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

Forward Looking Statements

We have made forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 concerning the Company's operations, economic performance and financial condition in this report, 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.

See the discussion in the "Risk Factors" and "Caution Concerning Forward-Looking Statements" sections of the Company's Annual Report on Form 10-K filed with the SEC on July 16, 2012, as amended. All written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements contained in the section entitled "Risk Factors" included in such Annual Report as well as other cautionary statements that are made from time to time in our other SEC filings and public communications. You should evaluate all forward-looking statements made in this report in the context of these risks and uncertainties.

Executive Overview

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

Strategy

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

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


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


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


•         Pursue Strategic Acquisitions. We have significantly increased our oil
          and gas properties through strategic low-cost / high-value
          acquisitions. Under the same strategy, our management team will
          continue to seek opportunities that meet our criteria for risk, reward,
          rate of return, and growth potential. We plan to leverage our
          management

team's expertise to pursue value-creating acquisitions when the opportunities arise, subject to the availability of sufficient capital.

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

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

Financial and Operating Results

We continued to utilize operational cash flow along with funds raised from the exercise of warrants under a Special Warrant Exercise Agreement and Bristol Warrant Exercise Agreement, the offering and sale of our Series B Preferred Stock and our initial public offering of our Series C Preferred Stock to support our capital expenditures during our second quarter of fiscal 2013. For the six-month period ended October 31, 2012, we reported notable achievements in several key areas. Highlights for the period include:

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

• On June 29, 2012, we closed our new credit facility with Apollo Investment Corporation and repaid our Guggenheim Credit Facility. For additional information refer to Note 7, Debt, in the condensed consolidated financial statements.

•         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.


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


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


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


•         On October 5, 2012, we issued 685,000 shares of a new class of 10.75%
          Series C Preferred Stock in a public sale pursuant to a prospectus
          supplement date September 18, 2012 (issued under our existing S-3
          registration statement, filed with the SEC as file number 333-183750).
          This new series of stock is listed for trading on the New York Stock
          Exchange under the ticker symbol MILLprC. We received net proceeds of
          $14,420 in connection with this sale.


•         On October 12, 2012, we entered into an At Market Issuance Sales
          Agreement with MLV for the placement and sale of our common stock and
          10.75% Series C Preferred Stock in one or more "at the market" public
          offerings from time to time.


•         On October 26, 2012, we completed a workover on the RU-1 well in the
          Redoubt Shoals field in Alaska. The workover involved replacing a
          failed electric submersible pump as well as removing other downhole
          obstructions. The workover was successful and we improved our access to
          the proved reserves.

2013 Outlook

As we head into the second half of fiscal 2013, we believe our inventory of recompletion, workovers, and exploration and development projects offers numerous growth opportunities. Our current 2013 capital budget is $50,000 to $100,000. The majority of this budget is expected to be spent on projects in Alaska, with the remaining amount allocated to our Appalachian region. Due to the uncertainty associated with changes in commodity prices, we closely monitor our cost levels and revise our capital budgets based on changes in forecasted cash flows. This means our plan for capital expenditures may change as a result of anticipated changes in the market place. Further, our ability to fully utilize the budget will be dependent on a number of factors including, but not limited to, access to capital, weather and regulatory approval.

We note that certain of the revenue sources drawn upon in the second quarter of fiscal 2013 were non-recurring in nature, and those revenue streams will not be available to us as we move into the second half of fiscal 2013.

We expect to fund our remaining 2013 capital budget with funds borrowed under the Apollo Credit Facility, proceeds received from additional sales of our Series C Preferred Stock 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 and six months ended October 31, 2012 was $105.68 and $102.60, respectively, as compared to $81.10 and $87.26, respectively, for the same periods in the prior year. These results exclude the impact of commodity derivative settlements.

• Production: Our net production for the three and six months ended October 31, 2012 was 78,145 boe and 155,040 boe, respectively, as compared to 112,010 boe and 203,650 boe, respectively, for the same periods 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 for a majority of the current period.

• Capital Expenditures and Drilling Results: During the three and six months ended October 31, 2012, we spent $9,622 and $18,947, respectively, 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, which are 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 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

Three Months Ended October 31, 2012 Compared to Three Months Ended October 31,
2011

Revenues

                           For the Three Months Ended October 31,
                           2012                                 2011
                          $ Value       Increase (Decrease)    $ Value
Oil revenues:
Cook Inlet            $    7,568               (4)%           $  7,893
Appalachian region           376                (4)                392
Total                 $    7,944                (4)           $  8,285
Natural gas revenues:
Cook Inlet            $       22               (59)           $     54
Appalachian region            90               (12)                102
Total                 $      112               (28)           $    156
Other revenues:
Cook Inlet            $    2,526               1,828          $    131
Appalachian region           228               (64)                633
Total                      2,754                260                764
Total revenues        $   10,810                17            $  9,205



Net Production

                            For the Three Months Ended October 31,
                           2012       Increase (Decrease)      2011
Oil volume - bbls:
Cook Inlet                 67,832            (32)%             99,589
Appalachian region          3,997             (4)               4,169
Total                      71,829             (31)            103,758
Natural gas volume1- mcf:
Cook Inlet                  4,632             (67)             14,040
Appalachian region         33,265             (6)              35,477
Total                      37,897             (23)             49,517
Total production2 - boe
Cook Inlet                 68,604             (33)            101,929
Appalachian region          9,541             (5)              10,081
Total                      78,145             (30)            112,010

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 second quarter of 2013 were 30% above the same period last year. For the three months ended October 31, 2012, realized oil prices averaged $105.68 per bbl, compared with $81.10 per bbl for the same period in the prior year.

Natural Gas Prices

Natural gas is subject to price variances based on local supply and demand conditions. The majority of our natural gas sales contracts are indexed to prevailing local market prices. Prices received for natural gas in the second quarter of 2013 were 5% below the same period last year. For the three months ended October 31, 2012, realized natural gas prices averaged $2.95 per mcf, compared with $3.11 per mcf for the same period in the prior year.

Oil Revenues

During the second quarter of fiscal 2013, oil revenues totaled $7,944, 4% lower than the same period in the prior year. The decline resulted from a 31% decrease in production partially offset by an increase in realized oil prices. Oil sales represented 73% of our second quarter consolidated total revenues.

Oil production decreased 31,929 bbls, driven by a 31,757 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 for the majority of the quarter.

Natural Gas Revenues

During the second quarter of fiscal 2013, natural gas revenues totaled $112, 28% lower than the same period in the prior year. The decline resulted from a combination of a 5% decrease in average realized prices and a 23% decrease in production. Natural gas represented 1% of our second quarter consolidated total revenues.

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 second quarters of fiscal 2013 and 2012, other revenues totaled $2,754, or 25%, and $764, or 8%, respectively, of our consolidated total revenues. The increase in other revenues resulted from our new grind and inject facility, which allows for the processing and safe disposal of solid material that is extracted as a byproduct of drilling wells, and a road building contract in the Cook Inlet region that was completed during the period.

Cost and Expenses

The table below presents a comparison of our expenses for the three months ended
October 31, 2012 and 2011:

                                     For the Three Months Ended October 31,
                                          2012                      2011             $ Variance      % Variance
Oil and gas operating costs      $            4,871         $            4,375     $       496             11  %
Cost of other revenues                        2,485                        146           2,339          1,602
General and administrative                    6,208                      7,949          (1,741 )          (22 )
Exploration expense                              28                        148            (120 )          (81 )
Depreciation, depletion, and
amortization                                  3,062                      4,050            (988 )          (24 )
Accretion of asset retirement
obligation                                      285                        268              17              6
Other operating expense
(income), net                                   (40 )                       (5 )           (35 )          700
Total costs and expenses         $           16,899         $           16,931     $       (32 )            -  %

Oil and Gas Operating Costs

Oil and gas operating costs increased $496 from second quarter fiscal 2012, or 11%. The majority of our operating costs are fixed, and as such, we did not experience a proportionate decrease in cost from current period declines in production. Increased drilling activities and rental of camp facilities and equipment in the Cook Inlet region require additional personnel in our camps, which increase the cost of support services.

Cost of Other Revenues

Our business is primarily focused on exploration and production activities. The cost of other revenues represent costs of services to third parties as a result of excess capacity, and are derived from the direct labor costs of employees associated with these services, as well as costs associated with equipment, parts and repairs. During the second quarter of fiscal 2013, we experienced increases in cost of other revenues in the Cook Inlet region as we began our grind and inject operations and completed a road and pad building contract.

For the Three Months Ended October 31,

                   2012         Increase (Decrease)    2011
Direct labor $   2,022                1,030%          $ 179
Equipment          220                (1,148)           (21 )
Repairs            207                 1,782             11
Insurance           17                   -                -
Other               19                 (183)            (23 )
Total        $   2,485                1,602%          $ 146

During second quarter fiscal of 2013, cost of other revenues increased 1,602% to $2,485. A substantial portion of this increase is related to labor costs associated with services provided under a road and pad building contract and cost associated with the addition of our new grind and inject facility in the Cook Inlet region.

General and Administrative Expenses

General and administrative ("G&A") expenses include the costs of our employees,
related benefits, professional fees, travel and other miscellaneous general and
administrative expenses.

                              For the Three Months Ended October 31,
                              2012         Increase (Decrease)     2011
Salaries                 $     911                 34%           $   681
Professional fees            1,431                (26)             1,924
Travel                         477                 31                364
Employee benefits              221                (73)               825
Stock-based compensation     2,639                (30)             3,757
Other                          529                 33                398
Total                    $   6,208                (22)%          $ 7,949

G&A expenses decreased $1,741 from second quarter fiscal 2012, or 22%. Salaries increased 34% from the same period in the prior fiscal year as we significantly expanded our corporate accounting and legal staff from the prior period. Professional fees decreased 26% over the same period last year due to a decrease in litigation related expenses and insurance reimbursements received for covered legal expenses. Stock-based compensation declined 30% due to the expense associated with awards that became fully vested exceeding 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.

                            For the Three Months Ended October 31,
                                       2012                          2011
Depletion:
Cook Inlet region  $             1,865                             $ 3,700
Appalachian region                 220                                 183
                                 2,085                               3,883
Depreciation:
Cook Inlet region                   60                                  40
Appalachian region                 926                                 127
                                   986                                 167
Total DD&A         $             3,071                             $ 4,050

The decrease in DD&A is primarily a result of declines in production from our Alaska West MacArthur River field and RU-1 in our Redoubt Shoals field being off-line for the majority of the quarter.

Other Income and Expense

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

                                             For the Three Months Ended October 31,
                                             2012        Increase (Decrease)     2011
Interest expense, net of interest income $   (1,537 )            75%           $ (879 )
Gain (loss) on derivatives, net              (2,045 )           (236)           1,506
Other income (expense), net                    (300 )          (1,134)             29
Total                                    $   (3,882 )          (692)%          $  656

Interest Expense

Interest expense, net of interest income, increased $658 from the second quarter of fiscal 2012, or 75%, driven primarily by a reduction in the percentage of interest expense that was capitalized during the period.

Gain (Loss) on Derivatives, Net

We experience earnings volatility as a result of not using hedge accounting to account for changes in commodity prices. As the positions of future oil production are marked-to-market, both realized and unrealized gains or losses are included on our 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 second quarter of fiscal 2013, unrealized losses on commodity derivatives totaled $476, while realized losses on commodity derivatives totaled $963. Unrealized losses on warrant derivatives of $606 make up the remaining portion of the total net loss on derivatives of $2,045.