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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION We have made forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company's operations, economic performance and financial condition in this report, our Annual Report on Form 10-K for the year ended April 30, 2012, as amended, 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;

• 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 report together with our Annual Report on Form 10-K for the year ended April 30, 2012, as amended, in its entirety, including the risks described in Item 1A. Risk Factors appearing in such Annual Report. Except for our ongoing obligations to disclose material information under the Federal securities laws, we undertake no obligation to release publicly any revisions to any forward-looking statements, to report events or to report the occurrence of unanticipated events. These forward-looking statements speak only as of the date of this report, and you should not rely on these statements without also considering the risks and uncertainties associated with these statements and our business.

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.
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 credit facilities along with other
financing sources and operational cash flow to support our capital expenditures
during our first quarter of fiscal 2013. For the three-month period ended July
31, 2012, we reported notable achievements in several key areas. Highlights for
the quarter include:
•         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. On June 29, 2012, we fully redeemed the outstanding
          shares.


•         On June 29, 2012, we closed our new credit facility with Apollo
          Investment Corporation and repaid our Guggenheim credit facility. For

•         Rig 34 was mobilized to the Otter natural gas prospect and the drilling
          phase was completed at a depth of 5,680 feet in the Beluga formation.
          Mud logs have reported two significant hydrocarbon gas shows in the
          zone of interest. Additional work is now needed to fully evaluate the
          Beluga formation as we plan to conduct a chemical treatment, a
          hydraulic fracture or both to stimulate the well. These two processes
          are commonly performed in wells in the Beluga formation.


•         On August 21, 2012, we gained approval from state regulators to
          commence drilling with Rig 35 on the Osprey offshore platform. The rig
          was already positioned over the RU-1 well. We are currently in the
          process of removing and repairing electronic submersible pumps and
          conducting wellbore optimization with a goal of increasing RU-1's
          historical flow rates. The well was previously producing approximately
          270 barrels of oil per day.

2013 Outlook
As we head into 2013, 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, 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.

Significant Operational Factors

• Realized Prices: Our average realized oil price for the three months ended July 31, 2012 was $99.59 compared to $95.69 for the same period in the prior year. These results exclude the impact of commodity derivative settlements.

• Production: Our net production for the three months ended July 31, 2012 was 77,079 BOE as compared to 92,008 BOE for the same period in the prior year. The decrease in production is attributable to a normal decline curve, fluctuation and shipping schedules, and RU-1 in our Redoubt Shoals field being off-line in the current period.

• Capital Expenditures and Drilling Results: During the three months ended July 31, 2012, we spent approximately $9,325 in capital expenditures. Rig 34 and Rig 35 have been approved by state regulators and are currently operational.

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

Results of Operations

Revenues
                              Three Months Ended July 31
                                   2012                   2011
                       $ Value    Increase (Decrease)    $ Value
                          (In thousands, except percentages)
Oil revenues:
Cook Inlet            $  7,242           (4)%           $  7,554
Appalachian region         404           (37)                637
Total                 $  7,646            (7)           $  8,191
Natural gas revenues:
Cook Inlet            $      6           (84)           $     37
Appalachian region          77           (15)                 91
Total                 $     83           (35)           $    128
Other revenues:
Cook Inlet            $    273            184           $     96
Appalachian region         260           (41)                440
Total                      533            (1)                536
Total revenues        $  8,262            (7)           $  8,855



Net Production
                                Three Months Ended July 31
                                            Increase
                             2012          (Decrease)      2011
                            (In thousands, except percentages)
Oil volume - bbls:
Cook Inlet                    66,758         (16)%        79,714
Appalachian region             4,345           1           4,303
Total                         71,103          (15)        84,017
Natural gas volume1- mcf:
Cook Inlet                     2,293          (83)        13,671
Appalachian region            33,565          (2)         34,270
Total                         35,858          (25)        47,941
Total production2 - boe
Cook Inlet                    67,140          (18)        81,993
Appalachian region             9,939          (1)         10,015
Total                         77,079          (16)        92,008

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
Oil Prices

All of our oil production is sold at prevailing market prices, which are subject to fluctuations driven by market factors outside of our control. As volatility increases in response to the rise in global demand for oil combined with economic uncertainty, prices will continue to experience volatility at unpredictable levels. Prices received for crude oil in the first quarter of 2013 were 4% above the same period last year. For the three months ending July 31, 2012, oil prices realized averaged $99.59 per barrel, compared with $95.69 per barrel for the same period in the prior year.

Natural Gas Prices

Natural gas is subject to price variances based on local supply and demand conditions. The majority of our natural gas sales contracts are indexed to prevailing local market prices. Average realized prices decreased 25% in the first quarter of 2013 compared to the same period in the prior year.

Oil Revenues

During the first quarter of 2013, oil revenues totaled $7,646, 7% lower than the same period in the prior year. The decline resulted from a 15% decrease in production partially offset by an increase in pricing. Oil sales represented 93% of our first quarter consolidated total revenues for the first quarters of 2013 and 2012.

Oil production decreased 12,914 bbls, driven by a 12,956 bbls decrease in the Cook Inlet region. The production decrease in the Cook Inlet region resulted from a normal decline curve, fluctuations in shipping schedules, and RU-1 in our Redoubt Shoals field being off-line in the current period.

Natural Gas Revenues

During the first quarter of 2013, natural gas revenues totaled $83, 35% lower than the same period in the prior year. The decline resulted from a combination of a 13% decrease in average realized prices and a 25% decrease in production. Natural gas represented 1% of our first quarter consolidated total revenues for the first quarters of 2013 and 2012.

Other Revenues

Other revenues primarily represent revenues generated from contracts for plugging, drilling, maintenance and repair of third party wells as well as rental income we receive for services and use of facilities in the Cook Inlet region. During the first quarters of 2013 and 2012, other revenues totaled $533 and $536, respectively, which represented 6% of our consolidated total revenues.

Cost and Expenses

The table below presents a comparison of our expenses:
                                              Three Months Ended July 31
                                                2012               2011           $ Variance       % Variance
                                                           (In thousands, except percentages)
Oil and gas operating costs               $       3,974       $       3,796     $       178              5  %
Cost of other revenues                              548                 227             321            141
General and administrative                        5,330               5,772            (442 )           (8 )
Exploration expense                                  29                  32              (3 )           (9 )
Depreciation, depletion, and amortization         3,125               3,373            (248 )           (7 )
Accretion of asset retirement obligation            284                 269              15              6
Other operating expense (income), net               (25 )              (892 )           867            (97 )
Total costs and expenses                  $      13,265       $      12,577     $       688              5  %

Oil and Gas Operating Costs

Oil and gas operating costs increased $178 from first quarter fiscal 2012, or 5%. The majority of our operating costs are fixed, and as such, we did not experience a proportionate decrease in cost from current period declines in production.

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.

                         Three Months Ended July 31
                    2012           Increase (Decrease)     2011
                      (In thousands, except percentage)
Direct labor $    287                         71  %       $ 168
Equipment          92                        268             25
Repairs           121                      1,110             10
Insurance          38                        100              -
Other              10                        (58 )           24
Total        $    548                        141  %       $ 227

During first quarter fiscal of 2013, cost of other revenues increased 141% to $548. A substantial portion of this increase is related to labor costs associated with services provided under the Tennessee Department of Environment and Conservation contract for plugging abandoned wells located in the Big South Fork area in Tennessee and cost associated with the addition of our new grind and inject facility in Alaska.

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.

                                      Three Months Ended July 31
                                2012           Increase (Decrease)      2011
                                  (In thousands, except percentages)
Salaries                 $      872                    (17 )%         $ 1,047
Professional fees             1,384                    125                614
Travel                          371                    (19 )              458
Employee benefits               210                    (14 )              243
Stock-based compensation      2,076                    (24 )            2,716
Other                           417                    (40 )              694
Total                    $    5,330                     (8 )%         $ 5,772

G&A expenses decreased $442 from first quarter fiscal 2012, or 8%. Salaries declined 17% from the same period in the prior fiscal year due to a decline in cash bonuses. Professional fees increased 125% over the same period last year due to an increase in legal and accounting fees. The 19% decline in travel related expenses primarily relates to a reduction in the use of our corporate aircraft. Stock-based compensation declined 24% due to the fact that the expense associated with awards that became fully vested exceeded the expense associated with newly granted awards.

Exploration Expense

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

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization ("DD&A") expenses include the
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.
                         Three Months Ended July 31
                              2012                 2011
                               (In thousands)
Depletion:
Cook Inlet region  $       2,604                 $ 2,974
Appalachian region           220                     232
                           2,824                   3,206
Depreciation:
Cook Inlet region             58                      40
Appalachian region           243                     127
                             301                     167
Total DD&A         $       3,125                 $ 3,373

The decrease is primarily a result of declines in production from our Alaska West MacArthur River field and RU-1 in our Redoubt Shoals field.

Other Income and Expense

The following table shows the components of other income and expense for the
first quarters indicated.

                                                 Three Months Ended July 31
                                           2012      Increase (Decrease)     2011
                                             (In thousands, except percentages)
Interest expense, net of interest income $  (131 )          (74)%          $  (495 )
Gain on derivatives, net                   8,941             138             3,756
Other income (expense), net                  (75 )          (342)               31
Total                                    $ 8,735                           $ 3,292

Interest Expense

Interest expense, net of interest income decreased $364 from first quarter fiscal 2012, or 74%, driven primarily by an increase in capitalized interest.

Gain 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 unaudited Condensed Consolidated Statements of Operations. We do not engage in speculative trading and utilize commodity derivatives only as a mechanism to lock in future prices for a portion of our expected crude oil production.

During the first quarter of fiscal 2013, unrealized gains on commodity derivatives totaled $3,550, while realized gains on commodity derivatives totaled $4,061. Unrealized gains on warrant derivatives of $1,330 make up the remaining portion of the total net gain on derivatives of $8,941.

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 . . .