NM		NM
Total costs and expenses	$	67,150		$	60,487		$	37,434	$	179.20	$	149.06	$	114.23

————————

NM = not meaningful

Oil and Gas Operating Costs

Oil and gas operating costs increased $9,837 from fiscal 2012, or 66%. The majority of the increase resulted from $7,462 in workover cost related to our RU-1 and RU-7 wells in the Redoubt Shoals field in the Cook Inlet region. In addition, the majority of our operating costs are fixed, and as such, we did not experience a proportionate decrease in cost from current period declines in production. Increased drilling activities and rental of camp facilities and equipment in the Cook Inlet region require additional personnel in our camps, which increase the cost of support services.

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 2013, we experienced increases in cost of other revenues in the Cook Inlet region as we continued to monetize our midstream capabilities.



	For the Year Ended April 30,
	2013		Increase (Decrease)	2012		Increase (Decrease)	2011
Direct labor	$	2,656	292%	$	677	57%	$	430
Equipment	775		100	—		(100)	41
Repairs	598		572	89		31	68
Insurance	91		100	—		—	—
Other	69		(57)	160		(41)	269
Total	$	4,189	352%	$	926	15%	$	808

During 2013, cost of other revenues increased 352% to $4,189. A substantial portion of this increase is related to direct labor and equipment costs incurred as a result of the road building contract and the grind and inject facility.

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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 Year Ended April 30,
	2013			Increase (Decrease)	2012		Increase (Decrease)	2011
Stock-based compensation	$	10,132		(28)%	$	14,072	175%	$	5,126
Professional fees	6,248			37	4,561		36	3,347
Salaries	3,732			12	3,330		29	2,580
Employee benefits	2,357			(38)	3,824		115	1,780
Travel	1,744			3	1,693		115	786
State production credits	(3,268		)	100	—		(100)	(873		)
Other	1,854			(17)	2,238		24	1,809
Total	$	22,799		(23)%	$	29,718	104%	$	14,555

G&A expenses decreased $6,919 from fiscal 2012, or 23%. Stock-based compensation decreased 28% from the same period in the prior year, predominantly due to significantly less awards granted during our 2013 fiscal year as compared to the previous fiscal year. Further, our stock-based compensation expenses in 2013 were spread over a longer vesting or requisite period than awards granted in our 2012 fiscal year. During 2013, we submitted two Alaska loss carryforward credit applications, which in accordance with our accounting policy, reduced our G&A expense by $3,268. Salaries increased 12% from the same period in the prior fiscal year as we continue to expand our engineering, legal and accounting staff. The increase in professional fees of 37% results from additional cost related to capital markets and investor relations activities.

Exploration Expense

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

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) expenses include the depreciation, depletion and amortization of leasehold costs and equipment. Depletion is calculated on a unit-of-production basis. Depreciation is calculated on a straight-line basis.



	For the Year Ended April 30,
	2013		2012		2011		2013		2012		2011
							(Per boe)
Depletion:
Cook Inlet region	$	8,460	$	11,790	$	9,703	$	26.80	$	29.42	$	29.86
Appalachian region	1,343		747		773		22.61		19.45		23.73
	9,803		12,537		10,476		26.16		28.55		29.31
Depreciation:
Cook Inlet region	2,591		169		2		NM		NM		NM
Appalachian region	776		604		483		NM		NM		NM
	3,367		773		485		8.99		1.76		1.36
Total DD&A	$	13,170	$	13,310	$	10,961	$	35.15	$	30.31	$	30.66

The decrease in depletion in the Cook Inlet region is primarily a result of decreased production. The increase in depreciation in the Cook Inlet region is primarily due to Rig 34 and Rig 35 being placed in service during the period.

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Other Income and Expense

The following table shows the components of other income and expense.



	For the Year Ended April 30,
	2013			Increase (Decrease)	2012			Increase (Decrease)	2011
Interest expense, net	$	(4,276	)	133%	$	(1,837	)	97%	$	(934	)
Gain (loss) on derivatives, net	6,751			338	(2,832		)	(181)	(1,008		)
Gain on acquisitions	—			—	—			—	6,910
Other income (expense), net	(329		)	(667)	58			111	(537		)
Total	$	2,146		147%	$	(4,611	)	(204)%	$	4,431

Interest Expense, Net

2013 vs. 2012. Interest expense, net of interest income increased $2,439 from fiscal 2012, or 133%, driven primarily by increased outstanding debt as of April 30, 2013, coupled with less capitalized interest recorded during 2013.

2012 vs. 2011. Interest expense, net, increased $903 from 2011, or 97%, driven primarily by a $632 increase in amortization of deferred financing costs. The Company capitalized $3,700 of interest in equipment and oil and gas properties as of April 30, 2012.

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 of future oil production are marked-to-market, both realized and unrealized gains or losses are included on our 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.

2013 vs. 2012. During fiscal 2013, unrealized gain on commodity derivatives totaled $5,235, On June 6, 2012, we terminated the commodity derivative contracts in place on April 30, 2012, which were settled against the NYMEX WTI Cushing Index. In consideration of such termination, the counterparty paid the Company settlement value of $4,283 which was recorded as a realized gain. The realized gain was partially offset by realized losses during 2013 to arrive at a net realized gain of $1,516 for the year. Our overall net gain position increased 338% from 2012, primarily as a result of changes in commodity prices and the correlating fair value of our derivatives.

2012 vs. 2011. During 2012, unrealized loss on derivatives totaled $3,436, offset by a net realized gain of $604. Our overall net loss position increased 181% from 2011, primarily as a result of changes in commodity prices. Unrealized net loss on commodity derivatives accounted for $3,436 of the total net loss on derivatives, with the remaining portion related to changes in the fair value of warrants.

Gain on Acquisitions

During 2011, we recorded a gain of $6,910 (inclusive of accrued interest) related to restricted cash held by the State of Alaska that was not previously accounted for as part of the Alaska acquisition in 2010. This amount could not be verified until our entry into the Performance Bond Agreement with the State of Alaska on March 11, 2011. Under the agreement, we are required to post a bond for an aggregate amount of $18,000 with $6,800 restricted cash held by the State to be applied to the total bond requirement. We recorded this event as a gain on acquisition for our Alaska subsidiary.

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Liquidity and Capital Resources

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

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

We may elect to utilize additional borrowing capacity under the Apollo Credit Facility when available, 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.

In fiscal 2013, 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 additional Series C Preferred Stock, in both “at-the-market” sales and additional underwritten offerings, combined with additions to the borrowing base under our Apollo Credit Facility which may become available, 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, our Apollo Credit Facility restricts our access to and control of certain bank accounts without compliance with certain provisions of the loan agreement.

The Apollo Credit Facility also contains financial and production covenants. As of April 30, 2013, we were not in compliance with such covenants. However, we received a waiver of such violations from Apollo on July 11, 2013. Under the terms of the waiver, we will be required to maintain compliance with the financial and production covenants on a quarterly basis commencing October 31, 2013. Based on our production levels existing at April 30, 2013, we would likely not achieve compliance with each of the covenants as of October 31, 2013. However, we believe we will sufficiently increase our production levels to enable us to achieve compliance with the financial and production covenants. Much of the increased production is expected to come from the success of RU-2A, which was brought online in June 2013. In addition to RU-2A, we are currently completing a sidetrack on RU-1 that we expect to bring online during the summer of 2013. Once RU-1 is online, we expect to commence with the recompletion of RU-5. We also have several ongoing development projects onshore, which we also expect will contribute to production in fiscal 2014, along with the offshore wells brought online subsequent to April 30, 2013. No assurance can be made regarding the success of these development and recompletion efforts and our ability to meet future financial and production covenants. In the event we do not comply with future financial and production covenants, we would evaluate alternative financing sources including, but not limited to, common or preferred equity offerings, joint ventures, and the financing of receivables.

These restrictions notwithstanding, absent an event of default, the Apollo Credit Facility requires that Apollo release to us funds needed to pay for approved operational activity, subject to certain limitations on the order in which we undertake new projects, and for the payment of certain permitted expenses that arise in the ordinary course of business. The release of funds for other purposes is subject to Apollo's discretion, except that, absent an event of default and so long as at least half of these funds are spent on projects included in our plan of development, we do have the right to use 50% of all proceeds raised from sales of equity securities in excess of $20,000 on such matters as we see fit. We reached this $20,000 threshold on October 5, 2012, the date of the initial public offering of Series C Preferred Stock. The intent of the restrictions in the Apollo Credit Facility on our ability to access cash in our accounts is to require that Company allocate available cash to high-priority projects first and to control spending that is not strongly linked to the development of our existing assets. To date, the restrictions have not impeded our ability to run the business in any way, except that we 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 Apollo Credit Facility, and, to date, Apollo has granted our requests when made. We do not anticipate that the restrictions placed on our accounts under the Apollo Credit Facility will interfere with or require any alteration of management's overall plans in the future, subject to the need to make additional adjustments to the approved plan of development as market conditions change.

Pursuant to the September 25, 2012 amendment ("September Amendment") to the Apollo Credit Facility, upon each sale of our Series C Preferred Stock, we have agreed to deposit a portion of the proceeds of the sale into a separate account in an amount

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at least equal to the dividends scheduled to come due on our Series B Preferred Stock and our Series C Preferred Stock on or prior to September 25, 2013. As of April 30, 2013, the balance in this account was $2,110. Although we presently have the right to direct disbursements from this account without Apollo's consent, Apollo has taken a security interest in this account, and the terms of the Apollo Credit Facility state that we may only disburse funds from this account as needed to pay dividends on the Series B Preferred Stock and Series C Preferred Stock. If an event of default were to occur under the Apollo Credit Facility, Apollo would have the right to take control over this account. We have paid cash dividends on the Series B Preferred Stock and the Series C Preferred Stock in accordance with the terms of the Series B Preferred Stock and the Series C Preferred Stock as set forth in our Charter.

Current restricted cash balances include amounts held in escrow to secure company related credit cards. As of April 30, 2013 and 2012, current restricted cash also includes $7,144 and $2,045 of cash temporarily held in an account that is controlled by our lender. Non-current restricted cash balances include amounts held in escrow to provide for the future plugging and abandonment of wells, including the possible dismantling of our off-shore platform, and general liability bonds.

Sources and Uses of Cash

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



	For the Year Ended April 30,
	2013			2012			2011
Sources of cash and cash equivalents:
Net cash provided by operating activities	$	—		$	6,901		$	7,734
Proceeds from borrowings, net of debt acquisition costs	51,147			28,754			5,500
Proceeds from sale of equipment	2,000			—			—
Exercise of equity rights	3,832			1,383			1,266
Issuance of preferred stock, net of issuance costs	33,200			10,000			—
	90,179			47,038			14,500
Uses of cash and cash equivalents:
Net cash used in operating activities	(11,491		)	—			—
Cash dividends	(1,231		)	—			—
Capital expenditures for oil and gas properties	(26,361		)	(7,558		)	(10,490		)
Purchase of equipment and improvements	(11,533		)	(26,409		)	(825		)
Payments on debt	(24,130		)	(8,764		)	(3,500		)
Redemption of preferred stock	(11,240		)	—			—
Increase in restricted cash	(5,613		)	(1,895		)	(1,121		)
	(91,599		)	(44,626		)	(15,936		)

Increase (decrease) in cash and cash equivalents	$	(1,420	)	$	2,412		$	(1,436	)

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 used by operating activities of fiscal 2013 totaled $11,491, down $18,392 from 2012. The decrease resulted primarily from a decrease in revenue coupled with an increase in operating costs.

Proceeds from Credit Facilities and Other Items

As of April 30, 2013, borrowings under our Apollo Credit Facility totaled $55,307, all of which was borrowed under the credit facility during fiscal 2013. In connection with the establishment of the facility, we paid $3,853 in debt issuance costs. The proceeds were used to repay our Guggenheim Credit Facility and redeem our outstanding Series A Preferred Stock. For additional

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information on the credit facilities, please see Note 3 - Debt in the Notes as set forth in the accompanying consolidated financial statements.

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

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 Financial Accounting Standards Board Accounting Standards Codification ("ASC") 480 "Distinguishing Liabilities from Equity". See Note 3 - Debt in the Notes as set forth in the accompanying 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. 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 7 - Stockholders' Equity in the Notes as set forth in the accompanying consolidated financial statements.

Starting on November 1, 2012, and periodically during the third and fourth quarters, we issued 144,901 shares of our Series C Preferred Stock in "at-the-market" offerings pursuant to the ATM Agreement and a prospectus supplement dated October 12, 2012 (issued under our existing S-3 registration statement, filed with the SEC as file number 333-183750). These sales were made at an average price on the date of such sale ranging from $22.00 to $23.51 per share. We received net proceeds of $3,112 in connection with these sales.

On February 12, 2013, we sold an additional 625,000 shares of the Series C Preferred Stock at a price of $22.90 per share for gross proceeds of $14,312. We incurred issue costs of $987, yielding net proceeds of $13,260.

We further note that, after the close of the fiscal year, and to date, we have sold an additional (i) 43,180 shares of the Series C Preferred Stock in "at-the-market" offerings, at an average price on the date of such sale ranging from $22.01 to $22.35 per share and (ii) 500,000 shares of the Series C Preferred Stock in an underwritten "follow-on" public offering, at a price of $22.25 per share, and (iii) 335,000 shares of the Series C Preferred Stock in an underwritten "follow-on" public offering at a price of $21.50 per share. We received net proceeds of $17,976 in connection with these post year-end sales.

Capital Expenditures

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 slightly from the same period last year. During the year ended April 30, 2013, we completed Rig 35 and its related winterization. Well related capital spending in Alaska included our Otter exploratory well and drilling and recompletion projects involving our RU-2A, RU-3 and RU-4 wells. Tennessee capital spending related to new drilling projects including our CPP-H-1 and Maynard H-1 wells and a workover of our Brimstone-Bowling #1 well. During the year ended April 30, 2012, capital spending primarily related to construction of and modifications to Rigs 34 and 35.

Liquidity

Cash and Cash Equivalents

As of April 30, 2013, we had $2,551 in cash and cash equivalents.

Debt and Available Credit Facilities

Outstanding debt consisted of $55,307 under our Apollo Credit Facility, $6,000 of which is classified as current debt obligations with the remainder classified as long-term debt on the accompanying consolidated balance sheets as of April 30, 2013. As of April 30, 2013 we had no additional borrowing capacity under our Apollo Credit Facility.

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Contractual Obligations

The following table summarizes our contractual obligations as of April 30, 2013. For additional information regarding these obligations, please see Note 3 - Debt and Note 5 - Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.



	Note Reference	Total		2014		2015 - 2016		2017 - 2018		and after
Contractual obligations:^(a)
Debt, at face value^(b)	Note 3	$	57,882	$	—	$	—	$	57,882	$	—
Interest obligations	Note 3	42,891		10,264		20,528		12,099		—
Dismantlement, removal and restoration (Osprey)^(c)	Note 5	12,000		1,000		3,500		4,500		3,000
Work commitments^(d)	Note 5	2,501		625		875		438		563
Rights of way and easements:^(e)	Note 5
Osprey to shore pipeline	Note 5	262		13		26		26		197
Osprey to shore optic cable	Note 5	7		—		1		1		5
CIRI Kustatan pipeline easement	Note 5	279		28		56		56		139
West Foreland CIRI/Salamatof agreement	Note 5	184		18		37		39		90
Salamatof surface use agreement	Note 5	450		50		100		100		200
Office and related equipment^(f)	Note 5	1,063		349		666		48		—
Total contractual obligations		$	117,519	$	12,347	$	25,789	$	75,189	$	4,194

———————

This table does not include the Company’s liability for dismantlement, abandonment, and restoration costs of oil and gas properties, derivative liabilities, or tax reserves. For additional information regarding these liabilities, please see Note 2 - Derivative Instruments, Note 4 - Asset Retirement Obligations and Note 5 - Commitments and Contingencies, respectively, in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.


b.	Debt includes Series B Preferred Stock of $2,575 which matures September 24, 2017, and the debt related to the Apollo Credit Facility of $55,307 which matures on June 29, 2017. Apollo has the right to call $1,500 per quarter until maturity, beginning with the first quarter of 2014; therefore $6,000 is classified as current in our Consolidated Balance Sheet as of April 30, 2013.


c.	This represents the Performance Bond Agreement with the State of Alaska for dismantlement, removal and restoration of the Redoubt Field offshore assets.


d.	Work commitments relate to three Susitna Basin Exploration Licenses.


e.	Obligations to landowners for use of surface and subsurface rights for West McArthur River Unit and Redoubt Unit facilities including processing facilities, pipelines, roads, etc.


f.	Other operating lease obligations relate to office and related equipment.

We are also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing of and monetary impact associated with these events or rulings prevents any meaningful accurate measurement, which is necessary to assess settlements resulting from litigation. For a detailed discussion of our legal contingencies, please see Note 9 - Litigation in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Off Balance Sheet Arrangements

We enter into customary agreements in the oil and gas industry for drilling commitments, firm transportation agreements, and other obligations as described herein under Contractual Obligations in this Item 7. Other than the off-balance sheet arrangements described, we do not have any off-balance sheet arrangements with unconsolidated entities that are reasonably likely to materially affect our liquidity or capital resource positions.

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Non-GAAP Measures

Adjusted Earnings

Adjusted earnings before interest, taxes, depreciation and amortization ("EBITDA") is a significant performance metric used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts and others to assess:


•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;


•	the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and


•	our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure.

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


•	depreciation, depletion and amortization;


•	write-off of deferred financing fees;


•	asset impairments;


•	(gain) loss on sale of assets;


•	accretion expense;


•	exploration costs;


•	(gain) loss from equity investment;


•	stock-based compensation expense;


•	unrealized (gain) loss from mark-to-market activities;


•	interest expense and interest (income)

Our Adjusted EBITDA should not be considered as a substitute for net income (loss), operating income (loss), 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 table presents a reconciliation of net loss before income taxes to Adjusted EBITDA, our most directly comparable GAAP performance measure, for each of the periods presented:



	For the Year Ended April 30,
	2013			2012			2011
Loss before income taxes	$	(30,203	)	$	(29,696	)	$	(10,161	)
Adjusted by:
Interest expense, net	4,276			1,837			934
Depreciation, depletion and amortization	13,170			13,310			10,961
Accretion of asset retirement obligation	900			1,072			1,407
Exploration expense	1,458			1,241			—
Stock-based compensation	10,459			14,072			5,126
Unrealized (gain) loss on derivatives	(5,235		)	3,436			1,008
Adjusted EBITDA	$	(5,175	)	$	5,272		$	9,275

Critical Accounting Policies and Estimates

General

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

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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. The following is a discussion of our most critical accounting policies.

Estimates of Proved Reserves and Future Net Cash Flows

Proved oil and gas reserves are the estimated quantities of natural gas and crude oil that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations.

Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.

Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our DD&A expense. Further, these reserves are the basis for our unaudited supplemental oil and gas disclosures.

Reserves as of April 30, 2013, 2012, and 2011, were calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.

We elected not to disclose probable and possible reserves or reserve estimates in this filing.

Asset Retirement Obligation

We have significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments.

Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with our oil and gas properties. We utilize current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. 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.

Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

Fair Value of Financial Instruments

We measure fair value of our financial and non-financial assets and liabilities on a recurring basis. Accounting standards define fair value, establish a framework for measuring fair value and require certain disclosures about fair value measurements for assets and liabilities measured on a recurring basis. All of our derivative instruments are recorded at fair value in our financial statements. Fair value is the exit price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date.

The following hierarchy prioritizes the inputs used to measure fair value:


•	Level 1 - Quoted prices in active markets that are unadjusted and accessible at the measurement date for identical, unrestricted assets or liabilities;


•	Level 2 - Quoted prices for identical assets and liabilities in markets that are inactive; quoted prices for similar assets and liabilities in active markets or financial instruments for which significant inputs are observable, either directly or indirectly; or


•	Level 3 - Prices or valuations that require inputs that are both unobservable and significant to the fair value measurement.

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

We consider an active market to be one in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis, and view an inactive market as one in which there are few transactions for the asset or liability, prices are not current, or price quotations vary substantially either over time or among market makers. Where appropriate, we consider non-performance risk in determining the fair values of the assets and liabilities.

Stock-Based Compensation

The computation of stock-based compensation requires the use of a valuation model. ASC 718, "Compensation - Stock Compensation," requires significant judgment and the use of estimates, particularly surrounding model assumptions such as stock price volatility, expected terms, and expected forfeiture rates, to value equity-based compensation. We use various pricing models to determine the fair value of our stock options and warrants. Changes in the underlying assumptions could result in a material change to the fair value of the stock-based awards. Although every effort is made to ensure the accuracy of our estimates and assumptions, significant unanticipated changes in those estimates, interpretations and assumptions may result in recording expenses that could have a significant effect on results of operations in the future.

Purchase Price Allocation

Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities.

The purchase price allocation is accomplished by recording each asset and liability at its estimated fair value. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and tax-related carryforwards at the merger date, although such estimates may change in the future as additional information becomes known.

In estimating the fair values of assets acquired and liabilities assumed, we made various assumptions. The most significant assumptions related to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties, we prepared estimates of crude oil and natural gas reserves as described above under Estimates of Proved Reserves and Future Net Cash Flows of this Item 7. Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future.

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, with a scope clarification issued in January 2013. 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 evaluated the new pronouncement and have determined that there is no impact to our 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.

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

Supplemental Quarterly Financial Information (Unaudited)

The following table sets forth selected unaudited quarterly results for the eight quarters ended April 30, 2013.



	Apr 30, 2013			Jan 31, 2013			Oct 31, 2012			Jul 31, 2012
Total revenues	$	7,730		$	7,999		$	10,810		$	8,262
Loss from operations	(14,757		)	(6,500		)	(6,089		)	(5,003		)
Net income (loss) attributable to common stockholders	(13,121		)	(6,164		)	(6,399		)	189
Diluted loss per share	(0.31		)	(0.14		)	(0.15		)	0.00

	Apr 30, 2012			Jan 31, 2012			Oct 31, 2011			Jul 31, 2011
Total revenues	$	8,898		$	8,443		$	9,205		$	8,856
Loss from operations	(7,354		)	(6,096		)	(7,726		)	(3,909		)
Net loss attributable to common stockholders	(8,360		)	(6,510		)	(4,484		)	(183		)
Diluted loss per share	(0.20		)	(0.16		)	(0.11		)	0.00

ITEM 7A. 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 Risk

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

We periodically enter into hedging activities on a portion of our projected oil production through financial arrangements intended to support oil prices at targeted levels and to manage our overall exposure to oil price fluctuations. In 2013 and 2012, approximately 48% to 60% of our crude oil production was subject to financial derivative hedges. Realized gains or losses from our price-risk management activities are recognized in gain (loss) on derivatives, net when the associated production occurs. We do not hold or issue derivative instruments for trading purposes.

On April 30, 2013, we had open oil derivative hedges in a liability position with a fair value of $842. A 10% increase in oil prices would increase the fair value by approximately $926, while a 10% decrease in prices would decrease the fair value by approximately $758. These fair value changes assume volatility based on prevailing market parameters at April 30, 2013. For notional volumes and terms associated with our derivative contracts, please see Note 3 - Derivative Instruments in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

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

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 April 30, 2013, there was no float-rate debt that would expose us to market fluctuations in interest rates.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

The financial statements and supplementary financial information required to be filed under this Item 8 are presented in Part IV, Item 15 of this Form 10-K and are incorporated herein by reference.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

a) Disclosure Controls and Procedures.

Under the supervision and with the participation of our management, including our principal executive officer and our principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended, at the end of the period covered by this report (the “Evaluation Date”).

In conducting our evaluation, we concluded there is a material weakness in the operating effectiveness of our internal control over financial reporting, as described below.

As a result of the foregoing, we have concluded that as of the Evaluation Date we did not maintain disclosure controls and procedures that were effective in providing reasonable assurance 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 disclosure.

Our management 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.

b) Management's Report on Internal Control over Financial Reporting

The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.

Management, including our principal executive officer and principal financial officer, conducted an evaluation of the effectiveness of such controls as of April 30, 2013. This assessment was based on criteria established for effective internal control over financial reporting in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

Management identified the following material weakness in the Company's internal control over financial reporting as of April 30, 2013:

We did not maintain a sufficient complement of corporate accounting and finance personnel necessary to consistently operate management review controls. This material weakness resulted in numerous material adjustments to the preliminary financial statements that were corrected prior to their issuance.

As a result of this material weakness, the Company's management has concluded that, as of April 30, 2013, its internal control over financial reporting was not effective based on criteria established in Internal Control - Integrated Framework issued by the COSO.

KPMG LLP, an independent registered public accounting firm, has issued audit reports on its assessment of internal control over financial reporting and our consolidated financial statements that are included in Item 15 of this Annual Report on Form 10-K.

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c) Changes in Internal Control over Financial Reporting and Remediation

During fiscal 2011, we were unable to complete our assessment of the effectiveness of the Company's internal control over financial reporting in accordance with SEC rules and regulations. Notwithstanding our inability to complete this assessment, we identified material weaknesses in our internal control over financial reporting as of April 30, 2011. At such time we did not maintain: i) a sufficient complement of personnel with an appropriate level of accounting knowledge, experience and training in the selection and application of U.S. GAAP and SEC reporting requirements commensurate with our financial reporting requirements, ii) sufficient policies, procedures and controls to prevent and/or detect material misstatements in our consolidated financial statements, or iii) adequate controls to ensure that the Company maintains compliance with various SEC rules and regulations regarding reporting.

During fiscal 2012, we hired experienced personnel and engaged independent consultants to evaluate, design, implement and document appropriate internal control over financial reporting. These actions enabled us to complete our assessment of the Company's internal control over financial reporting in accordance with SEC rules and regulations as of April 30, 2012. During fiscal 2012 we also provided training to key corporate accounting and finance personnel in U.S. GAAP and SEC reporting requirements. Despite these improvements, we concluded that a material weakness in the operating effectiveness of management review controls continued to exist as of April 30, 2012.

During fiscal 2013, we hired additional personnel and provided training to key corporate accounting and finance personnel in U.S. GAAP and SEC reporting requirements. Except for these efforts, during the fourth quarter there were no changes that materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. Accordingly, we concluded that a material weakness in the operating effectiveness of management review controls continues to exist as of April 30, 2013.

To remediate this material weakness, during fiscal 2014, we will:


•	Determine the appropriate complement of corporate accounting and finance personnel required to consistently operate management review controls.


•	Hire the requisite additional personnel and/or contractors with public company accounting and reporting experience.

We can give no assurance that the measures we take will remediate the material weakness that we identified or that any additional material weaknesses will not arise in the future. We will continue to monitor the effectiveness of these and other processes, procedures and controls and will make any further changes management determines appropriate.

ITEM 9B. OTHER INFORMATION

None.

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

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

The information required by this item will be contained in our proxy statement for our 2013 Annual Meeting of Shareholders to be filed on or prior to August 28, 2013 (the "Proxy Statement") and is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this Item will be contained in our Proxy Statement and is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this Item will be contained in our Proxy Statement and is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this Item will be contained in our Proxy Statement and is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

The information required by this Item will be contained in our Proxy Statement and is incorporated herein by reference.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.


a.	Documents included in this report:


1.	Financial Statements



Report of Independent Registered Public Accounting Firm	F-1
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets	F-3
Consolidated Statements of Operations	F-4
Consolidated Statements of Stockholders' Equity	F-5
Consolidated Statements of Cash Flows	F-6
Notes to the Consolidated Financial Statements	F-7


1.	Financial Statement Schedules

Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in our financial statements and related notes.


2.	Exhibits

The following documents are filed as a part of this annual report on Form 10-K or are incorporated by reference to previous filings, if so indicated:



EXHIBIT NO.		DESCRIPTION
2.1	–	Agreement and Plan of Reorganization dated December 20, 1996 between Triple Chip Systems, Inc. and Miller Petroleum, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K (Commission file number 033-02249-FW) dated January 15, 1997).
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 filed on January 17, 2001, 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).

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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 8A filed on September 28, 2012).
4.1	–	Form of warrant issued to David M. Hall, Walter J. Wilcox, II and Troy Stafford (incorporated by reference to Registrant's Current Report on Form 8-K filed on December 23, 2009).
4.2	–	Miller Petroleum, Inc. Stock Plan (incorporated by reference to Registrant's Current Report on Form 8-K filed on April 29, 2010).**
4.3	–	Form of common stock purchase warrant for March 2010 private placement (incorporated by reference to Registrant's Annual Report on Form 10-K for the year ended April 30, 2010), as amended by the Special Warrant Exercise Agreement filed as an exhibit to Registrant's Form 8-K filed on September 21, 2012.
4.4	–	Form of common stock purchase warrant issued to purchasers in the Miller Energy Income Fund 2009-A, LP offering (incorporated by reference to Registrant's Annual Report on Form 10-K for the year ended April 30, 2010).
4.5	–	Form of common stock purchase warrant issued to Sutter Securities Incorporated (incorporated by reference to Registrant's Annual Report on Form 10-K for the year ended April 30, 2010), as amended by the Special Warrant Exercise Agreement filed as an exhibit to Registrant's Form 8-K filed on September 21, 2012.
4.6	–	2011 Equity Compensation Plan (incorporated by reference to Registrant's Current Report on Form 8-K filed on March 17, 2011).
4.7	–	Form of Series PPA Warrant (incorporated by reference to Registrant's Current Report on Form 8-K filed on April 12, 2012).
4.8	–	Form of Common Stock Certificate (incorporated by reference to Registrant's Registration Statement on Form S-3 filed on September 6, 2012).
4.9	–	Form of Series PPB warrant (incorporated by reference to Registrant's Current Report on Form 8-K filed on September 24, 2012).
4.10	–	Form of warrant issued to Robert L. Gaylor (incorporated by reference to Registrant's Registration Statement on Form S-3 filed on October 5, 2012).**
4.11	–	Form of option issued to Martin Funderlic (incorporated by reference to Registrant's Registration Statement on Form S-3 filed on October 5, 2012).**
10.1	–	Purchase and Sale Agreement dated December 16, 1997 between AKS Energy Corporation and Miller Petroleum, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K (Commission file number 033-02249-FW) filed on March 17, 1998).
10.2	–	Termination Agreement, General Release and Covenant No To Sue Dated June 13, 2008 with Cresta Capital Strategies, LLC (incorporated by reference to Registrant's Annual Report on Form 10-K for the year ended April 30, 2009).
10.3	–	Agreement dated June 8, 2009 between Ky-Tenn Oil, Inc. and Miller Petroleum, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on June 12, 2009).
10.4	–	Agreement dated June 18, 2009 for Sale of Capital Stock of East Tennessee Consultants, Inc. and Sale of Membership Interests of East Tennessee Consultants II, LLC (incorporated by reference to Registrant's Current Report on Form 8-K filed on June 24, 2009).
10.5	–	Agreement for Sale of Membership Interest in Cook Inlet Energy, LLC (incorporated by reference to Registrant's Current Report on Form 8-K filed on December 23, 2009).
10.6	–	Form of Securities Purchase Agreement for December 2009 private placement (incorporated by reference to Registrant's Current Report on Form 8-K filed on January 4, 2010).
10.7	–	First Secured Promissory Note from Miller Petroleum, Inc. to Miller Energy Income 2009-A, LP (incorporated by reference to Registrant's Quarterly Report on Form 10-Q for the period ended January 31, 2010).

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10.8	–	Second Secured Promissory Note from Miller Petroleum, Inc. to Miller Energy Income 2009-A, LP (incorporated by reference to Registrant's Quarterly Report on Form 10-Q for the period ended January 31, 2010).
10.9	–	Loan and Security Agreement between Miller Petroleum, Inc and Miller Energy Income 2009-A, LP (incorporated by reference to Registrant's Quarterly Report on Form 10-Q for the period ended January 31, 2010).
10.10	–	Escrow Agreement (incorporated by reference to Registrant's Quarterly Report on Form 10-Q for the period ended January 31, 2010).
10.11	–	Form of Securities Purchase Agreement for March 2010 private placement (incorporated by reference to Registrant's Annual Report on Form 10-K for the year ended April 30, 2010).
10.12	–	Form of Registration Rights Agreement for March 2010 private placement (incorporated by reference to Registrant's Annual Report on Form 10-K for the year ended April 30, 2010).
10.13	–	Consulting Agreement dated March 12, 2010 with Bristol Capital, LLC (incorporated by reference to Registrant's Annual Report on Form 10-K for the year ended April 30, 2010).
10.14	–	Marketing Agreement dated August 1, 2009 with The Dimirak Companies (incorporated by reference to Registrant's Annual Report on Form 10-K for the year ended April 30, 2010).
10.15	–	Assignment Oversight Agreement dated November 5, 2009 between Cook Inlet Energy, LLC and The State of Alaska Department of Natural Resources (incorporated by reference to Registrant's Annual Report on Form 10-K for the year ended April 30, 2010).
10.16	–	Cook Inlet Energy, LLC Master Services Agreement with Fairweather E&P Services, Inc. dated January 1, 2010 (incorporated by reference to Registrant's Annual Report on Form 10-K for the year ended April 30, 2010).
10.17	–	Purchase and Sale Agreement by and between Cook Inlet Energy, LLC and Pacific Energy Alaska Operating LLC and Pacific Energy Alaska Holdings, LLC dated as of November 24, 2009 (incorporated by reference to Registrant's Current Report on Form 8-K/A filed on July 27, 2010).
10.18	–	Cook Inlet Spill Prevention and Response, Inc. Bylaws and Response Action Contract (incorporated by reference to Registrant's Annual Report on Form 10-K for the year ended April 30, 2010).
10.19	–	Third Secured Promissory Note from Miller Petroleum, Inc. to Miller Energy Income 2009-A, LP (incorporated by reference to Registrant's Registration Statement on Form S-1 filed on August 13, 2010).
10.20	–	Letter from the State of Alaska to Cook Inlet Energy, LLC announcing acceptance of terms for the extension of Susitna Exploration License #2 (incorporated by reference to Registrant's Current Report on Form 8-K filed on November 2, 2010).
10.21	–	Settlement Agreement between Cook Inlet Pipe Line Company and Cook Inlet Energy, LLC (incorporated by reference to Registrant's Current Report on Form 8-K filed on November 26, 2010).
10.22	–	Amended and Restated Employment Agreement with Scott M. Boruff (incorporated by reference to Registrant's Current Report on Form 8-K filed on December 29, 2010).**
10.23	–	Performance Bond Agreement between the State of Alaska and Cook Inlet Energy, LLC (incorporated by reference to Registrant's Current Report on Form 8-K filed on March 17, 2011).
10.24	–	Employment Agreement with David J. Voyticky (incorporated by reference to Registrant's Current Report on Form 8-K filed on June 14, 2011).**
10.25	–	Contract of Construction and Sale between Miller Energy Resources, Inc. and Voorhees Equipment and Consulting, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on June 16, 2011).
10.26	–	Collateral Assignment of Rig Contract between Miller Energy Resources, Inc. and Guggenheim Corporate Funding, LLC (incorporated by reference to Registrant's Current Report on Form 8-K filed on June 16, 2011).
10.27	–	Loan Agreement between Miller Energy Resources, Inc. and Guggenheim Corporate Funding, LLC, Citibank, N.A. and Bristol Investment Fund, Ltd. (incorporated by reference to Registrant's Current Report on Form 8-K filed on June 17, 2011).

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10.28	–	Shareholders' Agreement between Deloy Miller, Scott M. Boruff, David J. Voyticky, David M. Hall, Paul W. Boyd and Miller Energy Resources, Inc. (incorporated by reference to Registrant's Current Report on Form 8-K filed on June 17, 2011).**
10.29	–	Guarantee and Collateral Agreement between Miller Energy Resources, Inc. and its subsidiaries, and Guggenheim Corporate Funding, LLC (incorporated by reference to Registrant's Current Report on Form 8-K filed on June 17, 2011).
10.30	–	First Amendment to Consulting Agreement between Miller Energy Resources, Inc. and Bristol Capital, LLC (incorporated by reference to Registrant's Current Report on Form 8-K filed on June 17, 2011).
10.31	–	Lease between Miller Energy Resources, Inc. and Pellissippi Pointe II, LLC (incorporated by reference to Registrant's Annual Report on Form 10-K for the year ended April 30, 2011).
10.32	–	Form of Assignment of Membership Interest in Pellissippi Pointe, LLC (incorporated by reference to Registrant's Annual Report on Form 10-K for the year ended April 30, 2011).
10.33	–	Form of Assignment of Membership Interest in Pellissippi Pointe II, LLC (incorporated by reference to Registrant's Annual Report on Form 10-K for the year ended April 30, 2011).
10.34	–	First Amendment and to Loan Agreement and Limited Waiver (incorporated by reference to Registrant's Current Report on Form 8-K filed on August 29, 2011).
10.35	–	Limited Consent and Extension (incorporated by reference to Registrant's Quarterly Report on Form 10-Q filed on December 12, 2011).
10.36	–	Indemnification Agreement (incorporated by reference to Registrant's Quarterly Report on Form 10-Q filed on December 12, 2011).
10.37	–	Sales Agreement with Tesoro Refining and Marketing Company (incorporated by reference to Registrant's Current Report on Form 8-K filed on March 15, 2012, and amended on April 24, 2012).
10.38	–	Employment Agreement with Kurt C. Yost (incorporated by reference to Registrant's Current Report on Form 8-K filed on May 24, 2012).**
10.39	–	Loan Agreement, dated as of June 29, 2012 between Miller Energy Resources, Inc. and Apollo Investment Corporation (incorporated by reference to Registrant's Current Report on Form 8-K filed on July 5, 2012).
10.40	–	Guarantee and Collateral Agreement, dated as of June 29, 2012, among Miller Energy Resources, Inc., each of its consolidated subsidiaries (excluding Miller Energy Income 2009-A, LP), as guarantors and grantors, and Apollo Investment Corporation, as secured party (incorporated by reference to Registrant's Current Report on Form 8-K filed on July 5, 2012).
10.41	–	First Amendment to Promissory Notes and Related Documents, dated as of June 29, 2012 between Miller Energy Resources, Inc. and Miller Energy Income 2009-A, LP (incorporated by reference to Registrant's Current Report on Form 8-K filed on July 5, 2012).
10.42	–	Employment Agreement with Catherine Rector (incorporated by reference to Registrant's Current Report on Form 8-K filed on July 31, 2012).**
10.43	–	Acknowledgment and Amendment Regarding Series B Preferred Stock, dated August 13, 2012 (incorporated by reference to Registrant's Current Report on Form 8-K filed on August 17, 2012).
10.44	–	Special Warrant Exercise Agreement (incorporated by reference to Registrant's Current Report on Form 8-K filed on September 21, 2012).
10.45	–	Bristol Warrant Exercise Agreement (incorporated by reference to Registrant's Current Report on Form 8-K filed on September 21, 2012).
10.46	–	Acknowledgment and Amendment No. 2 (Series C Preferred Stock, Covenant Compliance, PDC Acquisition and APOD Adjustment), dated September 24, 2012 (incorporated by reference to Registrant's Current Report on Form 8-K filed on September 26, 2012).
10.47	–	Acknowledgment and Amendment No. 3, dated November 14, 2012 (incorporated by reference to Registrant's Current Report on Form 8-K filed on November 16, 2012).
10.48	–	Waiver and Amendment No. 4, dated February 7, 2013 (incorporated by reference to Registrant's Current Report on Form 8-K filed on February 7, 2013).

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10.49	–	Employment Agreement with Catherine Rector (incorporated by reference to Registrant's Current Report on Form 8-K filed on July 31, 2012).**
10.50	–	Waiver and Amendment No. 5, dated July 11, 2013 (incorporated by reference to Registrant's Current Report on Form 8-K filed on July 12, 2013).
21.1	–	Subsidiaries of the registrant *
23.1	–	Consent of Ralph E. Davis Associates, Inc. *
23.2	–	Consent of KPMG LLP*
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 *
99.1	–	Reserve Report of Ralph E. Davis Associates, Inc. at April 30, 2013 on Cook Inlet assets *
99.2	–	Reserve Report of Ralph E. Davis Associates, Inc. at April 30, 2013 on Appalachian region assets *
101.INS	–	XBRL Instance Document *
101.SCH	–	XBRL Taxonomy Extension Schema Document *
101.CAL	–	XBRL Taxonomy Extension Calculation Linkbase Document *
101.DEF	–	XBRL Taxonomy Extension Definition Document *
101.LAB	–	XBRL Taxonomy Extension Label Linkbase Document *
101.PRE	–	XBRL Taxonomy Extension Presentation Linkbase Document *

* Filed herewith

** Indicates management contract or compensatory plan or arrangement

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

Date: July 15, 2013



	MILLER ENERGY RESOURCES, INC.

	By:	/s/ SCOTT BORUFF
		Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Title	Date

/s/ DELOY MILLER	Chairman of the Board, Chief Operating Officer	July 15, 2013
Deloy Miller

/s/ SCOTT M. BORUFF	Chief Executive Officer, Director, Principal Executive Officer	July 15, 2013
Scott M. Boruff

/s/ DAVID J. VOYTICKY	President, Chief Financial Officer, Director, Principal Financial Officer	July 15, 2013
David J. Voyticky

/s/ HERMAN GETTELFINGER	Director	July 15, 2013
Herman Gettelfinger

/s/ GERALD HANNAHS	Director	July 15, 2013
Gerald Hannahs

/s/ DAVID M. HALL	Director	July 15, 2013
David M. Hall

/s/ MERRILL A. MCPEAK	Director	July 15, 2013
Merrill A. McPeak

/s/ CHARLES STIVERS	Director	July 15, 2013
Charles Stivers

/s/ DON A. TURKLESON	Director	July 15, 2013
Don A. Turkleson

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Miller Energy Resources, Inc.:

We have audited Miller Energy Resources, Inc.'s and subsidiaries (the Company) internal control over financial reporting as of April 30, 2013, based on criteria established in Internal Control ‑ Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting (Item 9A(b)). Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis. A material weakness related to an insufficient complement of corporate accounting and finance personnel to consistently operate management review controls has been identified and included in management's assessment.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Miller Energy Resources, Inc. and subsidiaries as of April 30, 2013 and 2012, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the years in the three-year period ended April 30, 2013. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2013 consolidated financial statements, and this report does not affect our report dated July 15, 2013, which expressed an unqualified opinion on those consolidated financial statements.

In our opinion, because of the effect of the aforementioned material weakness on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of April 30, 2013, based on the criteria established in Internal Control - Integrated Framework issued by the COSO.

/s/ KPMG LLP

Knoxville, Tennessee

July 15, 2013

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Miller Energy Resources, Inc.:

We have audited the accompanying consolidated balance sheets of Miller Energy Resources, Inc. and subsidiaries (the Company) as of April 30, 2013 and 2012, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the years in the three-year period ended April 30, 2013. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Miller Energy Resources, Inc. and subsidiaries as of April 30, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three-year period ended April 30, 2013, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Miller Energy Resources, Inc.'s internal control over financial reporting as of April 30, 2013, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organization of the Treadway Commission (COSO), and our report dated July 15, 2013 expressed an adverse opinion on the effectiveness of the Company's internal control over financial reporting.

/s/ KPMG LLP

Knoxville, Tennessee

July 15, 2013

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MILLER ENERGY RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(dollars in thousands, except per share data)



	April 30,
	2013		2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,551	$	3,971
Restricted cash	7,531		2,250
Accounts receivable	3,204		3,107
State production credits receivable	12,713		2,958
Inventory	3,382		1,835
Prepaid expenses and other	1,183		482
	30,564		14,603
OIL AND GAS PROPERTIES, NET	486,009		475,802
EQUIPMENT, NET	42,876		33,728
OTHER ASSETS:
Land	542		542
Restricted cash, non-current	10,207		9,875
Deferred financing costs, net of accumulated amortization	4,666		1,426
Other assets	541		413
	$	575,405	$	536,389
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable	$	13,129	$	9,504
Accrued expenses	6,338		6,744
Short-term portion of derivative instruments	842		2,803
Current portion of long-term debt	6,000		24,130
	26,309		43,181
OTHER LIABILITIES:
Deferred income taxes	157,530		167,319
Asset retirement obligation	19,890		18,366
Long-term portion of derivative instruments	—		7,700
Long-term debt, less current portion	51,559		—
	255,288		236,566
COMMITMENTS AND CONTINGENCIES (Notes 3, 5 and 9)
MEZZANINE EQUITY:
Series A cumulative preferred stock, redemption amount of $11,200	—		8,818
Series C cumulative preferred stock, redemption amount of $37,000	31,236		—

STOCKHOLDERS' EQUITY:
Common stock, $0.0001 par, 500,000,000 shares authorized, 43,444,694 and 41,086,751 shares issued and outstanding, respectively	4		4
Additional paid-in capital	88,184		64,813
Retained earnings	200,693		226,188
	288,881		291,005
	$	575,405	$	536,389

See accompanying notes to the consolidated financial statements.

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MILLER ENERGY RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(dollars in thousands, except per share data)



	For the Year Ended April 30,
	2013			2012			2011
REVENUES:
Oil sales	$	29,447		$	31,880		$	20,360
Natural gas sales	468			613			726
Other	4,886			2,909			1,756
	34,801			35,402			22,842
OPERATING EXPENSES:
Oil and gas operating	24,698			14,861			9,703
Cost of other revenue	4,189			926			808
General and administrative	22,799			29,718			14,555
Exploration expense	1,458			1,241			—
Depreciation, depletion and amortization	13,170			13,310			10,961
Accretion of asset retirement obligation	900			1,072			1,407
Other operating income, net	(64		)	(641		)	—
	67,150			60,487			37,434
OPERATING LOSS	(32,349		)	(25,085		)	(14,592		)
OTHER INCOME (EXPENSE):
Interest expense, net	(4,276		)	(1,837		)	(934		)
Gain (loss) on derivatives, net	6,751			(2,832		)	(1,008		)
Gain on acquisitions	—			—			6,910
Other income (expense), net	(329		)	58			(537		)
	2,146			(4,611		)	4,431
LOSS BEFORE INCOME TAXES	(30,203		)	(29,696		)	(10,161		)
Income tax benefit	(9,783		)	(11,006		)	(6,281		)
NET LOSS	(20,420		)	(18,690		)	(3,880		)
Accretion of preferred stock	(2,866		)	(847		)	—
Series C accumulated dividends	(2,209		)	—			—
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(25,495	)	$	(19,537	)	$	(3,880	)

LOSS PER COMMON SHARE:
Basic	$	(0.60	)	$	(0.48	)	$	(0.11	)
Diluted	$	(0.60	)	$	(0.48	)	$	(0.11	)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic	42,682,685			40,811,308			36,112,286
Diluted	42,682,685			40,811,308			36,112,286

See accompanying notes to the consolidated financial statements.

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MILLER ENERGY RESOURCES, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(dollars in thousands, except per share data)



	Common Stock			Additional Paid-in Capital		Retained Earnings			Total
	Shares	Amount		Additional Paid-in Capital		Retained Earnings			Total
Balance at April 30, 2010	32,224,894	$	3	$	27,597	$	249,605		$	277,205
Net loss	—	—		—		(3,880		)	(3,880		)
Issuance of equity for services	30,000	—		1,881		—			1,881
Issuance of equity for equipment	100,000	—		453		—			453
Issuance of equity for compensation	162,500	—		4,516		—			4,516
Exercise of equity rights	4,262,858	1		12,861		—			12,862
Conversion of notes	3,099,999	—		1,705		—			1,705
Balance at April 30, 2011	39,880,251	4		49,013		245,725			294,742
Net loss	—	—		—		(18,690		)	(18,690		)
Accretion of preferred stock	—	—		—		(847		)	(847		)
Issuance of equity for services	130,000	—		1,501		—			1,501
Issuance of equity for compensation	107,500	—		12,916		—			12,916
Exercise of equity rights	969,000	—		1,383		—			1,383
Balance at April 30, 2012	41,086,751	4		64,813		226,188			291,005
Net loss	—	—		—		(20,420		)	(20,420		)
Series C accumulated dividends	—	—		—		(2,209		)	(2,209		)
Accretion of preferred stock	—	—		—		(2,866		)	(2,866		)
Issuance of equity for services	351,477	—		2,154		—			2,154
Issuance of equity for compensation	527,665	—		11,694		—			11,694
Other equity issuances	192,800	—		1,341		—			1,341
Exercise of equity rights	1,286,001	—		3,832		—			3,832
Preferred stock redemption	—	—		2,510		—			2,510
Modification of warrants	—	—		1,840		—			1,840
Balance at April 30, 2013	43,444,694	$	4	$	88,184	$	200,693		$	288,881

See accompanying notes to the consolidated financial statements.

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MILLER ENERGY RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)



	For the Year Ended April 30,
	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(20,420	)	$	(18,690	)	$	(3,880	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	13,170			13,310			10,961
Amortization of deferred financing fees	828			1,123			491
Gain on acquisitions	—			—			(6,910		)
Loss on sale of equipment	—			—			626
Expense from issuance of equity	10,722			14,072			5,126
Dry hole costs and leasehold impairments	1,264			1,061			—
Payment-in-kind interest on debt	307			—			—
Deferred income taxes	(9,789		)	(11,006		)	(6,281		)
Unrealized (gain) loss on derivative instruments, net	(5,235		)	3,436			1,008
State production credits	(3,268		)	—			(873		)
Accretion of asset retirement obligation	900			1,072			1,407
Changes in operating assets and liabilities:
Receivables	(2		)	(808		)	(1,796		)
Inventory	(1,676		)	(235		)	(768		)
Prepaid expenses and other assets	(829		)	(654		)	1,448
Accounts payable, accrued expenses, and other	2,537			4,220			7,175
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	(11,491		)	6,901			7,734

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for oil and gas properties	(26,361		)	(7,558		)	(10,490		)
Purchase of equipment and improvements	(11,533		)	(26,409		)	(825		)
Proceeds from sale of equipment	2,000			—			—
NET CASH USED IN INVESTING ACTIVITIES	(35,894		)	(33,967		)	(11,315		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Cash dividends	(1,231		)	—			—
Payments on debt	(24,130		)	(8,764		)	(3,500		)
Debt acquisition costs	(3,853		)	(2,140		)	—
Proceeds from borrowings	55,000			30,894			5,500
Proceeds from sale of shares	—			10,000			—
Redemption of preferred stock	(11,240		)	—			—
Issuance of preferred stock	35,867			—			—
Equity issuance costs	(2,667		)	—			—
Exercise of equity rights	3,832			1,383			1,266
Restricted cash	(5,613		)	(1,895		)	(1,121		)
NET CASH PROVIDED BY FINANCING ACTIVITIES	45,965			29,478			2,145
NET CHANGE IN CASH AND CASH EQUIVALENTS	(1,420		)	2,412			(1,436		)

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	3,971			1,559			2,995
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	2,551		$	3,971		$	1,559
SUPPLEMENTARY CASH FLOW DATA:
Cash paid for interest	$	11,143		$	1,986		$	824

See accompanying notes to the consolidated financial statements.

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Miller Energy Resources, Inc. and our wholly owned subsidiaries (collectively, the "Company"). The 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. All intercompany balances and transactions are eliminated in the consolidation.

Reclassifications

Certain reclassifications have been made to the 2011 and 2012 consolidated financial statements to conform to the 2013 presentation.

Risks and Uncertainties

Factors that could affect our future operating results and cause actual results to vary materially from management's expectation include, but are not limited to: the capital intensive nature of our business and our ability to maintain and secure adequate capital to fully develop our operations and assets; our ability to perform under the terms of the Alaska Oversight Agreement with the Alaska DNR, including meeting the funding requirements of that agreement; the imprecise nature of our reserve estimates; our ability to recover proved undeveloped reserves and convert probable and possible reserves to proved reserves; fluctuating oil and natural gas prices; changes in environmental or regulatory requirements; our ability to control expenses; our ability to become compliant with covenants related to our credit facility; and the impact of changes in accounting principles. Negative developments in these or other risk factors could have a significant adverse effect on our financial position, results of operations and cash flows.

Use of Estimates

The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate our estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of its financial statements and changes in these estimates are recorded when known. Significant estimates made in preparing these financial statements include the fair value determination of acquired assets and liabilities, the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (see Supplemental Oil and Gas Disclosures (Unaudited)), assessing asset retirement obligations (see Note 4 - Asset Retirement Obligations) and the estimate of income taxes (see Note 6 - Income Taxes).

Cash Equivalents

We consider all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value due to their short-term nature.

Restricted Cash

As of April 30, 2013 and 2012, current restricted cash includes $7,144 and $2,045, respectively, of cash temporarily held in an account that is controlled by our lender. Current restricted cash balances include amounts held in escrow to secure Company related credit cards and the payment of dividends on our Series B Preferred Stock and Series C Preferred Stock outstanding through September 30, 2013. Non-current restricted cash balances include amounts held in escrow to provide for the future plugging and abandonment of wells, including the possible dismantling of our off-shore platform, and general liability bonds.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are stated at the historical carrying amount net of write-offs and allowance for uncollectible accounts. We routinely assess the recoverability of all material customer and other receivables to determine their collectability and record a reserve when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

reserve may be reasonably estimated. When collection is no longer pursued, we charge uncollectible accounts receivable against the reserve. As of April 30, 2013 and 2012, all of our accounts receivable were considered fully collectible and, therefore, no reserve was established.

Inventory

Inventory consists of crude oil produced but not sold, stated at the lower of cost or market.

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 depreciated using the unit-of-production method based on estimated total proved 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 estimated total proved reserves.

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. In fiscal 2013, our consolidated statement of operations includes $1,189 related to impairment of certain unproved properties, $110 in seismic and delay rental incurred in the Cook Inlet region, and $159 related to dry hole costs incurred in the Appalachian region.

Equipment

Equipment includes drilling rigs, automobiles, trucks, an airplane, office furniture, computer equipment and buildings. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets or group of assets, which range from five to forty years.

Equipment is reviewed for impairment when facts and circumstances indicate that book values may not be recoverable. In performing this review, an undiscounted cash flow test is performed on the impairment unit. If the sum of the undiscounted estimated future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property's net book value over its estimated fair value.

Capitalized Interest

Interest is capitalized as part of the historical cost of developing and constructing assets for significant projects. Significant investments in unproved oil and gas properties, significant exploration and development projects for which depreciation, depletion and amortization ("DD&A") is not currently recognized, and exploration or development activities that are in progress qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined based upon our weighted-average borrowing cost on debt for the average amount of qualifying costs incurred. The Company incurred $9,289, $5,500 and $436 of interest expense and amortization of deferred financing costs in fiscal years 2013, 2012 and 2011, respectively, of which $5,880, $3,700 and $0, respectively, were capitalized in equipment and oil and gas properties on the balance sheet. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment, along with other capitalized costs related to that asset.

Asset Retirement Obligations

Asset retirement obligations ("ARO") liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with our oil and gas properties. We utilize current retirement costs to estimate the expected cash outflows for retirement obligations. We estimate 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.

The initial estimated ARO is recorded as a liability, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. If the fair value of the recorded ARO changes, a revision is

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of an asset’s retirement. Asset retirement costs are depreciated using a systematic and rational method similar to that used for the associated property and equipment. Accretion expense on the liability is recognized over the estimated productive life of the related assets.

Loss Contingencies

Accruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change.

Revenue Recognition

Oil and natural gas sales revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.

Derivative Instruments and Hedging Activities

We periodically enter into commodity derivative contracts to hedge future production and minimize the Company's exposure to commodity price risk. These derivative contracts typically take the form of a swap contract. The oil reference prices, upon which the commodity derivative contracts are based, reflect market indices that have a high degree of historical correlation with actual prices received by us for our oil production.

We account for our derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which requires that all derivative instruments, other than those that meet the normal purchases and sales exception, be recorded on the balance sheet at fair value as either a current or non-current asset or liability, depending on the derivative position and the expected timing of settlement. Where we have a contractual right and intend to net settle, derivative assets and liabilities are reported on a net basis. Changes in fair value are recognized currently in earnings.

Stock-Based Compensation

We grant various types of stock-based awards including stock options, restricted stock units, and performance-based awards. Stock-based compensation awards granted are valued on the date of grant and are expensed, net of estimated forfeitures, over the requisite service period.

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date or the date of change in estimate for state income taxes.

We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.

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 consolidated balance sheets.

Guarantees

On July 12, 2012, we signed a direct guarantee for 55% of the loan obligations outstanding of $5,074 with FSG Bank for the Pellissippi Pointe equity investment. The Company's guarantee is included within the scope of ASC 460, "Guarantees" and a liability was recorded at the estimated fair value of $250; such amount is included in accrued expenses on our consolidated balance sheet as of April 30, 2013 and is being amortized over the five year life of the guarantee. The fair value was calculated using the

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

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 April 30, 2013, our maximum potential undiscounted payment under this arrangement is $2,791 plus additional lender's costs.

Income (Loss) Per Share

We determine basic income (loss) per share and diluted income (loss) per share in accordance with the provisions of ASC 260, “Earnings Per Share.” Basic income (loss) per share excludes dilution and is computed by dividing earnings available to common stockholders by the weighted-average number of common shares outstanding for the period. The calculation of diluted earnings (loss) per share is similar to that of basic earnings per share, except that the denominator is increased, if net income is positive, to include the number of additional common shares that would have been outstanding if all potentially dilutive common shares, such as those issuable upon the exercise of stock options and warrants, had been exercised. We compute the numerator for basic income (loss) by subtracting accretion of preferred stock and cumulative preferred stock dividends from net income (loss) to arrive at net income (loss) attributable to common stockholders. Preferred stock dividends include dividends declared on preferred stock (regardless of whether the dividends have been paid) and dividends accumulated for the period on cumulative preferred stock (regardless of whether the dividends have been declared).

Business Combinations

We account for business combinations under the acquisition method of accounting. The acquisition method requires that the acquired assets and liabilities, including contingencies, be recorded at fair value determined on the acquisition date and that changes thereafter be reflected in income (loss). The estimation of the fair values of the assets acquired and liabilities assumed involves a number of estimates and assumptions that could differ materially from the actual amounts recorded. The results of the acquired businesses are included in our results from operations beginning from the day of acquisition.

Statement of Comprehensive Income

No statement of comprehensive income is presented since net income (loss) and comprehensive income (loss) would be the same for all periods reported.

New Accounting Pronouncements Issued But Not Yet Adopted

In December 2011, the FASB issued Accounting Standards Update ("ASU") 2011-11, "Disclosures about Offsetting Assets and Liabilities," which increases disclosures about offsetting assets and liabilities, with a scope clarification issued in January 2013. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards ("IFRS") related to the offsetting of financial instruments. The existing GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance in ASU 2011-11 is effective for annual and interim reporting periods beginning on or after January 1, 2013. The disclosures should be applied retrospectively for all prior periods presented. We have evaluated the new pronouncement and have determined that there is no material impact to our 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

2. DERIVATIVE INSTRUMENTS

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

From time to time we issue warrants in connection with certain of our equity transactions. Certain warrants contain exercise reset provisions which are considered freestanding derivatives and are accounted for as liabilities measured at fair value in accordance with ASC 815. There were no warrants with exercise reset provisions outstanding as of April 30, 2013.

Derivative Instruments

Commodity Derivatives

As of April 30, 2013, we had the following open crude oil derivative positions:



	Fixed - Price Swaps
Production Period:	Bbls	Weighted Average Fixed Price
2014	147,000	$	95.30

Warrant Derivatives

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

The Series A Preferred Stock was redeemed on June 29, 2012 in connection with the initiation of the Apollo Credit Facility and the repayment of the Guggenheim Credit Facility. The mark-to-market adjustment from May 1, 2012 to June 29, 2012 of $443 was recorded to gain on derivatives, net, and the remaining liability of $2,510 was reclassified to additional paid-in capital.

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

On September 21, 2012, the Company entered into a Special Warrant Exercise Agreement with warrant holders, pursuant to which, warrant holders agreed to exercise 586,001 warrants immediately for $4.00 per share and waived their right to a cashless exercise. In addition, 42,857 warrants were cancelled in exchange for a settlement payment of $75. These modifications resulted in a loss of $210, which is included in other income (expense), net on our consolidated statement of operations for the year ended April 30, 2013.

The term for the remaining 138,197 warrants outstanding was extended for one year in exchange for the removal of the exercise price reset provision. The mark-to-market adjustment from May 1, 2012 to September 21, 2012 of $260 was recorded to gain (loss) on derivatives, net, and the remaining liability of $1,840 was reclassified to additional paid-in capital.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

Fair Value Measurements

As of April 30, 2013 and 2012, the fair market value of our derivative liabilities is as follows:



	As of April 30,
	2013		2012
Current liabilities:
Commodity derivatives	$	842	$	2,803
Current portion of derivative instruments	842		2,803
Long-term liabilities:
Commodity derivatives	—		2,551
Warrant derivatives	—		5,149
Long-term portion of derivative instruments	—		7,700
Total derivative liability	$	842	$	10,503

Commodity Derivatives

Our commodity derivatives consist of variable-to-fixed price commodity swaps. The fair values of our commodity derivatives are not actively quoted in the open market, thus we use an income approach to estimate fair value. The use of commodity derivative instruments also exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Thus, to minimize this exposure, we utilize an investment-grade rated counterparty. In measuring fair value, we also take into account the impact of counterparty risk on our derivative instruments and use observable market data for credit default swaps to assess the impact of non-performance credit risk when evaluating our net assets from the counterparty. We use the cumulative Standard & Poor's ("S&P") default rating for small, independent exploration and production companies to assess the impact of non-performance credit risk when evaluating our net obligations to the counterparty. As of April 30, 2013 and 2012, the effect of non-performance risk on our commodity derivatives was negligible.

Warrant Derivatives

Prior to the September 21, 2012 modification described above, certain of our warrants contained an exercise price reset provision and were considered freestanding derivative instruments which required liability classification with fair value measured on a recurring basis in accordance with the provisions of ASC 820, "Fair Value Measurements."

Series A Cumulative Preferred Stock. We utilized a binomial, or lattice model, to value the warrants. In selecting a binomial tree model, we evaluated the model's capability to incorporate certain provisions present in these financial instruments and believe it is consistent with the fair value measurement objectives and requirements under ASC 820.

A binomial tree valuation model uses a "discrete-time" (lattice based) model of the varying price over the term of the underlying financial instrument. Each node in the lattice represents a possible price of the underlying (stock price) at a given point in time. Valuation is performed iteratively, starting at each of the final nodes (those that may be reached at the time of expiration), and then working backwards through the tree towards the first node (valuation date). When valuing the warrant instruments, a lattice representing all possible paths the stock price could take during the life of the conversion and a lattice representing variations in the strike price if certain conditions are met are developed and used in concert.

The following weighted average assumptions were used to determine fair value at April 30, 2012: risk-free rate of 0.4%, expected volatility of 83% and an expected term of 2.80 years. As of April 30, 2012, the warrants had an aggregate fair value of $2,953. On June 29, 2012, the exercise price of the warrants became fixed and had a fair value of $2,510, which was reclassified to additional paid-in capital. The following weighted average assumptions were used to determine fair value at June 29, 2012: risk-free rate of 0.4%, expected volatility of 83% and an expected term of 2.84 years.

Warrants Issued in Connection with Other Equity Transactions. At April 30, 2012, we had 767,055 warrants outstanding that were issued in connection with our March 26, 2010 equity transaction. These warrants contained an exercise price reset provision, whereby the exercise price would be adjusted downward in the event our common stock is subsequently issued to others at a price below the initial warrant exercise price. Due to the reset provision, the warrants were considered freestanding derivative instruments and were classified as liabilities with fair value measured on a recurring basis in accordance with GAAP. On September 21, 2012, the exercise price reset provision was eliminated for the remaining warrants that were not exercised or canceled pursuant to the Special Warrant Exercise Agreement. We utilized the Black-Scholes model to determine fair value at April 30, 2012 with

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

the following weighted average assumptions: risk-free rate of 0.4%, an expected term of 2.90 years, expected volatility of 83% and a dividend rate of 0%. We utilized the Black-Scholes model to determine fair value at September 21, 2012 with the following weighted average assumptions: risk-free rate of 0.3%, an expected term of 2.51 years, expected volatility of 74% and a dividend rate of 0%.

Fair Value Hierarchy

ASC 820 provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

As of April 30, 2013 and 2012, all of our derivatives were classified as Level 2 instruments due to the lack of quoted prices readily available in an active market. The following table presents the hierarchy classification of our derivative instruments:



	Fair Value Measurements
At April 30, 2013	Level 1		Level 2		Level 3
Commodity derivative liability	$	—	$	842	$	—
Total	$	—	$	842	$	—
At April 30, 2012
Warrant derivative liability	$	—	$	5,149	$	—
Commodity derivative liability	—		5,354		—
Total	$	—	$	10,503	$	—

Derivative Activities Reflected on Consolidated Statements of Operations

Changes in the fair value of our derivative liabilities are recorded in gain (loss) on derivatives, net on our consolidated statements of operations.



	For the Year Ended April 30,
	2013		2012			2011
Realized gain recognized in earnings	$	1,516	$	604		$	—
Unrealized gain (loss) recognized in earnings	5,235		(3,436		)	(1,008		)
Gain (loss) on derivatives, net	$	6,751	$	(2,832	)	$	(1,008	)

On June 6, 2012, the Company terminated the commodity derivative contracts in place on April 30, 2012, which were settled against the NYMEX WTI Cushing Index. In consideration of such termination, the counterparty paid the Company settlement value of $4,283 which was recorded as a realized gain. This realized gain was partially offset by $2,767 in realized losses during the fiscal year ended April 30, 2013 to arrive at the realized net gain of $1,516.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

3. DEBT

As of April 30, 2013 and 2012, we had the following debt obligations reflected at their respective carrying values on our consolidated balance sheets:



	As of April 30,
	2013		2012
Guggenheim senior secured Credit Facility	$	—	$	24,130
Apollo senior secured Credit Facility	55,307		—
Series B Preferred Stock	2,252		—
Total debt obligations	$	57,559	$	24,130

Apollo Senior Secured Credit Facility

On June 29, 2012 (the "Closing Date"), the Company entered into a Loan Agreement (the "Loan Agreement") with Apollo Investment Corporation ("Apollo"), as administrative agent and sole initial lender.

The Loan Agreement provides for a $100,000 credit facility (the "Apollo Credit Facility") with an initial borrowing base of $55,000. Of that initial $55,000, $40,000 was made available to, and was drawn by, the Company on the Closing Date. On February 7, 2013 and April 25, 2013, we borrowed an additional $5,000 and $10,000, respectively, under the Apollo Credit Facility. The Apollo Credit Facility matures on June 29, 2017 and is secured by substantially all of the assets of the Company and its' consolidated subsidiaries (other than MEI), which subsidiaries also guarantee the loans. Amounts outstanding under the Apollo Credit Facility bear interest at a rate of 18% per annum, with interest payable on the last day of each of the Company's fiscal quarters. The Company will be required to pay the outstanding balance of the loan in full on the maturity date; however, beginning with the fiscal quarter ending on July 31, 2013, if requested by Apollo (at the direction of lenders holding a majority of the commitments under the Loan Agreement), the Company would be required to repay up to $1,500 in principal quarterly. Such payments of principal would be made, together with any interest due on such date, on the last day of the Company's fiscal quarter.

In addition, the outstanding debt includes paid-in-kind interest of $307 added to the principal amount as a part of the “PIK Election” as defined in the Loan Agreement. The Loan Agreement contains interest coverage, asset coverage, minimum and gross production covenants, as well as other affirmative and negative covenants. In connection with the Loan Agreement, the Company has granted Apollo a right of first refusal to provide debt financing for the acquisition, development, exploration or operation of any oil and gas related properties including wells during the term of the Apollo Credit Facility and one year thereafter. As previously reported by the Company, the financial and production covenants in the Apollo Credit Facility were amended in the September Amendment, to delay the date on which compliance with those covenants would be measured from October 31, 2012 to January 31, 2013, and to adjust the covenant levels to be met on that date. The financial and production covenants were further amended on February 7, 2013 to delay the date on which compliance with those covenants would be measured from January 31, 2013 to April 30, 2013, and to adjust the covenant levels to be met on the testing dates, as well as to include our Tennessee production in the minimum production covenant. As of April 30, 2013, we were not in compliance with such covenants. However, we received a waiver of such violations from Apollo on July 11, 2013. Under the terms of the waiver, we will be required to maintain compliance with the financial and production covenants on a quarterly basis commencing October 31, 2013. Based on our production levels existing at April 30, 2013, we would likely not achieve compliance with each of the covenants as of October 31, 2013. However, we currently believe we will sufficiently increase production levels to achieve compliance with the financial and production covenants.

On the Closing Date, we paid Apollo a non-refundable structuring fee of $2,750, payable to the account of the lenders, and we have agreed to pay an additional 5% fee to Apollo for the benefit of the lenders on the amount of every additional borrowing over and above the $55,000 amount of the borrowing base at the date of closing. In addition, we paid Apollo a supplemental fee of $500 on the Closing Date, and have agreed to pay another $500 fee on each anniversary of the Closing Date so long as the Loan Agreement remains in effect.

Additional compensation was due to Bristol Capital, LLC, a consultant to us, in connection with the closing of the Loan Agreement. This fee was paid by issuing 312,500 shares of the Company's restricted common stock.

The Company has used a portion of the initial $40,000 loan made available under the Apollo Credit Facility to repay in full the amounts outstanding under the Guggenheim Senior Secured Credit Facility ("Guggenheim Credit Facility") of approximately $26,200. The remaining $13,800 was used to (i) redeem the Company's outstanding Series A Preferred Stock; (ii)

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

pay certain outstanding payables of the Company; and (iii) pay transaction costs associated with the closing of the Apollo Credit Facility, such as attorneys' fees. The February and April Loans, in the net cash amount of $14,800, were used to fund our drilling projects and pay outstanding operational and general and administrative expenses otherwise permitted under the Apollo Credit Facility.

The fair value of the April 30, 2013 outstanding balance of the Apollo Credit Facility was $57,117 as calculated using the discounted cash flows method.

Guggenheim Senior Secured Credit Facility

On June 29, 2012, in conjunction with the initiation of the Apollo Credit Facility, we paid in full all outstanding principal and interest balances under the Guggenheim Credit Facility. The final payment of $26,200 was comprised of $21,900 principal, $4,100 in interest expense due to the make-whole premium and $200 accrued interest. The Loan Agreement under the Guggenheim Credit Facility and all related documents and security interests arising under them were terminated immediately upon the repayment.

Series B Preferred Stock

On September 24, 2012, we sold 25,750 shares of our Series B Cumulative Redeemable Preferred Stock (the "Series B Preferred Stock") to 10 accredited investors and issued those investors warrants to purchase 128,750 shares of common stock in a private offering exempt from registration under the Securities Act of 1933, as amended. We received gross proceeds of $2,575. We paid issuance costs of $167, which have been capitalized and are being amortized over the term of the instrument. The outstanding Series B Preferred Stock is classified as long-term debt, in accordance with ASC 480, "Distinguishing Liabilities from Equity." As of April 30, 2013, the fair value of Series B Preferred Stock is $2,462.

The designations, rights and preferences of the Series B Preferred Stock, include:


•	a stated value of one hundred dollars per share and a liquidation preference equal to the stated value;


•	the holders are not entitled to any voting rights and the shares of Series B Preferred Stock are not convertible into any other security;


•	the holders are entitled to receive annual cumulative dividends at the rate of 12% per annum, payable in arrears semi-annually, beginning on March 1, 2013;

•

dividends will be paid in cash on each relevant dividend date provided that (i) we are in compliance with certain financial covenants (designated the "Capital Covenants") under the Apollo Credit Facility, with compliance to be determined as of the most recent reporting date and, on a pro forma basis, on the dividend date, and (ii) no "Default" or "Event of Default" (as defined in the Apollo Credit Facility) has occurred or is continuing on the dividend date;


•	the shares may not be redeemed until 30 days after "Security Termination" (as defined in the Apollo Credit Facility), but otherwise may be redeemed at any time by the Company, with a required redemption on the fifth anniversary of issuance or, if later, on the 30th day after Security Termination.

Debt Issue Costs

As of April 30, 2013, our unamortized debt issue costs were $4,666, which relate to the Apollo Credit Facility and the Series B Preferred Stock. These costs are being amortized over the term of the respective debt instruments.

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

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

4. ASSET RETIREMENT OBLIGATIONS

The following table presents changes to the Company's asset retirement obligation liability for the years ended April 30, 2013 and 2012:



	2013		2012
Asset retirement obligation, beginning of year	$	18,366	$	17,294
Additions	64		—
Accretion expense	900		1,072
Revisions	560		—
Asset retirement obligation, end of year	$	19,890	$	18,366

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. There were no significant expenditures for abandonments during the years ended April 30, 2013, 2012 or 2011.

5. COMMITMENTS AND CONTINGENCIES

On November 5, 2009, CIE entered into an AOA with the Alaska DNR which set out certain terms under which the Alaska DNR would approve the transfer of oil and gas leases owned by the State of Alaska from Pacific Energy to CIE. This agreement remains in place following our acquisition of CIE in December 2009. Generally, the agreement requires CIE to provide the Alaska DNR with additional information and oversight authority to ensure that CIE is acting diligently to develop the oil and gas from Redoubt and West McArthur River units ("WMRU"). Under the terms of the AOA, until the Alaska DNR determines that CIE has completed certain development and operational commitments relating to the WMRU and Redoubt Units, CIE must do the following, in addition to the normal requirements under the terms of the leases:


•	file a quarterly summary of expenditures by oil and gas field, tied to objectives in CIE's business plan and plan of development previously presented to the Alaska DNR,


•	meet monthly with the Alaska DNR to provide an update on operations and progress towards meeting these objectives,


•	notify the Alaska DNR 10 days prior to commitment when CIE is preparing to spend funds on a purchase, project or item relating to the WMRU or Redoubt Leases of more than $5,000,


•	annually submit a new plan of development for the Alaska DNR's approval.

On March 11, 2011, the Company entered into a Performance Bond Agreement under its AOA with the state of Alaska. Under the Performance Bond Agreement, the Company is required to post a total bond of $18,000 for the dismantling and abandonment of the properties. As agreed with the state of Alaska, the Performance Bond Agreement fulfills our commitment under the AOA to fund the full dismantlement costs with respect to our onshore and offshore assets. The Performance Bond Agreement also stipulated that $6,628, plus accrued earnings, held by the state in an escrow account will be credited towards the $18,000. Upon execution of the Performance Bond Agreement, the Company recorded a $6,910 gain on acquisition (inclusive of accrued interest) during the year ended April 30, 2011.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

The AOA also prohibits CIE from using proceeds from operations at WMRU or Redoubt for non-core oil and gas activities, or activities unrelated to WMRU or Redoubt, without the prior written approval of the Alaska DNR until the parties mutually agree that the full dismantlement obligation under the assigned leases is funded.

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



July 1, 2013	$	1,000
July 1, 2014	1,500
July 1, 2015	2,000
July 1, 2016	2,500
July 1, 2017	2,000
July 1, 2018	1,500
July 1, 2019	1,500
	$	12,000

6. INCOME TAXES

The components of income tax benefit are as follows:



	For the Year Ended April 30,
	2013			2012			2011
Federal:
Current	$	—		$	—		$	—
Deferred	(10,023		)	(10,168		)	(1,992		)
Total	(10,023		)	(10,168		)	(1,992		)
State:
Current	6			—			—
Deferred	234			(838		)	(4,289		)
Total	240			(838		)	(4,289		)
Total income tax benefit	$	(9,783	)	$	(11,006	)	$	(6,281	)

A reconciliation of the provision for income taxes as reported and the amount computed by multiplying income before taxes by the U.S. federal statutory rate of 35% is as follows:



	For the Year Ended April 30,
	2013		2012		2011
Provision calculated at federal statutory rate	(35.0	)%	(35.0	)%	(35.0	)%
State and local income taxes, net of federal benefit	(8.4	)	(7.8	)	(5.6	)
Change in effective state tax rate	9.3		5.0		(22.1	)
Other	1.7		0.7		0.9
Total income tax benefit	(32.4	)%	(37.1	)%	(61.8	)%

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

Significant components of the Company's net deferred tax assets (liabilities) consist of the following:



	April 30,
	2013			2012			2011
Deferred tax assets:
Unrealized derivative loss	$	397		$	2,198		$	890
Asset retirement obligation	5,041			4,703			7,243
Net operating loss carryforwards	31,136			12,811			7,696
Stock options and warrants	11,384			7,308			2,555
Other	2,126			907			9
Gross deferred tax assets	50,084			27,927			18,393
Deferred tax liabilities:
Oil and gas properties and equipment in excess of tax basis	(205,953		)	(194,950		)	(196,616		)
Other	(1,661		)	(296		)	(103		)
Gross deferred tax liabilities	(207,614		)	(195,246		)	(196,719		)
Net deferred tax liability	$	(157,530	)	$	(167,319	)	$	(178,326	)

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. Partly 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. At April 30, 2013, we had net operating loss carryforwards for federal income tax purposes of approximately $71,000 with expiration through 2023.

In assessing the realizable value of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which these temporary differences become deductible. As management believes, based on assessment of both positive and negative evidence and objective and subjective evidence, that it is more likely than not that all of the deferred tax assets will be realized, we do not maintain a valuation allowance against deferred tax assets at April 30, 2013 or 2012. 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; rather we are relying solely on the reversal of significant existing temporary differences related to the excess of the Company's book carrying value of its oil and gas properties over their collective tax bases to support recovery of our deferred tax assets (primarily net operating loss carryovers). Additionally, we experienced a "section 382 ownership change" in our fiscal year ended April 30, 2010. However, we do not expect that this event will result in loss of availability of any tax attribute (such as our net operating loss carryover).

We conduct business solely in the United States and, as a result, file income tax returns in the U.S. federal jurisdiction and in Alaska and Tennessee. The taxable years ended April 30, 2013, 2012, 2011 and 2010 remain open to examination by the taxing jurisdictions to which we are subject. Additional years may be subject to examination to the extent that our net operating loss carry-forwards are utilized in an open tax year. Generally, for tax years which produce net operating losses, capital losses or tax credit carry-forwards ("tax attributes"), the statute of limitations does not close, to the extent of these tax attributes, until the expiration of the statute of limitations for the tax year in which they are fully utilized. We are not subject to any ongoing U.S. federal, local income tax examinations for any tax years; however, the State of Alaska's Department of Revenue recently opened an examination of income tax returns of the Company and its Cook Inlet subsidiary (CIE) for the tax years 2010-2012. No significant cash tax payments nor adjustments to tax attribute carryforwards are expected to result from this examination at this time. No other state income tax examinations are ongoing.

We have not identified any uncertain tax positions. No cash payments of income taxes were made during the year ended April 30, 2013, and no significant payments are expected during the succeeding 12 months.

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

7. STOCKHOLDERS' EQUITY

Common Stock

At April 30, 2013, we had 43,444,694 shares of common stock outstanding. We issued 2,357,943 shares during the year ended April 30, 2013, of which 351,477 shares were issued for services, 527,665 shares were issued to employees for compensation, 1,286,001 shares were related to the exercise of equity rights, and 192,800 shares for other equity issuances.

At April 30, 2012, we had 41,086,751 shares of common stock outstanding. We issued 1,356,500 shares during the year ended April 30, 2012, of which 130,000 shares were issued for services, 257,500 shares were issued to employees for compensation, and 969,000 shares were related to the exercise of equity rights.

At April 30, 2011, we had 39,880,251 shares of common stock outstanding. We issued 7,655,357 shares during the year ended April 30, 2011, of which 130,000 shares were issued for services and equipment, 162,500 shares were issued to employees for compensation, 4,262,858 shares were related to the exercise of equity rights, and 3,099,999 shares for other equity issuances.

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") pursuant to the Company's shelf registration statement on Form S-3, which became effective on September 28, 2012. The shares were offered to the public at $23.00 per share for gross proceeds of $15,755. We incurred issuance costs of $1,335, yielding net proceeds of $14,420. Subsequent to the initial offering on September 28, 2012 through April 30, 2013, we sold an additional 144,901 shares of Series C Preferred Stock to the public with prices ranging from $22.00 per share to $23.51 per share. We received gross proceeds of $3,225 and incurred issuance costs of $113, yielding net proceeds of $3,112. 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 net proceeds of $13,260 in connection with the offering. 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 $448 during the year ended April 30, 2013. The fair value of the Series C Preferred Stock was $33,292 based on the closing price at April 30, 2013.


•	The holders are entitled to receive a 10.75% per annum cumulative quarterly dividend, on March 1, June 1, September 1, and December 1, payable in cash on each dividend date unless the Company is prohibited by making such payment pursuant to the terms of any agreement of the Company (including any other class or series of equity securities or any agreement related to indebtedness);


•	The dividend may increase to a penalty rate of 12.75% if we fail to (A) pay dividends for four or more quarterly dividend periods, whether or not consecutive, or (B) maintain the listing of our Series C Preferred Stock on a national securities exchange (the events listed in clauses (A) and (B) being "Penalty Events");

•

There is no mandatory redemption or stated maturity with respect to the Series C Preferred Stock, and it is not redeemable prior to November 1, 2017 unless: (A) there is a change in control and redemption occurs pursuant to a special right of redemption related to that change in control or (B) the Closing Bid Price of our common stock has equaled or exceeded the conversion price initially set at $10.00 per share by 150% for at least 20 days trading days in any 30 consecutive trading day period (a "Market Trigger");


•	The redemption price is $25.00 per share plus any accrued and unpaid dividends;


•	Liquidation preference is $25.00 per share plus any accrued and unpaid dividends;


•	The Series C Preferred Stock is senior to all our other securities except our Series B Redeemable Preferred Stock, which is senior to the Series C Preferred Stock;


•	There is a general conversion right with respect to the Series C Preferred Stock with an initial conversion price of $10.00 per share, a special conversion right upon a change in control, and a market trigger conversion at our option in the event of a Market Trigger;


•	The Series C Preferred Stock has been listed on the NYSE and is registered under our universal shelf; and

•

Holders of the Series C Preferred Stock have no voting rights, except: 1) as otherwise required by law; 2) with respect to any proposal to (A) create, authorize or increase the authorized or issued amount of any class or series of our equity securities which rank senior to the Series C Preferred Stock or (B) amend, alter or repeal any provision of our charter, as amended, in a manner which materially and adversely affects any right, preference, privilege or voting power of the holders of the Series C Preferred Stock; and 3) the holders of the Series C Preferred Stock will have the right to elect two directors to our board of directors upon the occurrence of a Penalty Event.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

On April 30, 2013, our Board of Directors declared a dividend of $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 February 2013 through May 2013. The record date, as required in accordance with our charter, was May 15, 2013.

Series A Preferred Stock

On April 6, 2012, we issued 100,000 shares of our Series A cumulative preferred stock (“Series A Preferred Stock”) to 20 accredited and institutional investors in a private offering exempt from registration under the Securities Act of 1933, as amended. We received gross proceeds of $10,000 and paid a finder's fee of $84 to The Dimirak Companies. The Series A Preferred Stock is non-convertible and redeemable by us, at our discretion. Holders of the Series A Preferred Stock are entitled to dividends of 10% per annum, payable in cash or in kind, at our election, with any unpaid dividends accumulated and paid upon liquidation or redemption.

Purchasers of the Series A Preferred Stock were also issued warrants to purchase an aggregate amount of 1,000,000 shares of our common stock, at an above-market exercise price of $5.28 per share. At issuance of the Series A Preferred Stock, the attached warrants were treated as an embedded derivative and the fair value of the warrants was bifurcated and recorded as a derivative liability (see Note 2 - Derivative Instruments). The remaining balance of the proceeds was allocated to the Series A Preferred Stock. The Series A Preferred Stock was accreted to its redemption amount as an adjustment to net income (loss) attributable to common stockholders through June 29, 2012, the date the Series A Preferred Stock was redeemed.

Issuance of Common Stock

On January 8, 2013, we issued 12,500 warrants to MZ-HCI Group as compensation for services. The warrants have an exercise price of $3.56 per share and an expiration date of January 8, 2016. The grant date fair value of $24 was determined using the Black-Scholes model. Key assumptions used in the model included a risk-free rate of 0.1%, expected volatility of 74.9%, and an expected term of 3.5 years.

On July 11, 2012, we issued 150,000 warrants to Bristol Capital, LLC based on the existing consulting agreement as compensation for services rendered. The grant date fair value of $406 was determined using the Black-Scholes model. Key assumptions used in the model included a risk-free rate of 0.6%, expected volatility of 79%, and an expected term of 5 years.

On July 3, 2012, we issued 38,977 shares of common stock to non-employee directors in lieu of cash payments for compensation of services rendered. The fair value of the shares issued was $194 based on the closing price of our common stock on the transaction date.

On June 29, 2012, we issued 312,500 shares of common stock to Bristol Capital, LLC as compensation for services rendered in relation to the Apollo agreement. The fair value of the shares issued was $1,563 based on the closing price of our common stock on the transaction date.

On January 1, 2012, we issued 30,000 shares of common stock to a non-employee as compensation for services. The fair value of the shares issued was $100 based on the closing price of our common stock on the transaction date.

On August 4, 2011, we issued 100,000 shares of common stock to Bristol Capital, LLC based on the existing consulting agreement as compensation for services rendered. The fair value of the shares issued was $300 based on the closing price of our common stock on the transaction date.

On May 20, 2011, we issued 300,000 warrants to Bristol Capital, LLC as compensation for services. The warrants have an exercise price of $5.51 per share and an expiration date of May 20, 2016. The grant date fair value of $1,100 was determined using the Black-Scholes model. Key assumptions used in the model included a risk-free rate of 1.8%, expected volatility of 86%, and an expected term of 5 years.

On April 29, 2011, the Company modified an existing warrant agreement to remove the exercise price reset provision. The warrant agreement is for 300,000 shares with an exercise price of $2.50 per share and an expiration date of March 12, 2015. The estimated fair value on April 29, 2011, immediately prior to the modification, was $1,300. Such amount was reclassified from liabilities to equity on the modification date. Key assumptions utilized in the Black-Scholes calculated fair value as of April 29, 2011, included a risk-free rate of 1.4%, expected volatility of 77%, and an expected term of 3.9 years.

On December 3, 2010, we entered into a settlement agreement with Prospect Capital Corporation (“Prospect”) whereby we issued 2,013,814 shares of our common stock in exchange for Prospect forfeiting warrants to purchase 2,148,050 shares of our common stock.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

On November 17, 2010, we issued 100,000 shares of common stock to acquire a jet from three sellers, one of which is a consultant to the Company and another of which is affiliated with that consultant. The Company valued the transaction at $500 based on the fair value of the shares.

On October 29, 2010, we entered into a settlement agreement with Petro Capital III, LP and Petro Capital Advisors, LLC (collectively, “Petro”) and resolved litigation that had been pending in federal court in Texas. The settlement agreement resulted in the Company issuing a total of 518,510 shares of its common stock to Petro.

On October 1, 2010, we issued 100,000 warrants to an advisor as compensation for services. The warrants have an exercise price of $5.53 per share and an expiration date of October 1, 2020. The warrants had a grant date fair value of $400, which was determined using the Black-Scholes model. Key assumptions used in the model included a risk-free rate of 1.6%, expected volatility of 79%, and an expected term of 10 years.

On October 1, 2010, we issued 30,000 shares of our common stock to an advisor for services. The closing price of our common stock on that date was $5.53, resulting in non-cash expense of $200.

8. STOCK-BASED COMPENSATION

During fiscal years 2010 and 2011, our Compensation Committee and Board of Directors adopted share-based compensation plans authorizing 3,000,000 and 8,250,000 shares of common stock under each plan, respectively. The share-based compensation plans allow us to offer our employees, officers, directors and others an opportunity to acquire a proprietary interest in the Company and enable us to attract, retain, motivate and reward such persons in order to promote the success of the Company. Each plan authorizes the issuance of incentive stock options, nonqualified stock options and restricted stock. All awards issued under the share-based compensation plans must be approved by our Compensation Committee. At April 30, 2013 and 2012, there were 329,328 and 1,250,000 additional shares available under the compensation plans, respectively.

We recorded $8,791, $12,545 and $3,627 of employee compensation expense related to stock options during the years ended April 30, 2013, 2012 and 2011, respectively. The grant date fair value of employee stock options and warrants granted during the years ended April 30, 2013, 2012 and 2011 was $1,847, $13,839 and $7,400, respectively. The weighted average grant date fair value of employee stock options and warrants granted during the 2013, 2012 and 2011 fiscal years was $2.73, $3.40 and $2.25, respectively. We estimated the grant date fair value of employee stock options and warrants using the Black-Scholes pricing model with the following weighted average assumptions:



	2013	2012	2011
Risk-free interest rate	0.8%	1.4%	1.5%
Term (in years)	5.8	4.7	3.9
Volatility	83%	83%	63%
Dividend yield	—%	—%	—%

Risk-free interest rate:

The risk-free rate for the expected term of the option is based on the U.S. Treasury yield curve at the date of grant.

Expected term:

We use the simplified method to estimate the expected term of stock options due to the fact we experienced significant structural changes to our business in connection with the December 2009 acquisition of our Alaska properties. Due to these significant structural changes we do not believe that our historical exercise data provides a reasonable basis for estimating the expected term for the current share options granted. The simplified method assumes that employees will exercise share options evenly between the period when the share options are vested and ending on the date when the share options would expire.

Expected volatility:

In addition to our own historical volatility, we also consider the implied volatility of our options to estimate our future volatility. This is due to the fact that we do not believe that our historical volatility is the best indicator of future volatility. Accordingly, we have weighted both our historical volatility and our implied volatility to estimate our future volatility. Our historical volatility was considered for all grant dates subsequent to March 22, 2010, which is the date we filed our Form 10-Q for the third quarter ended January 31, 2010, which is the first filing that reported the financial impact of the Alaska business combination.

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

Expected dividend:

We have not estimated any dividend yield as we currently do not pay a dividend and do not anticipate paying a dividend over the expected term.

During the years ended April 30, 2013, 2012 and 2011, we also recorded $2,154, $1,501 and $600 of non-employee equity related expense for services, respectively. These expenses are included in general and administrative in our consolidated statements of operations. The grant date fair value of non-employee awards granted during 2013, 2012 and 2011 was $431, $1,119 and $444, respectively. The weighted average grant date fair value of non-employee awards issued for services during the 2013, 2012 and 2011 fiscal years was $2.65, $3.73 and $4.44, respectively.

We estimated the grant date fair value of non-employee stock awards issued for services using the Black-Scholes pricing model with the following weighted average assumptions:



	2013	2012	2011
Risk-free interest rate	0.6%	1.8%	1.6%
Term (in years)	4.9	5.0	10.0
Volatility	79%	86%	79%
Dividend yield	—%	—%	—%

The following table summarizes our stock-based compensation activities for the years ended April 30, 2013, 2012 and 2011:



	2013				2012				2011
	Number of Options and Warrants		Weighted Average Exercise Price		Number of Options and Warrants		Weighted Average Exercise Price		Number of Options and Warrants		Weighted Average Exercise Price
Balance at beginning of year	15,405,955		$	4.60	11,079,955		$	3.98	12,306,305		$	2.44
Granted	966,750		4.34		5,345,000		5.34		3,275,000		5.82
Exercised	(1,286,001	)	2.98		(969,000	)	1.43		(4,360,534	)	0.58
Canceled	(682,857	)	5.33		(50,000	)	5.94		(140,816	)	4.59
Balance at end of year	14,403,847		4.61		15,405,955		4.60		11,079,955		3.98
Options exercisable at April 30	9,821,403		$	4.25	8,268,459		$	3.78	5,146,625		$	2.67

The following table summarizes our stock options and warrants outstanding, including exercisable shares at April 30, 2013:



Options and Warrants Outstanding					Options and Warrants Exercisable
Range of Exercise Price	Number Outstanding	Weighted Average Remaining Contractual Life (in years)	Weighted Average Exercise Price		Number Exercisable	Weighted Average Exercise Price
$0.01 to $1.82	1,818,900	1.5	$	0.75	1,818,900	$	0.75
$2.00 to $4.99	2,483,000	4.6	3.00		1,733,893	2.59
$5.25 to $5.53	4,166,947	3.3	5.32		2,308,613	5.31
$5.89 to $5.94	3,310,000	7.4	5.92		2,593,331	5.93
$6.00 to $6.94	2,625,000	2.7	6.03		1,366,666	6.05
	14,403,847	4.1	$	4.61	9,821,403	$	4.25

The aggregate intrinsic value of stock options and warrants exercised during the years ended April 30, 2013, 2012 and 2011 was $1,201, $3,782 and $20,400, respectively. The aggregate intrinsic value was calculated as the difference between the exercise price of the underlying awards and the quoted price of our common stock for those awards that had an exercise price

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

below the quoted price on the exercise date. During the years ended April 30, 2013, 2012 and 2011, we received cash of $3,832, $1,383 and $1,266 for options exercised, respectively. As of April 30, 2013, we have unrecognized stock-based compensation expense of $7,969 with a weighted average vesting term of 1.76 years, over which the expense will be recognized. The impact on our basic earnings (loss) per common share that resulted from employee stock-based non-cash compensation is $0.21, $0.31 and $0.13 for the years ended April 30, 2013, 2012 and 2011, respectively.

9. LITIGATION

On October 8, 2009, we filed an action styled Miller Petroleum, Inc. v. Maynard, Civil Action No. 9992 in the Chancery Court for Scott County, Tennessee, seeking a declaratory judgment that there has been continuing commercial production of oil and the oil and gas lease owned by us is still in full force and effect. The defendant filed an Answer and Counterclaim, seeking in the Counterclaim a declaration that the oil and gas lease has expired. The parties reached a mutual settlement of this matter, effective as of November 9, 2012. Under the terms of this settlement, the related lease is still in full force and effect. An Order of Dismissal was filed on January 11, 2013, dismissing the case with full prejudice.

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

This action was revived on August 4, 2011, when a breach of contract case was filed against us in the United States District Court for the Eastern District of Tennessee. The case, styled CNX Gas Company, LLC v. Miller Energy Resources, Inc., Chevron Appalachia, LLC as successor in interest to Atlas America, LLC, Cresta Capital Strategies, LLC and Scott Boruff, arises from the same allegations as the previous action in the state court. The federal case seeks money damages from us for breach of contract; however, unlike the previous action, it does not seek specific performance of the assignments at issue. The Plaintiff claims that the other defendants tortiously interfered with, or induced the breach of, the letter of intent between us and the Plaintiff. We have filed our Answer and intend to vigorously defend this suit. We are presently conducting discovery, and trial is scheduled to begin on November 18, 2013. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.

On May 17, 2011, we were served with a lawsuit filed in the United States District Court for the Eastern District of Tennessee at Knoxville by Troy D. Stafford, the former Chief Financial Officer of our wholly owned subsidiary, Cook Inlet Energy, LLC. The suit, styled Troy D. Stafford v. Miller Petroleum, Inc., Civil Action No. 3-11CV-206, claims that we terminated Mr. Stafford's employment without cause in contravention of the terms of the Purchase and Sale Agreement between us and the sellers of CIE ("PSA"), failed or refused to pay his salary, severance, percentage of purchase price, expenses or stock warrant and violated a duty of good faith and fair dealing. The suit seeks damages in excess of $3,000, which includes $2,687 of damages for loss of vested warrants. We believe that all of the asserted claims are baseless, particularly in view of the fact that we issued the warrants in accordance with the terms of the PSA. We believe that we had appropriate cause to dismiss Mr. Stafford's employment after discovering that he had breached certain representations and warranties in the PSA, and had acted in violation of our Code of Conduct. We have filed our Answer, conducted discovery and are presently awaiting further action by the plaintiff. On January 21, 2013, Mr. Stafford's attorney filed a motion to withdraw as counsel, and on April 2, 2013, Mr. Stafford filed a motion to proceed pro se. We do not yet know how this will affect the timing of this matter. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.

On June 15, 2011, a breach of contract lawsuit was filed against us and CIE in the United States District Court for the Eastern District of Pennsylvania styled VAI, Inc. v. Miller Energy Resources, Inc., f/k/a Miller Petroleum, Inc. and Cook Inlet Energy, LLC. The Plaintiff alleges three causes of action: (1) breach of contract, (2) unfair enrichment, and (3) breach of the implied covenant of good faith and fair dealing. The case seeks damages in warrants to purchase our common stock and monetary damages for certain fees and expenses. The Sale Agreement with David Hall, Walter "JR" Wilcox, and Troy Stafford dated December 10, 2009 contains indemnification provisions relevant to this claim. We filed a Motion to Dismiss for lack of personal jurisdiction, but this motion was not granted by the court. We filed an Answer to the complaint in this case on October 10, 2012, and we have conducted discovery. We have filed a motion for summary judgment which is pending. Trial is set for November 4,

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

2013. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.

In August 2011, several purported class action lawsuits were filed against us in the United States District Court for the Eastern District of Tennessee. The lawsuits made similar claims and have been consolidated into one case, styled In re Miller Energy Resources, Inc. Securities Litigation. The suit names us, along with several of our current and former executive officers, Scott Boruff, Paul Boyd, Ford Graham, David Hall, and Deloy Miller, as defendants. The Plaintiffs allege two causes of action against the defendants: (1) violation of Section 10(b) and Rule 10b-5 of the Exchange Act, (2) violation of Section 20(a) of the Exchange Act. The case seeks money damages against us and the other defendants, and payment of the Plaintiffs' attorney's fees. We have filed a Motion to Dismiss the case, which is pending before the court. Given the current stage of the proceedings in this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.

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

On August 25, 2011, and August 31, 2011, two derivative actions were filed against us and our Board of Directors and former Chief Financial Officer in the United States District Court for the Eastern District of Tennessee. These cases were consolidated into Patrick P. Lukas, derivatively on behalf Miller Energy Resources, Inc. v. Merrill A. McPeak, Scott M. Boruff, Deloy Miller, Jonathan S. Gross, Herman Gettelfinger, David Hall, Charles M. Stivers, Don A. Turkleson, and David J. Voyticky, and Miller Energy Resources, Inc., nominal defendant. As noted below, this case has been dismissed by the trial court, but that dismissal is being appealed by the plaintiffs. It contained substantially similar claims as Valdez. The suit alleged the following causes of action: (1) Breach of Fiduciary Duty for disseminating false and misleading information; (2) Breach of Fiduciary Duty for failing to properly oversee and manage the company; (3) Unjust Enrichment; (4) Abuse of Control; (5) Gross Mismanagement, and; (5) Waste of Corporate Assets. The Plaintiffs sought unspecified money damages from the individual defendants, to have us take certain actions with respect to our management, restitution to us, and the Plaintiffs' attorney fees and costs. We filed a Motion to Dismiss, which was granted on September 21, 2012. On October 16, 2012, a notice of appeal of this dismissal was filed by the Plaintiffs with the Sixth Circuit Court of Appeals. The Plaintiffs filed their brief in support of this appeal and we subsequently filed a reply brief in answer to it. The parties are awaiting further action by the appeals court. Given the current stage of the proceedings with respect to this case, we currently cannot assess the probability of losses, or reasonably estimate the range of losses, related to this matter.

On August 31, 2012, we terminated an agreement with Voorhees Equipment and Consulting, Inc. (“Voorhees”) for the construction and sale of the rig currently being used on the Osprey Platform, Rig 35. We terminated the agreement based on our belief that Voorhees was in breach of its obligations thereunder. Although no action has been filed in connection with that termination, Voorhees has indicated its desire to arbitrate claims it believes it has under invoices arising between May 29, 2012 and August 31, 2012. We believe we have grounds to dispute liability with respect to some or all of these outstanding invoices. In addition, we expect to assert counterclaims against Voorhees for damages exceeding the amounts Voorhees claims are owed to it, for breach of the relevant contract by Voorhees. The parties have elected to engage a private arbitrator to settle this dispute and are currently conducting discovery. We expect that arbitration to begin on or before September 17, 2013. Given the current stage of the proceedings with respect to this matter, we believe that any loss would be limited to the payment of the outstanding invoices of approximately $531, plus the cost of defense. Based on the information currently available, we have accrued our best estimate of the potential loss on our consolidated balance sheet.

On April 4, 2013, we filed suit against a former contractor of CIE and its parent company (collectively “Cudd”) in the United States District Court for the District of Alaska at Anchorage. This case is styled Cook Inlet Energy, LLC v. Cudd Pressure Control Inc. and RPC, Inc. In our suit we are seeking declaratory relief and damages for breach of contract, breach of implied warrant of merchantability, breach of implied covenant of fitness for a particular purpose and breach of the implied covenant of good faith and fair dealing arising out of a dispute regarding certain equipment and services provided by Cudd on the Osprey

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

Platform that did not meet our needs or expectations as promised. We have not yet determined the full amount of damages claimed. On May 29, 2013, Cudd filed its Answer denying our claims and including a counterclaim for equipment and services, totaling approximately $1,889, plus the costs of defense. We have filed our counteranswer and denied that these amounts are owed, in whole or in part. We are presently beginning the discovery process. Given the current stage of the proceedings with respect to this case, we believe that any loss would be limited to $1,889 plus the cost of defense, related to this matter. Based on the information currently available, we have accrued our best estimate of the potential loss on our consolidated balance sheet.

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

10. FAIR VALUE OF FINANCIAL INSTRUMENTS

Fair Value Measurements

Cash and equivalents, trade receivables, account payables and other short-term liabilities

The carrying amounts reported on our consolidated balance sheets approximate fair value because of the short-term nature or maturity of these instruments.

Derivative contracts

We measure the fair value of our derivatives using multiple approaches depending on the nature of the underlying instrument (see Note 2 - Derivative Instruments).

11. OIL AND GAS PROPERTIES AND EQUIPMENT

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



	April 30,
	2013			2012
Property costs
Proved property	$	326,936		$	321,066
Unproved property	196,500			182,704
Total property costs	523,436			503,770
Less: Accumulated depletion	(37,427		)	(27,968		)
Oil and gas properties, net	$	486,009		$	475,802

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

Equipment is summarized as follows:



	April 30,
	2013			2012
Machinery and equipment	$	7,413		$	5,595
Vehicles	1,851			1,689
Aircraft	476			460
Buildings	2,725			2,683
Office equipment	759			533
Leasehold improvements	482			423
Drilling rigs	35,422			3,714
Construction in progress	—			21,589
	49,128			36,686
Less: Accumulated depreciation	(6,252		)	(2,958		)
Equipment, net	$	42,876		$	33,728

Depreciation, depletion and amortization consisted of the following:



	For the Year Ended April 30,
	2013		2012
Depletion of oil and gas related assets	$	9,803	$	12,537
Depreciation and amortization of equipment	3,367		773
Total	$	13,170	$	13,310

12. MAJOR CUSTOMERS AND CONCENTRATIONS OF CREDIT RISK

During the years ended April 30, 2013, 2012 and 2011, Tesoro Corporation accounted for 80%, 100%, and 99% of our consolidated total revenues, respectively. Tesoro Corporation also accounted for 55% and 83% of our accounts receivable as of April 30, 2013, and 2012, respectively.

Credit is extended to customers based on an evaluation of their credit worthiness and collateral is generally not required. We experienced no credit losses of significance during the years ended April 30, 2013, 2012 and 2011.

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 April 30, 2013, we held $10,457 in excess of the $250 limit insured by the Federal Deposit Insurance Corporation.

13. ALASKA PRODUCTION TAX CREDITS

During the years ended April 30, 2013 and 2012, the Company qualified 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,

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

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.

During the years ended April 30, 2013, 2012 and 2011, the Company recorded net carried-forward annual loss credits of $3,268, $0 and $1,800, respectively, which were recorded in the consolidated statements of operations as a reduction to general and administrative expense. As of April 30, 2013 and 2012, the Company has reduced the basis of capitalized assets by $14,547 and $7,837 for expenditure and exploration credits. The reductions are recorded on our consolidated balance sheets in "oil and gas properties." As of April 30, 2013 and 2012, the Company had outstanding net receivables from the State of Alaska in the amount of $12,713 and $2,958, respectively.

14. RELATED PARTY TRANSACTIONS

We use a number of contract labor companies to provide on demand labor at our Alaska operations. H&H Industrial, Inc. is an entity contracted by CIE, a wholly-owned subsidiary of the Company, to provide services related to the exploration and production of oil and natural gas. The company is owned by the sister and father of David Hall, Chief Executive Officer ("CEO") of CIE and member of our Board of Directors. Rediske Air, Inc. is an entity contracted by CIE to provide flight services to our production facilities in the Cook Inlet region. The Company is owned by the brother-in-law of David Hall. In addition, we utilize the audit committee of our Board of Directors determined that the amounts paid by us for the services performed were fair to and in the best interests of the Company. For fiscal 2013, 2012 and 2011, we paid H&H Industrial Inc. a total of $1,024, $632 and $193, respectively and we paid Rediske Air, Inc. a total of $680, $463 and $231, respectively.

From time to time the Company provides service work on oil and gas wells owned by Mr. Gettelfinger (and family), a member of the Board of Directors. As of April 30, 2013 and 2012, Mr. Gettelfinger owed us $11 and $17, respectively. The audit committee of our Board of Directors determined that the amounts paid to us for the services performed were fair and in the best interests of the Company.

The Company is required to remit payroll taxes related to certain stock-based compensation transactions. As of April 30, 2013, we have recorded a related payable of $620 as well as a corresponding receivable from the respective employees of $593. This receivable was collected subsequent to April 30, 2013.

In 2009, we entered into a marketing agreement with The Dimirak Companies, an affiliate of Dimirak Financial Corp. and Dimirak Securities Corporation, a broker-dealer and member of Financial Industry Regulatory Authority ("FINRA"). Mr. Boruff, our CEO, was then a director and 49% owner of Dimirak Securities Corporation. Under the terms of this agreement, we engaged The Dimirak Companies to serve as our exclusive marketing agent in a $20,000 income fund and a $25,500 drilling offering, which included the Miller Energy Income ("MEI") offering. The terms of the agreement expire upon the termination of the offerings. We agreed to pay The Dimirak Companies a monthly consulting fee of $5, a marketing fee of 2% of the gross proceeds received in the offerings or within 24 months from the expiration of the term of the agreement, a wholesaling fee of 2% of the proceeds and a reimbursement of certain pre-approved expenses. The agreement contained customary indemnification, non-circumvention and confidentiality clauses. During fiscal 2013, 2012 and 2011, we paid The Dimirak Companies and their affiliates approximately $49, $169 and $70, respectively. Effective July 24, 2012, Mr. Boruff sold his interest in Dimirak Securities Corporation and we terminated our agreements with it. The company is owned by the brother-in-law of David Hall.

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, (i) the later of 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 noncontrolling interest on our consolidated balance sheets or our consolidated statements of operations due to the fact that these amounts are immaterial.

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

15. SUBSEQUENT EVENTS

Series C Preferred Stock

Pursuant to our ATM Agreement, dated October 12, 2012 with MLV, between May 1, 2013 and July 5, 2013, we offered and sold an additional 43,180 shares of our Series C Preferred Stock, at prices ranging from $22.01 and $22.35 per share. The Company received $953 in gross proceeds as a result of these sales, from which MLV was paid a commission of $33. These securities are registered for sale to the public pursuant to a prospectus supplement, dated September 19, 2012, and 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.

Pursuant to an Underwriting Agreement, dated May 7, 2013, with MLV, for itself and as representative of the underwriters listed on Schedule I to that agreement, on May 10, 2013, we offered and 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 $765. These securities are registered for sale to the public pursuant to a prospectus, dated September 19, 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.

Pursuant to an Underwriting Agreement, dated June 27, 2013, with MLV, for itself and as representative of the underwriters listed on Schedule I to that Agreement, on July 2, 2013, we offered and 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 $7,200 in connection with the offering, from which MLV was paid a commission of $504. These securities are registered for sale to the public pursuant to a prospectus, dated September 19, 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.

Apollo Credit Facility Waiver and Amendment

On July 11, 2013, we entered into the July 2013 Amendment with Apollo under the Apollo Credit Facility. The fee for the Amendment was $100.

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

The following tables show our capital and operational costs for fiscal years 2013, 2012 and 2011:

a. Capitalized Costs Relating to Oil and Gas Producing Activities at April 30, 2013, 2012 and 2011 are as follows:



	2013			2012			2011
Natural gas and oil properties:
Proved properties	$	326,936		$	321,066		$	314,706
Unproved properties	196,500			182,704			182,220
	523,436			503,770			496,926
Accumulated depletion	(37,427		)	(27,968		)	(14,874		)
Net capitalized costs	$	486,009		$	475,802		$	482,052

b. Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities:



	2013		2012		2011
Property acquisition costs
Proved properties	$	689	$	—	$	—
Unproved properties	704		785		1,009
Acquisition costs	1,393		785		1,009
Exploration costs	1,268		180		—
Development costs	24,968		6,773		10,265
Total	$	27,629	$	7,738	$	11,274

c. Results of Operations for Producing Activities:



	2013			2012			2011
Production revenues	$	29,915		$	32,493		$	21,086
Oil and gas operating costs	(24,698		)	(14,861		)	(9,703		)
Depletion	(13,041		)	(13,094		)	(11,002		)
Results of operations for producing activities (excluding corporate overhead and interest costs)	$	(7,824	)	$	4,538		$	381

d. Reserve Quantity Information (Unaudited)

The following reserve quantity information was derived from reserve and engineering reports prepared for the Company by various third parties. The reserve and engineering reports for both Alaska and Tennessee properties were prepared by Ralph E. Davis Associates, Inc. for the years ended April 30, 2013 and 2012. Ralph E. Davis Associates, Inc. also prepared the reserve and engineering reports for our Alaska properties for the year ended April 30, 2011. Reserve and engineering reports for our Tennessee properties were prepared by Lee Keeling and Associates, Inc. for the year ended April 30, 2011.

The following schedule estimates proved oil and natural gas reserves attributable to the Company. Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Reserves are stated in barrels of oil (Bbls) and thousands of cubic feet of natural gas (Mcf). Geological and engineering estimates of proved oil and natural gas reserves at one point in time are highly interpretive, inherently imprecise and subject to ongoing revisions that may be substantial in amount. Although every reasonable effort is made to ensure that the reserve estimates reported represent the most accurate assessments possible, these estimates are by their nature generally less precise than other estimates presented in connection with financial statement disclosures.

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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



	Oil (MBbls)		Gas (MMcf)
Proved reserves
Balance, April 30, 2010	9,267		5,459
Discoveries and extensions	—		1,309
Revisions of previous estimates	(46	)	156
Acquisitions	—		(3,342	)
Production	(273	)	(339	)
Balance, April 30, 2011	8,948		3,243
Discoveries and extensions	94		1,850
Revisions of previous estimates	(124	)	(359	)
Acquisitions	—		—
Production	(384	)	(177	)
Balance, April 30, 2012	8,534		4,557
Discoveries and extensions	26		35
Revisions of previous estimates	(317	)	(519	)
Acquisitions	6		—
Production	(295	)	(133	)
Balance, April 30, 2013	7,954		3,940
Proved developed reserves at April 30, 2013	1,697		513
Proved developed reserves at April 30, 2012	2,325		2,601
Proved developed reserves at April 30, 2011	2,461		2,441
Proved undeveloped reserves at April 30, 2013	6,257		3,427
Proved undeveloped reserves at April 30, 2012	6,209		1,956
Proved undeveloped reserves at April 30, 2011	6,487		802

We have budgeted for capital expenditures of $125,000 in fiscal 2014.

The following schedule presents the standardized measure of estimated discounted future net cash flows from the Company's proved developed reserves for the years ended April 30, 2013, 2012 and 2011. All estimates were prepared by third party reserve and engineering firms. Because the standardized measure of future net cash flows was prepared using the prevailing economic conditions existing at April 30, 2013, 2012 and 2011, it should be emphasized that such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of the Company's recoverable reserves or in estimating future results of operations.

Each of the engineering reports also projected future cash flows from our net reserves and the present value, discounted at 10% per annum. Future cash flows are based upon gross income from future production, less direct operating expenses and taxes. Estimated future capital for development costs was also deducted from gross income at the time it will be expended. No allowance was made for depletion, depreciation, income taxes or administrative expense. In the following table, the price per barrel of oil was $98.12 and the price per MMcf of natural gas was $6.37 for the Cook Inlet reserves and $83.60 per barrel of oil and $2.58 per MMcf of natural gas for the Appalachian region reserves. In each instance these prices are computed in accordance with the SEC’s rule and represent the average fiscal year prices.

Operating costs and production taxes are estimated based on current costs with respect to producing gas properties. Future development costs are based on the best estimate of such costs assuming current economic and operating conditions.

Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved.

The future net revenue information assumes no escalation of costs or prices, except for gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.

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MILLER ENERGY RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

Standardized measures of discounted future net cash flows at April 30, 2013, 2012 and 2011 are as follows:



	2013			2012			2011
Future cash flows	$	801,134		$	894,027		$	657,564
Future production costs and taxes	(178,779		)	(158,938		)	(119,653		)
Future development costs	(72,434		)	(75,332		)	(79,007		)
Future income tax expense	(150,568		)	(217,312		)	(149,388		)
Future cash flows	399,353			442,445			309,516
Discount at 10% for timing of cash flows	(124,905		)	(139,242		)	(102,715		)
Discounted future net cash flows from proved reserves	$	274,448		$	303,203		$	206,801

Of the Company's total proved reserves as of April 30, 2013, 2012 and 2011, approximately 21%, 17% and 23%, respectively, were classified as proved developed producing, 0%, 21% and 17%, respectively, were classified as proved developed non-producing and 79%, 62% and 60%, respectively, were classified as proved undeveloped. All of the Company's reserves are located in the continental United States.

The following table sets forth the changes in the standardized measure of discounted future net cash flows from proved reserves for April 30, 2013, 2012 and 2011.



	April 30,
	2013			2012			2011
Balance, beginning of year	$	303,203		$	206,801		$	188,293
Sales, net of production costs and taxes	(5,217		)	(17,632		)	(11,383		)
Changes in prices and production costs	(59,253		)	116,689			33,625
Extensions, discoveries and improved recovery, less related costs	1,302			58,906			4,592
Acquisition of reserves in place	295			—			—
Changes in estimated future development costs	(2,856		)	7,641			(26,032		)
Development costs incurred	5,522			6,773			10,265
Revisions of previous quantity estimates	(21,828		)	(42,857		)	(555		)
Net changes in income taxes	49,486			(48,571		)	(5,397		)
Sales of reserves in place	—			—			(1,470		)
Accretion of discount	39,472			30,503			28,112
Changes in timing and other	(35,678		)	(15,050		)	(13,249		)
Balance, end of year	$	274,448		$	303,203		$	206,801

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