10-K 1 mill10k43012.htm ANNUAL REPORT MILL 10K 4.30.12

 

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

———————
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, 2012
OR
¨    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from: to

———————

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)
———————
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
 
 
 
Securities registered pursuant to Section 12(g) of the Act:
 
 
 
None
 
(Title of Class)
 
———————
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.
 
¨
Yes
þ
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, 2011 (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 $89,902,859. As of July 06, 2012, there were 41,945,393 shares of common stock of the registrant outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of registrant’s proxy statement relating to registrant’s 2012 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, 2012

TABLE OF CONTENTS
 
 
 
Page
 
 
 
 
 
 
PART I
 
 
 
 
 
 
 
 
 
 
 
PART II
 
 
 
 
 
 
 
 
 
 
 
 
 
PART III
 
 
 
 
 
 
 
 
 
 
PART IV
 
 


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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 annual report on Form 10-K, and may make other forward-looking statements from time to time in other public filings, press releases and discussions with our management,. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include those statements preceded by, followed by or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should” or similar expressions or variations on such expressions. For these statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that our expectations will prove to be correct. We undertake no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise. These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:
the potential for Miller to experience additional operating losses;
high debt costs under our existing senior credit facility;
potential limitations imposed by debt covenants under our senior credit facility on our growth and our ability to meet our business objectives;
our need to enhance our management, systems, accounting, controls and reporting performance;
uncertainties related to deficiencies identified by the SEC in certain Forms 8-K filed in 2010 and our Form 10-K for 2011;
litigation risks;
our ability to perform under the terms of our oil and gas leases, and exploration licenses with the Alaska DNR, including meeting the funding or work commitments of those agreements;
our ability to successfully acquire, integrate and exploit new productive assets in the future;
our ability to recover proved undeveloped reserves and convert probable and possible reserves to proved reserves;
risks associated with the hedging of commodity prices;
our dependence on third party transportation facilities;
concentration risk in the market for the oil we produce in Alaska;
the impact of natural disasters on our Cook Inlet Basin operations;
adverse effects of the national and global economic downturns on our profitability;
the imprecise nature of our reserve estimates;
drilling risks;
fluctuating oil and gas prices and the impact on our results from operations;
the need to discover or acquire new reserves in the future to avoid declines in production;
differences between the present value of cash flows from proved reserves and the market value of those reserves;
the existence within the industry of risks that may be uninsurable;
constraints on production and costs of compliance that may arise from current and future environmental, FERC and other statutes, rules and regulations at the state and federal level;
the impact that future legislation could have on access to tax incentives currently enjoyed by Miller;
that no dividends may be paid on our common stock for some time;
cashless exercise provisions of outstanding warrants;
market overhang related to restricted securities and outstanding options, and warrants;
the impact of non-cash gains and losses from derivative accounting on future financial results; and
risks to non-affiliate shareholders arising from the substantial ownership positions of affiliates.
Most of these factors are difficult to predict accurately and are generally beyond our control. You should consider the areas of risk described in connection with any forward-looking statements that may be made herein. Readers are cautioned not to place undue reliance on these forward-looking statements, and readers should carefully review this 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-

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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, 2012 is referred to as “fiscal 2012” or "2012," the year ended April 30, 2011 is referred to as “fiscal 2011” or "2011," the year ended April 30, 2010 is referred to as “fiscal 2010” or "2010" and the year ending April 30, 2013 is referred to as “fiscal 2013” or "2013."

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.
Boe/d. Boe per day.
Mcf. One thousand cubic feet of natural gas corrected to standard temperature and pressure.
MMBbls. Million barrels of oil.
MMcf. Million cubic feet of natural gas correct 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.
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,

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




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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 and development of oil and gas wells in the Appalachian region of East Tennessee and in southcentral Alaska. During fiscal 2012, 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 working interest in the new wells. This strategy will allow us to maintain operational control, which we believe will translate to long-term benefits;
Increase Production. We plan on increasing oil and gas production through the maintenance, repair and optimization of wells located in the Cook Inlet Basin and development of wells in the Appalachian region of East Tennessee. Our management team expects to employ the latest available technologies to explore and develop our properties;
Expand Our Revenue Stream. We intend on fully exploiting our mid-stream facilities, such as our injection wells and the Kustatan Production Facility, our ability to engage in the commercial disposal of waste generated by oil and gas operations, and our capacity to process third party fluids and natural gas and to offer excess electrical power to net users in the Cook Inlet area; and
Pursue Strategic Acquisitions. We have significantly increased our oil and gas properties through strategic low-cost / high-value acquisitions. Under the same strategy, our management team plans to continually 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 2012 results and the Company's 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
Apollo Investment Corporation 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 lender, along with other lenders party to the Loan Agreement from time to time (the “Lenders”). The loan agreement provides for a credit facility of up to $100 million (the “Credit Facility”) with an initial borrowing base of $55 million, of which $40 million was available upon the Closing Date. The remaining $15 million of the initial borrowing base will be made available following the satisfaction of certain conditions by the Company, most notably, the Company demonstrating to Apollo's satisfaction that it can raise at least $15 million in equity (the"Equity Requirement") and the delivery of audited year-end financial statements for fiscal year 2012. The Credit Facility matures on June 29, 2017 and is secured by substantially all the assets of the Company and its subsidiaries. Amounts outstanding under the Credit Facility bear interest at the rate of 18% per annum.

Draws under the Credit Facility may be made once per fiscal quarter (other than the draw of the remaining $15 million of the borrowing base not drawn on the Closing Date, which may be drawn by the Company upon satisfaction of the Equity Requirement and other relevant conditions). Increases in the borrowing base are subject to the discretion of Apollo. The borrowing base may be redetermined up to once per calendar quarter, following a request by the Company, or at the discretion of Apollo.

The Loan Agreement contains interest coverage, asset coverage, minimum gross production and leverage covenants, as well as other affirmative and negative covenants. In connection with the Loan Agreement, 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

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related properties including wells during the term of the Credit Facility and one year thereafter. Under the Loan Agreement, the Company must prioritize certain oil and gas development projects over others, and will be restricted from spending its cash on lower priority projects prior to the completion of those with a higher priority. A list of priorities was negotiated in connection with the closing of the Loan Agreement, and that list can only be changed with the consent of Apollo and the majority of the Lenders (as measured by the relative portion of the commitments held under the Loan Agreement from time to time).

On June 29, 2012, we, along with all of our subsidiaries, also entered into a Guarantee and Collateral Agreement (the “Guarantee”) with Apollo, for the benefit of the Lenders. We granted a security interest in substantially all of our subsidiaries' assets to secure the performance of our obligations under the Loan Agreement and the Guarantee.

The Company used $26.2 million of the initial $40 million loan made available under the Credit Facility to repay in full the amounts outstanding (including accrued interest) under the prior Loan Agreement, dated June 13, 2011 (the “Prior Loan Agreement”), between the Company, as borrower, Guggenheim Corporate Funding, LLC, as administrative agent and lender, and Citibank, N.A. and Bristol Investment Fund, as lenders. The Prior Loan Agreement and all related documents and security interests arising under them were terminated immediately upon that repayment.
Loan proceeds of $10.8 million were used to redeem the Company's outstanding Series A Cumulative Preferred Stock issued on April 6, 2012 as described below; while proceeds of $2.8 million were used to pay a non-refundable structuring fee to Apollo for the Loan Agreement. The remaining proceeds of $0.2 million were used to pay certain outstanding payables of the Company.
For a full description of the terms of the Credit Facility, please see Note 16 - Subsequent Events in the Notes to Consolidated Statements set forth in Part IV, Item 15 of this Form 10-K.
Private Placement of Series A Cumulative Preferred Stock
On April 6, 2012, we issued a new class of Series A Cumulative Preferred Stock (the "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 million and paid a finder's fee of $0.1 million to Dimirak Securities Corporation ("Dimirak"), a broker-dealer and member of FINRA. Mr. Boruff, our Chief Executive Officer, is a director and 49% owner of Dimirak.
The Preferred Stock is non-convertible and redeemable by us, at our discretion. Holders of the 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 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.  
Under the terms of the offering, the Preferred Stock must be redeemed by us within 30 days following the refinancing and repayment of our existing credit facility. If the Preferred Stock is not redeemed by us within 30 days of the repayment, purchasers of the shares will receive, as liquidated damages, a reduction in the exercise price of the warrants from $5.28 per share to $3.00 per share. Further, we are subject to an increased redemption premium if the Preferred Stock is not redeemed within 180 days of issuance. For a full description of the designations, rights and preferences of the Preferred Stock and a description of the warrants, please see Note 3 - Derivative Instruments and Note 8 - Capital Stock in the Notes to Consolidated Statements set forth in Part IV, Item 15 of this Form 10-K.

Renegotiated Alaska Crude Oil Sales Contract
On March 9, 2012, we entered into a crude oil sales agreement with an independent refiner and marketer of petroleum products whereby that company 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. The agreement strategically aligned the terms of our pricing with the ANS Index, which has historically averaged approximately $8 - $10 higher per barrel than WTI, as defined below. The newly negotiated price for each delivery of oil is equal to the higher of the arithmetic average of the published daily New York Mercantile Exchange (“NYMEX”) Settlement Prices for Light Sweet Crude Oil delivered at Cushing, Oklahoma ("WTI") for the applicable front month NYMEX Contract published each business day in the calendar month of delivery or the ANS Index Midpoint Price if it is at least $2.285/barrel greater than the WTI Index Price, subject to certain adjustments.
     Under the agreement, we are also responsible for paying taxes on the sale or on 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 Cook Inlet Spill Prevention and Response, Inc. ("CISPRI") charges, or closure of the purchaser's Alaska refinery.


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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.
 
 
2012 Production
 
Percentage of Total 2012 Production
 
2012 Oil and Gas Revenues
 
4/30/2012 Estimated Proved Reserves
 
Percentage of Total Estimated Proved Reserves
 
 
(In Boe)
 
 
 
(In thousands)
 
(In MBoe)
 
 
Cook Inlet 1
 
333,420

 
90%
 
$
30,700

 
9,157

 
99%
Appalachian region
 
38,423

 
10%
 
1,793

 
137

 
1%
Total
 
371,843

 
100%
 
$
32,493

 
9,294

 
100%
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1 
Cook Inlet production excludes 33,956 boe of fuel gas.

Alaska Region
Overview
The Cook Inlet Basin contains large oil and gas deposits including multiple offshore fields. In 2012 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 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, 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, 2012 and 2011, we owned approximately 105,713 and 115,124 gross acres of leasehold interests, the exploration license rights to an additional 534,383 acres and interests in 10 crude oil and five natural gas wells. The reduction in leased acreage from April 30, 2011 is a result of our surrender of five leases nearing expiration and the assignment of a portion of one lease to Union Oil Company of California ("Unocal"). The increase in license acreage resulted from the issuance of Susitna Basin Exploration License No. 5, consisting of 45,764 acres.  
At the time we acquired the Alaskan operations, all ten oil wells, three of four gas wells and four injection wells were shut-in. By April 30, 2010, three oil wells and five gas wells had been returned to production. In addition, we own a 30% working interest in two gas wells operated by Aurora Gas, which have been operated continuously.

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Oil wells drilled in this area range from 9,000 vertical feet to 10,000 feet in vertical depth while gas wells have a vertical depth of 8,000 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 giving total measured depth of 14,000 feet to 15,000 feet. 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 to 80 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. The Nikiski LNG plant is the only LNG export facility in the United States, and has been shipping Cook Inlet LNG to Japan for over 40 years.
Osprey Platform and Redoubt Shoals Field
The Osprey platform is located in the Redoubt Unit approximately 1.8 miles southeast of the 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 the Kustatan Production Facility to process all of Osprey's produced fluids. The platform has 21 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 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, but 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. We estimated the total cost of restoring full production, including the purchase and construction of a drilling rig, to be approximately $45 million. 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 $17.9 million.
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 impossible. As warmer temperatures moderated the region, we resumed work on the assembly of Rig 35, which in its present state is substantially completed and expected to be fully operational in July 2012.
Kustatan Production Facility
The Kustatan Production Facility was constructed in 2001-2002 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

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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 $3.0 million 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 $0.8 million. 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.
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 $2.3 million work commitment, we will gain the option to convert any part of the licensed area into oil and gas leases. We posted an initial performance bond of $0.2 million 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 ten-year license to explore for oil and gas on the specified lands. Upon fulfillment of a $0.3 million work commitment, we will gain the option to convert any part of the licensed area into oil and gas leases. We posted an initial performance bond of $50,000 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 with the Alaska Department of Natural Resources (“Alaska DNR”) which set out certain terms under which the Alaska DNR would approve the assignment of certain specified state oil and gas leases from Pacific Energy Resources 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 reserves from the Redoubt Shoal, West McArthur River and West Foreland Fields. Under the terms of the agreement, until the Alaska DNR determines, in its sole discretion, that CIE has completed its development and operation obligations under the assigned leases CIE agreed to the following:
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,
meet monthly with the Alaska DNR to provide an update on operations and progress towards meeting these objectives,
notify the Alaska DNR 10 days prior to commitment when CIE is preparing to spend funds on a purchase, project or item of more than $0.1 million during the first 12 months, more than $1 million during the second 12 months and more than $5 million thereafter, and
submit a new plan of development and plan of operations for the Alaska DNR's approval on or before December 15, 2009 and submit a plan of development annually thereafter on or before February 1, 2010. CIE timely met these deadlines.
The agreement required CIE to obtain financing in the minimum amount of $5.2 million to provide funds to be used for expenditures approved by the Alaska DNR as part of CIE's plan of development. We have provided these funds for the West McArthur River facility using a portion of the proceeds of our capital raising efforts described elsewhere herein.  
The agreement required CIE to demonstrate funding commitments to support restoration of the base production at the Redoubt Unit, including bringing a number of the shut-in wells back on line, which was estimated at $31 million in the agreement, but which we have internally increased to $45 million primarily to accommodate the contractual purchase price of a drilling rig.
CIE is prohibited from using any of the proceeds from the operations under the assigned leases of the funding commitments for non-core oil and gas activities under the assigned leases, or any activities outside the assigned leases, without the prior written approval of the Alaska DNR until the parties mutually agree that the full dismantlement obligation under the assigned leases is funded.
On March 11, 2011, CIE entered into a Performance Bond Agreement with the Alaska DNR that applies to the offshore obligations under the Assignment Oversight Agreement.  Under the Performance Bond Agreement, CIE is required to post a total bond of $18 million; however, the Performance Bond Agreement makes clear that approximately $6.8 million held

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by the state will apply to the total bond required. The first payment of $1.0 million toward the bonding requirement is due in July 2013.
The assigned leases will be subject to default and termination should CIE fail to submit the information required under the agreement and expenditure of funds for items or activities do not support core oil and gas activities, as reasonably determined by the Alaska DNR.
Membership in Cook Inlet Spill Prevention and Response, Inc.
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 $10,000 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 million. 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's 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, 2012, we owned approximately 49,260 gross acres of leasehold interests with 183 producing oil wells and 181 producing gas wells in which we own an interest. 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.
The Appalachian region of Tennessee has produced oil from a number of fields. Some of those fields include the Indian Creek, Burrville, Low Gap, Lick Branch, Gum Branch, Skull Creek, and Bendix Spur. We have acreage in and around these previously producing fields and plan to utilize our expertise to enhance present production and extract additional oil from areas previously overlooked.
Historically, only 12 percent to 18 percent of the oil in place has been recovered by primary recovery methods in the Mississipian age formations of the Monteagle Limestone and Fort Payne Limestone in Tennessee. We believe that Horizontal drilling within our acreage holdings described above will unlock much of the oil still in place. Horizontal drilling is the process of drilling a well from the surface to a subsurface location just above the target formation called the "kickoff point," then deviating the well bore from the vertical plane around a curve to intersect the formation at the "entry point" with a near-horizontal inclination. At this point, the well-bore remains in the horizontal plane until the desired length is achieved. With the Monteagle and Fort Payne being stratigraphic oil producing zones, horizontal drilling will be a way to recover a much greater percentage of the remaining oil in place by placing the well bore within the stratigraphic zone and not drilling through the zone vertically. This drilling and production method along with gas pressure maintenance will enable us to maximize the oil potential in Tennessee.
Another focus for the Appalachian region is the potential extraction from the Devonian age Chattanooga Shale. Across the U.S., from the West Coast to the Northeast, some 19 geographic basins are recognized sources of shale gas. Although natural gas has been known for years to exist in these formations, the natural gas trapped in it was not considered commercially viable to produce because of shale's tendency to be so dense that the trapped natural gas could not be accessed. The

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introduction of Horizontal Drilling and Multiple Zone Hydraulic Fracturing has allowed for this untapped resource to become commercially viable. As is the case above with the horizontal drilling in the Mississippian limestone formations, along this horizontal lateral, multiple-zone hydraulic fracturing breaks open the shale to allow natural gas to flow freely to the well bore. This horizontal approach to accessing the hydrocarbons trapped within the shale formation has proven to be more cost effective than traditional vertical drilling while minimizing the number of wells necessary to monetize a formation. Currently, within the acreage controlled by us, there are numerous potential well locations that can be drilled and produced to be used as a pressure maintenance program or natural gas storage within the Mississippian age Fort Payne Limestone.

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/barrel 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/barrel, then the price shall be equal to the WTI Index Price less $1.715; (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 or on 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 2012, 2011 and 2010, purchases by Tesoro accounted for 100%, 99%, and 100%, respectively, of our total Alaska oil and gas production revenues.
Currently, all natural gas produced by our Alaskan operations is used to generate heat and power at our production facilities. At such time as gas production exceeds our internal needs, we can sell the excess production 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 Marathon Pipelines.
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 statewide at our well sites by Barrett Oil Purchasing 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 2012, 2011 and 2010, sales to Barrett Oil Purchasing and Sunoco, collectively, represented approximately 35%, 2%, and 9%, respectively, of our total Tennessee 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 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. 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 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.
In addition to rig construction and modification activities, we successfully brought on-line two previously producing wells on the Osprey platform, RU-1 and RU-7. After a short period of production, RU-1 ceased production as a result of an ESP failure. Our objective for the coming year is to utilize Rig 35 on the Osprey platform to repair all non-producing wells and

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restore production to anticipated capacity.
We incurred dry hole costs on one well in Alaska and two wells in Tennessee. In Alaska, we explored two new zones in our KF-1 that were unproductive. The cost of exploring the two new zones was expensed in 2012. In Tennessee, we drilled two new development wells that were unproductive. The development cost of these wells was capitalized 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
 
2012
 
2011
 
2010
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development:
         

 
 
 
 
 
 
 
 
 
 
Producing
 
 
 
 
 
 
 
 
 
 
 
Cook Inlet

 

 

 

 

 

Appalachian region

 

 

 

 

 

Total producing

 

 

 

 

 

Non-Producing
 
 
 
 
 
 
 
 
 
 
 
Cook Inlet

 

 

 

 

 

Appalachian region

 

 

 

 

 

Total non-producing

 

 

 

 

 

Injection
 
 
 
 
 
 
 
 
 
 
 
Cook Inlet

 

 

 

 

 

Appalachian region

 

 

 

 

 

Total injection

 

 

 

 

 

Dry
 
 
 
 
 
 
 
 
 
 
 
Cook Inlet

 

 

 

 

 

Appalachian region
2

 
2

 

 

 

 

Total dry
2

 
2

 

 

 

 

Total development
2

 
2

 

 

 

 

Exploratory:
 
 
 
 
 
 
 
 
 
 
 
Productive
 
 
 
 
 
 
 
 
 
 
 
Cook Inlet

 

 

 

 

 

Appalachian region

 

 
3

 
3

 

 

Total productive

 

 
3

 
3

 

 

Dry
 
 
 
 
 
 
 
 
 
 
 
Cook Inlet
1

 
1

 

 

 

 

Appalachian region

 

 

 

 

 

Total dry
1

 
1

 

 

 

 

Pending determination

 

 

 

 

 

Total exploratory
1

 
1

 
3

 
3

 

 

Total drilling activity
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, 2012 is set forth below:
 
Producing Wells
 
Gross (a)
 
Net (b)
 
Oil
 
Gas
 
Total
 
Oil
 
Gas
 
Total
Cook Inlet
4

 
8

 
12

 
4

 
6

 
10

Appalachian region
183

 
181

 
364

 
114

 
117

 
231

Total
187

 
189

 
376

 
118

 
123

 
241

———————
(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, 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, 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, and is exclusive of work-over costs.
 
 
For the Year Ended April 30,
 
 
2012
 
2011
 
2010
Production - boe1
 
405,799

 
327,712

 
88,030

Average oil price - per bbl
 
$
93.10

 
$
75.75

 
$
70.90

Average natural gas price - per mcf
 
$
3.47

 
$
4.77

 
$
4.99

Average lease operating expenses - per boe
 
$
27.86

 
$
24.93

 
$
26.58

———————
1 
Total production for fiscal 2012, 2011 and 2010 includes 33,956, 34,987 and 11,695 boe of fuel gas, respectively, which is considered in the calculation of average production cost but excluded from the calculation of average sales prices.

Gross and Net Undeveloped and Developed Acreage
Our staff of professional geologists utilize 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, 2012:
 
Developed Acres
 
Undeveloped Acres
 
Total Acres
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Cook Inlet
34,997

 
32,801

 
639,470

 
621,621

 
674,467

 
654,422

Appalachian region
9,261

 
6,385

 
39,999

 
31,987

 
49,260

 
38,372

Total acreage
44,258

 
39,186

 
679,469

 
653,608

 
723,727

 
692,794


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 and 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. During fiscal 2012, the terms of the two Olsen Creek leases were extended to the Susitna Basin #5 Exploration License, a segment of ADL 17597 containing 1,000 net acres was assigned to Unocal, and five Cook Inlet leases near expiration were surrendered.

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Net Undeveloped Acres
Lease/Exploration License
 
Year of Expiration
 
Total Acres
Cook Inlet
 
 
 
 
MHT 9300062 - Olsen Creek
 
2013
 
5,483

MHT 9300063 - Olsen Creek
 
2013
 
3,906

ADL 391613 - Olsen Creek
 
2018
 
107

ADL 391614 - Olsen Creek
 
2018
 
35

ADL 391615 - Olsen Creek
 
2018
 
570

ADL 391623 - N Alexander
 
2018
 
5,513

ADL 390571 - Pretty Creek
 
2012
 
1,160

ADL 390749 - Otter
 
2013
  
2,522

ADL 390579 - Otter
 
2012
 
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
 
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

Total
 
 
 
621,621

 
 
 
 
 
Appalachian region
 
 
 
 
Lindsay
 
Held by production
 
1,439

Edwards-Fowler, Gann
 
Held by production
 
70

Gunsight
 
Held by production
 
1,501

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
 
2012 to 2013
 
1,770

Total
 
 
 
31,987

 
 
 
 
 
Total acreage
 
 
 
653,608


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.
“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-

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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 (see page from adjacent areas) and projected reserves based on future recovery methods.
The following table shows proved oil and gas reserves as of April 30, 2012, based on average commodity prices in effect on the first day of each month in fiscal 2012, 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, 2012
Reserves category:
 
Oil
(MBbls)
 
Natural Gas
 (MMcf)
 
MBoe
 
Reserve %
PROVED
 
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
 
Cook Inlet
 
2,234

 
2,329

 
2,622

 
28%
Appalachian region
 
91

 
272

 
137

 
1
Undeveloped
 
 
 
 
 
 
 
 
Cook Inlet
 
6,209

 
1,956

 
6,535

 
71
Appalachian region
 

 

 

 
Total Proved
 
8,534

 
4,557

 
9,294

 
100%
Our estimates of proved reserves, proved developed reserves and PUD reserves as of April 30, 2012, 2011 and 2010, 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 2012, we did not develop any PUDs. We anticipate developing three of our offshore PUDs in Alaska's Redoubt Unit during fiscal 2013, including Redoubt 4A, 2A and 5A. Additionally, we expect to develop the Redoubt 9 PUD in fiscal 2014. 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 2013 including WMRU 8 and 9.
Preparation of Oil and Gas Reserve Information
Our reserve estimates for oil and natural gas at April 30, 2012 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 estimate for oil and natural gas at April 30, 2011 and 2010 for our Cook Inlet assets was prepared by Ralph E. Davis Associates, Inc. Our reserve estimates for oil and gas at April 30, 2011 and 2010 for our Appalachian region assets were prepared by Lee Keeling and Associates, Inc., an independent engineering firms.

Internal Controls over Reserves Estimate
Our policies regarding internal controls over reserve estimates require reserves to be in compliance with the SEC definitions and guidance and for reserves to be prepared by an independent engineering firm. Our Acting Chief Financial Officer and the Chief Executive Officer of CIE 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 information is reviewed by the Chief Executive

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Officer of CIE and our Acting Chief Financial Officer prior to submission to our third party engineering firm. A letter which identifies 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, 2012.

Other Ancillary Services
We also generate ancillary revenue from drilling activities. While the equipment and personnel on hand are for the benefit of drilling on our own properties, from time to time we optimize unused capacity to perform drilling and related services on behalf of third parties. 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. Drilling wells for Atlas Energy Resources, LLC accounted for approximately 43% of our other revenue for fiscal 2010.

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 Marathon. However, we believe we have a competitive edge because we already have existing oil and gas production, facilities, infrastructure, and pipelines that connect us to the oil and gas markets as well as some of the lowest operating cost in the area. 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 six 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 believe we can effectively compete for leases, however, as in the Appalachian region we have name recognition of over 40 years, we are the largest operator of oil and gas wells in Tennessee and we have a staff of experienced, proven petroleum geologists and engineers that allows us to exploit the potential the Appalachian region provides.

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.

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The Regulatory Commission of Alaska regulates the intrastate pipeline tariffs and encompasses all pipelines CIE ships through including the 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 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 $0.8 million in Alaska and federal bonds. The Alaska DNR requires $0.6 million in bonding to operate oil and gas leases on state lands, and the Alaska Oil and Gas Conservation Commission (“AOGCC”) requires a $0.2 million 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 $0.9 million in designated accounts to satisfy future abandonment obligations. A $0.3 million 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 $0.3 million. 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; $0.6 million 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 $0.8 million 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 million. The agreement sets a payment schedule totaling $12 million in annual payments between July 2013 and July 2019.  An existing interest bearing account containing approximately $7.0 million as of April 30, 2012 is to be credited against the inflation-adjusted $18 million 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 $60,000 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 Gas and Oil 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 $0.02 million for ten wells. Currently, we have several old $10,000 blanket plugging bonds. For most of the reclamation bonds, we have deposited a $1,500 certificate of deposit with the Tennessee Gas and Oil 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 regulation 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;


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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" 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,
clean up contaminated property, including contaminated groundwater; or to perform remedial operations to prevent future contamination, 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 the insertion of a seven-inch diameter steel casing into each well, with cement on the outside of the casing. The cost of compliance with this environmental regulation is approximately $10,000 per well. 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

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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.
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, 2012, we had 70 employees.

Offices
Our principal executive offices are located at 9721 Cogdill Road, Suite 302, Knoxville, TN. At April 30, 2012, 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 $0.3 million.
Shortly thereafter, we acquired ETC, in exchange for an aggregate of 1,000,000 shares of our common stock valued at $0.3 million. 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.


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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 $0.3 million in cash to satisfy certain expenses as well as reimbursement for reasonable out of pocket expenses. Following the transaction, Mr. 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 closing we paid Pacific Energy $2.3 million and provided $2.2 million for bonds, contract cure payments and other federal and State of Alaska requirements to operate the facilities.
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 $0.4 million. 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, but have not become direct guarantors of the loans ourselves. As of April 30, 2012, the gross outstanding amount under the loans is $5.7 million. 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, TN. We executed a five-year lease for the space, and with the addition of us, the building is fully occupied by tenants.
In April 2011 we changed our name to Miller Energy Resources, Inc. Additional information regarding the acquisitions of the KTO assets, ETC, and CIE can be found in Note 2 - Acquisitions in the Notes to Consolidated Financial Statements set forth in Part VI, Item 15, of this Form 10-K.


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ITEM 1A.    RISK FACTORS.

In addition to the other information set forth elsewhere in the Form 10-K, you should carefully consider the following material risk factors associated with our business and the oil and gas industry in which we operate. 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. There may be additional risks that are not presently material or known, or may be included in the prospectuses for securities we issue in the future.
An investment in Miller is subject to risks inherent in our business. The trading price of our common shares will be affected by the performance of our business relative to, among other things, competition, market conditions and general economic and industry conditions. The value of an investment in Miller may decrease, resulting in a loss.
Risks Related to Our Business
We have a history of operating losses; we incurred a net loss in both fiscal 2011 and fiscal 2012 and our net income in fiscal 2010 was the result of one-time acquisition gains. Our revenues are not currently sufficient to fund our operating expenses and there are no assurances we will develop profitable operations.
We reported an operating loss of approximately $25.1 million in fiscal 2012, $14.6 million in fiscal 2011 and $11.3 million in 2010. Our net loss of approximately $18.7 million in 2012 is primarily attributable to the operating loss, plus $4.6 million in other expense, partially offset by an approximate $11.0 million benefit from income taxes. Our net loss of approximately $3.9 million in 2011 is primarily attributable to the operating loss, partially offset by an approximate $4.4 million in other income and a $6.3 million benefit from income taxes. Our net income of approximately $250.9 million in fiscal 2010 is attributable to $461.1 million in gains on the acquisition of the Alaska and Tennessee businesses. As a result of the continued expansion of our business during fiscal 2012, our operating expenses presently exceed our revenues. We anticipate that our operating expenses will continue to increase as we fully develop our operations following the acquisition of the Alaskan assets. Although we expect an increase in our revenues to come from these development activities, we will continue depleting our cash resources to fund operating expenses until such time as we are able to significantly increase our revenues. We may have to reduce our expansion efforts if we have not seen an increase in revenues in the next few months. While we believe that our revenue will increase and exceed our operating expenses, there are no assurances that we will develop profitable operations.
We will be subject to new 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 report, in June 2012 we entered into a Loan Agreement with Apollo Investment Corporation, under which a credit facility of up to $100 million (the “Apollo Credit Facility”) was made available to us. At closing, we drew $40 million under the Apollo Credit Facility. That amount and any other monies borrowed by us will bear interest at mezzanine rates and will be 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 such time as the facility has been repaid. We are also subject to restrictions on our ability to pay for general and administrative expenses. This could mean that we would 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. This may constrain management's ability to pursue projects in their optimal order, or require us to obtain consents from our lenders in order to deviate from the established list of priorities.
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:
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;

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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.
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. Also, the Apollo Credit Facility will require 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 as lower levels, or any event with 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 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.
Our business and stock price could be adversely affected if we are not successful in enhancing our management, systems, accounting, controls and reporting performance.
We have experienced, and may continue to experience, difficulties in implementing the management, operations and accounting systems, controls and procedures necessary to support our growth and expanded operations, as well as difficulties in complying with the accounting and reporting requirements related to our growth, acquisitions and status as an accelerated filer. With respect to enhancing our management and operations team, we may experience difficulties in finding and retaining additional qualified personnel, and if such personnel are not available locally, we may incur higher recruiting, relocation, and compensation expense. In an effort to meet the demands of our planned activities in fiscal 2013 and thereafter, we may be required to supplement our staff with contract and consultant personnel until we are able to hire new employees. 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.
The staff of the SEC has determined that certain of our Forms 8-K related to acquisitions we made in fiscal year 2010 are materially deficient which will adversely impact our ability to raise additional capital.
In connection with a review of our Annual Report on Form 10-K for the year ended April 30, 2010, the staff of the SEC has concluded that we omitted required audited financial statements of three acquired businesses, including ETC, KTO and CIE, from our Forms 8-K reporting these acquisitions.  Until such time as we file audited financial statements, the staff has advised us it considers those Forms 8-K to be materially deficient and that it will not waive these financial statement requirements.  As a result, we are unable to utilize a “short-form” registration statement on SEC Form S-3.  In addition, until such time as the audited financial statements of the acquired businesses are filed, the staff of the SEC has advised us it will not declare effective any registration statements or post-effective registration statements.  
It is currently expected that we will not be able to rectify the deficient filings until the filing of this fiscal 2012 Annual Report on Form 10-K, at which time we will ask the staff of the SEC to waive the financial statement requirements of Form 8-K for these acquisitions. There are no assurances we will be successful in our efforts to obtain a waiver.
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 on Form 10-K, 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. Our financial

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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 million, 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 million to $2.5 million per year, and totaling $12 million, as approximately $6.8 million 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 $50,000. 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.
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 have received a request from the SEC for a more detailed explanation regarding the specific circumstances that lead 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 have not received and cannot predict the nature of any regulatory 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 will be subject to risks in connection with acquisitions, 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. Inspection s 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

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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;
the challenge and cost of integrating acquired operations, information management, and other technology systems, and business cultures with our own while carrying on our ongoing business;
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 and adversely affected.
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 $3.3 million 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.
Approximately 71% of our total estimated proved reserves at April 30, 2012 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 the reserve engineer reports assumes that substantial capital expenditures are required to develop such reserves. 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, 2012. 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, probable reserves will become producing reserves to the level of the estimates.
Our commodity price risk management and trading activities may prevent us from benefitting fully from price increases and may expose us to other risks.
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.

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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 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 net 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.
Future economic conditions in the U.S. and key international markets may materially adversely impact our operating results.
The U.S. and other world economies are slowly recovering from a global financial crisis and recession that began in 2008. Growth has resumed but is modest and at an unsteady rate. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than in the years leading up to the crisis, and more volatility may occur before a sustainable, yet lower, growth rate is achieved. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate could result in decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which would reduce our cash flows from operation and our profitability.
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 and debris avalanches have also resulted in tsunamis. In 2009 the Cook Inlet Pipeline Co. 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.
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

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recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and underlying information set forth herein.
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 many operating risks 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 operation.
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 Resource Conservation and Recovery Act of 1976 ("RCRA"), and comparable state laws that impose requirements for the handling, storage, treatment or disposal of solid and hazardous waste from our facilities, the Comprehensive Environmental Response, Compensation and Liability Act ("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 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.
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

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“greenhouse gases.” 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.
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, the Federal Energy Regulatory Commission, or FERC, has authority to impose penalties for violations of the Natural Gas Act, up to $1 million 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.
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 proposed U.S. federal budget for fiscal year 2013 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 February 13, 2012, the Office of Management and Budget released a summary of the proposed U.S. federal budget for fiscal year 2013. 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 include elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the manufacturing tax deduction for oil and natural gas companies; and an increase in the geological and geophysical amortization period for independent producers. 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 to be 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 earning 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, 2012 we have common stock warrants outstanding to purchase an aggregate of 1,385,400 shares of our common stock with an average exercise price of $5.11 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 37% 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 effect our stock price.


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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 06, 2012 we had 41,945,393 shares of common stock outstanding together with outstanding options and warrants to purchase an aggregate of 15,450,955 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 06, 2012, approximately 8,953,411 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 15,450,955, 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.
As of April 30, 2012, we have warrants with “full-ratchet” or reset provisions, which means that the exercise or conversion price adjusts to pricing as described within the respective agreements. These instruments require liability classification and mark-to-market accounting with changes in the estimated fair value recorded to our consolidated statement of operations. In addition, 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, 2012, we have a derivative liability of $10.5 million. We recognized a non-cash loss on derivatives of $3.4 million in fiscal 2012, $1.0 million in fiscal 2011 and $13.3 million in fiscal 2010. Beginning in the first quarter of fiscal 2013, we expect to record either a gain or loss based upon the market price of oil and our common stock. 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 and our common stock 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.
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, 2012, management and members of the Board of Directors own approximately 23% 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.


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ITEM 1B.    UNRESOLVED STAFF COMMENTS.

The staff of the Securities and Exchange Commission (the “Staff”) conducted a review of our Annual Reports on Form 10-K for the years ended April 30, 2011 and April 30, 2010, and issued a letter commenting on certain aspects of these reports. We believe that all matters addressed in the comment letters, and in our subsequent responses to these letters to and discussions with the Staff, have been resolved with the exception of certain comments which remain under review. The Staff has indicated that it is still reviewing our responses but could have additional comments regarding (1) production costs used in our third party reserve reports, (2) support for our inclusion of RU 17 as a proved undeveloped reserve, (3) revisions to a third party engineering report (included as an exhibit to a prior filing) reducing probable and possible reserve estimates and (4) the correction of certain immaterial errors in our previous financial statements. We believe that we have adequately responded to these comments by the Staff, but the Staff may choose to issue additional comments related to these matters in the future.

ITEM 3.    LEGAL PROCEEDINGS.

The information set forth in Note 10 - 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 2012, our common stock, par value $0.0001 per share, was listed on the New York Stock Exchange 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 2012 and 2011. 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.
 
 
2011
 
2012
 
 
High
 
Low
 
High
 
Low
First quarter
 
$
7.48

 
$
4.40

 
$
8.02

 
$
4.41

Second quarter
 
6.31

 
4.05

 
3.95

 
2.16

Third quarter
 
5.69

 
4.20

 
4.04

 
2.63

Fourth quarter
 
6.11

 
4.80

 
5.47

 
3.90

The closing price of our common stock, as reported on the New York Stock Exchange for July 06, 2012, was $5.10 per share. As of July 06, 2012, there were 41,945,393 shares of our common stock outstanding held by approximately 348 stockholders of record and approximately 5,243 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 2012 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, 2008, through April 30, 2012. 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
Miller Energy Resources, Inc.
$
100

 
$
330

 
$
5,780

 
$
5,770

 
$
5,430

S&P's Composite 500 Stock Index
100

 
63

 
86

 
99

 
101

Dow Jones US Exploration & Production Index
100

 
52

 
75

 
100

 
87



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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, 2012, 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 discussed in more detail under Item 15, the fiscal 2010 data in the following table reflect a $461 million non-cash gain resulting from our acquisition of CIE. For a discussion of significant acquisitions, please see Note 2 - Acquisitions in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
 
As of or for the Year Ended April 30,
 
2012
 
2011
 
2010
 
2009
 
2008
 
(In thousands, except share and per share amounts)
Income Statement Data:
 
 
 
 
 
 
 
 
 
Total revenues
$
35,402

 
$
22,842

 
$
5,867

 
$
1,567

 
$
829

Net income (loss) attributable to common stockholders
(19,537
)
 
(3,880
)
 
250,941

 
8,356

 
(2,436
)
Net income (loss) per common share:
 
 
 
 
 
 
 
 
 
Basic
(0.48
)
 
(0.11
)
 
11.65

 
0.56

 
(0.17
)
Diluted
(0.48
)
 
(0.11
)
 
8.34

 
0.56

 
(0.17
)
 
 
 
 
 
 
 
 
 
 
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Total assets
$
536,389

 
$
509,081

 
$
500,342

 
$
9,942

 
$
2,934

Total debt
24,130

 
2,000

 
1,239

 
1,959

 
646

Weighted average common shares outstanding:
 
 
 
 
 
 
 
 
 
Basic
40,811,308

 
36,112,286

 
21,537,677

 
14,827,877

 
14,454,288

Diluted
40,811,308

 
36,112,286

 
30,092,017

 
14,827,877

 
14,454,288

    


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

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

Executive Overview
Strategy
Our mission is to grow a profitable exploration and production company for the long-term benefit of our shareholders by focusing on the development of our reserves, continued expansion of our oil and natural gas properties and increase in our production and related cash flow. We intend to accomplish these objectives through the execution of our core strategies, which include:
Develop Acquired Acreage. We will focus on organically growing production through drilling for our own benefit on existing leases and acreage in the exploration licenses with a view towards retaining the majority of working interest in the new wells. This strategy will allow us to maintain operational control, which we believe will translate to long-term benefits;
Increase Production. We plan on increasing oil and gas production through the maintenance, repair and optimization of wells located in the Cook Inlet Basin and development of wells in the Appalachian region of East Tennessee. Our management team will employ the latest available technologies to restore as well as explore and develop our properties;
Expand Our Revenue Stream. We intend on fully exploiting our mid-stream facilities, such as our injection wells and the Kustatan Production Facility, our ability to engage in the commercial disposal of waste generated by oil and gas operations, and our capacity to process third party fluids and natural gas and to offer excess electrical power to net users in the Cook Inlet area; and
Pursue Strategic Acquisitions. We have significantly increased our oil and gas properties through strategic low-cost / high-value acquisitions. Under the same strategy, our management team will continually seek for opportunities that meet our criteria for risk, reward, rate of return, and growth potential. We plan to leverage our management team's expertise to pursue value-creating acquisitions when the opportunities arise, subject to the availability of sufficient capital.
Our management team is focused on obtaining the financial flexibility required to successfully execute these core strategies. During fiscal 2012, through the use of funds provided under our credit facility, we completed the modification and improvements to Rig 34 and are on our way to completing the construction of Rig 35. These accomplishments, although marked with challenges, have bolstered our ability to carry out our onshore and offshore drilling plans. Our ability to deliver successful results and continue enhancing shareholder value have been strengthened as a result of these recent accomplishments.
However, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing current reserves and economically finding, developing and acquiring additional recoverable reserves. We may not be able to find, develop or acquire additional reserves to replace our current and future production at acceptable costs, which could materially adversely affect our business, financial condition and results of operations. We will focus on adding reserves through drilling and well recompletions, as well as the corresponding costs necessary to produce such reserves and will seek to grow our production and our asset base by pursuing both organic growth opportunities and acquisitions of producing oil and natural gas reserves that are suitable for us.

Financial and Operating Results
We continued to utilize funds under our prior credit facility along with other financing sources and operational cash flow to support our capital expenditures for fiscal 2012. For the 12-month period ended April 30, 2012, we reported notable achievements in several key areas. Highlights for the year include:
We completed significant modifications and improvements to Rig 34, allowing the rig to drill in winter conditions while complying with Alaska regulations. The AOGCC inspected and issued final approvals to operate the rig in March 2012. The rig was mobilized to our Kustatan Gas Field to workover the KF-1 well and, at completion of the KF-1 well, mobilized to the Otter Prospect to begin drilling Otter 1.
We successfully mobilized all components of Rig 35 to the Osprey platform. In January 2012 the region

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experienced prolonged near-record cold weather, which caused us to temporarily delay rig assembly efforts on the Osprey platform due to concerns of safety. The cold weather also led to significant generation of ice volume in the Cook Inlet and made shipping and the operation of work-boats impossible. As warmer temperatures moderated the region, we resumed work on the assembly of Rig 35, which in its present state is substantially completed and expected to be fully operational in July 2012.
On April 6, 2012, we issued a new class of Series A Cumulative Preferred Stock to 20 accredited and institutional investors in a private offering exempt from registration under the Securities Act of 1933, as amended. We received gross proceeds of $10 million. These funds were used primarily to workover the KF-1 well and drill the Otter 1 well.
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 $0.3 million work commitment, we will gain the option to convert any part of the licensed area into oil and gas leases.

2013 Outlook
As we head into 2013, with the expected completion of Rig 35, we believe our inventory of recompletion as well as exploration and development projects offers numerous growth opportunities. Our current 2013 capital budget is $50 to 100 million. Nearly all of our budget is expected to be spent on projects in Alaska, with the remaining amount allocated to our Appalachian region. Due to the uncertainty associated with changes in commodity prices, we closely monitor our cost levels and revise our capital budgets based on changes in forecasted cash flows. This means our plan for capital expenditures may change as a result of anticipated changes in the market place. Further, our ability to fully utilize the budget will be dependent on a number of factors including, but not limited to, access to capital, Rig 35 being operational in a timely manner, weather and regulatory approval.             
We expect to fund our 2013 capital budget with funds borrowed under the Apollo Credit Facility, proceeds received from anticipated preferred stock offerings, cash flows from operations and proceeds from potential asset dispositions. We may also access the capital markets as necessary to fund specific drilling programs and continue developing our assets. In the event we are unable to raise additional capital on acceptable terms, we may reduce our capital spending.
    
Results of Operations

Revenues
 
For the Year Ended April 30,
 
2012
 
2011
 
2010
 
$ Value
 
Increase (Decrease)
 
$ Value
 
Increase (Decrease)
 
$ Value
 
(In thousands, except percentages)
Oil revenues:
 
 
 
 
 
 
 
 


Cook Inlet
$
30,566

 
57%
 
$
19,459

 
437%
 
$
3,622

Appalachian region
1,314

 
46
 
901

 
12
 
808

Total
$
31,880

 
57%
 
$
20,360

 
360%
 
$
4,430

Natural gas revenues:


 
 
 


 
 
 


Cook Inlet
$
134

 
(53)%
 
$
286

 
100%
 
$

Appalachian region
479

 
9
 
440

 
18
 
372

Total
$
613

 
(16)%
 
$
726

 
95%
 
$
372

Other revenues:
 
 
 
 
 
 
 
 
 
Cook Inlet
$
1,212

 
61%
 
$
753

 
107%
 
$
363

Appalachian region
1,697

 
69
 
1,003

 
43
 
702

Total
2,909

 
66
 
1,756

 
65
 
1,065

Total revenues
$
35,402

 
55%
 
$
22,842

 
289%
 
$
5,867






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Production
 
For the Year Ended April 30,
 
2012
 
Increase
(Decrease)
 
2011
 
Increase
(Decrease)
 
2010
Oil volume - bbls:
 
 
 
 
 
 
 
 
 
Cook Inlet
325,756

 
28%
 
254,504

 
410%
 
49,901

Appalachian region
16,655

 
17
 
14,292

 
14
 
12,580

Total
342,411

 
27
 
268,796

 
330
 
62,481

Natural gas volume1- mcf:
 
 
 
 
 
 
 
 
 
Cook Inlet
45,985

 
8
 
42,480

 
100
 

Appalachian region
130,609

 
19
 
109,683

 
47
 
74,532

Total
176,594

 
16
 
152,163

 
104
 
74,532

Total production2 - boe
 
 
 
 
 
 
 
 
 
Cook Inlet
333,420

 
27
 
261,584

 
424
 
49,901

Appalachian region
38,423

 
18
 
32,573

 
30
 
25,002

Total
371,843

 
26
 
294,157

 
293
 
74,903

———————
1 
Cook Inlet natural gas volume excludes natural 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.

Pricing
 
For the Year Ended April 30,
 
2012
 
Increase
(Decrease)
 
2011
 
Increase
(Decrease)
 
2010
Average oil sales price - per barrel:
 
 
 
 
 
 
 
 
 
Cook Inlet
$
93.83

 
23%
 
$
76.46

 
5%
 
$
72.58

Appalachian region
78.89

 
25
 
63.04

 
(2)
 
64.25

Total
93.10

 
23
 
75.75

 
7
 
70.90

Average natural gas sales price - per mcf:
 
 
 
 
 
 
 
 
 
Cook Inlet
2.92

 
(57)
 
6.73

 
100
 

Appalachian region
3.66

 
(9)
 
4.01

 
(20)
 
4.99

Total
3.47

 
(27)
 
4.77

 
(4)
 
4.99

Crude Oil Prices
All of our crude 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 2012 were 23% above 2011. Crude oil prices realized in 2012 averaged $93.10 per barrel, compared with $75.75 per barrel in 2011.
Natural Gas Prices
Natural gas is subject to price variances based on local supply and demand conditions. The majority of our natural gas sales contracts are indexed to prevailing local market prices. Average realized prices decreased 27% in 2012 compared to 2011.
Crude Oil Revenues
2012 vs. 2011. During 2012, crude oil revenues totaled $31.9 million, 57% higher than 2011, driven by a 23% increase in average realized prices and a 27% increase in production. Crude oil represented 98% of our 2012 oil and gas revenues and 92% of our equivalent production, compared to 97% and 91%, respectively, in the prior year. Higher realized prices contributed $5.3 million to the increase in full-year oil revenues, while higher production volumes added another $6.2 million.

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Production increased 73,615 bbls, driven by a 71,252 bbls increase in the Cook Inlet region, with the Appalachian region contributing 2,363 bbls to total production for the year. The significant production increase in the Cook Inlet region resulted from bringing wells at our Redoubt Unit online.
2011 vs. 2010. During 2011, crude oil revenues increased $15.9 million to $20.4 million, driven by a 330% increase in production and a 7% increase in average realized prices. Production increased 206,315 bbls with approximately 99% of the increase contributed by increased production in the Cook Inlet region. Higher realized prices contributed $0.2 million to the increase in full-year oil revenues, while higher production volumes added another $15.7 million. The significant production increase in the Cook Inlet region resulted from a full year of production in fiscal 2011 subsequent to the mid-year fiscal 2010 acquisition of CIE.
Natural Gas Revenues
2012 vs. 2011. Natural gas revenues totaled $0.6 million, $0.1 million lower than the 2011 total of $0.7 million, driven by a 27% decrease in average realized prices, offset by a 16% increase in production. Natural gas represented 2% of our 2012 oil and gas revenues and 8% of our equivalent production, compared to 3% and 9%, respectively, in the prior year.
2011 vs. 2010. Natural gas revenues totaled $0.7 million, reflecting a $0.3 million increase from the 2010 total of $0.4 million. Production increased 77,631 Mcf to 152,163 Mcf with approximately 45% of the increase contributed by increased production in the Appalachian region and 55% in the Cook Inlet region. Higher production volume contributed $0.4 million to the increase in full-year natural gas revenues, offset by $0.1 million due to lower realized prices.
Other Revenues
2012 vs. 2011. Other revenues primarily represent revenues generated from contracts for plugging, drilling, 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, other revenues totaled $2.9 million, driven by a 69% increase in plugging activities in the Appalachian region and a 61% increase in facility rentals and other miscellaneous income in the Cook Inlet region.
2011 vs. 2010. Other revenues increased 65% to $1.8 million during 2011, reflecting a 107% increase in facility rentals in the Cook Inlet region combined with a 43% increase in plugging and drilling activities in the Appalachian 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,
 
2012
 
2011
 
2010
 
2012
 
2011
 
2010
 
(In thousands)
 
(Per boe)
 
 
 
 
 
 
 
405,799
 
327,712
 
88,030
Oil and gas operating
$
14,861

 
$
9,703

 
$
2,738

 
$
36.62

 
$
29.61

 
$
31.10

Cost of other revenues
926

 
808

 
755

 
NM

 
NM

 
NM

General and administrative
29,718

 
14,555

 
10,263

 
NM

 
NM

 
NM

Exploration expenses
1,241

 

 

 
NM

 

 

Depreciation, depletion and amortization
13,310

 
10,961

 
3,110

 
32.80

 
33.45

 
35.33

Accretion of asset retirement obligation
1,072

 
1,407

 
315

 
NM

 
NM

 
NM

Other operating expense (income), net
(641
)
 

 

 
NM

 
NM

 
NM

Total costs and expenses
$
60,487

 
$
37,434

 
$
17,181

 
$
149.06

 
$
114.23

 
$
195.17

———————
NM - Not Meaningful

Oil and Gas Operating Costs
2012 vs. 2011 Oil and gas operating costs increased $5.2 million from 2011, or 53%. On a per-unit cost basis, oil and gas operating costs increased $7.01 per unit due to higher costs associated with returning the Osprey platform and Kustatan production facility to operational status.

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2011 vs. 2010 Oil and gas operating costs increased $7 million from 2010, or 254%, as a result of increased activities in the Cook Inlet region. Costs associated with the work to restore nonproductive wells to producing status increased significantly, driven primarily by a 293% increase in total production with direct labor and contract services contributing an additional $3.03 per unit of production.
Cost of Other Revenues
Our business is primarily focused on exploration and production activities. The cost of other revenues represent costs of services to third parties as a result of excess capacity, and are derived from the direct labor costs of employees associated with these services, as well as costs associated with equipment, parts and repairs.
 
For the Year Ended April 30,
 
2012
 
Increase (Decrease)
 
2011
 
Increase (Decrease)
 
2010
 
(In thousands, except percentages)
 
 
 
 
 
 
 
 
 
 
Direct labor
$
677

 
57%
 
$
430

 
(18)%
 
$
527

Equipments

 
(100)
 
41

 
(61)
 
104

Repairs
89

 
31
 
68

 
(45)
 
124

Others
160

 
(41)
 
269

 
100
 

Total
$
926

 
15%
 
$
808

 
7%
 
$
755

2012 vs. 2011 During 2012, cost of other revenues increased 15% to $0.9 million. A substantial portion of this increase is related to labor costs associated with services provided under the U.S. Department of Interior contract for plugging abandoned wells located in the Big South Fork area in Tennessee and Kentucky.  
2011 vs. 2010 During 2011, cost of other revenues increased 7% to $0.8 million. We drilled three wells in 2011 and also entered into the contract with the U.S. Department of Interior for plugging abandoned wells located in the Big South Fork area in Tennessee and Kentucky. During 2010, we drilled 10 wells for Atlas Energy, and in preparation for the Atlas Energy drilling contract we spent significant time and expense maintaining and repairing our drilling equipment in fiscal 2010 which contributed to the costs for that year.
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,
 
2012
 
Increase (Decrease)
 
2011
 
Increase (Decrease)
 
2010
 
(In thousands, except percentages)
 
 
 
 
 
 
 
 
 
 
Salaries
$
3,330

 
29%
 
$
2,580

 
96%
 
$
1,317

Professional fees
4,561

 
36
 
3,347

 
11
 
3,023

Travel
1,693

 
115
 
786

 
192
 
269

Employee benefits
3,824

 
115
 
1,780

 
21
 
1,471

Stock-based compensation
14,072

 
175
 
5,126

 
52
 
3,375

Other
2,238

 
139
 
936

 
16
 
808

Total
$
29,718

 
104%
 
$
14,555

 
42%
 
$
10,263

2012 vs. 2011 G&A expenses increased $15.2 million from 2011, or 104%. As we continue to recruit and retain quality employees and build our professional staff, salaries and related employee benefits rose 29% and 115% respectively over the prior year. Professional fees increased 36% from 2011 due to an increase in legal fees and fees related to Sarbanes-Oxley implementation, internal audit and tax services. Our increase in travel expenses is related to evaluating financing alternatives, securing our new credit facility, raising equity and investor relations. In 2012, we granted equity awards for an additional 4,345,000 shares our common stock in exchange for certain employee and non-employee services provided to the Company resulting in a 171% increase in non-cash compensation expense. The 159% increase in other expenses primarily relates to increased cost of our new corporate office space, trade shows and exhibits and general liability insurance.

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2011 vs. 2010 During 2011, G&A expenses increased $4.3 million from 2010, or 42%. A substantial portion of the increase is related to non-cash compensation where we incurred expenses of $5.2 million. We also incurred an additional $2.1 million in salaries, travel and employee benefits.
Exploration expense
2012 vs. 2011 Exploration expense consists of abandonments of drilling locations, dry hole costs, delay rentals, geological and geophysical costs, and the impairment, amortization, and abandonment associated with leases on unproved properties. During 2012, we incurred $0.3 million related to the impairment of certain unproved properties and $0.9 million in seismic and dry hole costs incurred in the Cook Inlet region. These expenses were not incurred in previous periods.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization (“DD&A”) expenses include the depreciation, depletion and amortization of acquisition costs and equipment costs. Depletion is calculated on a unit-of-production basis.
 
For the Year Ended April 30,
 
2012
 
2011
 
2010
 
2012
 
2011
 
2010
 
(In thousands)
 
(Per boe)
Depletion:
 
 
 
 
 
 
 
 
 
 
 
Cook Inlet region
$
11,790

 
$
9,703

 
$
2,113

 
$
29.42

 
$
29.86

 
$
22.12

Appalachian region
747

 
773

 
506

 
19.45

 
23.73

 
20.24

 
12,537

 
10,476

 
2,619

 
28.55

 
29.31

 
21.73

Depreciation:
 
 
 
 
 
 


 
 
 
 
Cook Inlet region
169

 
2

 

 
NM

 
NM

 
NM

Appalachian region
604

 
483

 
491

 
NM

 
NM

 
NM

 
773

 
485

 
491

 
1.76

 
1.36

 
4.07

Total DD&A
$
13,310

 
$
10,961

 
$
3,110

 
$
30.31

 
$
30.66

 
$
25.80

———————
NM - Not Meaningful
2012 vs. 2011 Recurring successful-efforts depletion expense increased $2.1 million on an absolute dollar basis: $2.2 million from additional production, offset by $0.1 million on lower rates. Our successful-efforts depletion rate decreased 3% to $28.55 per boe as our historical cost basis remained relatively constant year over year. The decline in the West MacArthur River Unit rate per boe is due to a positive adjustment in the reserve base resulting from our April 30, 2011 reserve engineering report estimate. Other asset depreciation increased $0.3 million over 2011 primarily on slightly higher asset balances.
2011 vs. 2010 Recurring successful-efforts depletion expense increased $7.9 million on an absolute dollar basis: $7.6 million from additional production and $0.2 million on higher rates. Our successful-efforts depletion rate increased 35% to $29.31 per boe due to significant increases in production resulting from a full year of operations in the Cook Inlet region.

Other Income and Expense
The following table shows the components of other income and expense for the fiscal years indicated.
 
 
 
For the Year Ended April 30,
 
2012
 
Increase (Decrease)
 
2011
 
Increase (Decrease)
 
2010
 
(In thousands, except percentages)
Interest expense, net of interest income
$
(1,837
)
 
97%
 
$
(934
)
 
618%
 
$
(130
)
Loss on derivative, net
(2,832
)
 
181
 
(1,008
)
 
(92)
 
(13,299
)
Gain on acquisitions

 
NM
 
6,910

 
(99)
 
461,112

Other income (expense), net
58

 
NM
 
(537
)
 
NM
 
(751
)
Total
$
(4,611
)
 

 
$
4,431

 

 
$
446,932

———————
NM - Not Meaningful
Interest Expense

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2012 vs. 2011 Interest expense, net of interest income increased $0.9 million from 2011, or 97%, driven primarily by a $0.6 million increase in amortization of deferred financing costs. The Company capitalized $3.7 million of interest in equipment and oil and gas properties as of April 30, 2012.
2011 vs. 2010 During 2011, net interest expense increased $0.8 million from 2010, or 618%, reflecting a $0.5 million increase in amortization charges from deferred financing costs and a $0.3 million increase in interest expense associated with our 6% convertible note program.
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.
Changes in commodity prices typically account for a significant portion of our net gain (loss) on derivative transactions.
2012 vs. 2011 During 2012, unrealized loss on derivatives totaled $3.4 million, offset by a net realized gain of $0.6 million. 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 million of the total net loss on derivatives, with the remaining portion related to changes in the fair value of warrants.
2011 vs. 2010 Net loss on derivatives decreased $12.3 million, or 92% from 2010. During 2010, we recorded a non-cash loss of $13.3 million as a result of changes to certain warrant agreements that forfeited the option to purchase an aggregate amount of 3,300,000 shares of our common stock. The removal of these warrants resulted in our recognition of the $13.3 million year over year loss. As of April 30, 2011, we had one warrant agreement outstanding with the option to purchase 817,055 shares of our common stock.
Gain on Acquisitions
During 2011, we recorded a gain of $6.9 million 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 million with $6.8 million 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.  
    
Liquidity and Capital Resources

Our cash flows, both in the short-term and long-term, are impacted by highly volatile oil and natural gas prices. Significant deterioration in commodity prices negatively impacts revenues, earnings and cash flows, capital spending, and potentially our liquidity. Sales volumes and costs also impact cash flows; however, these historically have not been as volatile or as impactful as commodity prices in the short-term.
Our long-term cash flows are highly dependent on our success in efficiently developing current reserves and economically finding, developing and acquiring additional recoverable reserves. Cash investments are required continuously to fund exploration and development projects and acquisitions, which are necessary to offset the inherent declines in production and proven reserves. We may not be able to find, develop or acquire additional reserves to replace our current and future production at acceptable costs, which could materially adversely affect our future liquidity. For a discussion of risk factors related to our business and operations, please see Part I, Item 1A – Risk Factors, of this Form 10-K.
We may elect to utilize excess borrowing capacity, access to both debt and equity capital markets, or proceeds from the occasional sale of nonstrategic assets to supplement our liquidity and capital resource needs.
In fiscal 2012, we experienced operating losses and had a working capital deficit as of April 30, 2012. We anticipate that our operating expenses will continue to increase as we fully develop our assets in the Cook Inlet and Appalachian regions. Although we expect an increase in our revenues to come from these development activities, we will continue depleting our cash resources to fund operating expenses until such time as we are able to significantly increase our revenues above costs.
We believe that the liquidity and capital resource alternatives available to us, combined with internally generated cash flows and other potential sources of funds, will be adequate to fund our short-term and long-term operations, including our capital budget, repayment of debt maturities, and any amount that may ultimately be paid in connection with contingencies; however, we are restricted under our new Apollo Investment Corporation credit facility to commit to certain financial requirements and provisions as described in Note 16 - Subsequent Events in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

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Sources and Uses of Cash
The following table presents the sources and uses of our cash and cash equivalents for the years presented:
 
For the Year Ended April 30,
 
2012
 
2011
 
2010
 
(In thousands)
Sources of cash and cash equivalents:
 
 
 
 
 
Net cash provided (used) by operating activities
$
6,901

 
$
7,734

 
$
(730
)
Proceeds from borrowings, net of debt acquisition costs
28,754

 
5,500

 
4,957

Proceeds from preferred stock issuance
10,000

 

 

Proceeds from common stock activities
1,383

 
1,266

 
9,928

Release of restricted cash

 

 
1,796

 
47,038

 
14,500

 
15,951

Uses of cash and cash equivalents:
 
 
 
 
 
Capital expenditures
(33,967
)
 
(11,315
)
 
(4,903
)
Payments on credit facilities
(8,764
)
 
(3,500
)
 
(3,763
)
Acquisition of Alaska business

 

 
(4,337
)
Restricted cash
(1,895
)
 
(1,121
)
 

 
(44,626
)
 
(15,936
)
 
(13,003
)
 
 
 
 
 
 
Increase (decrease) in cash and cash equivalents
$
2,412

 
$
(1,436
)
 
$
2,948


Net Cash Provided by Operating Activities
Our sources of capital and liquidity are partially supplemented by cash flows from operations, both in the short-term and long-term. These cash flows, however, are highly impacted by volatility in oil and natural gas prices. The factors in determining operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, asset retirement obligation ("ARO") accretion, non-cash compensation and deferred income tax expense, which affect earnings but do not affect cash flows.
Net cash provided by operating activities for 2012 totaled $6.9 million, down $0.8 million from 2011. Despite the $12.6 million increase in revenues, driven by a combination of increases in oil prices and increases in volumes sold, operating expenses continued to rise at a higher rate than cash flows from operations. During 2012, oil and gas operating costs increased $5.2 million, with transportation, labor and contract services contributing all of the rise in cost. G&A expenses, excluding non-cash items, contributed another $6.2 million to the reduction in operating cash flows.
For a detailed discussion of commodity prices, production and expenses, please see “Results of Operations” in this Item 7. For additional detail on the changes in operating assets and liabilities and the non-cash expenses which do not impact net cash provided by operating activities, please see the Statement of Consolidated Cash Flows in the Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
Proceeds from Credit Facilities and Stock Related Issuances
During 2012, borrowings under the credit facilities totaled $28.8 million, net of $2.1 million in financing costs. The proceeds were used to finance all of our capital projects on-going in the Cook Inlet region.
On April 6, 2012, we issued 100,000 shares of Series A Cumulative Preferred Stock for total proceeds of $10 million, before expenses. The proceeds were used to supplement our projects in the Cook Inlet region. For additional information on the preferred stock offering, please see Note 3 - Derivative Instruments and Note 8 - Capital Stock in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
During 2012, we also received $1.4 million in proceeds from the exercise of equity rights.
Repayment of Debt
We made payments in an aggregate amount of $8.8 million to our lenders during fiscal 2012, including the termination of the Plains Capital line of credit. For information on this line of credit, please see Note 4 - Debt in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K. In May 2012, we paid another $2.2 million in mandatory payments, drawn by the lenders as part of our monthly requirement to make payment on the outstanding obligations equal to

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90% of our consolidated net revenues. On June 29, 2012, the Guggenheim credit facility was paid in full. For additional information on the repayment, please see Note 16 - Subsequent Events in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
Capital Expenditures
We use a combination of operating cash flows, borrowings under credit facilities and, from time to time, issues of debt or common stock to fund significant capital projects. Due to the volatility in oil and natural gas prices, our capital expenditure budgets, both in the short-term and long-term, are adjusted on a frequent basis to reflect changes in forecasted operating cash flows, market trends in drilling and acquisition costs, and production projections.
During 2012, we placed significant emphasis on rig construction and modification activities. Total spending on capital projects was up 200% from 2011, primarily on the construction of Rig 35 and modification to Rig 34. We spent a portion of the budget on recompletion activities and brought RU-1 and RU-7 on-line during the first quarter of the year. Some of the costs were spent on exploratory projects, which were proved unsuccessful in both the Cook Inlet and Appalachian regions.

Liquidity
Cash and Cash Equivalents
As of April 30, 2012, we had $6 million in cash and cash equivalents.
Debt
Outstanding debt consisted of $24.1 million in borrowings under the Guggenheim credit facility, which is classified as current on the accompanying consolidated balance sheet of April 30, 2012. The Guggenheim credit facility was paid in full on June 29, 2012.
Available Credit Facilities
We had $10.9 million in borrowing capacity under our Guggenheim credit facility as of April 30, 2012.
On June 29, 2012, we closed a new credit facility with Apollo Investment Corporation and the Guggenheim credit facility was repaid in full. For a full description of terms of the Apollo Investment Corporation credit facility, see Note 16 - Subsequent Events in the Notes to Consolidated Statements set forth in Part IV, Item 15 of this Form 10-K.

Contractual Obligations
The following table summarizes our contractual obligations as of April 30, 2012. For additional information regarding these obligations, please see Note 4 - Debt and Note 6 - 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
 
2013
 
2014-2015
 
2016-2017
 
and after
 
 
(In thousands)
Contractual obligations:(a)
 
 
 
 
 
 
 
 
 
 
 
Debt, at face value
Note 4
 
$
24,130

 
$
24,130

 
$

 
$

 
$

Interest payments
Note 4
 
3,163

 
2,292