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MILL > SEC Filings for MILL > Form 10-Q on 9-Sep-2013All Recent SEC Filings

Show all filings for MILLER ENERGY RESOURCES, INC.

Form 10-Q for MILLER ENERGY RESOURCES, INC.


9-Sep-2013

Quarterly Report


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion and analysis should be read in conjunction with the condensed consolidated financial statements and accompanying notes included herein and the consolidated financial statements and accompanying notes included 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, as amended, for the year ended April 30, 2013, and may make other forward-looking statements from time to time in other public filings, press releases and discussions with our management. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include those statements preceded by, followed by or that otherwise include the words "may," "could," "believes," "expects," "anticipates," "intends," "estimates," "projects," "target," "goal," "plans," "objective," "should" or similar expressions or variations on such expressions. For these statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that our expectations will prove to be correct. We undertake no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise.
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 15, 2013 and was further amended on August 28, 2013. 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 - 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 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.


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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, acquiring and developing additional recoverable reserves. We may not be able to find, acquire or develop 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 sales of our Series C Preferred Stock made in "at-the-market" and "follow-on" public offerings to support our capital expenditures during our first quarter of fiscal 2014. For the three-month period ended July 31, 2013, we reported notable achievements in several key areas. Highlights for the period include:
Starting May 1, 2013, and periodically during the quarter, we issued 239,452 shares of our Series C Preferred Stock in "at-the-market" offerings pursuant to the ATM Agreement and a prospectus supplement dated October 12, 2012 (issued under our existing S-3 registration statement, filed with the SEC as file number 333-183750). These sales were made at an average price on the date of such sale ranging from $21.48 to $22.35 per share. We received net proceeds of $4,999 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. We will primarily deliver gas on
          the new agreement with production from the RU-3 and RU-4A wells in the
          Redoubt Shoals field. Contractual gas sales commenced during the month
          of May and continued throughout the quarter.


         On June 19, 2013, we began drilling our Sword #1 well located near our
          West McArthur River Unit ("WMRU") in the Cook Inlet region. The Sword
          #1 well has been planned as an extended reach well intended to be
          drilled directionally to approximately 19,000 feet total in an adjacent
          fault block to the WMRU. 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 daily production of 1,281
          barrels of oil per day and a water cut of 19% and a rate of production
          of 1,307 barrels of oil per day through July 31, 2013.


         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, Cook Inlet Energy, 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 announced that we elected Marceau Schlumberger to
          our board of Directors. Mr. Schlumberger is Miller's sixth independent
          director. Mr. Schlumberger has nearly twenty years of investment
          banking experience, including international and domestic mergers and
          acquisitions, restructuring, strategic analysis, and financial
          experience.

Subsequent to the end of the first quarter of fiscal 2014, we amended the Apollo Credit Facility and brought our RU-1A oil well online. For additional information on the Apollo Credit Facility, refer to Note 7 - Debt and Note 15 - Subsequent Events. Our RU-1A oil well was successfully brought online on August 17, 2013. The well was a sidetrack of our previously producing RU-1 well. From August 18, 2013 through August 29, 2013, the well produced in excess of 700 barrels of oil per day.


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Fiscal 2014 Outlook
As we head into the second quarter of fiscal 2014, we believe our inventory of recompletion, workovers, and exploration and development projects offers numerous growth opportunities. We are currently working on recompleting our RU-5B oil well. We also have several development projects onshore, which we expect will contribute additional production in fiscal 2014. No assurance can be made regarding the success of these development and recompletion efforts. Our current fiscal 2014 capital budget is $125,000. The majority of this budget is expected to be spent on projects in Alaska, with the remaining amount allocated to our Appalachian region. Due to the uncertainty associated with changes in commodity prices, we closely monitor our cost levels and revise our capital budgets based on changes in forecasted cash flows. This means our plan for capital expenditures may change as a result of anticipated changes in the market place. Further, our ability to fully utilize the budget will be dependent on a number of factors including, but not limited to, access to capital, favorable weather and regulatory approval.
We note that, although we expect to continue to sell our Series C Preferred Stock in additional "at-the-market" offerings during fiscal 2014, we cannot guarantee that market conditions will continue to permit such sales at prices we would find acceptable. If that occurred, cash generated from those offerings would cease.

Significant Operational Factors
            Realized Prices: Our average realized oil price for the three months
             ended July 31, 2013 and 2012 was $104.57 and $99.59, respectively.
             These results exclude the impact of commodity derivative
             settlements.


            Production: Our net production, excluding fuel gas, for the three
             months ended July 31, 2013 and 2012 was 125,080 boe and 77,079 boe,
             respectively.


            Capital Expenditures and Drilling Results: During the three months
             ended July 31, 2013, we incurred $28,965 which is inclusive of the
             increase in our capital accrual account of $12,991. Cash paid for
             capital expenditures was $15,974 for the three months ended July 31,
             2013.

We experience earnings volatility as a result of not using hedge accounting for our crude oil 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 crude oil 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 crude oil production.


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Results of Operations

Three Months Ended July 31, 2013 Compared to Three Months Ended July 31, 2012
Revenues
                          For the Three Months Ended July 31,
                         2013      Increase (Decrease)     2012
Oil revenues:
Cook Inlet            $  11,633            61%           $ 7,242
Appalachian region          625            55                404
Total                 $  12,258            60            $ 7,646
Natural gas revenues:
Cook Inlet            $     156           2,500          $     6
Appalachian region          114            48                 77
Total                 $     270            225           $    83
Other revenues:
Cook Inlet            $     247           (10)           $   273
Appalachian region          233           (10)               260
Total                       480           (10)               533
Total revenues        $  13,008            57            $ 8,262



Net Production
                            For the Three Months Ended July 31,
                            2013     Increase (Decrease)    2012
Oil volume - bbls:
Cook Inlet                 108,435           62%           66,758
Appalachian region           6,975           61             4,345
Total                      115,410           62            71,103
Natural gas volume1- mcf:
Cook Inlet                  28,173          1,129           2,293
Appalachian region          29,848          (11)           33,565
Total                       58,021           62            35,858
Total production2 - boe:
Cook Inlet                 113,130           68            67,140
Appalachian region          11,950           20             9,939
Total                      125,080           62            77,079


-------


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

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


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Pricing
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 2014 were 5% above the same period last year. For the three months ended July 31, 2013, realized oil prices averaged $104.57 per bbl, compared with $99.59 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. Prices received for natural gas in the first quarter of fiscal 2014 were substantially above the same period last year. For the three months ended July 31, 2013, realized natural gas prices averaged $4.63 per mcf, compared with $2.38 per mcf for the same period in the prior year. The increase in the averaged realized gas prices resulted from our new natural gas sales contract in the Cook Inlet region with a gross price of $6.00 per mcf. Oil Revenues
During the first quarter of fiscal 2014, oil revenues totaled $12,258, 60% higher than the same period in the prior year. The increase resulted from a 62% increase in production and a 5% increase in realized oil prices. Oil sales represented 94% of our first quarter consolidated total revenues. Oil production increased 44,307 bbls, driven by a 41,677 bbls increase in the Cook Inlet region and a 2,630 barrel increase in the Appalachian region. The production increase in the Cook Inlet region resulted from RU-2A in our Redoubt Shoals field being on line during the three months ended July 31, 2013. Natural Gas Revenues
During the first quarter of fiscal 2014, natural gas revenues totaled $270, 225% higher than the same period in the prior year. The increase resulted from a combination of a 95% increase in average realized prices and a 62% increase in production. The increase in the averaged realized gas prices resulted from our new natural gas sales contract in the Cook Inlet region with a gross price of $6.00 per mcf. The increase in natural gas production resulted from selling natural gas in excess of our fuel gas needs from our RU-3 and RU-4A wells in the Cook Inlet region. Natural gas represented 2% of our first quarter consolidated total revenues.
Other Revenues
Other revenues primarily represent revenues generated from contracts for road building, 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 fiscal 2014 and 2013, other revenues totaled $480, or 4%, and $533, or 6%, respectively, of our consolidated total revenues.

Cost and Expenses
The table below presents a comparison of our expenses for the three months ended
July 31, 2013 and 2012:
                                  For the Three Months Ended July 31,
                                         2013                2012         $ Variance       % Variance
Oil and gas operating costs      $            6,265     $      3,974     $     2,291            58  %
Cost of other revenues                          284              548            (264 )         (48 )
General and administrative                    6,360            5,305           1,055            20
Exploration expense                             286               29             257           886
Depreciation, depletion, and
amortization                                  5,692            3,125           2,567            82
Accretion of asset retirement
obligation                                      297              284              13             5
Total costs and expenses         $           19,184     $     13,265     $     5,919            45  %

Oil and Gas Operating Costs
Oil and gas operating costs increased $2,291 from first quarter fiscal 2013, or 58%. The increased oil and gas operating costs are directly attributable to increased production and drilling activity. The increased production creates additional labor and camp facility costs, well maintenance, and transportation costs. The increased drilling activity substantially increases the cost of


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control of well insurance. Approximately $1,043 of the increase resulted from the sale of crude oil inventory that was recorded in the previous period at a higher cost per barrel due to well workovers. 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 first quarter of fiscal 2014, we experienced decreases in cost of other revenues in the Cook Inlet region as we had limited projects during the period.

For the Three Months Ended July 31,
                  2013        Increase (Decrease)    2012
Direct labor $   165                 (43)%          $ 287
Equipment         39                 (58)              92
Repairs           70                 (42)             121
Insurance          -                 (100)             38
Other             10                   -               10
Total        $   284                 (48)%          $ 548

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 July 31,
                            2013      Increase (Decrease)     2012
Salaries                 $     923            6%            $   872
Professional fees            2,162            56              1,384
Travel                         454            22                371
Employee benefits              413            97                210
Stock-based compensation     1,600           (23)             2,075
Other                          808            106               393
Total                    $   6,360            20%           $ 5,305

G&A expenses increased $1,055 from first quarter fiscal 2013, or 20%. Included in the overall 20% fluctuation, salaries increased 6% from the same period in the prior fiscal year as we continue to expand our corporate accounting and legal staff from the prior period. Professional fees increased 56% over the same period last year due to an increase in litigation related expenses and employee recruitment during the quarter. Stock-based compensation declined 23% due to the expense associated with awards that became fully vested exceeding the expense associated with newly granted awards. The increase in other expense resulted from an increase in liability insurance premiums due to our increased drilling activities and an increase in office rent related to the addition of office space in both Tennessee and Alaska. Salary increases for our named executive officers, in the aggregate annual amount of $1,035, which were approved by our Compensation Committee on July 29, 2013, were made effective as of July 17, 2013. As a result, the impact of these increases are not fully reflected in the G&A expenses for our last fiscal quarter, and will be relatively higher in future periods.
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.


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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 July 31,
                                     2013                        2012
Depletion:
Cook Inlet region  $            4,192                          $ 2,604
Appalachian region                345                              220
                                4,537                            2,824
Depreciation:
Cook Inlet region                 119                               58
Appalachian region              1,036                              243
                                1,155                              301
Total DD&A         $            5,692                          $ 3,125

The increase in DD&A is primarily a result of increased production from our Alaska properties and Rig-35 being in service during the three months ended July 31, 2013.

Other Income and Expense
The following table shows the components of other income and expense for the
first quarters indicated.
                                    For the Three Months Ended July 31,
                                   2013      Increase (Decrease)     2012
Interest expense, net           $ (2,281 )         1,641%          $  (131 )
Gain (loss) on derivatives, net   (3,076 )          (134)            8,941
Other expense, net                   (14 )           81                (75 )
Total                           $ (5,371 )         (161)%          $ 8,735

Interest Expense, Net
Interest expense, net, increased $2,150 from the first quarter of fiscal 2013, or 1,641%. The increase in interest expense resulted from a combination of higher debt balances, a reduction in the percentage of interest expense that could be capitalized on self-constructed assets and administration and amendment fees on the Apollo Credit Facility.
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 first quarter of fiscal 2014, unrealized losses on commodity derivatives totaled $2,519, while realized losses on commodity derivatives totaled $557. Conversely, during the first quarter of fiscal 2013, we experienced a net gain on commodity and warrant derivatives of $8,941 of which $4,880 was unrealized.


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Liquidity and Capital Resources . . .

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