Miller Energy Resources' CEO Discusses F4Q 2012 Results - Earnings Call Transcript

Jul.25.12 | About: Miller Energy (MILL)

Miller Energy Resources, Inc. (NYSE:MILL)

F4Q 2012 Earnings Conference Call

July 25, 2012 16:30 ET

Executives

Scott Boruff – Chief Executive Officer

David Hall – Chief Executive Officer, Alaska Subsidiary

David Voyticky – Chief Financial Officer

Analysts

Neal Dingmann – SunTrust

Michael Cahill – Compass Investments

Jonathan Fite – KMS Investments

Jeffery Connolly - Sidoti & Company

Operator

Good afternoon and welcome to the Miller Energy Resources Fourth Quarter Conference Call. This call is being recorded. At this time, all participants have been placed in a listen-only mode. A question-and-answer session will follow the presentation by the company’s CEO, Scott Boruff.

Before we begin, the company has requested that I make the following announcement. The comments made during this conference call may contain forward-looking statements within the meaning of Section 27A of the Securities and Exchange Act and the Private Securities Litigation Reform Act of 1995. They represent Miller Energy’s expectations and beliefs concerning future events.

These forward-looking statements involve the implied assessment that the resources described can be profitably produced in the future, based on certain estimates and assumptions. Forward-looking statements are based on current expectations, estimates and projections that invoke a number of risks, uncertainties and other factors that could cause actual results to differ materially from those anticipated by Miller Energy Resources and described in the forward-looking statements.

These risks, uncertainties, and other factors include, but are not limited to the potential for Miller Energy to experience additional operating losses, high debt costs under its existing senior credit facility, potential limitations imposed by debt covenants under its senior credit facility on its growth and ability to meet business objectives; the need to enhance management, systems, accounting, controls, and reporting performance; uncertainties related to deficiencies identified by the SEC in certain forms 8-K filed in 2010 and the Form 10-K for 2011; litigation risk; it’s ability to perform under the terms of its oil and gas leases, and exploration licenses with the Alaska DNR, including meeting the funding our work commitments of those agreements; it’s ability to successfully acquire, integrate and exploit new productive assets in the future; it’s ability to recover proved undeveloped reserves and covert profitable and possible reserves to proved reserves, risks associated with the hedging of commodity prices; it’s dependence on third-party transportation facilities, concentration risk in the market for the oil we produce in Alaska; the impact of natural disasters on its Cook Inlet Basin operations; adverse effects of the national and global economic downturns on our profitability; the imprecise nature of its reserve estimates, growing risk, 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 reserves that maybe uninsurable; constraints on production and cost 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 the future legislation could have on the access to tax incentives currently enjoyed by Miller that no dividends maybe paid on its common stock for sometime; 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 risk to non-affiliate shareholders arising from substantial ownership positions of affiliates.

Additional information on these and other factors which could affect Miller Energy’s operations or financial results are included in Miller Energy’s reports on file with the United States Securities and Exchange Commission, including its most recent filing of its Annual Report on Form 10-K.

Miller Energy’s actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed in its periodic reports that are filed with the Securities and Exchange Commission. All forward-looking statements attributable to Miller Energy Resources or to persons acting on its behalf are expressively qualified in their entirety by these factors.

Investors should not place undue reliance on these forward-looking statements, which speak only as of this date of this conference. Miller Energy Resources assume no obligation to update forward-looking statements, should circumstances or management’s estimates or opinions change unless otherwise required under securities law. Miller Energy Resources is not responsible for changes made to this call by the conference call company or internet services.

At this time, it’s my pleasure to turn the call over to Miller Energy’s CEO, Scott Boruff. Please go ahead, sir.

Scott Boruff – Chief Executive Officer

Thank you, (Karianne). I want to thank you for joining us this afternoon to review the results of our fourth quarter and fiscal year end April 30, 2012. Today I’ll provide a brief overview of our accomplishments and results of our operations for the quarter following my reviews David Hall, CEO of our Alaska subsidiary will present an update an update on our Alaska operations and David Voyticky, our President and Acting CFO will provide additional detail on our financial results. Upon the completion of management presentations, we’ll be accepting questions and comments.

As 2012 was a transformational year for Miller Energy. During the year we laid groundwork from Miller to begin developing our significant reserves and assets that we have in Alaska as well as consolidated our interest in Tennessee. I want to take a few minutes to highlight these accomplishments since we believe they will be drivers of our future growth and probability. With the bulk of our production coming from Alaska I’ll briefly touch on Tennessee before covering Alaska in more detail. Throughout this past year, Miller acquired outside interests in some of its producing wells and surrounding acreage in Tennessee. As a result Miller’s working interest and net revenue interest in these producing wells has increased. In fiscal 2013 we’ve planned an aggressive rework program and horizontal drilling program in Mississippian lime which we believe will be more viable to us and we where ever had that greater interest in these wells.

We expect to increase our daily production in both reworks and recovering all left in place with our horizontal well program. In addition to lying the foundation for enhancing oil production intensity this past March Miller completed $1.6 million Department of Interior plugging contracts in the Big South Fork, National River and Recreation Area plugging orphan wells within the par. This two year contract was completed approximately three months early within budgets with an extemporary safety record. The contractor performance assessment report produced by the government said that Miller’s overall performance was very good. We’re excited about the potential shale oil production in Tennessee at the Mississippian lime and feel this fiscal year and 2013 will be a watershed for Miller in Tennessee.

Turning to Alaska one of our key initiatives during the year was to secure funding to purchase the new drilling rig and equipment while supporting our expanding operations. In June of 2011 we signed a new credit facility that provided the initial funding for these programs. With the new funding we were able to complete Rig 34 for our onshore drilling program and purchased Rig 35 a custom design drilling rig for our offshore program on the Osprey platforms. Owning our own rigs is a key part of our strategy to become more vertically integrated in developing our onshore and offshore properties oil and natural gas in Alaska. Because it enables us to set our own schedule without rigs drilled.

Rig 34 was shipped from Tennessee to Alaska and there is substantially a rework and upgraded for drilling in Alaska. It received approval for operations from the Alaska Oil and Gas Conservation Commission in March of 2012. This is first deployed to drill KF1 in the Kustatan Field and was later moved to a new well on our Otter lease. In the future it will be used to implement our Alaska onshore drilling program including exploration prospects on our Otter and Olsen Creek leases.

Later on this call David Hall will provide a current update on our drilling programs for rigs 34 and 35. Rig 35 is a 2000 horsepower rig that we had custom design for the Osprey platform. And also has the flexibility to be used for onshore and offshore drilling projects. We have began taking delivery of Rig 35 in Alaska in late October 2011 and had originally planned for it to be assembled in early 2012. However, as many of you know the harsh winter in Alaska fired against us and shutdown our operations for part of that season. But today I’m very pleased to report that Rig 35 is complete on the Osprey platform and we are waiting final certification from the Alaskan Oil and Gas Conservation Committee who inspected the rig just yesterday. We expect to receive final approval so that we can complete short list. We plan to put Rig 35 to work on RU-1 as soon it certifies.

Rig 35 will allow us to re-complete and work over existing wells and explore new drilling opportunities on the Osprey platform in a timely and effective manner. We believe Rig 35 will transform our operations to a more production driven company since we will control the rig and not be dependent on third-party operators to execute our drilling calendar. It is part of our strategy to become more vertically integrated in our old and development programs.

During the year we also concentrated on pulling the people and systems in place to manage our future growth. We’ve realigned our management team to address our continued growth and believe as the event of fiscal 2013 in a much stronger position than we were a year ago. We’ve made progress on the accounting front as demonstrated by our timely filing report with the SEC this year including our year end annual report for fiscal 2012. We had worked closely with KPMG, our independent certified public accountants to achieve these improved results. We are pleased to receive that we received a clean opinion from KPMG regarding our audited financials. However, we still have work to do to improve our internal control as KPMG noted on the report.

In order to address the internal control issues and to (indiscernible) department to manage our future growth, we are adding three new hirers including a Chief Accounting Officer and two staff accountants. Catherine Rector as CPA and Certified Internal Auditor would join us next week as our new Chief Accounting Officer. She has 20 years of accounting experience including Sarbanes Oxley compliance and public accounting. Most recently, she was the Director of financial reporting and accounting consolidations for an international public company. We are very excited to welcome Catherine to our team. We have discussed our plan regarding these additions with our audit committee and KMPG and believe that the additional staff will be a material staff and in removing the internal control deficiencies noted by KPMG.

In addition to the new accounting staff, it also beats up our legal team. We’ve recently hired Kurt Yost as our General Counsel for Miller. Kurt had 15 years of corporate law experience including substantial work in corporate finance and mergers and acquisitions. Kurt will be supported by our existing staff attorney and newly hired railcar. The additional legal staff should help us to reduce the cost of our compliance and transactional legal work.

In April of this year, we issued a new class of series A cumulative preferred stock in a private offering. We raised $10 million from the sale of preferred stock that were used in part to fund the drilling of KF-1 with the Rig 34 and the drilling of order. In June after the close of our fiscal year end we negotiated a new $100 million credit facility with Apollo Investment Corporation that has a $55 million borrowing base has longer terms than our previous credit facility and has a lower interest rate and has improved repayment provision that will be passed into our cash flow during the next year.

We used part of the initial draw to payoff our previous credit facility and to redeem the preferred stock. Again we focused on closing a straight debt deals, so we will not diluted our existing shareholders, no options or warrant for granting the conjunction with Apollo deal. We believe the new credit facility come out with our cash flow from operations will be sufficient to fund our growth in the coming year. We are very pleased with this new funding is in place in advance of Rig 35 coming online so, we would have the resources to pursue our drilling program this year.

Before I turn the call over to David Hall, I want to highlight an additional lease that we acquired in April and new pricing contract for oil produced in Alaska that we signed in March will have a positive impact on our revenues going forward. Miller was awarded the Susitna Basin Exploration License No. 5 on April 1, 2012. This award includes an exclusive 10-year license to explore for oil and natural gas on 45,764 acres adjacent to the land that we have a license for the Susitna Basin. With this new license, Miller currently has interest in 580,000 acres in Susitna Basin.

Our new crude oil sales contract with Tesoro was signed in March and is based on the Alaskan North Slope index. The ANS index strategically allowed our Alaskan production with the ANS index while also resulting in a higher price for oil services (indiscernible). For example, the recent price for West Texas base crude was about $90 a barrel compared with ANS price is almost $106 a barrel. The ANS index has originally been crossed from $8 to $15 a barrel higher than what we’ve previously received in the West Texas based contract. Obviously, this will have a very positive effect on our margins going forward especially as we ramp our production this year.

I’m very pleased the Miller reported record oil production and record revenues in 2012. I am also excited about potential increase in our production in fiscal 2013 as we benefit from the deployment of Rig 34 for onshore drilling and Rig 35 for offshore drilling.

With that, I will turn the call over to David Hall to provide more detail on our operations and production plans in Alaska. David.

David Hall – Chief Executive Officer, Alaska Subsidiary

Thank you, Scott. Well, I’ll start with an update on Rig 34 as Scott mentioned the rig construction has been completed and we’ve since put it to work. First, on Kustatan Field No. 1 well, KF-1 for short, it is the gas well that has produced nearly 0.4 Bcf that it reached the end of its productive life in 2010-2011 timeframe.

We started looking for additional behind pipe gas opportunities as well as other uses for the well bore including using it from our disposal well. We discovered additional gas opportunities on the Beluga and Upper Tyonek Formation. We then permitted for the proposed work over for both the behind pipe gas opportunity as well as disposal well. The work over design and corporate to the flexibility of both, so that in the event, the additional gas opportunity did not materialize, we could simply activate the disposal well option, which would support our vastly increased grind and inject operations.

We currently have ongoing grind and inject operation and we believe that we’ll grow to be a very lucrative business not only from dealing from our own company generated materials, which lowers our drilling cost, but also third-party materials was generated revenue. Under the proposed, I am sorry – under the disposal well scenario, we would take drilling mode and cuttings grinded into small particles and injected in the permeable sands. They would also serve as a redundant backup to our current disposal well. Rig 34 executed the prescribed and permanent work over on our KF-1 with ease and we are very pleased with its performance.

Post KF-1 work over, we then conducted a well test. They show proof of hydrocarbons, but unfortunately it appeared wet. We decided before we had swap it over to a disposal well. We would attempt to dewater the gas filling of interest and hopes that the gas would follow. We are about to start this next step, but either way, we feel that KF-1 will be utilized as a gas producer or a disposal well.

I’d like to also update on the status of the drilling of our order prospect, orders exploration, gas prospect located approximately 10 miles north of the Beluga gas field and 34 miles west of the City of Anchorage. Order well number one was recently drilled to a depth of approximately 5680 feet in the 9-acre outer prospect, which is in the Beluga gas formation. Beluga gas sands are very prolific and productive in the Beluga gas field, which produced over a Tcf of gas. And the (Ivon River) and Luis River are two other nearby productive gas fields. Our third-party engineering reserve report showed order to hold 45 Bcf and up to 13 wells. While drilling order number one, the (indiscernible) reported two significant hydrocarbon gas shows and the zone of interest, both showed high levels of methane gas proving the presence of hydrocarbon and the indication of permeability.

The electric log showed good resistivity and porosity. Although, the well has been drilled and logged, additional work is needed to fully evaluate the Beluga formation. That consist of conducting petrophysical, geochemical, geo-work porosity water saturation, permeability density in clay, mineralogy and sensitivity just to mention a few. In addition, we plan to conduct a chemical treatment and/or a hydraulic fracture to stimulate the well. These are two processes that are commonly performed in wells in the Beluga formation and we are actively working. It would expect it would not take more than two months to complete this. But this depends on how quickly we can complete our assessment and stimulation.

We are very excited about the order number one with this great number of gas shows and proving gas charge sands as well as confirmation of the geological structure as originally identified by our seismic. But we still have high hopes for the order that will become a very prolific gas field. As we evaluate the order structure, additional wells maybe planned in the prospect that target the same Beluga sands and the underlying Tyonek Formation.

Moving on to an update on Rig 35, as everyone knows, we’ve been working very hard with the rig construction and assembly contractor to finish the rig safely as soon as possible. And as per the rig purchase contract, it included a $500,000 incentive on the front end and a $250,000 payment on the front end for the rig build within 60 days of signing the contract, and on the back end, $250,000 payment, if the rig was assembled within 60 days once the rig arrived in Alaska.

Despite these efforts that took longer than expected, however, to-date there has been no reported injuries or accidents. And we have a well-built rig of exceptional quality and design that will provide years of dependable service.

Regarding the current status I’m happy the report that Rig 35 is assembled and has been inspected about the State Rig Inspector. The inspection is a very rigorous and thorough process for any new rig to the State of Alaska to ensure it’s capable of performing its intended task as well as providing well controlled at all times. We already went through the commissioning stage where the systems are functionally checked for safe operations. We expect to complete the clean up identified items during the rig inspection over the next few weeks and plan to move into the first work-over. The first work-over is, are you one well that entails removal of old failed ESPs and the replacement with a new one.

Rig-35 a new twang of work-over drill pipe on board already as well as new ESP and cable outstanding by onshore. We’re extremely excited with the huge potential RU-1 it has especially few – especially for successful remove on the yield completion and implementing well bore optimization like we employed on RU-7 with great success. The re-completion on RU-7 doubled production and we hope that the same will occur on RU-1. RU-7 continues to perform exceptionally well with double historical crude oil rates with an approximately 55% water cut and a 13.9% decline rate in sense the 2011 work-over, which is down from 27% historical decline, so we’ve just seen a great success post work-over.

The key point here is we're running RU-7 at minimum speed, which means that the well is capable of producing more. We expect to ramp up its production as we bring on more wells and reduce our concentration risk. Much of the success is due to the completion on well bore optimization. We believe brining our structure will continue to be great success with these techniques and Rig-35 availability to continue out on our plans. Moving on to West Mc, West McArthur River unit, we currently have three crude oil producers (indiscernible) 1A, 5 and 6 current production from this field alone is approximately 750 barrels of oil a day with a field decline curve at 10.3% since the 2010 work-overs. West Mc production continues to be constant and reliable. We have identified three infield development wells, two oil and one gas and hope to drill them over the next two years. We believe West Mc has a lot of life left in it especially if you consider the fault separated opportunities to the North that could hold new discoveries.

Before, I move onto the midstream assets I want a mention the May 2012 for calendar year lease sale we participated in. We were successful high bidder on 18 tracks, covering 78,000 acres. On seven of the tracks we out bid other interested oil and gas companies. The added acreage will enhance our existing prospects area coverage as well as expand our oil and gas prospects to the east side of the Cook Inlet, who have been evaluating promising potential.

Lastly our ramp up with updating everyone on the midstream assets as I'm always excited to talk about our midstream assets and their potential, because there are no other facilities nearby that are as new as ours or have the access capacity for ours to process third party oil and gas. Our midstream assets include facilities located on the west side of Cook Inlet with the ability of processing not only company production but third party production as well. Nearby facilities are at near capacity are over 30 year – are over 50 years old. We’re in discussions with folks in the Cook Inlet regarding not only oil and gas processing, but exporting power as well. Our facilities have state-of-the-art power generation network that could easily export power to the region.

In addition to our current midstream assets, we are also looking at expanding them with an oil pipeline leak in the west side of the Cook Inlet to the East side assuring a continuous, reliable, and a cost effective way to transport our crude oil to Tesoro located in Nikiski. We saw a need for such a pipeline over two years ago and started preliminary design and engineering studies and we are about to enter into an open season process with our current operators as well as newcomers are asked if they’d be willing to use the new line or bill.

We’re also moving forward with final engineering and permitting and hope to have the project fully sanctioned by year end with a planned installation of summer of 2014 and completion by fall of 2014. We believe this project will add to what we already have the newest most modern, most flexible facilities in the Cook Inlet and will fit in with our plans to maximize the value of midstream assets. Scott, I am turning the call back over to you now?

Scott Boruff – Chief Executive Officer

Thank you, David. I want to thank you and your team for your continued excellent work in Alaska and specifically for your work on Rig 35. We plan to provide investors with an updated report on Rig 35 once we receive certification and have started our drilling program in Osprey platform, which should be the next few weeks. I want to now turn the call over to David Voyticky to provide a more detailed update on our financial results for the fourth quarter. David?

David Voyticky – Chief Financial Officer

Thank you, Scott. We completed fiscal year 2012 with solid year-over-year growth in revenue. Our revenue grew 55%, a $35.4 million, which represents a $12.6 million increase over the same period last year. The increase was due to increased production from our Redoubt Shoals field in Alaska and increased on our average realized oil price. Our net production for fiscal year 2012 increased 78,087 BOE or 24% to 405,799 BOE compared with 327,712 BOE last year.

Broken down by region, Alaska contributed 90% of our net production and Tennessee contributed 10%. Our average realized sales price per barrel for oil for the quarter was $93.10, which is an increase of $17.35 or a 23% increase over the same period last year. Our fourth quarter revenues rose 38% to $8.9 million compared with $6.4 million in the fourth quarter of last year. Our expenses for the fourth quarter increased $4.4 million or 37%, $16.3 million compared with $11.8 million for the same period last year, reflecting our increased pace of activity in Alaska. The largest increases were in oil and gas operating costs and non-cash G&A expenses.

The increase in our oil and gas operating costs were directly attributable to restarting production from our Redoubt Shoals field. The Redoubt Shoals field, which includes the operating cost of both the Osprey platform and the Kustatan production facility with non-operation until May of 2011. G&A expenses increased $3.6 million or 65% to $9.3 million compared with $5.6 million the prior year. The increase in G&A expenses was primarily due to increase in the non-cash compensation and professional fees.

Non-cash compensation expense is the calculated expense for the period related to the value of stock options, warrants, and grants that we issued to our employees and others as an incentive in lieu of cash compensation. We have also experienced a significant increase in professional fees due to higher litigation costs, the implementation of our SOX compliance programs and subcontract internal audit fees that were previously not required.

Our fourth quarter results included other expenses of $4.3 million compared to other income of $4.1 million for the same period in fiscal year 2011. The decrease since last year was due to a combination of a $6.9 million gain on acquisitions during the fourth quarter of 2011 and a $1.3 million increase in our loss on derivatives compared with the same period in the prior year. As I have noted in past calls, our derivative instruments – investments result in the earnings volatility as the result, but no, we are not using hedge accounting for our commodity derivatives. This resulted Miller effectively recognizing all realized and unrealized gains or losses associated with the derivatives in our earnings each quarter.

Our net loss for the fourth quarter was $8.4 million or $0.20 per share. Our net loss increased from the same quarter last year due to the increased cost from operating the Redoubt Shoals field, non-cash compensation, professional fees, and interest expense as well as the net loss on derivates without a proportional increase in revenues.

Regarding our cash flows, we generated $6.9 million in cash from operating activities in 2012. This is down slightly from $7.7 million in fiscal year 2011 largely due to changes on working capital. Our net cash used for investment activities jumped $22.6 million from the prior year due primarily to the purchase of Rig 35. This increase was funded from our new financing activities in fiscal year 2012, which included the proceeds from borrowing on our (indiscernible) credit facility and the issuance of preferred stock at the end of this fiscal year.

Before I turn the call back over to Scott, I want to briefly comment on our expectations for Q1 of fiscal 2013, the two transactions that will have a positive impact on our first quarter’s results, the first we sold the generator from our Kustatan facility in May for $2 million. It’s another operator in the area. The generator was one of our midstream assets we acquired in Alaska and was surplus to operations. We are also looking at other opportunities to monetize our midstream assets by using our excess capacity to generate revenues from other oil and gas – to other oil and gas producers in the area. As David Hall mentioned, we have entered into three cuttings and disposal contracts with some of our neighbors, but we will dispose of their ways through our injection wells.

We also booked a $4.3 million gain during the first quarter on hedging swaps that we have in place for our crude oil production in Alaska. As we’ve noted previously, we switched our pricing index for the oil we sell to Tesoro and Alaska from NYMEX to Alaska North Slope. And accordingly, we switched our hedges from being based on NYMEX WTI Cushing Index and we placed them with netted against the Brent index, which historically closely tracked the Alaska North Slope pricing that will be used going forward with our sales to Tesoro.

I also want to give a update on our outstanding SEC comments. As noted in our 10-K, the SEC has been reviewing our 2010 10-K and our 2011 10-K. This common process began in April 14, 2011 and was continued through several rounds of comments. I am happy to report that on Friday, we received notification from the SEC that they have completed the review of our filings.

With that overview of our financial results, I’ll turn the call back over to Scott.

Scott Boruff – Chief Executive Officer

Thanks, Dave. Before I open up the call to your questions, I want to comment on a few other matters. I want to close by saying how excited we are about our prospects in the Cook Inlet in Susitna Basin at Alaska. The Cook Inlet has produced approximately 1.3 billion barrels of oil and 7.83 in cubic feet in natural gas. Our Osprey platform is the newest platform in a Cook Inlet from the 16 platforms in the inlet. We believe it will provide Miller with significant drilling opportunities going forward, the first which we work in the 5 wells that were previously producing on the Osprey platform.

As David Hall mentioned, we are also looking at the opportunity to build an 8-inch pipeline that restricts 25 miles across the Cook Inlet to significantly reduce our transportation cost. The proposed $53 million pipeline is being planned to carry 90,000 barrels per day that exceed the current production in the current area, but the lower transportation cost associated with a new pipeline would benefit Miller as well as other operators who are currently paying $11 to $12 per barrel for transporting oil by shuttle tankers from the Inlet’s west side to the Tesoro Corporation refinery on the east side.

We would expect the new pipeline to reduce the expense of getting oil to Tesoro to about $4 per barrel, which would result in a $7 to $8 savings per barrel at the savings of two-thirds. We believe the lower transportation cost will allow Miller and other companies such as Hilcorp and others, which now operates nearby Trading Bay and Granite Point field points to boost west Cook Inlet development.

Engineering is now underway on the pipeline and construction could begin in 2014 with oil shipments beginning in late that year. We believe that the addition of the pipeline would add further to our value of our midstream assets in the region. Before we open up the call to questions, our council has about just not to come pending litigation around certain questions relating to the filing of last year’s 10-K discussions, discussions with the SECs are offered themselves.

That concludes our formal remarks for today’s call. Operator, we would now like to open up the call for questions.

Question-and-Answer Session

Operator

(Operator Instructions) We’ll go first to Neal Dingmann with SunTrust.

Neal Dingmann – SunTrust

Good afternoon fellows. So, I have few questions Scott maybe for you and then maybe one other David as far as just overall when you see kind of expansion opportunities Scott number one you clearly have a lot of acreage already that are you pretty contained with what you have and just to drill up now that you got looks to be that second rig running as well maybe you can give me a brief just overview of kind of CapEx?

David Voyticky

Yeah I can take the first part of that. We were excited Neal to have the acreage position that we have. We believe its the second largest – we used to be the largest lease sale and export rig positioned but now we’re the second. But as noted at this past lease sale again we bid on a lot of tracks and got most of everything we bid for, we were the second largest bidder, but we had close to 750,000 total acres in exploratory lots in Alaska. So, we’re comfortable with what we have under lease right now and we just plan on getting our rigs more onshore and offshore to drill those the own prospects and exploratory prospects and bring in JV partners to drill the rigs.

Neal Dingmann – SunTrust

Okay and then wondered you mentioned about CapEx I was just wondering you got a slide out not it’s terribly long I mean few months back or quarter or two back pretty outline I guess what I am trying to get an idea now that you got Rig 34 and 35 working. Where do you see maybe an update what’s your CapEx guidance would be maybe for the year from you David Voyticky. And besides RU-1 if you can give us an idea of both and I think Dave Hall mentioned some of these what both 34 and 35 will kind of be going after if you kind of lay out kind of milestones for the next two to three quarters?

David Voyticky

Hi David, why don’t I start and then you can supplement okay. Neal as you mentioned with Rig 35 being complete essentially the drilling program that we outlined for our offshore activities will begin. So, you can look at the same timeline and essentially this plug-in starting in August. What we had originally contemplated was RU-1 and that’s a two week project that was previously producing in the 200 or 300 barrel of oil a day range. We’re expecting that we’ll re-complete it at that rate or better. Our second project will be RU-2 that’s the well that was previously producing at about 600 barrels oil per day and we’re into a sidetrack there that’s expected to be in the 45 to 60 day range. And each of the sidetracks RU-4, RU-3 and RU-5 are expected to have similar timeline. In terms of the CapEx spend RU-1 has a $2.5 million gross CapEx AFE associated with it. As you know we expect to get 40% of that back from State of Alaska, so the net cost is about $1.5 million.

Each of the sidetracks we contemplate spending about $10 million gross and having a net CapEx after the tax credit of about $6 million. So, when you look at the beginning of our offshore program and those five reworks and we’re looking at a total of $43 million approximately on a gross basis and a little more than $25 million on a net basis. And we’d expect to be complete with those reworks by the end of March next year. I think as we talked about previously this rig we build to operate 12 months out of the year irrespective of whether or not that it’s direct. Once we’re complete with the sidetracks we’ll begin with some new drills new wells RU-8 will be the first of those. Historically with these wells that were drilled before 10 years ago they were drilled on average within 90 days. We’ll expect to build should replicate that timing on the new drills or perhaps a little bit better with this rig. So, from the end of the first calendar quarter in 2013, we’d expect to do one new well per quarter thereafter.

And that we’d expect that the IP rates that they mirror what occurred previously would be in the 1000 barrel a day range. With respect to Rig 34, it’s a little bit less clear. As David mentioned, we are currently completing the work on the ordered, first ordered well. Once we understand the sands and the clays that we are dealing and have a good idea of what the right drilling program is. We’ll either drill a second well there towards the beginning of September or go and drill a new well in September for Olsen Creek.

And depending on the result of those two fields, we effectively think that we could add a new well on every month to month and a half or so into those two fields. The ordered well had a gross cost of $7 million, net cost of a little bit under $5 million. That includes the cost of using our own rig, I mean we’d expect to continue as we continue this drilling program to able to improve those costs as we go forward.

Neal Dingmann – SunTrust

Okay. And then two more if I could, could you answer those? Just on the midstream for you, David Hall, David mentioned about entering those three cutting disposal contracts with neighbors or even maybe for Scott just give me an idea obviously when you bought into that, you’ve bought whole lot of infrastructure up there. Just trying to get a sense of what other opportunities are around there either around the power gen to some of these others or I guess trying to look at on a valuation standpoint, what other type of sales or earnings could be derived from your midstream?

David Voyticky

Neal, I’ll take a little bit of that and I’ll let you add on David Hall to it. As we mentioned last quarter, our midstream is something that’s never been looked at. Hall, we have looked at it strong with our cuttings contract that it’s on. As you mentioned, we signed three cuttings contracts and we are spending capital to get the equipment to get that up and going. So, we have had about a month work of work in actually putting those contracts to work. And I think in June, we received revenues that are close to $300,000 on that, but we have just in the cuttings contracts alone there, we have got the capacity to put about 500 barrels a day with our cuttings down the house.

We charge anywhere from $250 to $500 a barrel cuttings of being what kind of cuttings they are and that compared to taking the ship in it somewhere else with our charge, $700 or $1000 a barrel if you have to ship it off of there. So, we expect that be significant as we ramp up. So, clearly, we are excited about that and we’ll be signing more of those common. And so we’ll be happy to update you on our quarter as that business developed and it’s got a very nice margin with it. Also we are winning camp space, all the procedures up there shooting 3D seismic, so we get some very nice money of winning camp space on a daily basis. We are acting as a general contractor using our equipment to build roads and build past that.

And as we made them before, we see ourselves exporting power to the region. We have 15 megawatts of power that we can sell. We are using currently 1.5 megawatt our sales. Oil and gas processing as we noted before we have the capability of processing up to 50,000 barrels a day of oil for ourselves and others. And so with the expanded pipeline project with us taking the pipeline project and you expand it in the west side, the east side, we see that businesses (indiscernible) and so we are excited about that. And David Hall, can you add anything to that?

David Hall

I am super excited about our midstream capabilities. Same points you were making those guy from grind and injection, that’s going be a fairly big piece of it. I mean, we are the lowest cost option right now for many operators to send their cuttings and my products too. Power generation can be very big. Kustatan production facility is very easily expandable on the power side. Oil and gas processing, we’ve been in discussions with one operator already are soon going to be operator on the setting up a facility sharing agreement. And the new pipeline we call it a pipeline. We see that could be a very big revenue stream, but from camp rentals, tank rentals and also as Scott already mentioned too, building roads and pans were one of the soon-to-be operators too. We are really capitalizing on increasing our midstream revenue stream.

Neal Dingmann – SunTrust

Got it. Thanks David. And then last question guys if I could made for David Hall and Scott, I was just wondering, David on the – or I’m sorry for Dave Voyticky on just the G&A obviously said it was more non-cash. Just wondering if you could give idea on kind of how you see that tracking forward. And then the last question, Scott just want an overall word of round, currently we are about to current production and if you could throw any sort of just sort of maybe production range or estimate out there towards the end of this year?

David Voyticky

Yeah, I mean, Neal on the non-cash G&A and that’s largely related to the past option grants that were indicated and previous filings over the past year and we anticipate bringing on one or two more employees that will receive grants of a similar nature. But I think where we look at the businesses is our cash flow from operating activities and essentially we were a little bit down, but that was primarily related to changes and works and capital.

With respect to cash G&A cost, the big change there has been additional personnel that David has added to his team as we get closer to having a (indiscernible) drilling program and the changes that we have made here corporate and bringing on additional accounting staff and Kurt Yost to lucky to have joined us and from a cost standpoint, Kurt joined us year ago when we did the facility we paid and closed to $0.5 million in legal closing cost and Kurt accomplished closing the power transaction with probably less than 50,000 outside, 75,000 so, you paid from twice over and we would expect really going forward that’s been a big line item for us in terms of legal expenses that we’ve reached deductible on our policy with respect to the shareholder losses so, those costs are now this quarter are going to be covered by the insurance policy. With Kurt addition that’s going to be another strong point so, we think to keep that below where was last year.

Neal Dingmann – SunTrust

On production guidance again as everyone noted and our sales now that the offshore Rig 35 is completed waiting certification. We see our same program starting up in August so David Voyticky get RU-1 – with RU-1, RU-2, RU-4, and RU-3 getting completed this year by December, which would give us roughly 17,000 barrels or 2000 barrels a day to go along with our current 12,000 barrels a day. So, we see about 3,000 barrels a day come out of a full stop and in the onshore exploration wells that were drilling and i.e., KF-1 and Otter and Olsen Creek and so I would get from three to five depending on how many exploratory wells production comes on shale. So, still feel comfortable given the 4000 boe a day year end and hopefully depending on what those looks like it could be substantial?

David Voyticky

It’s interesting to note, David to comment on that is the activity in the Cook Inlet has stepped up quite a bit and there are multiple companies that are bringing rigs into the inlet and we heard of at least three companies that are bringing additional rigs in the inlet this winter and we think that for expansion of the development of our West McArthur River field as well as the adjacent and we are not going to have to go through what year along process. We think we will be, they were opportunistically and cost effectively mobilized rigs that are being brought to the inlet.

Neal Dingmann – SunTrust

It’s great update. Thanks guys.

David Voyticky

Thank you. Thanks Neal.

Operator

We will go next to Michael Cahill with Compass Investments.

Michael Cahill – Compass Investments

Thank you, guys. I have a couple of questions. My first question is on your Alaska reserves at the latest Ralph E. Davis report for FY ‘12 showed a 48% increase in the value of your proven Alaskan oil and gas reserves over FY ‘11. I was just wondering over the next 12 months on the Osprey platform what impact do you expect these five new wells RU-1 through 5 to have on the quantity and our value of your reserves? And then just lastly you were talking about the other companies and the other activity taking place in the inlets, I had a question about Apache. Last month Apache announced at an investor conference that their ongoing seismic survey of inlets had located a new field that they reported could contain potentially between 400 million and 600 million barrels of oil. Can you tell us where this field is in relation to your Kustatan assets and if that’s onshore or offshore? Thank you.

Unidentified Company Speaker

Hey David Hall why don’t you start and we’ll chime in if necessary.

David Hall

Be glad to well as far as our reserves going down one main contributing factor is that we do the reserve reports. We have them conducted by a third party engineering firm annually. And of course we’ve produced over the past 12 months. So, that explains a lot of the production. One thing I would point out and I think you just mentioned that is even our reserves went down the value went up by about $115 million if take in on account the amount that we produced over the past year. So, the value went up, but that was mainly contributed to our pricing index restructure based of the Alaskan North Slope crude.

Michael Cahill – Compass Investments

And I was just wondering about historically when Forest operated those assets as you bring them back on line is that going to have an impact on your proven reserves in terms of the quantity?

David Hall

RU-1, 2, 3, 4 and 5 are already in the proved reserve class. So, really what it will do is it will – those work-overs and sidetracks will go basically from PUDs to PDPs. And RU-2, 3, and 4 and 5 basically have a PV10 value of in excess of $40 million each

Michael Cahill – Compass Investments

Yeah I think my….

Unidentified Company Speaker

To give you kind of sense of what we expect to happen as those wells come back online as Dave alluded to with the re-completion techniques that we used on 7, we saw a more than doubling of the production from RU-7 decrease in the decline rate and a substantial increase in the PV10 value that was described to you previously. So, if we see a similar sort of improvement in the other wells, the answer is yes you could expect a very significant increase in our PV10 values. It’s going to really depend on the performance of the wells, but as you know the reserve engineers will look at the IPs and the decline rates and the reassess the reserves. And the way we’ve looked at this is that the data when these wells were previously operating under the last operator are pretty poor because they didn’t have the rigs, they didn’t have the capital to have these wells fully functioning. So, we’re in a much better position and we think that we’ll see some of the result as we saw in 7 and as we have those results you could expect to see some increases in the reserves.

Michael Cahill – Compass Investments

Thank you. And then on the Apache field can you tell us where that is – that this is the one that the disclosed to the conference a few weeks ago where that is in relation to your leased assets?

Unidentified Company Speaker

Yeah, if you are referring to the acreage that they plan on drilling first, from my understanding it’s located on the west side of the Cook Inlet which is going to be about roughly 10 miles North – I’m sorry South of some of our existing working interest acreage.

Michael Cahill – Compass Investments

Okay. Thank you very much.

Unidentified Company Speaker

In terms of the timing Mike I think we’re looking at is obviously we’ve got playful with our redevelopment opportunities, but as you noticed that we been buying up additional leases on the West side and few on the East side. And we can continue to accumulate the position to see how Apache and others do and feel pretty good about our land holdings.

Michael Cahill – Compass Investments

Good luck guys. Thank you.

Unidentified Company Speaker

Thank you, Mike.

Michael Cahill – Compass Investments

Yep.

Operator

Moving next to Jeffery Connolly with Sidoti & Company.

Jeffery Connolly - Sidoti & Company

Hi guys. Can you talk a little bit about the increasing these operating expense in the fourth quarter and where you see that going over the next fiscal year?

Scott Boruff

David, do want to go through that?

David Voyticky

Be glad to it was several moving targets there in fact there is one is supporting the G&I operation as well as increased activity associated with all the various supports that we offer to operators in the Cook Inlet. For example, we’re renting tank space, we are providing fuel logistic support for some of the operators and then of course to support our G&I operation.

Jeffery Connolly - Sidoti & Company

And David maybe before coming a little bit on what we expect to happen with per barrel basis as the Osprey platform becomes more fully functional?

David Voyticky

Be glad to of course lease operating costs are basically a factor of your direct operating cost as well as production. So, of course as production increases we would see our lease operating cost drop. Per every incremental barrel increase we see a lease operating cost increasing by a little less than $2 a barrel. So, we’ve got fixed operating cost we don’t really see that going up very much as we add new production. We do have some of the lowest lease operating costs in the Inlet.

Jeffery Connolly - Sidoti & Company

And then getting back to the pipeline is that all the permits are set for that and do you plan to bring in partners to develop it?

David Voyticky

Well, as for us the new pipeline to transport on this pipeline, we do not have all the permits to-date. However, we are vigorously working on obtaining those permits. And we are working with the several interested parties on the fund on the pipeline. We've got several very, very interested people on wanting to fund the pipeline.

Jeffery Connolly - Sidoti & Company

Okay, thank you.

Operator

We'll hear now from Jonathan Fite with KMS Investments.

Jonathan Fite – KMS Investments

Good afternoon gentlemen. Can you comment it looks like with the Apollo line combined with I guess the issuance of another preferred you’d have about $30 million of capacity to fund your $43 million CapEx plans, can you talk a little bit about funding model for the outfield as well as the onshore fields going forward?

Scott Boruff

Yeah you stated funding model.

Jonathan Fite – KMS Investments

Yeah. I’ve just got – how does the CapEx plan gets funded, if you can talk a little bit about that?

Scott Boruff

Oh sure, sure. As we talked about little bit earlier in the call. Our financials have been submitted on time and we expect that sometime during months of September we’ll file in shelf. We’ll have three funding sources. We will look at different preferred equity options as well as common equity options. And then of course it would be Apollo facility. The most likely outcome is going to be to raise additional $15 million to $25 million in equity and utilize the Apollo facility for the remainder of the program. The timing of which will depend on our need for capital with respect to shallow gas opportunities. The immediate projects we have funding for the summer.

So, we expect that between those two sources we’ll be held to complete all the re-drills on the Osprey platform as well as the exploratory work we want to do with respect Olsen and Otter. Now the Apollo facility has a – one difference between the Apollo facility and the (indiscernible) facility is that if we are in compliance with the covenants the Apollo facility turns into a borrowing base facility and the borrowing base is calculated based on our proven reserves in our PDNPs. So, that combination of our assets Apollo did a hard asset appraisal, which I don’t think we have posted yet, but at some point we may just post that on our website. It showed third-party appraisal should we have a little over 190 million fair market value of assets aside from our reserves. And then lastly, we received some credit in our borrowing base for the Alaska tax credits as we file them. So, we think that the Apollo facility will be fully utilized by this time next year and as we have additional opportunities that come up and as our equity becomes fully valued, we’ll look at more of the equity options if we have abilities to accelerate.

Jonathan Fite – KMS Investments

Great thanks guys

Scott Boruff

Thank you.

Operator

And that appears that’s all the time we have kept for question. I’ll turn the conference back to our speakers for closing remarks.

Scott Boruff – Chief Executive Officer

Thank you for joining us today to provide you with an update on Miller Energy strategy’s financial results. We are very excited about the future Miller and the potential of our properties. We plan to keep you updated on operations on future calls and look forward to you joining us. That concludes today’s call. Thank you.

Operator

That will conclude today’s conference. Thank you all for joining us.

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