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Miller Energy Resources, Inc. (NYSE:MILL)

F2Q13 Earnings Call

December 10, 2012 4:30 pm ET

Executives

Scott M. Boruff – Chief Executive Officer

David M. Hall – Chief Executive Officer-Cook Inlet Energy

David J. Voyticky – President and Acting Chief Financial Officer

Analysts

Neal Dingmann – SunTrust Robinson Humphrey

Jonathon Fite – KMF Investments

Operator

Good afternoon, and welcome to the Miller Energy Resources Fiscal 2013 Second Quarter Conference Call. This call is being recorded. At this time, all participants have been placed on listen-only mode. A question-and-answer session will follow the presentation, led by the Company's CEO, Scott Boruff.

Before we begin, I would like to call your attention to the customary Safe Harbor disclosure in the Company's press release regarding forward-looking information. Today's conference call and webcast may include forward-looking statements. Forward-looking statements involve risks and uncertainties including, but not limited to, the implied assessment that the Company's oil and gas reserves can be profitably produced in the future; Miller Energy's ability to fund its operations and business development plans; operating hazards; drilling risks; fluctuations in the prices received for the sale of oil and gas; litigation risks; and changes in government regulations.

Additional information on these and other factors, which could cause Miller Energy's actual results to differ materially from those anticipated and these forward-looking statements 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, as amended. To obtain copies of Miller Energy's SEC filings, please visit their website at www.millerenergyresources.com.

All forward-looking statements attributable to Miller Energy or to persons acting on its behalf are expressly qualified in their entirety by these factors. Investors should not place undue reliance on these forward-looking statements, which speak only as of the date of this conference call. Miller Energy assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change unless otherwise required under securities law. Miller Energy is not responsible for changes made to this call by the conference call company or internet services.

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

Scott M. Boruff

Thank you for joining us this afternoon to review the results of our second fiscal quarter ended October 31, 2012. Today, I’m very pleased to report on the progress we made at Miller since our last earnings call. To begin, I will provide a brief overview of our comps missed in the last quarter. Following my review, David Hall, CEO of the Alaska operations; and David Voyticky, our President and Acting CFO will provide additional detail on our financial results. Upon completion of the management presentations, we will open the call with your questions.

During the second quarter, Miller received approval to begin drilling with Rig 35 on the Osprey platform, and we completed our first workover just before the quarter closed in late October. We removed about 31,000 pounds of debris and obstructions from the well casing on RU-1 and we were very pleased with its initial production of 482 barrels per day. Rig 35 is the newest drilling rig in the Cook Inlet, and its size and versatility allowed us to complete a much better workover of RU-1 than would've been possible with the older drilling rigs.

We are very pleased with the rig's performance and we learned a lot about Rig 35’s capabilities that will help us in working over future wells on the platform. RU-1 averaged about 260 barrels per day in November and we expect its output will contribute meaningfully to our third quarter results. Unfortunately, we received only a few days' production from RU-1 in our second-quarter results, so its outputs had no material effect on our second-quarter's revenues.

As reported in second quarter’s release, we expect our third quarter oil production to be ahead of the 89,234 barrels of oil reported in third quarter of last year. This is due largely to the contribution of RU-1 coming online that was offset partially by RU-7 being out of production for most of the third quarter. We experienced a failure of the ESP on RU-7 in mid-November. Given logistical issues of moving an object of size and Rig 35 across the platform, we elect to complete its currently scheduled projects before using it back to pull the RU-7's pump. We believe this will be the most cost effective way to get the RU-7 back online and maximize return we see on Rig 35.

Miller installed the existing pump on RU-7 about 17 months ago, and it met our expectations in terms of operating lifespan. We are disappointed in the timing of the pump’s failure, but we also recognize that it was due for a routine replacement. We used Rig 35 to complete RU-3, RU-4, RU-2 and RU-5 before making it available to service RU-7. Rig 35 is in final days of working over RU-3, a gas well. And David Hall, today, will provide a more detailed update on the status for completing RU-3 as well as an update on our drilling program with Rig 34, in his remarks.

Before I turn the call over to him, I wanted to comment on our assets in Tennessee. We’ve grown our base in Tennessee, through acquisitions like the most recently announced purchase of assets from PDC, to over a total of 180 producing oil wells and 180 producing gas wells, we plan to begin an aggressive workover on many of these wells to increase our Tennessee production. This effort will be led by David Wright, Executive Vice President of our Tennessee operations.

One of his first projects will be the completion of our first horizontal drilling program in the Mississippian Lime. We received the permit for this project in late October, and began drilling this project late last week. We believe this may be the first horizontal well to be drilled in the Mississippian Lime in Tennessee, and possibly East of the Mississippi River. We expect this drilling program to be complete before year end, and look forward to reporting our progress.

In the coming months, David Wright and his team have planned an aggressive workover program that we believe will create more value, due to a greater interest in these wells. We expect an increase in the daily production, of both workover and recovering oil left in plays, with the horizontal well program.

Today, I'm also pleased to report the rate of about $18 million through two preferred stock offerings to close during the second quarter. We completed the sale of $2.6 million both of our preferred B offering at September 24 that has a 12% rate and no conversion option to common stock.

On October 5, we completed the sale of our preferred C offering, at a 10.75% rate that added an additional $15.8 million. The preferred C is registered with the SEC and listed on the New York Stock Exchange. It has a conversion option to the stock at $10 per share.

We also closed at the market facility with MLV & Company to allow us to make additional public offerings of preferred C at market prices, allowing us greater flexibility in accessing the capital markets. We were able to complete the series C offering under the S-3 shelf registration we filed in early September.

As I noted last quarter, this file was a very significant event for Miller in three key areas. First of all, it highlights that Miller cured all of its remaining deficiencies in an earlier public filing, and it kept us from raising our securities for sale to the public. Second, we believe that the access to the public markets will allow us greater flexibility in financing Miller’s operations and potentially do so at a lower cost of raising capital. The recent preferred offering certainly does demonstrate in fact.

And third, we believe that the filing of the S-3 highlights the improvements that we achieved in our financial reporting. We've worked closely with auditors and KPMG to achieve these improved results. And we're pleased that we received a clean opinion from KPMG regarding our financials for the past two years.

Since the last quarter, we added additional staff in our accounting departments including Financial Reporting Director, Internal Auditor, and a Staff Accountant. We believe these additions will contribute to the curing of material weakness in our turn of controllers reported as of our year-end audit. Our new staff is providing a strong complement to our accounting department led by Catherine Rector, Chief Accounting Officer. And we welcome them to the Miller Energy team.

I'm very pleased with the progress we continue to make as a company. And I'm also excited about the potential increases in our production in the second half of fiscal 2013 as we benefit from the deployment of Rig 34 for onshore drilling, and Rig 35 for offshore drilling.

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

David M. Hall

Thank you, Scott. Well, I will start with Rig 35 and its performance and ability to execute our workovers and drilling plans. As mentioned before, Rig 35 is the newest platform rig to the Cook Inlet in nearly 30 years. With that, we tried to implement many features into the design to accommodate not only workovers but also long, extended-reach directional wells planned for the Osprey platform. From rig fast trip speed time, brute torque for milling and drilling, to sheer pulling power, we’re very pleased with the Rig 35 ability to execute our plans as quickly and safely as possible.

Moving on to the Redoubt Shoals Field where the Osprey platform sets over, November production – reported production was over 10,000 barrels, with an average of 335 barrels per day. Current Redoubt production is down to between 200 and 220 barrels of oil per day, as a result of RU-7 ESP failure. RU-1 work over was a success by removing an enormous amount of fish that was attempted by previous operator to no success. We left one significant fish in the hole for the time being. The decision was made to stop fishing and return the well to production and that we would finish fishing at a later date.

Even though RU-1 production rate is higher than historical, we believe with the removal of the last fish rates can be significantly increased. RU-7 as already mentioned had an abrupt ESP failure, recently on November 12, after nearly 17 months of production. ESP failure is to be expected as commonly seen from 17 months to 24 months is a typical life of an ESP in the Cook Inlet. RU-7 performance not only meets our expectations, but exceeded it as well, with over double historical flow rates over double bottom-haul flowing pressures and a reduction in water cut all of which indicate a strong and vibrant future for the Redoubt Field.

RU-7 was producing an average of 226 barrels of oil per day prior to failure. The ESP change out is predicted to be short and straightforward, and is estimated to take seven days once the rig is over the well and ready to work. The timing of the ESP change out will depend on, when we skid the rig over the leg where RU-7 resides.

Since the ESP failure we have identified 50 feet of additional potential pay in the oil bearing Hemlock Sands. The permit has already been submitted and approved. The current plan is to finish all work on leg three, where Rig 35 is currently on, which includes RU-3, RU-4, RU-2, and RU-5 before we skid the rig over to leg two RU-7 unless we experience any delays in any of the sidetracks.

Moving on to RU-3, as everybody knows, we’re currently working over RU-3 well, a well that previously produced out of the G-zero Tyonek gas sands at a measured depth of about 14,000 feet. It was a strong producer, with a reported well test over 8 million cubic feet a day, and flowed for only a few short months, and recovered just under half a Bcf of gas, well under the initial recovery estimates. Production dramatically fell off, and the previous operator thought it was a formation matter.

However, we believe it was not a formation problem, but rather a surface mechanical issue due to the high pressure with only 4,000 PSI on the surface without a sufficient pressure-reducing device in place to keep the well head and associated piping from literally freezing off.

Our workover plan basically consists of removing all the old completion, reassessing the zone of interest, followed by the necessary device to effectively reduce the high pressure from without freezing. The workover has gone as planned, and the old completion and fish have been successfully removed and we’re currently running completion and expect to move right into well testing.

RU-3 is the only well ever completed in the Tyonek gas sands, which overlay the Redoubt Shoals structure. The well is completed on the southern flank of the Redoubt Shoals southern fault block, and has exhibit over 60 feet of hydrocarbon rich sands with very good permeability and porosity. Upon the success of RU-3 gas producer, it could further prove up additional Tyonek gas sands in Redoubt Field. We have also identified similar Tyonek gas sands in RU-4, which leads me into the RU-4.

RU-4 has a gas opportunity that we plan to execute right after RU-3 mainly due to the heightened gas shortages in the Cook Inlet, but also due to the expected short time needed to conduct the workover and access the gas. A previous operator conducted a drill stem test on the well in several Tyonek gas sands and found the lower Tyonek gas sand to produce at commercial rates.

The test showed an IP of 1.4 million cubic feet of gas a day. We’re hopeful we can exceed a higher flow rate based on the previous operators very short test period that did not fully recover the workover fluid possibly hampering flow rate. One thing I want to clarify is that RU-3 and RU-4 has excellent oil opportunities and are slated for sidetracks after they have depleted gas reserves or until such economic drivers dictate otherwise.

Moving on to onshore, I'll start with West McArthur River unit. November production produced was little over 21,000 barrels with an average daily production of 700 barrels. Current production comes from three oil producers, WMRU-5, WMRU-6, and WMRU-1a with an average field water cut of 68% and a gas oil ratio of 0.235 of which is used in operations.

We have various workovers planned, one of which is WMRU-7a. Current plans call to sidetrack the well to access Tyonek gas sands known to be prolific in the nearby West Forlands gas wells. The Company reserve report shows 5 Bcf with a reported PV10 value of 18 million. We hope to conduct the sidetrack in 2013. Also in the WMRU field is WMRU-2a well, which is a crude oil well currently shut in that we’re currently evaluating water flood activation, or crude oil reactivation options.

Directly adjacent to the WMRU field is our Sword play. A potential major new oil field, sort of a four way fault separated trap within the same plunging anticline. It is to the north of the prolific West MacArthur River unit field wells that have produced over 13 million barrels. Company has 3D seismic over the prospect that is currently planning to drill, and is currently planning to drill the Sword Number 1 well in 2013.

A 2000 horsepower onshore rig selection process has already begun. One exploration well was drilled in the virgin fault block with Hemlock shows over 600 foot interval. Current well design shows a surface location to be located on drill site pad the Company built in 2010 off existing West McArthur River unit production pad. Bottom-haul placement is estimated at 20,000 feet measured depth. Company reserve report shows over 800,000 barrels of oil with a PV-10 value of $41 million for the Sword Number 1 well with an estimated CapEx of $17.5 million which is a growth number.

Now, on to Otter, we conducted a hydraulic frac last summer. The frac went as designed and engineered, and consumed over 800 barrels of liquid propellant and 50,000 pounds of sand yielding a projected 53 feet of penetration over at the gas zone of interest. Once the frac was completed we went right into liquid removal as a result of the hydraulic frac, but remaining frac liquids are believed to be suppressing the formation gas from entering the well bore.

We have recovered about 200 barrels of frac fluid to date. One thing I want to point out while drilling the Otter well, we experienced mud pump problems that kept us from drilling to a planned depth of 7000 feet. We had to stop short at approximately 5,600 feet. As a result, we only evaluated a short portion of the prospective Beluga formation and none of the Tyonek formation.

Not only we purchased new mud pumps but we are ready planning a second well to a minimum depth of 7,500 feet that should yield more potential gas pay zones for evaluation. We still view Otter as a very promising gas field and expect to not only server as a potential gas source to maintain operations, but also become a net exporter as well.

Recently, we had to winterize the well head due to extreme cold temperatures until spring. We are also evaluating deepening the Otter 1 well to fully evaluate the Beluga formation as well as the Tyonek formation.

Now on to the Olsen Creek prospect. We have been working hard to construct and repair a total of 14 miles of road as well as building a new drill site pad, and is estimated to take two to three months to complete these tasks. We had previously planned to spud by the end of December 2012, but construction were delayed due to severe and abnormal weather resulting in road section washouts that had pushed our spud date to early summer 2013.

The Olsen Creek prospect as Northeast and on strike with production from Aurora 3 mile Creek field, other nearby fields include the Beluga River to the east which has produced 1.2 Tcf of gas; Lewis River, which has produced 21 Bcf; and the Pretty Creek, which has produced 12 Bcf.

Each of these fields encountered multiple gas reserves within the objective section. Multiple prospective zones are present within the Olsen Creek prospect. The initial well is ideally suited to evaluate the Olsen Creek structure. If successful, a potential of 24 wells maybe required to totally develop the structure.

The estimated potential for each well is up to 3.5 Bcf that could yield a potential reserve size for the field of approximately 84 Bcf. One thing I'd like to point out here is we have submitted the permit to drill to the state of Alaska and has just recently been approved.

And lastly, as a Trans-Foreland pipeline overview, our proposed new 8-inch diameter sales oil pipeline, which would move oil from the Kustatan production facility on the west side of the Cook Inlet to the KPL tank farm on the east side of the inlet, near the Tesoro refinery. Portions of the pipeline would be installed on the seafloor of the Cook Inlet. The purpose of the new line is needed to eliminate the risk of volcanic activity and ice movement to oil shipments through the Drift River terminal to eliminate the need to move oil and tankers across the Cook Inlet and reduce transportation expenses.

Currently, sales of oil on the west side of the Cook Inlet moves to the CIPL system to the Drift River oil terminal. Oil is then loaded into tankers and transported across the inlet to the KPL dock in Nikiski. The oil is offloaded from the barge the tanks at the refinery.

We are pretty far along with the permitting for the project now, and about to roll into final design and engineering efforts in January. The permit applications have been submitted to the U.S. Army Corps of Engineers and the National Marine Fisheries Service and the U.S. Fish and Wildlife Service, and the U.S. Coast Guard and the Kenai Peninsula Borough.

We are particularly pleased to have had our right-of-way application accepted by the State Pipeline Coordinator's Office last week. Commissioning of the pipeline is targeted for August 2014. This would be a common carrier pipeline which would improve not only the economics and lower the risk for Miller, but for all operators on the west side of the Cook Inlet.

So with that, Scott, I'm turning the call back over to you.

Scott M. Boruff

Thanks, David, and all the senior team for the continued excellent work in Alaska. And now, we'll turn it over David Voyticky to provide a more detailed update on our financial results for the second quarter. David?

David J. Voyticky

Thank you, Scott. We made significant progress during our second fiscal quarter, to bring Rig 35 online and begin our aggressive drilling program on the Osprey platform. As Scott noted, we completed the workover of RU-1 with an initial production of 482 barrels per day.

Total revenues in the second of fiscal 2013 were up 17% to $10.8 million, compared with $9.2 million in the second quarter of the prior year. The majority of the increase was from other revenues including Miller’s grind and inject facility and a road building contract in the Cook Inlet.

As we have mentioned in the past calls, we believe our midstream assets hold significant value for shareholders. And we believe these projects highlight the potential we have to leverage them in the future. Not only are we using the grind and inject facility for our own operations, but we are also selling excess capacity to other operators in the region.

In addition to the growth in other revenues, our results reflected a higher price for oil sold at the latest fiscal quarter, offset partially by lower production due to RU-1 being offline during the majority of the second quarter of fiscal 2013.

Our total net production for second quarter of fiscal 2013 was 78,145 BOE compared with 112,010 BOE last year. This decrease was due to RU-1 being offline during the majority of the second quarter of fiscal 2013, a normal decline curve and fluctuation in shipping schedules.

Broken down by region, Alaska contributed 87.8% of our net production; and Tennessee contributed the remaining 12.2% in the latest quarter. Our average realized sales price for the quarter rose 30% to $105.68 per barrel compared with $81.10 in the same period last year.

Our total operating costs and expenses were $16.9 million for the second quarter of fiscal 2013, as well as for the same period in 2012. G&A expenses declined 22% to $6.2 million, compared with $7.9 million in the second quarter of fiscal 2012, due primarily to a decrease in litigation-related expenses and insurance reimbursements received for covered legal expenses.

Depreciation, depletion, amortization, and accretion expense declined 24% to $3.1 million compared to $4.1 million in the second quarter of 2012. The decrease in depletion, depreciation, amortization and accretion was due primarily to the decline in the production from our Alaskan West MacArthur River field and RU-1 and our Redoubt Shoals Field being offline for the majority of the quarter.

Other expense in the second quarter was $3.9 million compared with other income of $656,000 in the second quarter of 2012. The change was due primarily to a $3.6 million swing in the loss on derivatives. Miller reported a $2.0 million loss on derivatives in the second quarter of fiscal 2013 compared with a $1.5 million gain in the second quarter of fiscal 2012.

As I noted in past calls, our derivative investments result in earnings volatility as a result of Miller not using hedge accounting for our commodity derivatives. This results in Miller effectively recognizing all realized and unrealized gains or losses associated with the derivatives in our earnings each quarter.

Our pretax loss for the second of fiscal 2013 was $10 million compared with a pretax loss of $7.1 million in the second quarter of last year. Our net loss attributable to common shareholders for the second quarter of fiscal 2013 was $6.3 million or $0.15 per diluted share compared with a net loss of $4.5 million or $0.11 per diluted share for the same period in fiscal 2012.

Before I turn the call back over to Scott, I want to briefly comment on our expectations for Q3 of fiscal 2013. We expect our third-quarter revenues to be higher than we reported in the third quarter of last year due to an increase in production associated with RU-1 and higher oil prices compared with the third quarter of last year.

We expect RU-1 to make a significant contribution to our third-quarter results, and average 260 barrels per day during November. And recent prices for oil remain well above the levels for third quarter of last year.

As Scott mentioned, RU-7’s pump failure in mid-November will only give about 12 days of production from RU-7 for our third-quarter results. Prior to the pump failing it was producing an average of about 235 barrels per day. David Hall and his team will be working to get it back online, as Rig 35 completes other scheduled projects and can be conveniently moved over the well.

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

Scott M. Boruff

Thanks, Dave. Before I open the call to your questions, I want to comment on a few other matters. Today, we’re excited about the progress we continue to make, especially in Alaska, where we deployed Rig 34 and 35 as a significant part of our oil and gas development program. These rigs, combined with our Osprey platform, represent the newest equipment to Cook Inlet, and we remain positive about the contribution of Miller going forward. Our Tennessee operations are also shaping up. And our program for horizontal drilling could be a very positive step to an increase in our production.

With the closing of our preferred offerings in the second quarter, we believe we have the financial resources to fund our development in drilling programs this year through our increased access to the public markets, as well as our new credit facility with Apollo. We also expect to generate more cash flow from oil sales upon the successful workover of wells on the Osprey platform and the workover existing wells in Tennessee to increase our production.

Finally, we plan on keeping you informed on the progress both with respect to completion of RU-3, which should be within the next 10-day, and the horizontal drilling program. Before we open the call to questions, our counselor has advised us not to comment on the pending litigation.

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

Thank you. (Operator Instructions) We will take our first question from Neal Dingmann. Please go ahead.

Neal Dingmann – SunTrust Robinson Humphrey

Hi. Afternoon, guys. Good update. Say, Scott – for you or David Hall to start off, just wondering, again, David kind of walked through what you all have going with RU-3. I guess it's tough to predict with weather and all. But can you give an idea of what you're kind of envisioning as far as timing behind RU-3 and RU-2 and RU-5 before you get to RU-7; what we can kind of look at?

David M. Hall

Yeah, Scott, I can take that. Well, as I mentioned earlier, Neal, we’re currently on RU-3 now and we are just running completion as we speak. As soon as we’re done completion, then we’ll immediately roll right into well testing. Fortunately, the way we’re set up, as soon we are done with well testing, we’re set up to where we can – we’re all tied into the gas network system. So we could be a net exporter in short order.

Neal Dingmann – SunTrust Robinson Humphrey

I guess two things, David, just to that point – you know how quick I guess from the well testing to having that all in line. And then Scott mentioned, I know the problems of moving that rig all the way if you were to slide it over to RU-7. But even with weather, could we see some issues just moving it from RU-3 to RU-2 or RU-5, et cetera?

David M. Hall

Well, the rig does not have to move to workover RU-4, RU-2. So it is already on the same leg. It just us to move from the current leg to work over RU-7, which is on a different way.

Neal Dingmann – SunTrust Robinson Humphrey

Okay. So no issues there as far as – once you're done, you'll immediately be able to basically tie that gas in and start with the next one, correct?

David M. Hall

That is correct. And as I mentioned is before RU-4 is a straightforward workover. We perceive that to only take about seven days, once the rig is centered over that particular well.

Neal Dingmann – SunTrust Robinson Humphrey

Got it. Okay. And then just one more question, David, for you, or maybe I’m not sure if it’s for you or David Voyticky. It just seems that what I want to call the other revenue was quite a bit better than what I thought it would be in the quarter; I guess quite a bit higher than what it's been. I think you all talked about the grind and inject facility and midstream asset rentals, and et cetera. Could you talk a little bit about how that did so well in the quarter, and kind of what to expect from that on a go-forward basis?

David J. Voyticky

Yeah. David Voyticky, I can start off with it. Well, a large part of that was building a road and pad for third-party company here in the Cook Inlet, as well as renting camp space and other ancillary things too, and then of course the grind and inject facility. We did receive a fair amount of mud cuttings from an operator in the Cook Inlet.

And matter of fact, we're just receiving a large batch now and plan to continue receiving more over the next several weeks. So, I think with what we’ve done to-date, I think we're going to continue emphasizing and exploiting all of our midstream assets and portray to the various operators in the Cook Inlet the synergies that we have to offer.

Neal Dingmann – SunTrust Robinson Humphrey

Okay. And then just last two questions for me. Just along with that, David, maybe you could comment on infrastructure, on the build-out; what’s that coming there, maybe even Scott maybe add to something, as far as how much third-party maybe revenue we could potentially see or what the timing of that from infrastructure, I know there's a lot of that that seems to be basically not showing up in the stock yet. I'm just wondering what your comments on infrastructure.

And then, lastly, maybe for David Voyticky, just wondering on differentials, obviously, you had much better pricing up in the area for the quarter. Wondering what you’re seeing currently for pricing and what you expect going forward?

David M. Hall

Well, back on the midstream in addition to the grind and inject. There’s other rentals we’ve been doing too, with – for example renting our crude oil tank is there at Kustatan and there’s an operator that’s moved in near us, that we’ve built the road and pad for, and upon their success, we hope to be processing some of their oil and gas.

So there, again, there’s another potential opportunity to capitalize on our midstream assets. And then as we keep moving along on our Trans-Foreland pipeline, we're really hoping that could be a major addition to our midstream asset. Its going not only lower the transportation costs, but just provide good constant revenue.

David J. Voyticky

And then, Neil, I think that we’re continuing to see Apache as looking forward to their drilling program. You know, Hilcorp is slated to begin their workovers. I think that's – we're expecting that to start in a real way in the summer of the 2013. And as those activities increase and we believe we’ll see an increase in opportunity for third-party revenues.

With respect to pricing differentials, we haven’t put any additional hedges in place with respect to oil. We’re going to wait until RU-2 is complete to do that. With respect to – we’re continuing to receive, in Alaska, in the North Slope minus four. It's clearly WTI and Alaska North Slope will have to come down quite a bit before that trade is not attractive for us to keep going with the Alaska North Slope.

With respect to gas prices, as you know, we're a net buyer right now. It's really one of the reasons why we are excited to put additional gas in place with RU-4 versus going on to the oil sidetracks. And right now, for the prices that we are paying for our gas, and others are paying, it’s pretty close to $15 [an yen] and we expect those prices to continue all winter. It’s very attractive for us to continue now looking to cut additional gas resources online. So there's been a big spike in gas prices this winter, and the winter has just started. So we're expecting that will continue throughout the rest of the winter.

Neal Dingmann – SunTrust Robinson Humphrey

Perfect, perfect. Thank you, I'll get back in queue.

Operator

Thank you. We will take our next question from Kim Pacanovsky. Please go ahead.

Unidentified Analyst

Hi, good afternoon, everybody.

Scott M. Boruff

Good afternoon, Kim.

Unidentified Analyst

First, let's just talk about RU-1. What is the current daily rate on that well? And is the average rate that you saw for November, was that within your expected range of decline?

David M. Hall

Current production for RU-1 is ranging between 200 and 225 barrels of oil per day.

Unidentified Analyst

Okay, so that November average is actually kind of what it stabilized at?

David M. Hall

Correct.

Unidentified Analyst

Okay.

David M. Hall

We are trying to ramp it up or right now maintaining in that range. And I just…

Unidentified Analyst

Okay, terrific.

Scott M. Boruff

Dave, if you want to talk a little bit about how RU-7 being down could be affecting it as well?

David J. Voyticky

Well, certainly. One thing I do want to point out to on RU-1, as I mentioned earlier too was the remaining significant fish in the hole, we still believe is post-restriction. So upon moving the rig back on it and removing that, we think we can really increase flow rates upon that.

Unidentified Analyst

Okay. What is the – when did you get everything out of the hole in RU-3? And I know you mentioned in the release that there have been some weather issues. How many days have you just been not working on the well because of weather? Because I guess I'd anticipated we would've heard something.

David J. Voyticky

Yeah. And even though we’ve had some delays resulting to the weather, it’s not been time lost. For example, we’ve been making good use of rig time by doing maintenance, operational issues on the rig, injecting our leftover mud and what not. But we finished removing all of the fish from the well about a week ago – a week to 10 days ago and then after that, we’ve rolled into – there is a series of scraper runs, cleanout runs, that we have to do in preparation to run the new completion. So that’s what we’ve been doing over the past seven to 10 days.

Unidentified Analyst

Okay.

David J. Voyticky

And we are roughly about 2,000 feet from having completion landed. So we're pretty close.

Unidentified Analyst

Okay great, super. Okay, and then on your LOE. I guess there are so many different things happening every quarter, I just feel like it's an extremely difficult number to model. Is there any guidance that you can give us with that number, and how much of increased gas costs are going into that number? And maybe you could just talk about that.

Scott M. Boruff

Well, you're right, as far as the increased gas cost, as Voyticky quoted what gas is commonly sold for here in the Cook Inlet. And we're buying about a million cubic feet a day. And so that dramatically increased our fuel gas cost. Now we hope that’s coming to an end here pretty quick as soon as upon the success of RU-3 and hopefully RU-4 as well.

Unidentified Analyst

Okay.

Scott M. Boruff

And we can hopefully then become a net exporter as well.

Unidentified Analyst

Great. And you described RU-4 and RU-2, did I missed a description of RU-5 that’s also a gas well?

Scott M. Boruff

RU-5 is currently slated for a crude oil sidetrack.

Unidentified Analyst

Oh, okay. So that is crude. Okay. All right. And then if you could just approximate what the anticipated cost of RU-3 is, and maybe break up the CapEx for the quarter?

Scott M. Boruff

Yeah RU-3 the growth – estimated CapEx was just slightly under $3.5 million.

Unidentified Analyst

Okay.

Scott M. Boruff

And granted, that does not take into account the cash back that we will get from the state of Alaska as a result of the credits. And as far as intercompany billing for the drill rig.

Unidentified Analyst

Right.

Scott M. Boruff

So net realized CapEx cost is going to be quite a bit less than that.

Unidentified Analyst

Okay. And then one final question on the Mississippi Lime. What's the AFE on that well? And is there any – I'm assuming there's nobody else larger than you, or a lot larger than you in that area that's drilling horizontals, which is why you're going ahead and not sticking to more of a wait-and-see type of strategy. Is that correct?

David M. Hall

It’s correct. The AFE is slightly over $1 million and we have the vast majority of the Mississippi Lime acreage in Tennessee.

Unidentified Analyst

Okay. All right, thanks a lot guys.

David M. Hall

You’re welcome, Kim.

Operator

Thank you. Our next question will come from Jonathon Fite. Please go-ahead.

Jonathon Fite – KMF Investments

Hey, good afternoon to all.

Scott M. Boruff

Good afternoon, Jonathon.

Jonathon Fite – KMF Investments

I wanted to spend a couple of minutes on the production side of things and then turning to capital allocation? First, on RU-7, when was it that David said that failed? That was November 12, is that right?

David M. Hall

That’s correct. 12 days in a November.

Jonathon Fite – KMF Investments

Okay. And I just want to clarify some additional comments. He said RU-3 had roughly 10 days left, and he thought RU-4 as a gas well workover would be a fairly quick seven days. Is that correct?

David J. Voyticky

That’s correct. We expect to finish running completion on RU-3 today. Then we will spend a day or two going into the testing phase of the well. So some point within the next seven to 10 days we expect to be off that well entirely and starting RU-4. Once over RU-4, we are expecting that hole will take about a week.

Jonathon Fite – KMF Investments

And just given we've seen to date, that 10-day view on what's left on RU-3, and the seven day's view of what's left on RU-4, is a conservative not an aggressive estimate?

Scott M. Boruff

Yeah. I would say that the 10 days is extremely conservative. The seven days is a little bit more involved. So that has probably more variability.

Jonathon Fite – KMF Investments

Okay.

Scott M. Boruff

But that seven days is expected time, the 10 days is giving us a bit of cushion.

Jonathon Fite – KMF Investments

And then the remaining wells on that leg – as I recall a previous conversation – are kind of 60 to 90-day lead time. Can you talk a little bit about the cost trade-off of moving the rig over to the other leg to rework RU-7, which might be, according to David, a seven-day reworked time in order to get production and cash flow flowing; versus staying on the existing leg after RU-3 and RU-4 are done, and spending 60 or 90 days there working on those new – or recompleting the oil wells there?

Scott M. Boruff

I think we are going to do is see how strong RU-3 and RU-4 in terms of the overall performance, in terms of the way we are thinking about it, the trade offs that you were talking about. We are far less likely to go and RU-7 back online, if RU-3 and RU-4 is strong performers. If they are weaker performers, we would go and get RU-7 back online.

The trade off, as we see it, is the two to three weeks to move the rig over its leg, the two or three weeks takes back. So we would have approximately a month or 45 days of total rig move time as oppose to moving to RU-4 which obviously the short projects that makes a lot of sense and then moving on to the two sidetracks.

Now with respect to the two sidetracks, they could take slightly less time or more time. But we expect that the 60 to 90 days is extremely conservative, so we hope to do better than that. If we have very strong production from RU-3 and RU-4, and given the prices that we have been getting for gas over the winter, we feel that the best thing to do is not to lose the additional 30 to 45 days of rig time with the move, and just to keep going.

Jonathon Fite – KMF Investments

Okay, that makes a lot of sense. Real quickly then on RU-1, I know that that IP close to 500. And then you said the average production in November was closer to half that. Is that what you expected? Or are you guys treating it a little bit more gingerly, given what happened with RU-7? I'm just wondering if you could touch or comment on that production relation to the IP rate.

Scott M. Boruff

David, do you want to take him through that in detail?

David M. Hall

Yeah, and we are keeping that – we are treating it with white gloves and being careful with the well, trying to – in recognition of the significant fish that's still in the hole. So as I mentioned a while ago, we will be taking other efforts to try and improve upon the current production rate.

Jonathon Fite – KMF Investments

Okay, what was that drop expected?

David J. Voyticky

I think there’s two things that David could go into. The first is that we've – as you remember – we left a LLC valve down the whole plus about 120 feet of fish. And what our plan would be is to go back in and be more aggressive with that fish. When we have RU-3, RU-4, RU-2, and RU-5 online, we don't have to baby it anymore in terms of our well concentration.

Jonathon Fite – KMF Investments

Okay.

David J. Voyticky

And so until we have those online, we're not going to be aggressive either with the reduction or the removal of that fish. But the fish that we're talking about – and, again, this is a well that is higher up on the structure than RU-7. It should be a much stronger well than RU-7.

But because RU-7 had that fish removed, the bottom-haul pressures we were getting on RU-7 were about 800 PSI stronger than what we got in RU-1 just because of the removal of that one fish. As you remember, we doubled the bottom-haul pressure when removed the ESP – the LLC on the RU-7. So we’ve had a hard time with maintaining that pressure without having to draw down too much, we could cause some more casing damage.

And the other thing is when RU-7 went down; we were slipstreaming fluid produced water from RU-7 down to one to try to keep that LLC valve a little bit warmer. And RU-1 is a – has no water cut, so it's just oil. So it's a lot of colder fluid. And when RU-7 went down, we lost the ability to do that. So we're being careful with it. And we'll readdress it once we get these other four on the leg back on.

Jonathon Fite – KMF Investments

Okay. So let me try, I guess to the implication of some of these things, if we've lost RU-7; RU-1 is running half of what it IPed at. I know in previous discussions, you had a high degree of confidence that the production covenants tied to the Apollo credit line would be waived in January. Can you comment, given on where things stand today, if you guys are similarly as confident that that is not an issue?

Scott M. Boruff

Yeah. I don’t think anything has changed with respect to the relationship with Apollo. So we continue to maintain a very good relationship with those guys.

Jonathon Fite – KMF Investments

Okay. Let me just turn to a few points then on capital allocation. I know that you guys and many members of the board believe that there is tremendous potential for Miller in unlocking the value of the onshore gas acreage. And you guys have identified a few of the opportunities onshore. Can you just speak to – I think David said the Olsen Creek opportunity was going to be in mid-2013. Is that correct? Were you guys looking to deploy Rig 34 onshore?

Scott M. Boruff

That's correct. We had some very unusually bad weather and the road that was leading to Olsen Creek got washed out. So we are in the process of repairing that road. The repairs are going to push that project back until spring. So we’ll working on it as soon as the inlet allows us to bring a heavy materials over and that will typically is sometime in late March or April. So we can work on it then.

Jonathon Fite – KMF Investments

Does that delay, put at risk, any of the lease provisions as far as certain activity that needs to be done at a certain amount of time, or at the lease expires?

Scott M. Boruff

We don’t think so, because there are force majeure provisions in there and we maintain a good relationship and we have a big commitment to the two groups up there that are landholders. So we feel that we'll be able to continue moving forward. We are continuing to move forward on it as we speak. Work hasn’t stopped. But until the road is complete, you just can’t bring the rig to the pad.

Jonathon Fite – KMF Investments

Okay.

Scott M. Boruff

And that’s going to take another two months are so to get done.

Jonathon Fite – KMF Investments

Just a couple more things here. I know you guys are familiar with our thesis that Miller represents about $10 to $12 of proven asset value, given the reserves under the Osprey and the value of the midstream assets. We understand that this estimate could prove to be wildly conservative in light of the onshore acreage. But given the potential for Apollo to come back to you guys – the potential covenant or liquidity concerns associated with that. We continue to believe that the onshore program should only commence in our S-1 production from multiple wells underneath the Osprey are up and running. Do you guys agree with that capital allocation timeline? Or do you still think moving into 2013 being fairly aggressive on the onshore drilling plan make sense?

Scott M. Boruff

So I mean the interesting thing, Jonathon, is that we're not going to be in a position to spend any money on the onshore piece just because of the weather delays until springtime. So call it – April is probably a good date to earmark for us in terms of the weather. By that time, we should have completed the vast majority of the reworks. And so I think…

Jonathon Fite – KMF Investments

Okay.

Scott M. Boruff

I think that’s going to be academic at this point.

Jonathon Fite – KMF Investments

Okay. Last thing and then I'll drop off. Just turning to Tennessee for a minute; I know that David, you and Scott spend every waking moment thinking about how to maximize shareholder value. But given how much attention is paid to the Alaskan assets, and rightly so, it would seem that maybe some of your deal making prowess might be directed at spinning off some of the Tennessee assets into a separate entity.

It seems that there are very few synergies between the two operating teams and the market attributes really no value to those assets. And it would seem that a portion of some of the highest G&A that burdens the current operation might be served directly supporting a stand-alone entity. I'm just wondering if you could comment on that at all as far as some of the thoughts that you and Scott might be spending your time on.

Scott M. Boruff

When you look at the Tennessee acreage, we think that we have the best oil potential acreage in Tennessee. And with our current activities, we’re looking to exploit that. And if it’s exploded and the market doesn’t recognize it, we wouldn’t have any issue in spinning it off or selling it. I think with respect to the gas, it's going to be a little while before gas prices come back in lower 48 to meet the acreage than what it was worth four years ago. But we acquired that acreage at very low cost.

So we're excited about the opportunities that holds. But we look at it and that's exactly the reason why we are spending a little bit of money on developing some of the oil potential. At the end of the day, we have two ways to do that. One is with these horizontals that we're going to try. And the other is just a reworking of old production. But if we can bring that production to a reasonable level, I think we’ll have a decent opportunity there to recognize value per shareholders.

Jonathon Fite – KMF Investments

Last thing, the latest Q shows there were a good bit of options that were exercised; although we haven't seen any (inaudible). So I'm assuming that any of those options that were exercised were simply exercised and held, and not liquidated. Is that correct?

David J. Voyticky

I’m not sure which options you are talking about, but there hasn’t been any sales by insiders this quarter.

Jonathon Fite – KMF Investments

Okay. And given the soft we've seen today, I would expect and hope that management and members of the Board, would be aggressively buying shares once your blackout period lifts. I remember Scott once proclaiming last summer that you would be aggressively buying in the market. And much of the uncertainty that surrounded the stock since then has been lifted. And I was hoping that either you or Scott might be able to comment on the intent of management or our Board to exploit these prices with their own money, rather than simply getting granted more options?

David J. Voyticky

Yeah. I think that for each member or Board or management's personal decision – from my perspective, myself and my kids are looking at our preferred, we think that’s an excellent buying opportunity and sure to see some buying from us and some of our Board members over the next few months. But if preferred is an attractive piece of paper to put into the college fund for the kids. I have personal plans to do so. And I think that our stock, where it is, is an attractive opportunity. So I'm sure you will see some buying from management as we go forward.

Jonathon Fite – KMF Investments

Can Scott comment on his or some of the Board members' intentions?

Scott M. Boruff

Yes. This is Scott, I own about 5 million shares, and I bought most of my shares. And like David, as well, we've talked about the preferred shares that are trading at 10.5 % on yield. And we think that’s a good opportunity as well which we just sold those a couple of months ago. And I wish we were in a blackout period today, because I would be buying more today and it’s a great company, its – a lot of our investors that are on this call have been with us since we were a pink-sheet company that’s moved to New York Stock Exchange company; have been with us since we were 12,000 acres that have grown to 750,000 acres as a company and is growing to a million acres; have been with us since we were at $800,000 revenue losing $5 million a year to $36,000 million last year growing to $100 million this year; have been with us since we had no rigs in the Cook Inlet, and now own and operate two newest rigs in the Cook Inlet and some of the most sophisticated midstream assets in the Cook Inlet.

And they've been with us since we had regional accounting, have moved to the national accounting, have just finished two years with KPMG, and have been with us since we had no SOX compliance, to where we have a 125 SOX processes in place. So as we come onto this call today, it feels like I watched the stock when landed in Houston, and it was down $0.30 or $0.40, God Bless America. I'm [not] doing my job. These shareholders do not understand what they have and where we are going, and how we are getting there. But I'll tell you right now, for those shareholders on the shares, you'll like what you see in the next 12 months, trust me.

Jonathon Fite – KMF Investments

I understand that, Scott. And I understand you bought lots of shares when it was in the pennies.

Scott M. Boruff

Yes.

Jonathon Fite – KMF Investments

And (inaudible) granted lots of options in the $4 and $5 range. And I would prefer, as a major shareholder, to hear management talking about how cheap the shares are in relation to the $8, $10, $12 asset value of known value. Not to mention the upside of the onshore acreage and lots of balanced fixed income instrument you know that is trading at 10%.

So it's surprising to me that that's what you and David focus on. I would like for you and David – I think our shareholders would like for you and David to continue to focus on execution, to having mud pumps available when mud pumps should be available; to have contingency plan and timetables that are conservative and nonaggressive; and that for your interests to be continue to be aligned with what we hope is an execution-focus, execution-minded operation. So I appreciate your updates today. I think you know where we stand in our view of the value of the business. And we continue to hope management focuses on execution to deliver that value. Thank you.

Operator

Thank you. We will take our next question from Jeffrey Connolly. Please go ahead.

Unidentified Analyst

Good afternoon, guys. Most of the questions have already been answered. But I just wanted to know if you could give us some more color on the horizontal wells in Tennessee, as far as lateral length, like EUR, what kind of expectations you have for those?

Scott M. Boruff

Yes, I'll take that. We’re drilling actually the first Mississippian horizontal well in Tennessee, and it’s probably right at a 2,800 total measured depth horizontal length about a center stage frac. We hope to complete it naturally. We hope to complete it naturally. We hope it comes along naturally but we've got it in our AFE to do center stage frac if necessary and because it’s new we don’t know what the EUR is going to be.

In Tennessee, like we talked about earlier, we’ve got 50,000 acres. We are probably one of the most full paying acres in Tennessee. And so it's kind of a new frontier for us and so it’s a total of (inaudible) AFE total cost. And we’ve had a couple of partners lined up to do with us but as always they never come to the table in enough time. So we have done it and we are actually drilling as we speak. We’ve already completed the top hole and now are into the horizontal as we speak, and should have results, good or bad in the next two weeks.

And like David Hall talked about earlier on RU-3, where we should have completion results on that in the next 10 days. So might give our guys a good Christmas present. So we look forward to it. But hope I answered your question.

Unidentified Analyst

Yes. So is the plan to drill smaller laterals to prove up the concepts and then maybe expand it?

Scott M. Boruff

Yes, absolutely. And what we're seeing out in Kansas City in the horizontal wells out there is they have water associated with it. We do not have water associated with ours. So we think that, the good thing because usually when you have water, you have carrying costs and disposal costs and so we are going to – we will drill less and hopefully comes on, we are the most prolific driller in Tennessee. We've drilled probably 83% of the wells that have been drilled. So we have good well controllable wells on the well that drilled, so we literally go in between wells that needed, 700, 800 barrels a day and the theory is those wells which thought 20 acre and 40 acre spacings have depleted their fields. But it looks like it only went out 20 to 30 to 40 feet and if that’s the case we should have some nice results.

Unidentified Analyst

Great. And then I have one for David Hall. Can you just repeat what you said on Otter? I think you mentioned it's shut in until the spring right now.

David M. Hall

Yeah, that’s correct, primarily due to the cold weather that we’ve been experiencing here in the Cook Inlet. Just here last week, temperatures had dropped down to below 10, below zero which as you can imagine it did makes it very problematic to try and swab and unload a well with those fluids freezing, and potentially cracking the well head.

Unidentified Analyst

Okay. And then is spring – would that be March, April?

David M. Hall

Yeah, presumably would be in early spring in March, mid to late March and we will resume those activities. And as I mentioned before too, we are exploring other ways to perhaps deepen the well to fully evaluate the Beluga and Tyonek formation as well.

Unidentified Analyst

Okay. Thank you very much, guys. I appreciate it.

Operator

Thank you. And we will take a follow-up from Kim Pacanovsky. Please go ahead.

Unidentified Analyst

Hi, sorry. With the Otter well, what are your theories on why you're not getting the fluid back as quickly as you might have expected? Is it pressure? Is it chemical formulation?

Scott M. Boruff

Well, one thing that we’ve learned about the Otter, it’s got a – its every sensitive to any type of drilling in muds and fluids, and we were hoping fracking would help resolve some of those issues. We still, as I mentioned before, we still haven’t recovered all of the frac fluid back at only 200 out of the 800 barrels.

Unidentified Analyst

Right. But that is essentially my question. Why do you think that fluid is not coming back to you?

Scott M. Boruff

Primarily I think it’s just related to the disturbance of the field. We would hope it would all be driven by formation pressure and we do see the – if you calculate the hydrostatic ahead of the fluid in the well bore you can drive with your formation pressure. So we are still optimistic as we would recover fluids and ultimately we would think that the gas would come in, usher in behind the water. But there is something’s that we don’t fully understand about the formation yet. It’s – we drill order number one and that was very first well in that formation. So there is little bit of a learning curve and that’s why we lost into the sensitivity studies when we were taken samples and see what the formation is responsive to, and we are still digesting all of that information.

Unidentified Analyst

All right. And then on RU-7, can you just – I think you said how many days that well was down in the quarter, or how many days it produced in the quarter?

David M. Hall

Well, it failed on November the 12.

Unidentified Analyst

Okay. Great, that's the date I need. And then, finally, I know you produce mostly oil. But it would be really helpful to have a breakup of the oil and gas, because that's sort of how we build out our models for every company. Do you happen to have that?

David M. Hall

As far as Alaska, we are currently producing about just shy of 400,000 Mcf a day.

Unidentified Analyst

Okay, and Tennessee?

David M. Hall

I will let Scott or Voyticky speak to that.

Unidentified Analyst

Okay.

David M. Hall

Thanks. About 72 barrels of oil there.

Unidentified Analyst

Okay. And gas?

David M. Hall

About 200 Mcf.

Unidentified Analyst

Okay, thanks. That's all I have.

Operator

Thank you. And we have no further questions at this time.

Scott M. Boruff

Thank you for joining us this afternoon to provide you with an update on Miller Energy strategy and financial results. We are very pleased about Miller's future and potential of our properties. We plan to keep you up to date on our operations on future calls and look forward to you joining us. That concludes today's call. Thanks.

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