News Column

MILLER ENERGY RESOURCES, INC. - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

July 14, 2014

This discussion summarizes the significant factors affecting the consolidated financial statements, financial condition, liquidity, and cash flows of Miller Energy Resources, Inc., for the fiscal years ended April 30, 2014, 2013 and 2012. The following discussion and analysis should be read in conjunction with the consolidated financial statements and the notes included elsewhere in this Form 10-K. Executive Overview We are an independent exploration and production company that utilizes seismic data and other technologies for geophysical exploration, development and operation of oil and gas wells in the Appalachian region of east Tennessee and in southcentral Alaska. Occasionally, during times of excess capacity, we offer these services on a contract basis to third-party customers primarily engaged in our core competency - oil and natural gas exploration and production.



Strategy

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



production through drilling for our own benefit on existing leases and

acreage in the exploration licenses with a view towards retaining the majority of working interest in the new wells. This strategy will allow



us to maintain operational control, which we believe will translate to

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



Expand Our Revenue Stream. We intend to fully exploit our mid-stream

facilities, such as our injection wells and the Kustatan Production

Facility, our ability to engage in the commercial disposal of waste generated by oil and gas operations, our capacity to process third party fluids and natural gas and, when available, to offer excess electrical power to net users in the Cook Inlet region; and Pursue Strategic Acquisitions. We have significantly increased our oil and gas properties through strategic low-cost / high-value



acquisitions. Under the same strategy, our management team continues to

seek opportunities that meet our criteria for risk, reward, rate of

return, and growth potential. We pursue value-creating acquisitions

when the opportunities arise, subject to the availability of sufficient

capital. Our management team is focused on maintaining the financial flexibility, assembling the right complement of personnel, and procuring the equipment required to successfully execute these core strategies. Our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing current reserves and economically finding, developing and acquiring additional recoverable reserves. We may not be able to find, develop or acquire additional reserves to replace our current and future production at acceptable costs, which could materially adversely affect our business, financial condition and results of operations. We will focus on adding reserves through new drilling, well workovers and recompletions of our current wells. Additionally, we will seek to grow our production and our asset base by pursuing both organic growth opportunities and acquisitions of producing oil and natural gas reserves that are suitable for us. Financial and Operating Results We continued to utilize operational cash flow along with funds from our credit facilities and funds raised from sales of our Series C Preferred Stock and Series D Preferred Stock, including "at-the-market" public offerings to support our capital expenditures during fiscal 2014. For the fiscal year ended April 30, 2014, we reported notable achievements in several key areas. Highlights for fiscal 2014 and early fiscal 2015 include: Starting May 1, 2013, and periodically during the fiscal year, we issued 924,968 shares of our Series C Preferred Stock in "at-the-market" offerings pursuant to the October 12, 2012 At Market Issuance Sales Agreement ("Series C ATM Agreement") with MLV and Co. LLC ("MLV") and a prospectus supplement dated October 12, 2012 (issued 39

-------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data) under our existing S-3 registration statement, filed with the SEC as file number 333-183750). These sales were made at an average price on the date of such sale ranging from $21.48 to $26.71 per share. We received net proceeds of $20,202 in connection with these sales. On May 10, 2013, we issued 500,000 shares of our Series C Preferred Stock in a "follow-on" best efforts public offering. The shares were registered in the prospectus supplement dated May 7, 2013 and we received net proceeds of $10,320. Effective May 15, 2013, we entered into a new commercial gas sales



agreement in the Cook Inlet region with Chugach Electric Associations,

Inc., Alaska's largest electric utility. Contractual gas sales commenced during the month of May and have continued throughout the period. We have primarily delivered gas on the new agreement with production from the RU-3 and RU-4A wells in the Redoubt Shoals field. On June 19, 2013, we began drilling our Sword #1 well from our West McArthur River Production Facility in the Cook Inlet region. The Sword



#1 well was completed as an extended reach well drilled directionally

to approximately 19,000 feet in an adjacent fault block to the West McArthur River Field. The 3D seismic data shows a faulted four-way closure and an estimated 240-acre structure with an estimated ultimate recovery ("EUR") of approximately 800,000 barrels of oil from the Sword #1 well.



On June 20, 2013, we brought a new oil well, RU-2A, into production.

This well is a sidetrack of a previously producing oil well, RU-2. After clearing the well of drilling fluids from the sidetrack, a subsequent well test showed an initial gross production of 1,281



barrels of oil per day with a water cut of 19%. The rate of production

has averaged 926 barrels of oil per day through April 30, 2014.

On July 2, 2013, we issued 335,000 shares of our Series C Preferred

Stock in a "follow-on" best efforts public offering. The shares were registered in the prospectus supplement dated June 27, 2013 and we received net proceeds of $6,655.



On July 22, 2013, we announced that our Board of Directors appointed

David M. Hall to Chief Operating Officer ("COO"). Mr. Hall has been the

Chief Executive Officer of our wholly-owned Alaskan operating

subsidiary, CIE, since 2009 and will continue in that capacity. In his

new role as COO, Mr. Hall will oversee our drilling operations in both Alaska and Tennessee.



On July 25, 2013, we elected a new independent director, Marceau

Schlumberger, to our board of Directors. Mr. Schlumberger has nearly

twenty years of investment banking experience, including international

and domestic mergers and acquisitions, restructuring, strategic analysis, and financial experience. On August 5, 2013, we entered into the Sixth Amendment to our credit facility with Apollo (the "Prior Credit Facility") which allowed us to borrow an additional $20,000 at a temporarily reduced interest rate of 9%. For additional information on the Sixth Amendment and the Prior Credit Facility, refer to Note 4 - Debt. On August 17, 2013, we successfully brought our RU-1A oil well online. The well is a sidetrack of a previously producing oil well, RU-1. The newly completed well displayed an initial gross production rate of 700 barrels of oil per day and an approximate water cut of 5%. The rate of production has averaged 476 barrels of oil per day through April 30, 2014. On September 30, 2013, we completed our initial public offering of our Series D Preferred Stock, issuing 1,000,000 shares at $25.00 per share with net proceeds of $23,125.



On September 30, 2013, we completed negotiations for a multi-year gas

sales agreement with Chugach Electric Association, Inc., which expanded

upon the short-term contract signed in May. The contract was submitted

to the Regulatory Commission of Alaska and was approved on November 25,

2013.

On October 12, 2013, we brought our RU-5B oil well online. The rate of

production has averaged 130 barrels of oil per day through April 30, 2014. On October 15, 2013, we brought our Brimstone H-1 well online in



Tennessee. Similar to our other horizontal wells, this well requires

additional testing. At April 30, 2014, the well had produced 2,503 net

barrels of oil.

On October 23, 2013, we reached total depth on our Sword #1 well. On

November 20, 2013, we brought the well online. Its initial gross

production rate was 883 barrels of oil per day. At April 30, 2014, the

well was producing approximately 403 barrels of oil per day.



On October 24, 2013, we received an Underground Injection Control

("UIC") permit from the EPA. We intend to re-inject gas into a vertical

well adjacent to our CPP H-1 horizontal well in Tennessee to maintain

reservoir pressure and hopefully increase production.

On October 31, 2013, we completed our workover of the RU-D1 disposal

well to prepare for additional drilling activity on the Osprey platform. 40

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On October 31, 2013, the Susitna #2 License expired. Prior to

expiration, we received confirmation from the State of Alaska that we

had met our work commitment under the Susitna #2 License and were

eligible to convert acreage under the license to leases. We applied for

conversion and requested issuance of the proposed leases in three

groups. The first group of leases consisting of a total of 47,000 acres

were issued with an effective date of November 1, 2013. The second and

third group of leases consisting of a total of 120,900 acres were issued with an effective date of January 1, 2014. Upon award, an annual rental fee of $3.00 per acre was paid to the State of Alaska. The annual rental fee for all three groups of leases totals $504.



On November 22, 2013, we entered into an agreement to acquire the North

Fork Properties in the Cook Inlet region and the Anchor Point Equity

for $64,975, subject to customary adjustments, with approximately

$5,000 to be paid in our Series D Preferred Stock (213,586 shares). Beginning November 26, 2013 and periodically thereafter, we issued 70,448 shares of our Series D Preferred Stock in "at-the-market" offerings pursuant to the October 17, 2013 At Market Issuance Sales Agreement ("Series D ATM Agreement") and a prospectus supplement dated



October 17, 2013 (issued under our existing S-3 registration statement

filed with the SEC as file number 333-183750). These sales were made at

an average price ranging from $23.95 to $24.38 per share. We received

net proceeds of $1,654 in connection with these sales. On November 28, 2013, we spudded our WMRU-8 oil well from our West McArthur River Production Facility. WMRU-8 was drilled as a



directional well into a separate fault block to the main producing

structure in the West McArthur River Field. The well reached a total

depth of 15,536 feet on February 12, 2014 after successfully drilling

and logging the Jurassic and West Forelands secondary targets.

On February 3, 2014, we entered into a new loan agreement with Apollo,

as administrative agent, which set forth the terms of the Second Lien

Credit Facility. Proceeds from the new $175,000 term credit facility

were used to repay the previously existing credit facility, repay all obligations to Miller Energy Income 2009-A, LP, acquire the North Fork Properties and provide working capital.



On February 6, 2014, we entered into the Trans-Foreland Pipeline

Development Agreement with Tesoro Alaska Company and Trans-Foreland

Pipeline Company, LLC. This agreement allows for the construction of

the Trans-Foreland Pipeline to connect our Kustatan Production Facility

on the west side of the Cook Inlet to the Kenai Pipe Line Company tank farm on the east side. Completion of the pipeline would provide numerous advantages to us, including reduced transportation cost and delays.



On February 12, 2014, our Board of Directors appointed John M. Brawley

as our Chief Financial Officer. In addition, the Board of Directors

approved a change in the title of David J. Voyticky to President, as he previously held the title of President and Acting Chief Financial Officer.



On March 31, 2014, we purchased ten wells and associated infrastructure

in Tennessee. On April 17, 2014, we held our annual meeting of shareholders at which



Bob G. Gower, Joseph T. Leary and William B. Richardson were elected to

our Board of Directors as three new independent directors. The Board

now consists of eight directors, six of whom are independent.

On April 17, 2014, we received a construction permit from the State of

Tennessee for the construction of a gas processing facility. Once

operational, the facility will allow us to process high BTU gas, strip

the liquids, and produce the lower BTU gas into the sales line without

blending. The operational target date is July 2014.

On May 8, 2014, we entered into the Merger Agreement with Savant

subject to due diligence and regulatory approval for $9,000. Savant

currently owns, and we would acquire as a result of this merger, a

67.5% working interest in the Badami Unit and 100% ownership in certain

nearby leases. ASRC Exploration, LLC owns the remaining 32.5% working

interest in the Badami Unit. In additional to the working interest in

the Badami Unit and the leases, we would acquire certain midstream

assets located in the North Slope. We expect the transaction to close by December 2014, following regulatory approval.



On June 2, 2014 we entered into a credit agreement, among the Company,

as borrower, and KeyBank National Association, as administrative agent.

In addition to KeyBank, the syndicate includes CIT Finance LLC, Mutual

of Omaha Bank and OneWest Bank N.A. The First Lien Loan Agreement

provides for a $250,000 senior secured, reserve-based revolving credit

facility $60,000 of which was made available to us on the closing date.

Amounts outstanding under the First Lien RBL are priced on a sliding

scale, based on LIBOR plus 300 to 400 basis points, depending upon the

level of borrowing. We drew $20,000 on the closing date under the First

Lien RBL to provide working capital for development drilling in Alaska. On June 24, 2014, we drew an additional $10,000 under the First Lien RBL to provide working capital for development drilling in Alaska. On June 24, 2014, we received the proceeds of Alaska production credits

totaling $21,837 from the State of Alaska. 41

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On July 4, 2014, we entered into a Purchase and Sale Agreement with

Teras Oilfield Support Limited ("Teras") for the right to purchase the

Glacier Drilling Rig #1, a Mesa 1000 carrier-mounted land drilling rig

(the "Glacier Rig"), and related equipment (the "Glacier PSA"). The Glacier PSA is dated as of July 3, 2014, but was signed by Teras the following day. A payment of $700 was required in connection with the execution and delivery of the Glacier PSA. An additional payment of $6,300 will be due if the sale is finalized. Fiscal 2015 Outlook As we head into fiscal 2015, we believe our inventory of recompletion, workovers, and exploration and development projects offers numerous growth opportunities. Subsequent to April 30, 2014, we have continued our onshore and offshore drilling programs. Since the year end, we have brought the WMRU-2B oil well online and have begun drilling the West Foreland #3 gas well. We have also received the second commingling permit for our Sword-1 well, with all three zones currently producing. Following the West Foreland #3 well, we plan to drill the nearby Sabre prospect. The Sabre-1 well will be drilled in the fall, following completion of upgrades to the newly acquired Rig 36. On the Osprey platform we are continuing to drill the RU-9 South step-out well using Rig 35 and expect to complete the well during the summer of 2014. Following successful completion of the well, we will assess the next development activity on the Osprey platform and plan to drill our RU-12 grassroots oil well located in the Northern Fault. On the east side of the Cook Inlet, we also have several development projects at North Fork, which we expect will also contribute to production in fiscal 2015. Beyond our existing assets, on May 14, 2014 we announced our intent to acquire Savant, subject to due diligence and regulatory approval, for $9,000 in cash. Savant would become a wholly-owned subsidiary of Miller. Through Savant, Miller would own a 67.5% working interest in the Badami Unit, with ASRC Exploration, LLC remaining as a 32.5% working interest partner. Miller would also obtain a 100% working interest in nearby exploration leases. As of May 2014, these assets would add approximately 600 bopd net of current production and ownership of midstream assets located in the North Slope with a design capacity of 38,500 bopd and 50 miles of pipeline. We are currently evaluating development plans and opportunities for joint ventures in the Badami Unit. No assurance can be made regarding the success of these development and recompletion efforts. Our current 2015 capital budget is approximately $200,000 and excludes potential development activities associated with the pending Savant acquisition. The majority of this budget is expected to be spent on projects in Cook Inlet, Alaska. Due to the uncertainty associated with changes in commodity prices and production, 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 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, rig availability, access to capital, weather and regulatory approval. On June 2, 2014, we entered into the First Lien RBL contemplated by the Second Lien Credit Facility, with an initial borrowing base of $60,000. At closing we drew $20,000 and on June 24, 2014 we drew an additional $10,000. The remaining availability under the First Lien RBL was $30,000 as of July 7, 2014. As reserves grow, the borrowing base may be adjusted to provide additional capital to fund our development program. We note that the borrowing base of our First Lien RBL is calculated at the discretion of the lenders based on our proved reserves, commodity prices, total debt and other factors at their sole discretion. As such, it is possible our borrowing base could be reduced in the future. On June 24, 2014, we received proceeds of Alaska production credits totaling $21,837 from the State of Alaska. Additionally, following our year end, we entered into a capital lease for the newly purchased Rig 36, for a total of $3,250 which can be expanded up to $5,000, as we upgrade Rig 36. Effective as of July 4, 2014, we entered into a Purchase and Sale Agreement with Teras which grants us the right to purchase the Glacier Rig and the Glacier PSA. The Glacier PSA is dated as of July 3, 2014, but was signed by Teras the following day. A payment of $700 was required in connection with the execution and delivery of the Glacier PSA, which we are entitled to have refunded if we fail to close by August 8, 2014, if it should be determined that Teras lacks clear title to the Glacier Rig, there are liens or encumbrances (other than immaterial defects in title or liens to which we consented) or if the Glacier Rig is affected by a significant casualty prior to closing. An additional payment of $6,300 will be due if the sale is finalized. We believe that we will be able 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 with State of Alaska production credits, potential joint ventures, and through the debt, equity and preferred equity capital markets. Although we have the ability to sell our Series C and Series D Preferred Stock in additional "at-the-market" offerings during fiscal 2015, subject to certain limits under our First Lien RBL, we cannot guarantee that market conditions will continue 42 -------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data) to permit such sales at prices we would find acceptable. If that occurred, cash generated from those offerings would cease. In the event we are unable to raise additional capital on acceptable terms, we may reduce our capital spending. 43 -------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data) Results of Operations Revenues For the Year Ended April 30, 2014 % Variance 2013 % Variance 2012 Oil sales: Cook Inlet $ 62,018 122 % $ 27,891 (9 )% $ 30,566 Appalachian region 2,482 60 1,556 18 1,314 Total $ 64,500 119 $ 29,447 (8 ) $ 31,880 Natural gas sales: Cook Inlet $ 4,588 11,090 $ 41 (69 ) $ 134 Appalachian region 381 (11 ) 427 (11 ) 479 Total $ 4,969 962 $ 468 (24 ) $ 613 Other: Cook Inlet $ 379 (90 ) $ 3,950 226 $ 1,212 Appalachian region 710 (24 ) 936 (45 ) 1,697 Total $ 1,089 (78 ) $ 4,886 68 $ 2,909 Total revenues $ 70,558 103 % $ 34,801 (2 )% $ 35,402 Net Production For the Year Ended April 30, 2014 % Variance 2013 % Variance 2012 Oil volume - bbls: Cook Inlet 659,188 139 % 275,658 (15 )% 325,756 Appalachian region 25,513 29 19,825 19 16,655 Total 684,701 132 295,483 (14 )



342,411

Natural gas volume1- mcf: Cook Inlet 682,831 9,004 7,500 (84 ) 45,985 Appalachian region 110,876 (11 ) 125,238 (4 ) 130,609 Total 793,707 498 132,738 (25 ) 176,594 Total production2 - boe: Cook Inlet 772,993 179 276,908 (17 ) 333,420 Appalachian region 43,993 8 40,698 6 38,423 Total 816,986 157 % 317,606 (15 )% 371,843 -------



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

gas. 2 These figures show production on a boe basis in which natural gas is



converted to an equivalent barrel of oil based on a 6:1 energy equivalent

ratio. This ratio is not reflective of the current price ratio between the

two products. 44

-------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data) Pricing For the Year Ended April 30, 2014 % Variance 2013 % Variance 2012 Average oil sales price - per barrel: Cook Inlet $ 101.20 (1 )% $ 102.74 9 % $ 93.83 Appalachian region 92.73 10 83.92 6 78.89 Total 100.85 (1 ) 101.53 9 93.10 Average natural gas sales price - per mcf: Cook Inlet 6.72 68 3.99 37 2.92 Appalachian region 3.43 1 3.41 (7 ) 3.66 Total 6.26 78 3.52 1 3.47 Oil Prices All of our oil production is sold at prevailing market prices, which are subject to fluctuations driven by market factors outside our control. As volatility increases in response to the rise in global demand for oil combined with economic uncertainty, prices will continue to experience volatility at unpredictable levels. Prices received for crude oil in fiscal 2014 were 1% below fiscal 2013, decreasing from an average of $101.53 per bbl in 2013 to $100.85 per bbl in 2014. 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. During fiscal 2014, realized natural gas prices averaged $6.26 per mcf, compared with $3.52 per mcf for the same period in the prior year. The increase in the average realized gas prices primarily resulted from natural gas sales at higher realized prices as a result of the acquisition of the North Fork Properties. Oil Sales 2014 vs. 2013. During 2014, oil sales totaled $64,500, which is 119% higher than 2013. The increase resulted from a 132% increase in production partially offset by a 1% decrease in realized oil prices. Oil sales represented 91% of our consolidated total revenues in 2014 and 84% of our equivalent production. Oil production increased 389,218 bbls, driven by a 383,530 bbl increase in the Cook Inlet region and a 5,688 bbl increase in the Appalachian region. The production increase in the Cook Inlet region resulted from RU-1A, RU-2A and RU-5B in our Redoubt Shoals field and our new Sword #1 being online during 2014. The difference between net barrels sold and net barrels produced is approximately equal to the change in quantity of our crude oil inventory balance during the period. Although we attempt to minimize crude oil inventory balances, shipping schedules in the Cook Inlet region are beyond our control and occasionally require us to store crude oil. In addition, we are required to maintain certain inventory levels in third party pipelines and storage facilities. As noted in the following table, we experienced an above average increase in inventory levels during fiscal 2014, which significantly reduced the potential revenue that may have resulted from our increased oil production during the current period. The increase in our inventory balance primarily resulted from shipping schedules and a requirement to maintain increased inventory levels in third party facilities in the Cook Inlet region. April 30, 2014 Cook Inlet Appalachian Total In barrels: Beginning inventory balance 30,130 12,148 42,278 Gross production 788,324 25,513 813,837 Gross sales (732,939 ) (26,766 ) (759,705 ) Pipeline adjustments (3,020 ) - (3,020 ) Ending inventory balance 82,495 10,895 93,390 Net change in inventory 52,365 (1,253 ) 51,112 45

-------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data) 2013 vs. 2012. During 2013, oil sales totaled $29,447, 8% lower than 2012, driven by a 9% increase in average realized prices and a 14% decrease in production. Oil sales represented 85% of our consolidated total revenue and 93% of our equivalent production in 2013. Oil production decreased 46,928 bbls, driven by a 50,098 bbls decrease in the Cook Inlet region, offset by a 3,170 bbls increase in the Appalachian region. The production decrease in the Cook Inlet region resulted from wells being offline during certain portions of the year, a normal decline curve, and fluctuations in shipping schedules. Natural Gas Sales 2014 vs. 2013. During 2014, natural gas sales totaled $4,969, which is 962% higher than 2013. The increase resulted from the acquisition of the North Fork Properties and from selling natural gas in excess of our fuel gas needs from our RU-3 and RU-4A wells in the Cook Inlet region which increased production by 498%. The North Fork Properties acquisition contributed $4,124 to natural gas sales during 2014. Natural gas represented 7% of our consolidated total revenues in 2014 and 16% of our equivalent production. 2013 vs. 2012. During 2013, natural gas sales totaled $468, 24% lower than the 2012. The decrease resulted from a 25% decrease in production. Natural gas represented 1% of our consolidated total revenues in 2013 and 7% of our equivalent production. Other 2014 vs. 2013. Other revenues primarily represent revenues generated from contracts for road building, plugging, drilling and maintenance and repair of third party wells as well as rental income we receive for services and use of facilities in the Cook Inlet region. During 2014 and 2013, other revenues totaled $1,089, or 2%, and $4,886, or 14%, respectively, of our consolidated total revenues. The decrease in other revenues primarily resulted from the completion of the road and pad building project in the Cook Inlet region which contributed to our revenue in 2013. 2013 vs. 2012. During 2013 and 2012, other revenues totaled $4,886, or 14%, and $2,909, or 8%, respectively, of our consolidated total revenues. The increase in other revenues primarily resulted from a road and pad building project in the Cook Inlet region. Cost and Expenses The table below presents a comparison of our expenses for the years ended April 30, 2014, 2013 and 2012: For the Year Ended April 30, 2014 % Variance 2013 % Variance 2012 Lease operating expense $ 20,187 (9 )% $ 22,288 97 % $ 11,305 Transportation costs 5,599 132 2,410 (32 ) 3,556 Cost of other revenues 1,147 (73 ) 4,189 352 926 General and administrative 31,744 22 26,067 (12 ) 29,718 Alaska carried-forward annual loss credits, net (16,342 ) 400 (3,268 ) N/A - Exploration expense 2,009 38 1,458 17 1,241 Depreciation, depletion, and amortization 33,528 155 13,170 (1 ) 13,310 Accretion of asset retirement obligation 1,239 38 900 (16 ) 1,072 Other operating (income) expense, net 2,140 (3,444 ) (64 ) (90 ) (641 ) Total costs and expenses $ 81,251 21 % $ 67,150 11 % $ 60,487 46

-------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data) Lease Operating Expense The table below presents a comparison of our lease operating expense for the years ended April 30, 2014 and 2013: For the Year Ended April 30, 2014 2013 $ Variance % Variance Lease operating expense $ 20,187$ 22,288$ (2,101 ) (9 )% Net production - boe1 816,986 317,606 Lease operating expense per boe produced $ 24.71 $ 70.17$ (45.46 ) (65 )% -------

1 Net production for fiscal 2014 and 2013 excludes 152,373 and 57,123 boe of fuel gas, respectively. Lease operating expense decreased $2,101 from fiscal 2013, or 9%. The decreased lease operating expense is primarily attributable to decreases in workover cost related to our RU-1 and RU-7 wells in the Redoubt Shoals field in the Cook Inlet region slightly offset by increases in our production. The increased production creates marginal increases in labor and camp facility costs and well maintenance; however, the majority of our production costs are fixed. For the year ended April 30, 2014 our lease operating expense per boe produced was $24.71 as compared to $70.17 for the year ended April 30, 2013. We expect our lease operating expense per boe produced to continue to decline as production increases. The table below presents a comparison of our lease operating expense for the years ended April 30, 2013 and 2012: For the Year Ended April 30, 2013 2012 $ Variance % Variance Lease operating expense $ 22,288$ 11,305$ 10,983 97 % Net production - boe1 317,606 371,843 Lease operating expense per boe produced $ 70.17 $ 30.40$ 39.77 131 % -------

1 Net production for fiscal 2013 and 2012 excludes 57,123 and 33,956 boe of fuel gas, respectively. Lease operating expense increased $10,983 from fiscal 2012, or 97%. The majority of the increase resulted from $7,462 in workover cost related to our RU-1 and RU-7 wells in the Redoubt Shoals field in the Cook Inlet region. As the majority of our operating costs are fixed, we did not experience a proportionate decrease in cost from the declines in production. Transportation Costs 2014 vs. 2013. Transportation costs increased $3,189 from fiscal 2013, or 132%. Increased oil transportation costs were due to increased production, and increased gas transportation costs were primarily due to the acquisition of the North Fork Properties for which we incurred $1,403 in gas transportation costs. 2013 vs. 2012. Transportation costs decreased $1,146 from fiscal 2013, or 32%. The decrease is primarily due to decreased production and a decrease in contractual oil transportation charges. 47 -------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data) Cost of Other Revenues Our business is primarily focused on exploration and production activities. The cost of other revenues represent costs of services to third parties as a result of excess capacity, and are derived from the direct labor costs of employees associated with these services, as well as costs associated with equipment, parts and repairs. During 2014, we experienced decreases in cost of other revenues in the Cook Inlet region as we had fewer projects during the year. For the Year Ended April 30, 2014 % Variance 2013 % Variance 2012 Direct labor $ 665 (75 )% $ 2,656 292 % $ 677 Equipment 121 (84 ) 775 100 - Repairs 316 (47 ) 598 572 89 Insurance - (100 ) 91 100 - Other 45 (35 ) 69 (57 ) 160 Total $ 1,147 (73 )% $ 4,189 352 % $ 926 2014 vs. 2013. During 2014, cost of other revenues decreased 73% to $1,147. A substantial portion of this decrease is related to direct labor and equipment costs incurred as a result of a road and pad building contract that was completed in 2013. 2013 vs 2012. During 2013, cost of other revenues increased 352% to $4,189. A substantial portion of this increase was related to direct labor and equipment costs incurred as a result of a road and pad building contract that was completed in 2013. 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, 2014 % Variance 2013 % Variance



2012

Stock-based compensation $ 8,684 (14 )% $ 10,132 (28 )%

$ 14,072 Professional fees 10,955 75 6,248 37 4,561 Salaries 5,050 35 3,732 12 3,330 Employee benefits 1,759 (25 ) 2,357 (38 ) 3,824 Travel 2,001 15 1,744 3 1,693 Other 3,295 78 1,854 (17 ) 2,238 Total $ 31,744 22 % $ 26,067 (12 )% $ 29,718 2014 vs 2013. G&A expenses increased $5,677 from fiscal 2013, or 22%. Stock-based compensation decreased 14% from the same period in the prior year, primarily due to fewer awards granted during our 2014 fiscal year as compared to the previous fiscal year. Salaries increased 35% from the same period in the prior fiscal year as we continue to expand our engineering and accounting staff. The increase in professional fees of 75% results from additional cost related to corporate governance, litigation matters and investor relations activities. 2013 vs. 2012. G&A expenses decreased $3,651 from fiscal 2012, or 12%. The decrease to stock-based compensation of 28% was primarily due to significantly fewer awards being granted during our 2013 fiscal year as compared to our 2012 fiscal year. Salaries increased 12% from fiscal 2012 to fiscal 2013 as we continue to expand our engineering, legal and accounting staff. The increase in professional fees of 37% resulted from additional cost related to corporate governance and investor relations activities. Alaska Carried-Forward Annual Loss Credits, Net 2014 vs. 2013. During 2014, Alaska carried-forward annual loss credits, net increased $13,074, or 400%. Alaska carried-forward annual loss credits, net are generated when there is an annual loss per the State of Alaska tax statues. Increased expenses and increased drilling activity led to higher annual losses per the State of Alaska tax statutes for carried-forward annual loss credits. 48 -------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data) 2013 vs. 2012. During 2013, Alaska carried-forward annual loss credits, net increased $3,268, or 100%. Increased expenses and increased drilling activity led to higher annual losses per the State of Alaska tax statutes for carried-forward annual loss credits. Exploration Expense Exploration expense consists of abandonments of drilling locations, exploration licenses, dry hole costs, delay rentals, geological and geophysical costs, and the impairment, amortization, and abandonment associated with leases on unproved properties. 2014 vs. 2013. Exploration expense increased 38% to $2,009 primarily due to an increase in delay rentals as compared to the same period in the prior year. 2013 vs. 2012. Exploration expense increased 17% to $1,458 primarily due to the timing of impairments of unproved properties. Depreciation, Depletion and Amortization Depreciation, depletion and amortization ("DD&A") expenses include the depreciation, depletion and amortization of leasehold costs and equipment. Depletion is calculated on a unit-of-production basis. Depreciation is calculated on a straight-line basis. For the Year Ended April 30, 2014 2013 2012 2014 2013 2012 (Per boe) Depletion:



Cook Inlet region $ 28,316$ 8,460$ 11,790$ 36.63$ 26.80

$ 29.42 Appalachian region 976 1,343 747 22.19 22.61



19.45

29,292 9,803 12,537 35.85 26.16



28.55

Depreciation:

Cook Inlet region 3,506 2,591 169 NM NM

NM

Appalachian region 730 776 604 NM NM

NM 4,236 3,367 773 4.37 8.99 1.76 Total DD&A $ 33,528$ 13,170$ 13,310$ 40.22$ 35.15$ 30.31 -------- NM = not meaningful 2014 vs. 2013. The increase in depletion in the Cook Inlet region is primarily a result of the additional depletion expense associated with the acquisition of the North Fork Properties and increased production from the Cook Inlet region. The increase in depreciation in the Cook Inlet region is primarily due to Rig-35 being in service during all of fiscal 2014. 2013 vs. 2012. During fiscal 2013, the decrease in depletion in the Cook Inlet region was primarily a result of decreased production. The increase in depreciation in the Cook Inlet region from fiscal 2012 to fiscal 2013 was primarily due to Rig 34 and Rig 35 being placed in service during the period. Accretion of Asset Retirement Obligation Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. 2014 vs. 2013. Accretion of asset retirement obligations increased 38% to $1,239 primarily due to additions of asset retirement obligations during fiscal 2014. 2013 vs. 2012. Accretion of asset retirement obligations decreased 16% to $900 primarily due to revisions of assumptions. Other Operating (Income) Expense, Net 2014 vs. 2013. During fiscal 2014, we recorded other operating expenses of $2,140 which is due to asset impairment charges of $890 and a charge of $1,250 in connection with the settlement the CNX lawsuit, for additional information please see Note 10 - Litigation. 49 -------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data) 2013 vs. 2012. Other operating income decreased $577 from 2012 primarily due to income recognized in 2012 related to revised estimates of royalties due based on a 2012 commission ruling. Other Income and Expense The following table presents the components of other income and expense: For the Year Ended April 30, 2014 % Variance 2013 % Variance 2012 Interest expense, net $ (7,470 ) 75 % $ (4,276 ) 133 % $ (1,837 ) Gain (loss) on derivatives, net (10,179 ) 251 6,751 (338 ) (2,832 ) Other income (expense), net 34 (110 ) (329 ) 667 58 Loss on debt extinguishment (15,145 ) 100 - - - Total $ (32,760 ) 1,627 % $ 2,146 (147 )% $ (4,611 ) Interest Expense, Net 2014 vs. 2013. Interest expense, net of interest income increased $3,194 from fiscal 2013, or 75%, driven primarily by an increase in the average debt balance outstanding during fiscal 2014. 2013 vs. 2012. Interest expense, net, increased $2,439 from 2012, or 133%, driven primarily by an increase in amortization of deferred financing costs and an increase in the average debt balance outstanding during fiscal 2013. Gain (Loss) on Derivatives, Net We have not designated any of our commodity derivative instruments as accounting hedges. As a result, gains and losses on derivatives include both amounts realized from the cash settlements of our derivative positions and amounts from changes in the fair value of open derivative positions in the period of change. 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. 2014 vs. 2013. Gain (loss) on derivatives, net experienced an unfavorable change of $16,930 in fiscal 2014 as compared to fiscal 2013. Of the total change, $5,331 was due to an unfavorable change in realized cash settlements related to our derivative positions in fiscal 2014 compared to fiscal 2013. The remaining amount was due to changes in the fair value of our open derivative positions in each period. 2013 vs. 2012. Gain (loss) on derivatives, net experienced a favorable change of $9,583 in fiscal 2013 compared to fiscal 2012. Of the total change, $912 was due to a favorable change in realized cash settlements related to our derivative positions in fiscal 2013 compared to fiscal 2012. The remaining amount was due to changes in the fair value of our open derivative positions in each period. Loss on Debt Extinguishment In connection with the termination and repayment of the loans outstanding under the Prior Credit Facility, we determined that the Second Lien Credit Facility had substantially different terms from the Prior Credit Facility and recorded a loss on debt extinguishment of $15,145, consisting of a $9,223 prepayment and extension fee owed to Apollo payable in four equal installments of $2,306 on the last day of each calendar quarter, commencing June 30, 2014, and a charge of $5,185 to extinguish the debt discount, the unamortized deferred financing costs and prepaid administrative fee. Additionally, there was a charge of $737 in connection with the termination and repayment of all obligations under the MEI Loan Documents. Income Tax Benefit 2014 vs. 2013. Income tax benefit increased $5,103 from fiscal 2013, or 52% due to an increase in loss before income taxes. Our effective income tax rate for 2014 was 34.3%. This rate differed from the statutory rate primarily due to the effect of our state valuation allowance. 2013 vs. 2012. Income tax benefit decreased $1,223 from fiscal 2012, or 11% primarily due to a revaluation of deferred tax items due to an increase in the blended effective state tax rate. Our effective income tax rate for 2013 was 32.4%. This rate differed from the statutory rate primarily due to changes in our effective state tax rate. 50 -------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data)



Liquidity and Capital Resources

Our cash flows, both in the short-term and long-term, are impacted by highly volatile oil and natural gas prices and production. 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. Our long-term cash flows are highly dependent on our success in efficiently developing current reserves and economically finding, developing and acquiring additional recoverable reserves. Cash investments are required continuously to fund exploration and development projects and acquisitions, which are necessary to offset the inherent declines in production and proven reserves. We may not be able to find, develop or acquire additional reserves to replace our current and future production at acceptable costs, which could materially adversely affect our future liquidity. For a discussion of risk factors related to our business and operations, please refer to the section entitled "Risk Factors" in this Annual Report. In fiscal 2014, we experienced an operating loss. We anticipate that our operating expenses will continue to increase as we fully develop our assets in the Cook Inlet and Appalachian regions and make additional acquisitions. Although we expect an increase in revenues from these development activities, we will continue to utilize our cash to fund drilling and workover activities as well as other operating expenses until such time as we are able to significantly increase our revenues above our operating expenses and capital costs. At our fiscal year end, our cash and cash equivalent balance was $5,749, excluding restricted cash balances of $12,754 held in escrow to secure corporate credit cards and provide for the future plugging and abandonment of wells, including the possible dismantling of our off-shore platform, and general liability bonds. On February 3, 2014, we refinanced the Prior Credit Facility by entering into the New Apollo Loan Agreement which set forth the terms of the Second Lien Credit Facility. The New Apollo Loan Agreement provided for a $175,000 term credit facility, all of which was made available to and drawn by us on the closing date and was used to refinance the Prior Credit Facility, to close the North Fork Properties acquisition and for general corporate purposes. The amounts drawn were subject to a 2% original issue discount. Amounts outstanding under the Second Lien Credit Facility bear interest at a rate of LIBOR plus 9.75%, subject to a 2% LIBOR floor. The Second Lien Credit Facility carries a four year maturity and contains leverage ratio, interest coverage ratio, current ratio, asset coverage ratio, minimum gross production and change of management control covenants as well as other covenants customary for a transaction of this type. The Second Lien Credit Facility permitted us to enter into a reserve-based revolving credit facility in the nature of the First Lien RBL. On June 2, 2014, we entered into the First Lien RBL contemplated by the Second Lien Credit Facility, with an initial borrowing base of $60,000. At closing, we drew $20,000, and on June 24, 2014, we drew an additional $10,000. The remaining availability under the First Lien RBL was $30,000 as of July 7, 2014. As reserves grow, the borrowing base may be adjusted to provide additional capital to fund our development program. The borrowing base of our First Lien RBL is calculated at the discretion of the lenders based on our proved reserves, commodity prices, total debt and other factors at their sole discretion. As such, it is possible our borrowing base could be reduced in the future. On June 24, 2014, we received proceeds of Alaska production credits totaling $21,837 from the State of Alaska. Additionally, following our year end, we entered into a capital lease for the newly purchased Rig 36, for a total of $3,250, which can be expanded up to $5,000, as we upgrade Rig 36. We believe that we will be able 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 with State of Alaska production credits, potential joint ventures, and through the debt, equity and preferred equity capital markets. Although we have the ability to sell our Series C and Series D Preferred Stock in additional "at-the-market" offerings during fiscal 2015, subject to certain limits under our First Lien RBL, we cannot guarantee that market conditions will continue to permit such sales at prices we would find acceptable. If that occurred, cash generated from those offerings would cease. In the event we are unable to raise additional capital on acceptable terms, we may reduce our capital spending. 51 -------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data)



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

For the Year Ended



April 30,

2014 2013



2012

Sources of cash and cash equivalents: Net cash provided by operating activities $ 15,322 $ - $ 6,901 Proceeds from borrowings, net of debt acquisition costs 189,173 51,147 28,754 Proceeds from sale of equipment - 2,000 - Proceeds from Alaska expenditure and exploration based credits 18,531 131 - Exercise of equity rights 4,638 3,832 1,383 Issuance of preferred stock, net of issuance costs 58,844 33,200 10,000 Release of restricted cash 4,984 - - Other 3 - - 291,495 90,310 47,038 Uses of cash and cash equivalents: Net cash used in operating activities - (11,491 ) - Cash dividends (8,552 ) (1,231 ) -



Capital expenditures for oil and gas properties (136,320 ) (26,492 ) (7,558 ) Purchase of equipment and improvements

(2,943 ) (11,533 ) (26,409 ) Payments on debt (75,306 ) (24,130 ) (8,764 ) Redemption of preferred stock - (11,240 ) - Repayment of MEI loans (3,071 ) - - Prepayment of drilling costs (1,692 ) - - North Fork acquisition (59,557 ) - - Acquisition of land (356 ) - - Savant purchase deposit (500 ) - - Increase in restricted cash - (5,613 ) (1,895 ) (288,297 ) (91,730 ) (44,626 )



Increase (decrease) in cash and cash equivalents $ 3,198$ (1,420 )$ 2,412

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, 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 of fiscal 2014 totaled $15,322, an increase of $26,813 from 2013. The increase resulted primarily from an increase in revenue and a favorable shift in the timing of cash receipts and payments to vendors in the ordinary course of business. Proceeds from Credit Facilities and Other Items During fiscal 2014, we borrowed $20,000 under our Prior Credit Facility and borrowed $175,000 under our Second Lien Facility. In connection with the borrowings, we incurred approximately $5,827 in debt acquisition costs. We also repaid $75,306 under our Prior Credit Facility during fiscal 2014. For additional information on the credit facilities, please see Note 4 - Debt. Net cash flows provided by financing activities included $62,738 received from the issuance of our Series C and Series D Preferred Stock, partially offset by issuance costs of $3,894 during fiscal 2014, as compared to $35,867 received from the issuance of our Series C Preferred Stock, partially offset by issuance costs of $2,667 during fiscal 2013. 52 -------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data) Under the terms of the North Fork Purchase Agreement, we paid $59,557 in cash to the North Fork Sellers for the acquisition of the North Fork Properties. During fiscal 2014 we paid $8,552 for quarterly dividends on our Series C Preferred Stock and Series D Preferred Stock. During fiscal 2013, we paid $1,231 for quarterly dividends on our Series C Preferred Stock. Short-term restricted cash primarily relates to accounts controlled by the administrative agent under the New Apollo Loan Agreement, Tennessee oil revenue accounts for joint interest holders and a credit card collateral account. The lenders under the New Apollo Loan Agreement required revenues and certain other items to be deposited directly into depository accounts subject to a Deposit Account Control Agreement. As Apollo, in its capacity as administrative agent, exercised control of the depository accounts subject to a Deposit Account Control Agreement, Apollo had the ability to prevent disbursements from those restricted accounts to our unrestricted cash accounts. Amounts deposited into these accounts were generally released to us in a timely manner. Subsequent to our entry into the First Lien Loan Agreement, we are in the process of moving our depository accounts to KeyBank where we will be able to control disbursements from our accounts until such time as KeyBank exercises control under a new Deposit Account Control Agreement. Long-term restricted cash balances include amounts held in escrow to provide for the future plugging and abandonment of wells, the possible dismantling of our off-shore platform, performance bonds and general liability bonds. Amounts released from our long-term restricted cash accounts, if any, would be the result of a release from escrow by the beneficiary. Amounts transferred to our long-term restricted cash accounts result from bonding requirements for new wells and additions to our current bonding requirements. Capital Expenditures and Alaska Production Credits We use a combination of operating cash flows, borrowings under credit facilities and, from time to time, issuances of debt or common stock to fund significant capital projects. Due to the volatility in oil and natural gas prices and production, our capital expenditure budgets, both in the short-term and long-term, are adjusted on a frequent basis to reflect changes in forecasted operating cash flows, market trends in drilling and acquisition costs, and production projections. Total spending on capital projects increased significantly from the same period last year. For the year ended April 30, 2014, we incurred total capital expenditures of $167,919 which is inclusive of the increase in our capital accrual account of $28,656. Cash paid for capital expenditures was $139,263 for the year ended April 30, 2014. During the year ended April 30, 2014, we collected $21,775 related to our Alaska production credits. The amounts collected related to expenditure and exploration based credits and carried-forward annual loss credits. Prepayment of Drilling Costs We occasionally are required to pay in advance for certain equipment rental and services related to our drilling activities. The advance payments are recorded in prepaid expenses at the time of payment and amortized to capital expenditures as the costs are incurred. At April 30, 2014, we had $1,692 in prepaid drilling costs and other capital related items. Liquidity Cash and Cash Equivalents As of April 30, 2014, we had $5,749 in cash and cash equivalents. Debt and Available Credit Facilities Outstanding debt consisted of $175,000 under our new Second Lien Credit Facility, and an Apollo prepayment and extension fee note payable for $9,223 which is classified as a current debt obligation on the accompanying consolidated balance sheet as of April 30, 2014. In accordance with the terms in our Second Lien Credit Facility, we are required to pay down our outstanding debt with the proceeds received from selling our airplane, which we believe is probable to occur within the next twelve months. Accordingly, a portion of the outstanding debt balance under the Second Lien Credit Facility is classified as a current debt obligation on the accompanying consolidated balance sheet as of April 30, 2014, with the remainder classified as long term debt. As of April 30, 2014 we had no additional borrowing capacity under our Second Lien Credit Facility. 53

-------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data) Contractual Obligations The following table summarizes our contractual obligations as of April 30, 2014. 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 2015 2016-2017 2018-2019 and after Contractual obligations:(a) Debt, at face value(b) Note 4 $ 187,984$ 9,459$ 950$ 177,575 $ - Interest obligations Note 4 81,802 22,030 44,053 15,719 - Dismantlement, removal and restoration (Osprey)(c) Note 6 11,000 1,500 4,500 3,500 1,500 Work commitments(d) Note 6 3,326 875 1,700 188 563 Rights of way and easements:(e) Note 6 Osprey to shore pipeline Note 6 248 13 26 26 183 CIRI Kustatan pipeline easement Note 6 251 28 56 56 111 West Foreland CIRI/Salamatof agreement Note 6 166 18 38 40 70 Salamatof surface use agreement Note 6 400 50 100 100 150 Office and related equipment(f) Note 6 1,578 447 625 249 257 Total contractual obligations $ 286,755$ 34,420$ 52,048$ 197,453$ 2,834 -------



a. This table does not include the Company's liability for dismantlement,

abandonment, and restoration costs of oil and gas properties, derivative

liabilities, or tax reserves. For additional information regarding these

liabilities, please see Note 2 - Derivative Instruments, Note 5 - Asset

Retirement Obligations and Note 6 - Commitments and Contingencies,

respectively, in the Notes to Consolidated Financial Statements set forth in

Part IV, Item 15 of this Form 10-K.

b. Debt includes Series B Preferred Stock of $2,575 which matures September 24,

2017, and the debt related to the Second Lien Credit Facility of $175,000

which carries a four year maturity, and a prepayment and extension fee owed

to Apollo in the amount of $9,223.

c. This represents the Performance Bond Agreement with the State of Alaska for

dismantlement, removal and restoration of the Redoubt Field offshore assets.

d. Work commitments relate to two Susitna Basin Exploration Licenses, Otter, and

Olsen Creek.

e. Obligations to landowners for use of surface and subsurface rights for West

McArthur River Unit and Redoubt Unit facilities including processing

facilities, pipelines, roads, etc.

f. Office and related equipment relate to leases for office space and equipment.

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



Off Balance Sheet Arrangements

We enter into customary agreements in the oil and gas industry for drilling commitments, firm transportation agreements, and other obligations as described herein under Contractual Obligations in this Item 7. Other than the off-balance sheet arrangements described, we do not have any off-balance sheet arrangements with unconsolidated entities that are reasonably likely to materially affect our liquidity or capital resource positions. 54 -------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data)



Non-GAAP Measures

Adjusted EBITDA Adjusted earnings before interest, taxes, depreciation and amortization ("EBITDA") is a significant performance metric used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts and others to assess: the financial performance of our assets without regard to financing



methods, capital structure or historical cost basis;

the ability of our assets to generate cash sufficient to pay interest

costs and support our indebtedness; and

our operating performance and return on capital as compared to those of

other companies in our industry, without regard to financing or capital

structure.



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

depreciation, depletion and amortization;

write-off of deferred financing fees;

asset impairments;

(gain) loss on sale of assets;

accretion expense; exploration costs;



impairment and dry hole costs;

(gain) loss from equity investment;

stock-based compensation expense;

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

interest expense and interest (income);

non-recurring litigation settlements and related matters;

non-recurring North Fork Properties gas transportation costs.

Our Adjusted EBITDA should not be considered as a substitute for net income (loss), operating income (loss), cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Our Adjusted EBITDA may not be comparable to similarly titled measures of other companies. 55 -------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data) The following table presents a reconciliation of net loss before income taxes to Adjusted EBITDA, our most directly comparable GAAP performance measure, for each of the periods presented: For the Year Ended April 30, 2014 2013 2012 Loss before income taxes $ (43,453 )$ (30,203 )$ (29,696 ) Adjusted by: Interest expense, net 7,470 4,276 1,837 Depreciation, depletion and amortization 33,528 13,170



13,310

Asset impairments 890 - - Accretion of asset retirement obligation 1,239 900 1,072 Exploration expense 2,009 1,458 1,241 Loss on debt extinguishment 15,145 - - Stock-based compensation 9,034 10,459 14,072 Non-recurring litigation settlements and matters 4,215 - - Non-recurring North Fork Properties transportation costs 1,403 - - Derivative contracts: (Gain) loss on derivatives, net 10,179 (6,751 ) 2,832 Cash settlements (3,815 ) 1,516 604 Adjusted EBITDA $ 37,844$ (5,175 )$ 5,272



Critical Accounting Policies and Estimates

General

The preparation of consolidated financial statements requires us to utilize estimates and make judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosure of contingent assets and liabilities. These estimates are based on historical experience and on various other assumptions that we believe to be reasonable under the circumstances. The estimates are evaluated by management on an ongoing basis, and the results of these evaluations form a basis for making decisions about the carrying value of assets and liabilities that are not readily apparent from other sources. Although actual results may differ from these estimates under different assumptions or conditions, we believe that the estimates used in the preparation of our financial statements are reasonable. The following is a discussion of our most critical accounting policies. Estimates of Proved Reserves and Future Net Cash Flows Proved oil and gas reserves are the estimated quantities of natural gas and crude oil that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations. Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our DD&A expense. Further, these reserves are the basis for our unaudited supplemental oil and gas disclosures. Reserves as of April 30, 2014, 2013, and 2012, were calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements. We elected not to disclose probable and possible reserves or reserve estimates in this filing. 56

-------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data) Asset Retirement Obligations ("AROs") We have significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. AROs associated with retiring tangible long-lived assets are recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with our oil and gas properties. We utilize current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Fair Value Measurements We measure the fair value of our financial and non-financial assets and liabilities on a recurring basis. Accounting standards define fair value, establish a framework for measuring fair value, and require certain disclosures about fair value measurements for assets and liabilities measured on a recurring basis. All of our derivative instruments are recorded at fair value in our financial statements. Fair value is the exit price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date. The following hierarchy prioritizes the inputs used to measure fair value: Level 1 - Measurements are based on quoted prices in active markets that are unadjusted and accessible at the measurement date for identical, unrestricted assets or liabilities; Level 2 - Measurements are based on significant observable pricing inputs other than quoted prices included in Level 1 that are either directly or indirectly observable as of measurement date; or Level 3 - Measurements are based on process or valuation models that



use inputs that are both significant to the fair value measurement and

less observable from objective sources (i.e., supported by little or no market activity). These inputs generally reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability. Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between level 1, level 2, and level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. Stock-Based Compensation The computation of stock-based compensation requires the use of a valuation model. FASB Accounting Standard Codification ("ASC") 718, "Compensation - Stock Compensation," requires significant judgment and the use of estimates, particularly surrounding model assumptions such as stock price volatility, expected term, and expected forfeiture rates, to value equity-based compensation. We use various pricing models to determine the fair value of our stock options and warrants. Changes in the underlying assumptions could result in a material change to the fair value of the stock-based awards. Although every effort is made to ensure the accuracy of our estimates and assumptions, significant unanticipated changes in those estimates, interpretations and assumptions may result in recording expenses that could differ from those estimates and assumptions. Purchase Price Allocation Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets acquired and the liabilities assumed. The purchase price allocation is accomplished by recording each asset and liability at its estimated fair value. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company's assets and liabilities and tax-related carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. 57 -------------------------------------------------------------------------------- Table of Contents (Dollars in thousands, except per share data and per unit data) In estimating the fair value of assets acquired and liabilities assumed, we made various assumptions. The most significant assumptions related to the estimated fair value assigned to proved and unproved crude oil and natural gas properties. To estimate the fair value of these properties, we prepared estimates of crude oil and natural gas reserves as described above under Estimates of Proved Reserves and Future Net Cash Flows of this Item 7. The estimated fair value assigned to assets acquired and liabilities assumed involve a number of judgments and estimates that could differ materially from the actual amount.



Recent Accounting Pronouncements

In July 2013, the FASB issued ASU 2013-11, "Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists." The amendments in ASU 2013-11 require an entity to present an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for a net operating loss ("NOL") carryforward, a similar tax loss, or a tax credit carryforward except when: (1) a NOL carryforward, a similar tax loss, or a tax credit carryforward is not available as of the reporting date under the governing tax law to settle taxes that would result from the disallowance of the tax position; or (2) the entity does not intend to use the deferred tax asset for this purpose (provided that the tax law permits a choice). If either of these conditions exists, an entity should present an unrecognized tax benefit in the financial statements as a liability and should not net the unrecognized tax benefit with a deferred tax asset. The amendment does not affect the recognition or measurement of uncertain tax positions under ASC Topic 740, Income Taxes. The amendments in this ASU are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The amendments should be applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application is permitted. We do not expect this ASU to have a material impact to our consolidated financial statements. In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)" ("ASU 2014-09"). ASU 2014-09 is intended to improve the financial reporting requirements for revenue from contracts with customers by providing a principle based approach. The core principal of the standard is that revenue should be recognized when the transfer of promised goods or services is made in an amount that the entity expects to be entitled to in exchange for the transfer of goods and services. ASU 2014-09 also requires disclosures enabling users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. This standard will be effective for financial statements issued by public companies for annual reporting periods beginning after December 15, 2016. Early adoption is not permitted. The Company is currently evaluating the potential impact of ASU 2014-09 on the consolidated financial statements. There are no other recently issued accounting pronouncements that are expected to have a material impact on our financial condition, results of operations or cash flows.



Supplemental Quarterly Financial Information (Unaudited)

The following table sets forth selected unaudited quarterly results for the eight quarters ended April 30, 2014.

Apr 30, 2014 Jan 31, 2014 Oct 31, 2013 Jul 31, 2013 Total revenues $ 22,126$ 16,628$ 18,796$ 13,008 Income (loss) from operations 6,351 (6,585 ) (4,283 ) (6,176 ) Net loss attributable to common stockholders (17,241 ) (6,824 ) (8,285 ) (9,417 ) Diluted loss per share (0.38 ) (0.15 ) (0.19 ) (0.22 ) Apr 30, 2013 Jan 31, 2013 Oct 31, 2012 Jul 31, 2012 Total revenues $ 7,730$ 7,999$ 10,810$ 8,262 Loss from operations (14,757 ) (6,500 ) (6,089 ) (5,003 ) Net income (loss) attributable to common stockholders (13,121 ) (6,164 ) (6,399 ) 189 Diluted loss per share (0.31 ) (0.14 ) (0.15 ) 0.00


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Source: Edgar Glimpses


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