Miller Energy Resources' CEO Presents Operational Update (Transcript)

| About: Miller Energy (MILL)

Miller Energy Resources Inc (NYSE:MILL)

Operational Update Call

October 30, 2012 4:15 PM ET


Scott Boruff – CEO

David Hall – CEO, Cook Inlet Energy LLC

David Voyticky – President


Michael Cahill – Compass Investments

Anthony Santelli – AES Capital

Jonathon Fite – KMF Investments

Mike Jacks – Sutter Securities


Good afternoon, and welcome to the Miller Energy Resources Call. This call is being recorded. At this time, all participants have been placed on a listen-only mode, a question and answer session with CEO Scott Boruff; President David Voyticky, and David Hall, CEO of Miller Energy subsidiary, Cook Inlet Energy LLC will follow the company’s presentation.

Before we begin, I’d like to call your attention to the customary safe harbor disclosure 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 affect Miller’s operations, or financial results are included in Miller energy resources 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 filing, please visit their website at

Miller Energy Resources 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 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 circumstance, or management’s estimate 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’s CEO, Scott Boruff. Please go ahead sir.

Scott Boruff

Yes. Thank you for joining us this afternoon to hear an update on our operations. In a few moments, David Hall, CEO of our Alaskan subsidiary, Cook Inlet Energy, will present an update on our Alaska operations. Upon completion of this presentation, we’ll be accepting your questions.

Today, I’m very excited to announce that our latest work over RU-1, a previously producing oil well, located on an offshore platform is complete.

We’ve been working tirelessly on this project since receiving certification of our new drilling rig, Rig 35, and are thrilled with the result.

I’ll turn the call over to David Hall, to provide more detail of the work over in our Alaska operations. David?

David Hall

Thank you, Scott. Well, we’re proud to announce that RU-1 is now online. We have a successful work over. RU-1 was brought online on October 27 with an initial production crude oil rate of 482 barrels of oil per day with no water cut.

I’m not aware of any other crude oil well on the Cook Inlet that produces 100% oil. RU-1 is well positioned, high on the (inaudible) structure, producing from the Himlot formation which is over 700 feet thick.

We knew this complex work over will bring a set of challenges because of other attempts by our previous operators, however, we felt with the new robust drill rig and a strong technical team, we stood a very good chance at being successful.

The work over entailed the removal of a number of fish that consisted of three ESPs, packers, sub surface panels, clamps, straps, electrical cable, basically various stuff left in the well from other operators.

Thankfully, we were able to remove the majority of these – and we estimated that we removed a total of 31,000 pounds.

In addition to the fish removal, we also encountered clamp casing, nearly 2.5 miles down that required a fair amount of time to expand it back to its original inside diameter by a process called sledging.

Although we were successful in removing nearly all of the fish, we got to the last major fish and determined, that it would require significant milling to enable us to latch on to it, and remove it. As a result, we did not remove the last subsurface safety valves, and ESP from the well. And we believe that this potential exists to substantially improve well performance in the future.

However, this process would bring with it a level of risk which could lead to additional cost and delays to restoration of production which we do not feel prudent to take on given our well concentration at this point. At that point, we made the call to stop fishing, and installing new ESP, and get the well back online.

We were thrilled with our success in getting RU-1 back online and to production with outstanding results of an IP of 482 barrels of oil per day. It’s considerably higher than the previous operator reported an average rate of 125 barrels of oil per day, that’s nearly 400% increase. We’re very pleased to bring you another success story on the Redoubt Shoals Field, since we took over operations.

I also want to talk a little bit about the performance of our new rig, Rig 35 performed as designed; we did not run into any situations where we were rig limited. As a result of the 2000 horsepower, 500 ton top drive and million pound rated dirk we were well equipped with this work over. We are optimistic about the future performance of Rig 35 as we target other previously producing wells and new wells on the Redoubt oil spring, Redoubt platform going forward.

Before I move on to RU-3, I want to take this opportunity to mention RU-7, and its outstanding performance. When compared to the previous operator, since January, 2012, RU-7 has produced nearly 60,000 barrels compared to 41,000 barrels reported by the previous operator, far exceeding historical rates once again.Our next target is RU-3, a previously producing gas well that had a previous IP of over 8 million cubic foot of gas a day.

Rig 35 has already been skidded over RU-3 well, and we believe that RU-3 has enormous potential, and will hopefully fill our internal gas needs as well as help us become a net gas exporter.

Now I know we previously announced that we intended to go right to RU-2 sidetrack after RU-1, but we have elected to push RU-3 next due to the heightened concerns about our gas needs because of the ongoing gas shortages on the Cook Inlet.

With that said, we believe that it’s a prudent security, significant gas source, and we expect RU-3 will help us to meet this need. RU-3 is a previously producing gas well out of the G-0 counted gas sands, at a measured depth of about 14,000 feet. It was a very strong producer with a well test of over 8 million cubic foot a day and flowed for only a few short months, and recovered just under half of 1 Bcf.

Well under the internal 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 nearly 4,000 PSI without a sufficient pressure reducing device in place to keep the well hit and associated piping from literally freezing off.

Our work over plan basically consists of removing all the old completion and re-assessing the zone of interest, followed by installing the necessary devices to effectively reduce the high pressure without freezing.

Moving onto a different well. We were finally able to mobilize the necessary hydraulic equipment to Otter location and successfully conducted the hydraulic frack. The hydraulic frack went as designed and engineered and consumed over 800 barrels of liquid propellant in 50,000 pounds of sand, yielding a projected 53 feet of penetration over the gas-on of interest. Once the frack was completed, we went right into liquid removal as a result of the hydraulic frack. But remaining frack fluids are believed to be suppressing the formation gas from entering the well bore.

Currently, we are recovering portions of the frack fluid as the well releases it. We have recovered 150 barrels to date. We’re still very optimistic about Otter and will continue trying to bring it online once we recover the frack fluids.

One thing I want to point out while drilling Otter, we experienced mud pump problems that kept us from drilling to a planned depth of 7,000 feet. We had to stop short at approximately 5,600 feet. And as a result, we only evaluated a short proportion of the perspective Beluga Formation and none of the Tyonek Formation. Not only have we purchased new mud pumps, but we are already 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.

Finally, I want to take a minute to update you on our plans for Rig 34 and our next well we plan to drill with it, which is Olsen Creek. As many already may know, we have another exploration gas prospect called Olsen Creek, which is located approximately 7 miles southwest of the Otter well number one. Olsen Creek is a totally different gas structure but one we feel has strong potential. Olsen Creek leases comprise of 10,100 acres.

Olsen Creek prospect is northeast and on strike with the production from Aurora Three-Mile Creek Field. Other nearby fields include the Beluga River to the East having produced over 1.2 Tcf of gas, the Luis River at 21 Bcf gas and Pretty Creek at 12 Bcf of gas. Each of these fields encountered multiple gas reservoirs within the objective section. Multiple perspectives zones are present within the Olsen Creek prospect area.

The initial planned well is ideally situated to evaluate the Olsen Creek structure. If successful, we see the potential for 24 wells on our leases. We estimate a potential for each well up to 3.5 Bcf of gas per well bore with a potential reservoir size for the field of approximately 84 Bcf of gas. We’re also evaluating the oil potential in the field and well plans are flexible enough to accommodate such changes.

Over the past few months, we have been upgrading and extending the road system to the Olsen Creek and hope to complete the road in the next few weeks and start on the construction of the well frack pad. Currently, our targeted spud date is early to mid-December and economics assume a realized CapEx of approximately $3 million to $5 million per well depending on a location with an average PV10 value of $10 million per well.

There are still shortages of natural gas in the Cook Inlet and we feel that we have some of the best perspective leases to find, explore, and develop natural gas to meet a growing demand.

So at this time, I’d like to turn the call back over to Scott.

Scott Boruff

Thanks, David, for that, for your comments. That concludes our formal remarks for today’s call. Operator, we’d like to now open up the lines for questions.

Question-and-Answer Session


Thank you. (Operator Instructions) We’ll take our first question from Michael Cahill with Compass Investments.

Michael Cahill – Compass Investments

Congratulations, guys. That’s great news on RU-1. I have a couple of short questions for David Hall and one for David Voyticky. Perhaps, David, if you could take the first, David Hall. Can you tell us of Apache has started drilling on the West side yet? And when do you expect to know drill results for NordAQ’s Tiger Eye unit next to Kustatan? And very quickly, where is Apache and NordAQ planning to dispose of their drill shavings? And then, lastly, for David Voyticky, perhaps, you could comment on the recent Seeking Alpha article that’s been very critical of Miller Energy. Thank you.

David Hall

Well, Apache and NordAQ have been very busy in the Cook Inlet. Starting with Apache, as most everyone knows, they’ve been very aggressive and shooting 3D seismic in the Cook Inlet on and offshore. Per my understanding, they have mobile lines to drill rig up from the Lower 48, which is currently in the Cook Inlet. I do not know their exact time of spud. I do know what’s on the West side of the Cook Inlet, their proposed well location.

As far as NordAQ, they have a prospect, as you mentioned, Tiger Eye located on the West side of the Cook Inlet, very close to our West McArthur River field. I can’t comment on the exact conditions of where they’re at in their well to date, but I do know they have spudded.

Michael Cahill – Compass Investments

Sure. And regarding Apache, how far away is Apache from either Olsen Creek or Otter Creek?

David Hall

Well, Apache has an array of acreage in and around a lot of our leases, but there, in some cases, they have acreage adjoining the Olsen prospect as well as real close to the Olsen Creek prospect.

Michael Cahill – Compass Investments

And is that the location where Apache is planning to spud this fall?

David Hall

Per my understanding, their permitted spud location is South of Olsen Creek.

Michael Cahill – Compass Investments

Okay, thank you.

David Hall

Probably to the tune of 6 to 10 miles South of Olsen Creek.

Michael Cahill – Compass Investments

Okay, very good. Thank you, David. And then, lastly, for David Voyticky?

David Voyticky

We saw the Seeking Alpha article but didn’t spend too much time on it. I kind of viewed it as a follow-up to the sort of misleading sort of reporting that we saw last year from StreetSweeper. I think in summary, it’s the same story different year, really sort of to try to tank the properties because of the previous operator’s bankruptcies indicating that we’re exaggerating reserves, exaggerating our production cost and kind of making some bad attempts at relative valuation to companies that just aren’t comparable, and a few other things thrown in.

I think in general what Scott, the team here have tried to do over the last two and half years really is to build a world-class company with a world-class board and an operating team. We look at the criticisms and advice of all our shareholders very carefully. And we obviously don’t think that the fact that previous operators that own these properties that went bankrupt is comparable to us. We have a much lower debt load. We don’t have $500 million of debt on these properties. I think that when people want to talk about exaggeration of reserve reports and if you look at our reserve reports over history we’ve beaten the reserve report expectations for every well that we’ve brought online.

And in fact when you look at our press releases compared to others that have a tendency to over exaggerate production numbers, two years – two and a half years ago, we reported production numbers on the West McArthur River fields at about 1,100 barrels in total and two and a half years later we’re still producing between 700-800 barrels a day.

And a year and a half ago, we reported an IP on RU-7 of 250 barrels a day and it averaged over 230 barrels in the last month a day. So we take that stuff very seriously and we take the things that we put out in the market very seriously. And we believe that overtime we’ll be able to outperform both our reserve reports which we’ve done to date and give investors a very good indication of what’s happening.

And I think in terms of – everyone wants to understand what our production costs are. It’s another easy thing to attack. And I don’t have this in front of me, but I remember the ‘forensic encounters’ they call themselves in this article, have made some really poor comparison, our operating cost to Forest Energy last operating cost numbers which of course makes no sense because Forest Energy also owned the 46% working interest and five of the oldest platforms in the Inlet now which was majority of their production at that time and they had the highest operating cost in the Inlet which really has nothing to do with us.

In fact as you probably know no one even picked up that 46% interest. But to compare us to them, that makes no sense.

As we indicated in the press release and as we’ll prove out over the course of next year, we have the newest assets both for exploration and production in the Cook Inlet and we believe that our incremental cost for producing oil, operating cost for producing oil (inaudible) opportunity less than $5 a barrel.

There may be a number of other things. If there are any specifics we’re happy to address them, but in short it’s just a hatch of the job that is not fully researched and not substantiated by any of the facts.

The one thing that we still want to time on here though as we move forward and one of the things that we want to give a better viewpoint to our shareholders really is on projections because if you look at the history, when the assets were first acquired, we looked at putting someone else’s rig on the platform and someone else’s rig in the West McArthur River field.

And we had the ability two years ago to start production a lot sooner, but we would have been paying some significant day rates, not have control over the cruise and not have the right capital and structure in place. And quite frankly it could have repeated the mistakes of previous operators.

And I think the company made a decision as 34% investors in not to do something for the short term and not to do something just to respond to any pressures that we may feel from being in the public markets to produce a short-term result.

And we took a year and a half which is a long time to get the rig and the right financing in place, but we’ve done what we think a long-term investor would do is get the lower cost of capital, get our own cruise, our own equipment in place and put ourselves in a position to control our own destiny.

And so we certainly have not been great at that – at that thing when things were – are going to happen. And even with this example with RU-1, we tend to over communicate in terms of what we think is going to happen and we’d probably just take a step back and think about exactly what we communicate because as you know the last time we talked on RU-1 we – it was a two-week project and we did not expect to be able to get the top ESP and the top LLC out of that well bore.

And when we were able to get it, it led to an opportunity which is long-term shareholder we wanted to take. And it made sense for us to do. And quite frankly we sat around weighing whether or not, as David indicated, to mill through the remaining impediment and to try to get that last LLC out because of the pressure change that we saw on RU-7 by taking out the LLC. And we thought we would see something very similar if we could get that last LLC out.

And quite frankly, if we had 10 other wells online, we would have taken that risk and probably spend another two or three weeks working on this. But the reason we stopped is not because of the pressure to get news out.

We don’t have the same pressure that other operators have to turn these pumps all the way up and collapse the casing. Our view is to get as much oil as possible out, diversify our risk and do things to create long-term shareholder value.

But in doing so, I think what we’re going to look to do better is to explain to shareholders what we see on the future. We know one thing is certain that being a company that has two rigs operating that we don’t have the well diversification to have projections in terms of activities that are going to be up – that are going to be accurate.

Because if we have 20 wells – 20 rigs drilling, some would be slow, some wouldn’t be slow and it will all average out. But one thing we know is that as we go into these well bores, we’re finding stuff that was leading to different course of action.

And as David mentioned, he took out 31,000 pounds of junk out of this well bore and there’s still more in it. And once we get our well diversification up, we’ll probably go back and optimize that well and get better production than we’re getting now.

But as we get information, I want to try to do a little better job giving our investors a sense of the timing of events that are coming.

Michael Cahill – Compass Investments

Okay, thank you, fellows. Best of luck.


And we’ll take our next question from Anthony Santelli with AES Capital.

Anthony Santelli – AES Capital

Hi, guys. Congratulations on the – on the RU-1 work over. What is the total number of barrels a day that is – that is flowing now from Alaska?

David Voyticky

Yes, the total number of barrels of oil that’s flowing from Alaska is off the Redoubt platform we’re doing slightly more than 700 barrels of oil and from the West McArthur River field we’re in the mid 700s barrels as well. So it’s in some place between 1,400 barrels and 1,450 barrels in oil.

The one thing that we didn’t mention, David, you may want to go into this, but we’ve done some smaller work overs that have increased our gas production. So we’re producing over growth of over 1 million cubic feet a day at this point.

So when we base this from Alaska, you’re looking at something between 1,500 barrels and 1,600 barrels.

Anthony Santelli – AES Capital

And going forward over the next, say, 12 months or so, how many additional wells do you anticipate working over and producing from?

David Voyticky

Being – and I’ll let David answer this, that’s right. Yes, as I answered Mike, it was an expectation. Things could change. Things could be faster or slower.

And in fact, we’ve found some things in RU-1 which may lead to faster work overs for the remaining previously producing wells.

But on average we’re expecting to work over one well on the Esprit platform of the four previously producing wells every 45 to 60 days. That’s our – that’s our average that we’re expecting. And then we start new wells, we’re expecting the new wells between 90 and 120 days. And in fact that’s the 120 is really what we – what they saw before that were drilling these wells. Yes.

On shore, again this is important for us because one of the things we think that previous operator did incorrectly was to run from one well to the next well without looking at learning anything from the well that was just drilled.

But on shore, yes, we’re learning a lot from the Otter well. It’s going to help us prove our chance to success with Olsen Creek. But we’d expect to drill at least four to six wells over the next 12 months on shore. And the production rates and you can get these off of the AOGCC, they show all the production previously producing rates for these wells, but everything that we’ve indicated has been, we’re going to do, where it was previously producing at.

As David Hall had pointed out, in RU-7, we produced more oil since we brought that well online than the previous operator had produced in almost three year period prior to that.

So we think there’s things that we can do to make some exceptions, but the guidance that we’re continuing to give is a guidance where these wells were previously producing at. So for RU-3, that was producing gas in the 3 million cubic feet and it was producing oil, we’re bringing on oil and the 400 barrels to 500 barrels in RU-2 and RU-4, we’re expecting to be in the 600 barrel a day range in RU-5 the same, essentially the same as RU-3.

The IP rates, if we’re successful with the gas wells, we’re expected to be in the 3 million a day.

Lastly, and the one thing that could change, is with additional capital available to us right now because we certainly have a significant amount of cash available to increase our, the speed of our development, we feel with the shelf and with the preferred offering that’s outstanding in the ATMs, we’ll look to see if we can have an additional rig to do additional onshore drilling for both gas and oil.

Scott Boruff

As we secure those rigs, we’ll provide updates to our drilling activities.

Anthony Santelli – AES Capital

Thank you very much.

Scott Boruff

You’re welcome.


And we’ll take our next question from Jonathan Fite with KMS Investments.

Jonathon Fite – KMF Investments

Hey, good afternoon guys.

Scott Boruff

Hey, Jon.

Jonathon Fite – KMF Investments

Hey. Dave, I appreciate kind of the stepping back approach on the timeline, and the communication, I think that’s absolutely the right approach. And I would recommend you guys for doing the right thing as far as seeing an opportunity to fish out some more of the impediments and going for that, rather than trying to rushing to get a news release out.

A couple of extra weeks in the grand scheme of things isn’t a big deal.

David Voyticky

You know, it’s interesting we just finished a tour, of Llyods of London, where we were going to try to get a stronger insurance rate. And we highlighted that extensively, our own interest in the company, and the fact that David Hall’s team in the three years that they’ve been operating haven’t had any significant reportable incidents of injury, or environmental.

And that sort of stuff is very important as we’re building this rig in the winter and we had the strong incentive to push, push. I think we appreciate that the fact that you understand that we’re looking at this on a long term basis.

Jonathon Fite – KMF Investments

With that said, and I appreciate kind of the initial guidance really just equating to the old production rates and not trying to take any credit for enhancing production or better methods, just on kind of the initial IP estimates, given the timeline, the 45 to 60, or 90 to 120 depending on the well, should we back off a little bit around the assessment of 3,000 barrels per day exiting calendar 2012 and 4,000 barrels per day exiting calendar, or I guess fiscal 2013?

David Voyticky

Yes, it’s interesting. And again, we’ll tell you what we expect, and obviously, it’s not going – if it’s right, that would be a good thing. But it’s what we expect and it can change.

We’re going to be working on RU-3, if the gas well is previously producing – previously producing gas wells, are not as certain as bringing back on as previously producing oil wells or like be a little bit more tested.

But if we’re successful, that well could be brought on at this 3 million a day rate which would equate to the 600 barrels, which will get us over 2,000 barrels. And we expect that will be done in November.

As soon as we’re complete with that, and we’ll be working on RU-2. And based on what we have learned in RU-1, we think we have some additional opportunities there to make some more modifications.

We don’t think it’s going to add significantly to the timeline, it could even shorten it, but there’s around that end of year, we still think that that 3,000 barrels is close if we hit our expectations.

The 4,000 barrels by the end of April, we also feel comfortable with because that would have – bring two more wells on in this 400 barrels to 600 barrels range. So we think we’ll be good with that as well.

The only thing that may change that, obviously if, if things take a little bit longer than normal, or if they take shorter than normal which has happened before, hasn’t happen recently. But as I mentioned, with additional access to capital, and our partners at Apollo, we’re going to look carefully at some additional pods in the western part of the River field, we could drill out and perhaps bring some additional things online.

So there could be a couple of things that changed. If we have changes, and we’re going to get better at this over time, seeing how we’re really kind of a well by well company, we understand the need for information for investors.

I think what we can promise you is, as we have significant information that’s either negative or positive, that changes those assumptions, we’ll put out new releases.

We struggled over when to put out a release sort of to put out and update on RU-1. And I think that if we don’t have any news other than to say we’re still going, I don’t think we’re going to put that out, but if something negative or something positive, we’ll get it out.

Jonathon Fite – KMF Investments

Good. And I know previously we had talked about because of the well concentration risk, that you guys are really being fairly gentle with RU-7. Has RU-1 – do you still kind of consider yourself in yellow, cautionary zone, or by bringing RU-1 online, do you start to dial up RU-7, or do you want to wait a little bit longer before you consider doing that?

David Voyticky

David Hall can answer that if I don’t answer correctly or completely. But what I would say is as got comfortable with where we were on RU-1, when we decided we’re going to start running completion, we knew we were going to have a successful well; we actually did turn up the pump just to see how the well is going to react.

David can tell you how much we’ve turned it up. But production jumped by about 5% to 10% by turning up that well a bit.

David, you want to comment a little bit more?

David Hall

Yes, I certainly can. We did speed it up as David Voyticky just mentioned just to monitor the reservoir pressure and see how fast, if any of that it would decline. And it still shows very, very strong reservoir pressure support.

We haven’t – we only increased the speed by less than 5%, it’s still doing a strong 230 barrels of oil per day.

Right now, we’re just continuing to monitor it, and as we’re continuing to level out RU-1 as well. But as time goes on, and our comfort level increases then we’ll continue to ramp it up.

David Voyticky

Yes. So we went from, just to give you an idea of exact numbers, it went from 219 barrels a day, September, and so far, in October, we’re doing 232 barrels a day.

Jonathon Fite – KMF Investments

Okay. And can you just help me understand a little bit of the puts and takes as RU-3 comes online from a cash flow perspective and the way that gets reported? You guys just look to kind of offset your own gas needs.

Did that just kind of play out of the negative cost, or how does that flow in the revenues, and cash flow? Can you just talk a little bit of the cash flow impact? And then as a follow on to that, can you comment about discussions with Apollo regarding any cash flow covenants, and waivers and kind of a pact toward the spring and toward the summer without any noise along that side?

David Voyticky

Yes, we don’t expect any significant issues as with the street, with Apollo, we projected this well, and the 250 barrels to 270 barrels range. So we’re happy with where it came in at.

With respect to the cash flow covenants, our first covenant test is going to be at the end of January. And we feel very comfortable with those levels.

And given our access to the capital. We feel like we have a number of – we have possible routes, but we certainly value them as a partner. They’ve been an excellent partner and providing us assistance in multiple ways.

With respect to cash flow changes because of the RU-7, RU-3 gas, one of the things that made us change our mind and change our plan was the providers in the inlet didn’t have any more gas to sell us.

And we became concerned because first, the price went from 720 nm up into the low teens. And then we got indications from the providers that they couldn’t provide gas beyond a certain point and we were fortunate enough to secure a contract.

But we understand that the shortage is certainly there and it was prudent for us to try to bring this gas well online. If we’re not successful we may have changed our plans and try to bring RU-4 on as gas and then just bring this one back as oil which was our original plan.

In terms of the impact on cash flow generation, it will simply be that we won’t have that expense, that million or so a day that we’ve been buying. And if we produce at the level we – we’ll hope this will come back online that we’ll either choose to sell in the spot market over the winter which – with at various prices or enter into a long-term contract.

And so our model has been very conservative. I think our reserve report and model is out selling gas in the $6 an Mcf and we certainly think we’ll be able to get that.

Jonathon Fite – KMF Investments

Great. And then last question and I’ll head back in the queue, given the progress compared to kind of the – kind of the respect I would say I guess in the marketplace looking at just multiple bucks a share. When you’ve got kind of proven value of $8 to $9 a share, you’ve got midstream assets maybe worth another $3 to $4 bucks a share plus – and kind of the output stuff that you guys are drilling on and that you’re not even really getting enough credit for.

The bias as 30% plus owner simply do you prod along and continue to prove this out and let that speak for itself or, I mean, given the implication of higher capital, gain tax rates in 2013, the kind of massive cash flow that a lot of your neighbors currently are sitting on, is there an interest to you to at least have more dedicated talk between now and the year – at the end of the year on strategic alternatives?

David Voyticky

Yes. And I’ll answer your question pretty broadly; we looked at various ways to maximize shareholder value on a daily basis. We look at our cost of capital and we look at asset divestitures. We look at joint ventures. And quite frankly we look at the opportunity to sell the entire business.

And I think the point that you mentioned at the beginning is the point that we’ve been focused on the most which is we see some low risk activities in bringing these previously producing wells back online and getting credit for them.

And we also see the opportunity to bring them online at higher than previously producing rates. And when we do that, not only to take assets that were considered pods and perhaps more risky than we would have meant to PDPs, but to bring them on higher rates and get a – and get a double bang for our buck.

And that’s one of the reasons why we’re taking this strategy of moving forward in these assets in the development plan that we have.

We think we don’t look at these as our – at our pods as pods, we look at it on as PDNPs. The SEC rules classify them as pods because they – there hasn’t been any production out of them for a certain period of time. But we know there’s oil and the wells are produced. They’ve had definable casing failures or pump failures and we’re addressing those as we go. So we still feel very confident about that.

And we think at the upside is significant enough for us to be patient. Once we get to a stabilized viewpoint as to what these fields can produce, I think different alternatives become more useful and more realistic to talk about. But for the stuff that we’re doing now, it’s harder for us to give up upside when we think it’s – the risk is fairly low. As we move forward to next year, I think that some of those alternatives and quite frankly the things that our neighbors are doing will continue to add value to our asset base and will require us to look at more of the things that are out there.

But right now I think we see this as basic blocking and tackling, have the lowest cost of capital possible, stir step the deployment of capital, lower our risk and then put ourselves in position to take advantage of where we’re sitting in the inlet.

Jonathon Fite – KMF Investments

Keep it up guys. You’re doing a great job. Your share price is incredibly undervalued and we continue to buy more. I know you guys have done a lot, but at these prices and with the upside that we’re all looking at, it seem clear that I’ll maybe take a little bit of that salary and buy a little more of yourselves given the opportunity you’re looking at.

David Voyticky

That’s a good idea.

Jonathon Fite – KMF Investments

All right, thank you guys.

David Voyticky

Thank you.


And we’ll take our last question from Mike Jacks with Sutter Securities.

Mike Jacks – Sutter Securities

Great job, guys. I’m impressed of what you’ve done. (Inaudible) spoke today; it looks like it’s about $110, 50,000 barrels a day that’s made in a half a month, what’s the down time, David, for you? I mean does that equate to about $12 million in net profit stuff, is that correct?

David Voyticky

Yes, David, what do you think the average – we can answer the question, but David Hall, what do you think the average run time will be for this well 365 day basis, well maintenance and the average sort of down time?

David Hall

I think we’re going to have an average of 95% of run time by year if not better.

David Voyticky

And so let me answer your question, Mike. And let me – let me highlight this because this is important. This well is different than RU-7 is different than West McArthur River five and six.

And this well, it had three ESPs stuck down. And as David mention, it had areas where the casing was sucked in and compromised. And if we have done everything we wanted to do to this well, we would got that last ESP out and the last 120 feet of completion and the LLC and we would have reinforced the casing at various points. We would have re-perforated it with a number of things

And so we are not drilling down on this well as hard as we could because we’d rather have the 400 barrels to 500 barrels than zero and that’s something very different than what happened when these wells were previously operated. They were pushed very hard. And ultimately it didn’t work out very well.

So I’d love to tell you that we’re going to keep pushing this well at this level. But we’re going to monitor it. We’re going to monitor for any changes and we’re going to – we’re going to run it at the – yet, the highest level we feel without risking having casing failures before we can get back in there and finish the rest of the work.

But I think that given where it is, if I was to project this out, I would project out something in the 300 barrels to 350 barrels range for the year is probably where will – this will level out at and we’re not pushing this as hard as the other wells.

And at the 95% level, I’d say you’re closer to – closer to $10 million, $9 million to $10 million versus $12 million.

Mike Jacks – Sutter Securities

And out of $170 million market cap that sounded significant. Can you clarify a little bit what the net expense savings will be when and if RU-3 comes on? What are we spending on a monthly basis to purchase gas and what will the net savings be that accompany from the use of the gas from RU-3?

David Voyticky

Yes. RU-3 we were paying $12 to $14 for a little while, but if you look at a million cubic feet a day and call it $10, you are basically $300,000 a month. So that will be our savings, bottom line. Plus if we have another $2 million to $3 million to sell and you can multiply by two or three and that’s additional revenue that should come in over in the winter months.

Mike Jacks – Sutter Securities

So they can rig another $5 million to $6 million from RU-3. So we’re up to $15 million maybe on a $170 million cap. I guess the next question to David Hall. David, what did you learn from drilling Otter that’s going to help make us more successful as we move forward? It’s tough. It’s tricky drill on up there. I’m just curious what you’ve learned and what’s going to help us moving forward.

David Hall

That’s a good question. Number one thing is, of course, we’re going to quip Rig 34 with new, more robust mud pumps, which we already have purchased and they’re enroute or soon to be enroute back to Alaska. So we’ll have better mud pumps. The other thing we’ve learned is it is a fairly faulted structure. We’ve seen and encountered all the different gas horizons at the various projected depths that we expected to see those in. But we have learned that the formations are sensitive. So we’re re-evaluating our drilling mud program to make sure it accommodates those sensitivities.

Mike Jacks – Sutter Securities

How many pay zones did you find in 5,000 feet?

David Hall

Well though, as I mentioned earlier, we only evaluated a short section of the Beluga Formation, and matter of fact, we didn’t fully evaluate all of it to the tune of about 1,000 feet that we didn’t even drill into. But through that short section of the Beluga Formation that we did evaluate, we identified over 127 seed of potential gas pay zone.

Mike Jacks – Sutter Securities

And I guess my last questions for Scott and/or Dave Voyticky. If we get up to 2,500 barrels a day as projected at the end of the year, is that going to be enough to allow us the key conventional bank financing guys? It seems like you’re going to be very solid and profitable company and we shouldn’t have to pay the Apollo type rates anymore. Have you had those discussions with the major banks and what level of profitability will they be able to extend credit to us?

David Voyticky

We actually think that Apollo will be our partners for the next two years, at least, maybe longer. We’re still fortunate to be in their BDC, which is typically a little bit lower rate lender. We came in a little early. We’re happy with the relationship. We think that they’re going to be a good capital provider for us in combination with the preferred – but quite frankly, to get to the commercial bank market, and Mike, I’ll kind of review where we’ve come from.

We started with the company that had one well, major well up, and we got a deal done for 25% with these same partners when we’re just getting started, with no warrants and no equity kickers. We brought that down to 18% and we hope to bring it down with those same partners further. And then we have with Shell we’ve got a very strong preferred, which others suggested on the call, with policy management and the investor in the near future as we load up our (inaudible) and stuff like that.

But the fact of the matter is that to get to the commercial bank financing in two years, with the Alaska, getting people from here to Alaska is going to take some time to build some relationships and have much better well-border diversification. I think it’s going to take us the full two years, but I think the relationships we have right now get us closer to that cost of capital where PV cans are getting closer to the 10% discount, which is what we want.

Mike Jacks – Sutter Securities

And do you anticipate keeping the Tennessee production within the company or are you thinking about spinning out of this standalone company?

David Voyticky

Well, I was going to answer flippingly that Deloy would love that because he’d love to run it and take it back.

Mike Jacks – Sutter Securities

Well, it just seems like we don’t get any value, any credit for it at all. I mean, that’s where we started years ago and it just seems like we’ll never get any value for those holdings. So I’m just curious if the company, anybody has given any thought to spinning that out as a standalone company to shareholders.

Scott Boruff

Mike, I’ll take it. That’s a great question. Yes, we actually just got permitted today, a couple of hours ago, to drill our first Mississippi line horizontal well. Total measure is up about 2,600 feet. So we’ll be doing that within the next three weeks, surveyed, it’s permitted. And that could be a game-changer for Tennessee. We just acquired the assets and operating wells of PCs as well with the properties there. So we’re optimizing those well bores.

And we had a pretty aggressive approach moving forward for the next 12 months for Tennessee. And we had people approach us about combining it with other companies and spinning it out. But when the time is right, we’ll look at it and if it works, then we’ll do it. But you’re right –

Mike Jacks – Sutter Securities

It just seems like we don’t get any credit for those assets at all. On a conference, never anybody asking about them. So just curious if we got plans to maximize those items at some point. Thanks, guys.

David Voyticky

Thanks, Mike. Thanks for your call.


And ladies and gentlemen, that concludes today’s question-and-answer session. Mr. Boruff, I’d like to turn the conference back to you for any additional or closing remarks.

Scott Boruff

Yes, thank you. Thanks for joining us this afternoon to provide you with an update on Miller Energy strategy and operating results. As you can tell, we are excited about Miller’s future and potential of our properties. We plan to keep you up to date on operations and future calls, and we look forward to you joining us again. Thanks and have a great day. That concludes today’s call.


And ladies and gentlemen, that does conclude today’s conference. We thank you for your participation.

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