Miller Energy Resources' CEO Presents at Operational Update Conference (Transcript)

Feb.27.13 | About: Miller Energy (MILL)

Miller Energy Resources, Inc. (NYSE:MILL)

Operational Update Conference Call

February 26, 2013 4:30 pm ET


Derek Gradwell – Senior Vice President-Natural Resources

Scott M. Boruff – Chief Executive Officer

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

David J. Voyticky – President and Acting Chief Financial Officer


Kim M. Pacanovsky – MLV & Co


Good afternoon, and welcome to the Miller Energy Resources Operational Update Call. All participants will be in a listen-only mode. (Operator Instructions) Please note that this event is being recorded. I would now like to turn the conference over to Mr. Derek Gradwell at MZ Group North America. Please go ahead, Mr. Gradwell.

Derek Gradwell

Thank you, operator. I’d like to welcome everyone to today’s update call for Miller Energy Resources. This call will cover Miller’s growth strategy, and recent corporate and operational developments. On our call today is Mr. Scott Boruff, CEO of Miller; David Voyticky, President; David Wright, Executive Vice President of Tennessee Operations; and David Hall, CEO of Cook Inlet Energy; Miller’s wholly owned Alaskan operating subsidiary.

Management from Miller will be discussing developments before opening the floor to questions. A slide deck of the company’s presentation is available on the Company’s website at

Before we get started, I’m going to read a disclaimer about forward-looking statements. This call’s discussion may contain in addition to historical information forward-looking statements within the meaning of the Federal Securities Law regarding Miller Energy Resources. Forward-looking statements include statements about plans, objective, goals, strategies, future events and performance, underlying assumptions and other statements that are different from historical facts.

These forward-looking statements are based on current management expectations they are subject to risks and uncertainties and may result in expectations not being realized. And they cause actual outcomes to differ materially from expectations reflected in these forward-looking statements. Potential risks and uncertainties include changes in demand for the company’s products, the impact of competition and government regulations. Another risk contained in the statements filed from time-to-time with the regulating bodies.

All such forward-looking statements, whether written or oral, made on behalf of the company are expressly qualified by these cautionary statements. Such forward-looking statements are subject to risks and uncertainties, and we caution you not to place undue reliance on them.

It’s pleasure to introduce Scott Boruff to you. Scott, the floor is yours.

Scott M. Boruff

Thanks, Derek, and hello and welcome to Miller Energy Resources’ operational update call. And as many of you’ve been following our progress closely know that this is an exciting time for us as more production is being added in both Alaska and in Tennessee.

Today, you’ll be hearing from David Hall, our CEO of our Alaska subsidiary, Cook Inlet Energy, who will be providing you with an update on our operations in Alaska. David Wright, our Executive Vice President of Tennessee Operations will provide you the details of our recent developments there, and Dave Voyticky, our President, who will discuss the implications of our recent development, and what that means going forward.

But before I turn the call over to them, let me give you a few of my own thoughts on where we stand from an operational perspective. This is a tremendously exciting time for Miller. Over the past five to six months, we’ve made great strides forward in our overall strategy with attacking projects that we expect to be low risk, high return prospects.

In Alaska, we’ve deployed Rigs 34 onshore and Rigs 35 offshore, and opportunities on Osprey platform have yielded terrific returns at a relatively low cost. These rigs combined with our platform represent some of the newest equipment in the Cook Inlet and we remain positive about their contribution to Miller going forward. Our Tennessee Operations are also outperforming every expectation, and more than justifying our commitment to operations in this basin.

Our program for horizontal drilling has yielded some of the exciting inceptors, which David Wright will discuss in detail later on. Drilling into the Fort Payne formation, we believe our success with our cPTH-1 will obviously change the way the market looks at oil production in Tennessee, and we are uniquely well positioned to expand on that success at other well south in the region as well.

With that said, let’s begin with an update in Alaska, with David Hall. David, take it away.

David M. Hall

Thank you, Scott. Well, first I’ll start with production status in Alaska. The current production in Alaska which includes approximately 850 barrels of oil per day, and about 2.1 million worth of gas for a combined production of 1,200 BOE a day. So as you can see, there is an increase mainly attributed to our recent announcements on RU-3 and RU-4 gas wells. This does not include any production from RU-7, and any potential increases in production from RU-3 and RU-4 once we start selling gas to third parties.

Moving on to RU-3, we’re very pleased with our most recent announcement of RU-3 gas well, the workover was complex, but yet successful. With the subsequent four-point test showing a maximum flow rate of 3.7 million cubic feet a day.

Keep in mind, this is the gas on those previously abandoned by a well know E&P company. One thing, we believe that gives us an advantage is not only understanding of (inaudible) of the equation, but also the operational side of things as well, enabling us to recover reserves otherwise left behind.

RU-3 is on of interest within the low atomic with a measured depth of 14,800 feet, with an identified net pay of 20 feet. What made this workover complex was regaining accessibility to the gas on of interest. There was a number of fish that needed recovered including, some that were previously unknown.

Thankfully, it went well followed by putting the well online in early February, and has been producing approximately 1 million cubic foot a day, which I might add at a reduced rate to our current demand.

Now, moving on to RU-4 in conjunction with RU-3; RU-3 and RU-4 are both fulfilling 100% of our current fuel gas demand with a combined flow-rate around 1.6 million a day. There is room to further increase flow-rates on these wells once we start selling gas. We are in discussions with multiple parties to establish gas sales, and hope to have an agreement in place in the near future.

I will say that we are expecting to sell between 500,000 and 2 million Mcf a day. Both wells have been exhibiting great performance today with minimum declines. One thing of particular interest is in RU-3 and RU-4 are in separate fault blocks with a total of six departmental fault blocks that comprise the readout structure. What this means as we expect a high probability of success and accessing some of the remaining untapped fault blocks, which could prove productive in which we anticipate will grow our gas position.

In general, the readout structure is very exciting and we estimate that only a small portion of the oil in place has been recovered to-date. We expect that in the future, huge amounts of oil and gas maybe recovered through detailed earth science work.

Some of that work includes reinterpretation of our recently reprocessed 3D seismic over the readout structure to better identify a potential oil and gas targets. Techniques such as enhanced pre-stack time migration have been improved deep imaging and we believe we’ll identify further drilling targets and ultimately lead to a higher recovery in the field.

Moving on to RU-7; RU-7, our workover was recently completed. The well was put online a few days ago and is currently cleaning up as a result of fluids that was used during the workover. As of pending new well, there’s a period of time if the well needs to produce fluids used during the workover, before the formation begins to contribute into the well-bore.

The workover ramped up very well, although in our attempt to add the newly identified 53 feet of perforations, we have difficulty getting the perforation gallons on depth. We discovered that in order to add the new perforations, we will need to pickup drill pipe and conduct a clean out run in which we were not set or perform at that time, due to conducting simultaneous work on RU-3, RU-4, and RU-D1.

However, we’re very excited about the great potential revenue perforations and prior to add that the next time we pull into plays RU-7 ESP. One more to change on this workover was that we elected to increase the electrical submersible pump size as we expect that will better enable us to draw the formation down.

Prior to November 2012, ESP failure, RU-7 exhibited strong formation pressure support with a flowing bottom haul pressure to approximately 2,200 psi. As the well cleans up and resumes previous flow rate of 2,200 barrels oil per day, we’ll then start increasing the speed of our larger ESP hopefully increasing production.

In the past, we have mentioned taking part of RU-7’s warm fluid and routing it down RU-1 in an effort to assist and boost RU-1 production. Those efforts have not been deployed due to needed time for RU-7 to clean up and establish a new production baseline first. However, we do plan to implement this when operationally ready. The theory is by taking this warmer fluid from RU-7 and routing it down at RU-1 that will help the liquid level controller, LLC feather open increasing flow rate.

Now that RU-7 is complete and online, a concentrated effort is underway to start Rig 35 from Leg 2 over to Leg 3 in the platform, so that we can began the work on RU-2. As many already know, RU-2 is our first planned sidetrack to mitigate the class casing and restore the previously producing oil production of approximately 600 barrels of oil per day.

The summary of RU-2 well is as follows: RU-2 have been producing at an oil rate of approximately 600 barrels oil per day with a water cut of 31% and had a total off take rate of approximately 850 barrels of fluid per day, then experienced what appears to be a split in the casing about the Hemlock formations, followed by the oil rate quickly dropping off to zero on May of 2005.

RU-2 had been shut ever since. The planned sidetrack is straightforward process that basically consist of utilizing as much of exiting well-bore as possible by the pass casing, followed by milling through the casing, and then by drilling around that bad segment of the well-bore to the similar bottom hole destination.

Two noted change during the plan sidetrack are, first we planned to use heavier well casing to eliminate any class casing issues; and second as we have a new revised bottom-hole location like could potentially getting us 200 feet structurally higher than the original well-bore. These changes provide a sound well-bore design that will hopefully increase production by better well placement.

There are a number of things taken place in preparation for RU-2 sidetrack including items such as installing solid handling equipment, but we expect to start the sidetrack in about four to five weeks, once these things are complete. Once RU-2 sidetrack is underway as expected it take about 60 days to complete.

We’re confident that we have developed a sound sidetrack plans with consultation firm Brammer Engineering who provides oversight, throughout the entire process from planning stage to implementation. Brammer Engineering has already played an important role in our recent successes including RU-3 and RU-4.

Now moving on to onshore operations to order, our engineering team is currently finalized on our plans to deepen out at world number one by a minimum depth of 900 feet, with a potential maximum depth of 1,300 new feet. Another 900 feet will get us fully through Beluga formation, so that we can immediately get into the Tyonek formation. Rig 34 has already setting of item number one and the plan is to extend the well-bore before the end of June.

Now moving on to Olsen Creek; although the pad has been built and the road extension is complete. We are currently working to repair a section of road that was damaged in the last year’s severe weather, when a segment of the road system had washed out. The permit to drill has been approved, and so the maximum approved drilled depth of 7,500 feet with our primary target being the Beluga formation, with the upper Tyonek as the secondary back, really secondary target.

One point to note is that our engineering team is evaluating the Hemlock potential. If we determine that it could be profitable to take the well deeper to evaluate the Hemlock, we will need to amend our permit, and use a large drilling to go deeper. Currently plan to spread Olsen Creek number one well as soon as the weather and road allows, which we expect to be in early to mid-summer.

Moving on to additional wells; we’re currently looking to secure additional onshore drilling rigs to drill the following wells, WMRU-7A, WMRU-8, WMRU-9, West Forelands 3, and West Forelands 4.

Now I’ll move on to Susitna Basin in particular Kroto Creek prospect. We’re moving forward with the preparation to explore prospects in our Susitna number, license number two located north of the Cook Inlet Basin, with Susitna number two, exploration license is set to expire on October 31 of this year. We have an option to convert all or part of the license areas to leases upon exploration. Although we have identified a number of prospects we are focused on one in particular, which is Kroto Creek.

Kroto Creek is a gas exploration play within the exploration for licensed area located about 50 miles northwest of Anchorage in the remote area. The prospect is about 12 miles from the nearest road, separated from road access by the Susitna River.

We have recently permitted for a groomed winter trail in the area including an ice breakage processes in the river, and work is ongoing. The company has submitted a plan of operations or completion of the four mile groomed winter trail as part to the proposed pad area, which includes brushing the trial, compacting the pad area, and drilling a water well and conductor. It is necessary to lay this ground order this winter season in preparation for an intensive operation in the future.

With that Scott, I am turning the call back over to you.

Scott M. Boruff

Thanks David, great update and as you guys can see we’ve been expanding the base in Alaska, a great job on basically the first four reworks on all four platform bringing two gas wells online at above expectations and reworking those two oil prospects and bring those online as well. So we’re excited about that.

And now I’ll turn the call over to David Wright, who will give us some update on Tennessee operations, David?

David Wright

Thanks Scott. Today we drilled horizontal wells in Mississippian Lime in Tennessee. We have two more scheduled in the near future. The first well, CPPH-1, we’re continuing to calibrate the path to keep the production up in the CPPH-1. We’re doing this by experiment that by placing downhill turn at the different elevations, sheet metal, gas anchor et cetera. We want to find out where we need to put these to maximize production.

Nitrogen, which was used in the frac, content of nitrogen is still high in the well, as the gas can now in the oil. January 17, we had 63% nitrogen in the gas sample. February 21, we still had 56% nitrogen in the gas sample.

So we’re still giving back nitrogen from the same frac that we did. Like I said we’re in a learning curve on these horizontal wells. This has taken much longer than any of the vertical wells and some of your reservoirs and wells take a while to get back to – is taking a bit longer (inaudible).

This week we moved the rig permit number 2,100 which in one of the wells adjacent to the horizontal that we drilled. We’re going to be running 4.5 inch casing with formation frac issue and turning on a pack or in order to make ready for gas re-injection, when we get an EPA permit to re-inject gas into this formation. This new timeframe on the permit maybe as far as in the next three, four weeks, we should be getting the permit.

Additionally, we are also drilling our other two wells that were adjacent to these horizontal wells– two vertical wells, permit number 2047 and 2080, drilling them back on time and once again this is real good. We’re trying to see the impact of these horizontal wells and all vertical wells and production and once again we’re breaking new ground in Tennessee. So we’re trying to get as much information as we can.

We’re continuing to survey on new ore in the next horizontal locations in Skull Creek, Gum Branch area which is where CPPH-1 is. We’re planning on drilling one well off the same pad as the CPPH-1 and the L-1 is – other locations due leased with the terminus of CPPH-1.

Second well – horizontal well we drilled in Tennessee, the Maynard H-1; we’re presently evaluating down haul situation to best produce this well. Maynard H-1 had natural shale oil and gas and not quite as good as the CPPH-1, but still had good shale of oil and gas. And we stimulated this well also and with the result from the stimulation treatment, it looks like we need to further isolate different segments of the horizontal leg in order to maximize production. We’ve got a little bit different lithologies in this well than we did in the CPPH-1. So we won’t be using the substratal packers to isolate these zones which should enhance the production even better.

We are nearly putting two vertical wells that are adjacent to this horizontal well. We’re putting them on time, Permit No.1989 and Permit No. 2048. These wells should be back on time within the next three to four days. After we finish those two wells, we’ll be putting Permit No.1728 and Permit No.1919 which are two other wells in the same proximity of the horizontal, we’re putting them back on time also. Once again, we’re getting information and we’re going to see the impact – horizontal wells, on vertical wells, vertical wells and the horizontal wells shale.

The next two areas that we’re going to be drilling are – the next two horizontals are Burrville area and the Low Gap area. Both of these areas, we’ve chosen the location. Surveyors began surveying in the locations of both areas. We’re running to get entire opinions on both areas. These horizontal wells that we drill in these oil fields is very complicated otherwise. We’re no longer drilling a vertical well. We’re drilling a horizontal well; half a mile to three quarters for mile in length, taking in potentially many, many surface land owners and the main things where we need to protect is the correlative rights of each of those land owners. So title becomes very tricky on these horizontal wells.

We’ve been told that a drilling rig should be ready for us by the end of March. We should be ready in both of these locations, both at Burrville area and Low Gap area to begin drilling the next two horizontal wells. Once we drill these two, it looks like we’ve got five to six horizontal well locations in both of these areas together, five or six both areas.

We still have a learning curve on drilling these horizontal wells. We’re trying to take our time, need to walk before you run, so we want to make sure that we’re doing things properly and to our best ability. So we take being real prudent in developing these horizontal wells.

We also have a vertical well that we’re going to do a rework on. That is in the Low Gap area. One of the areas that we we’re going to be putting the next two horizontals. This is an older well that we purchased. We’re moving our rare rig over within the next five days. It should take about four to six days to complete this well.

What we’re going to be doing, this well has a shale obstruction that has stopped production of the well. The old owner abandoned the well. We picked it up; we locked the potential of this well. We know the history of the well and we plan on drilling in, drilling out to shale obstruction running 4.5 inch casing or formation packers in, then a small last job on the (inaudible) Mississippian Lime running tubing rods and place this well on time. Anticipated flowage production, we think will be around 15 to 20 barrels a day. AFE on this vertical rework is right at $92,000. We feel very comfortable about this well. We are extremely excited about the next two horizontal locations and we’re looking forward to continuing. Back to you Scott.

Scott M. Boruff

Thanks David. To summarize that, we drilled two horizontals. This is a new process. Again, we were the first probably in the east of Mississippi to drill into the Mississippi Lime horizontal. So as we went down the road, just trying to give estimations, EURs, flow rates, until we get our EPA permit, we will not flow these wells. They’ve just been flowing naturally on and off and have high gas content as well and good pressure.

So we drilled two, we’re planning for two other. As you can imagine, we had several calls from people across the country with our out piece we had on the wells. And we’re consulting with large majors that are looking at it and (inaudible) what they’ve done in Kansas City and other places with their wells, compare their nose to ours.

For those of you who remember, we used to drill through the Chattanooga Shale before we figured out a way to frac it and now it’s one of the most prolific gas wells in Tennessee. The Chattanooga Shale, we’re kind of experimenting these wells as we go forward. And it’s exciting time because our best production in Tennessee is 100 barrels a day and so we’re looking pretty self-substantial this year and we’ll keep you guys informed on our quarterly calls and operational calls as we learn.

So thanks Dave for that date and next we’ll hear from Dave Voyticky, our President and acting CFO. He is going to tell us about the identification of our previous developments and what’s going – what that means actually going forward. Dave, are you there?

David J. Voyticky

Thank you, Scott. So I’m going to give you a quick summary of where we were three years ago when we set forward our plans and redeveloped the assets and where we are now as a comparison. But in January 2010, when we acquired the assets of Pacific Energy, we had no wells online. We have limited access to capital markets really only two of the pipes market. We had limited rig availability.

And probably over the last three years, we’ve had an average cash balance of something around $2 million. We understood that our assets were unique and that a large portion of these assets were previously producing. And that we had an opportunity either to issue a bunch of equity at prices we thought were below fair value and for lease other peoples’ rigs at a higher cost and higher risk in order to take a long-term strategy, which would involve bringing on the lower costs, lower risk wells, and stair stepping our capital structure development.

And now in February 2013, I think with this operational update, with RU-3 and RU-4 both being online for gas and RU-1 and RU-7 having work-overs complete, we’re in a very different position than we were three years ago. And we’ve had success on 10 out of 12 Alaskan reworks. Out of the 10 that have been successful, all of those have come on just significantly higher production rates than the previous operators. In fact, over half of those were not productive under the previous operator at all.

For the one that is not complete yet of the 12 West McArthur River 7A and we’re looking to finish that up in this spring early summer. And KF-1, which costs approximately $1 million, which is the one that was not successful, is then offer better returns to Miller at its disposal wells than it would at the production rate that we are able to restore.

So that in combination with the four wells of the platform, the four wells onshore plus the 30% working interest that we have in our two our own wells, we have such very good well-bore concentration plus cash flow diversification compared to where we were in 2010. And commensurate with that, we have been able to reduce our capital cost from – under our first facility with digging at 25% back to our current facility with Palo, which we did in January of 18%, and now we are showing perpetual preferred with the 10.75% coupon.

So we’ve been able to stair step down our cost to capital, increase our well-bore diversification. And at the same time, we’ve been able to make certain operational improvements at full internal growing teams and G&D team, we’ve gone from three people on accounting to over nine, and we’ve added two people to our legal team and obviously switch from (inaudible). So we’ve really made a lot of changes in the business over the past three years. But with these additional wells coming online, we see ourselves going into a different stage of development.

A stage of development that we believe is prudent given our capital costs, our availability to capital, the fact that we have our own rigs both in Tennessee and Alaska, and we have a cost to capital to support that drilling activity. And included in our operational achievements for the past couple of years has been really a terrific increase in the price of oil that we’ve received, renegotiating our contract with this oil, where we used to receive WTI, we now receive Alaskan North Slope minus 4, which is a $14 increase.

And we’ve also seen our operational came up in Alaska decreased our shipping costs from $20 a barrel, that’s a real $5 of barrel per day. So in combination, it’s almost a $30 increase in cash flow from oil sales that we’re receiving.

With RU-3 and RU-4 online, we’re no longer subject to the high prices for gas up in Cook Inlet and in fact, the unavailability of gas up in the Cook Inlet, we’ll talk about that later as we talk about the decision to use that production for our own operations, and how much we are going to sell to third-parties. But most importantly, when you look at our cash position, many of our shareholders have looked at us over the past year, had concern over capacity, ability to execute on our plan with our cash position, and if fact we either have an events or have to issue equity and we set for three year straight. We’re not going to issue equity at these prices on a warrant.

Our position today, we have over $25 million of liquidity, which is obviously substantially more than the average of $2 million that we’ve seen over the past three years, and we’re in very good position to begin of the more expensive and higher return reworked with three things that are a big part of the value proposition.

Four, folks that are interested who are obviously take compliance with our senior loan agreement, and covenants levels were reduced to aid with future complains of Apollo and team Miller has been great partners. It’s very few company that can stay after three years of having a relationship with a bank that you have no issues and very excited going forward, and Apollo has been help to us in every step of our development, and has been to our systems and helping us form our plan and our steps going forward.

When you look at our future development and what we’re focused on in the next year, David Hall mentioned, the primary opportunity is the sidetrack opportunities off of the offspring to be that structure. We have up to five sidetrack opportunities, which will each have a gross CapEx around $10 million, but when you exclude the costs of our own rig about $8 million per sidetrack. We have 13 new drill targets on the Redoubt structure. So that rig that we put on the platform is going to be busy for quite some time.

But David also mentioned as we bring our additional cash flow, and what else we’re going to have opportunity to accelerate our drilling program onshore. They are got opportunities in the West MacArthur River field and then we have the adjacent Sword and Saber structure which have multiples zones of interest of both gas and oil.

And we still have West MacArthur River 7A as a work over as well as the shallow gas wells, that’s what that David mentioned (inaudible). But as you take a look at this operational update, I think the key thing for us is today, we have very well four diversification, good cash flow, and strong liquidity and we’re looking to move forward into the next phase of our development.

And as you look at the development, when we had a barrel of oil in terms of cash flow at today’s price is we’ve look at it very simply, Alaskan was minus four, Alaskan were pretty much narrow spreads, maybe $1 or $2 off, we have about $5 for transportation and as our production goes up that number will go down, and then we think we have incremental operating expenses for lifting oil and between $3 and $5 a barrel, and with a 81% to 83% net revenue interest, we think our cash flow, for additional barrel of oil that we produce from this full plant forward at these prices in the $80 barrel range, which is the great economic prospect for us.

With that Scott, I’ll turn it back over to you.

Scott M. Boruff

Thanks David and before I open up the call to your questions, I want to comment a few other matters. Given what you just heard I think you can see why we’re so excited here at Miller. We’ve made tremendous progress from an operational perspective in the last five months realizing on our plan in Cook Inlet and demonstrating new value in Tennessee.

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

Question-and-Answer Session


Thank you, sir. We will now begin the question-and-answer session. (Operator Instructions) Our first question is from the line of Neal Dingmann with SunTrust. Please go ahead.

Unidentified Analyst

Hi, I’m calling in for Neal actually, and I was wondering how the weather is expecting activity this year versus last year?

Scott M. Boruff

Well, as far as Alaska, so far weather hasn’t really impacted any of our operations whether it would be on the platform or onshore.

Unidentified Analyst


Scott M. Boruff

With that a pretty mild winter so far.

Unidentified Analyst

Okay. And could you repeat your current production now that – are you agreeing on forward online?

David M. Hall

Yeah, we’d be glad to, we’re currently producing about 850 barrels of oil per day.

Unidentified Analyst


David M. Hall

And about 2.1 million cubic feet of gas a day for combined production of about 1,200 BOE a day.

Unidentified Analyst


Scott M. Boruff

And the same if you remember about our 1,200 is that sort of gas mainly need for the production is necessary for own operations, so we are not currently selling gas to third parties, and we sell – if we decide to sell gas to third parties that number in terms of gas go up between 0.5 million cubic feet a day to additional 3 million cubic feet a day. It also does not include any production from RU-7, which was previously producing at 230 barrels a day.

Unidentified Analyst

Okay, awesome. And also could you tell me what the drilling and completion costs are for your onshore wells?

David M. Hall

For Alaska?

Unidentified Analyst

For both Alaska and Tennessee.

David M. Hall

Yeah some of the estimated costs that we put together for some of our onshore wells, I’ll start with Sword, for example, which is one of our onshore prospects located near the western parts of River field. That one an extended ridge, deep oil well. And we have an estimated cost of about 17.5 million gross. Some of our other wells, for example, the Olsen Creek well, which were still fine tuning our cost estimate and subsequent AFE, but that one is estimated to be in the 7.5 million to 8.5 million gross.

Unidentified Analyst

Okay. So that’s just average you think?

David M. Hall

I think so with the exception of WMR RU 8, 9 those won’t be quite of extended reach, so those will probably be in the 15 million to 15.5 million range.

Unidentified Analyst

Okay, thank you.

Scott M. Boruff

And keep in mind that’s the gross number and we always speak in gross number, but we get that $1.40 back in Alaska. And as for Tennessee, the horizontal wells running about 1.1 million to drill and about 200,000 to complete again with the 14 states frac, so the first relative Tennessee frac was really about 125 for the frac and only about 185, so about 1.3 million on the Olsen Creek Tennessee. And in the vertical rework that we are doing we’re going to spend about 95,000 on that well and we expect 15 barrels to 20 barrels a day kind of add. Thanks for your question.

Unidentified Analyst

Thank you.


Thank you. Our next question is from the line of Kim Pacanovsky. Please go ahead.

Kim M. Pacanovsky – MLV & Co

Good afternoon everyone. I just have a couple of questions, first of all on the excess gas, what are some of the pros and cons of selling that into the spot market, versus having a contract to solve that gas, and because I slightly understand that there’s a pretty large differential, but I know the spot market was about $20 this winter. And if it is so through contract with the party who are the perspective parties that would buy that gas and can you just explain to us actually where that gas would go into?

David M. Hall

Sure. Can I take that question? The way we are looking at selling our excess gas really starts from our long-term perspective. So I’m not sure that we have enough gas to fulfill our own operational needs. Currently, we are having about 1.7 million cubic feet a day with the one rig running and operational. We believe that if we open up the wells we could produce these wells at more than twice that level comfortably. The way we are looking at entering into a long-term contract for part of that supply if there are a number of end users up there from M Star through gas compared to their electric properties that are often looking for gas. From our perspective, if we can enter into a long-term contract or settlement that will be ideal, and we can opportunistically take advantage of the spot market. But from our perspective we are most focused on making sure that we have enough to fill our drilling needs.

As we get an additional gas wells online and much like our hedging program on oil, we will feel more comfortable connecting to large amounts. And I think that by the end of the summer, we’ll be in that position where we’ll look to take the vast majority of our production, that goes in for long-term contract and then during winter months opportunistically take advantage of the price spikes.

As David mentioned with respect to weather, there has been a fairly mild winter in Alaska. With a winter months, March really being the last of the very cold months. So we are not back at assurance about that opportunity this year. And we will be focused much more for this defect of production for looking for a long-term contract. Second of course making sure that we have enough for our own facilities.

Kim M. Pacanovsky – MLV & Co

Okay. And how do you see your own needs changing say over the next 12 months?

Scott M. Boruff

The biggest thing that could change our needs would be if we are successful in securing an additional rig to draw up absorb West MacArthur River eight or nine. We can have some increased power needs. Then we also, as David mentioned are looking for a rig to finish the work in West MacArthur River 7A and West Foreland Creek. So those things could lead to an increase and need for power over the summer months.

Kim M. Pacanovsky – MLV & Co


Scott M. Boruff

And then going into the next winter, if we start that program going, we could be at a little bit higher levels. So that’s a key thing for us.

Kim M. Pacanovsky – MLV & Co

Okay. And David well mentioned that there are six fault blocks that you would expect a high probability of future gas success. Can you just maybe give us an idea of what those potential reserve sizes are, are they bigger, they all ran the same size, is there any variability that we need to be aware of?

David M. Hall

We do arrange those in size, but we always think a renown restructure and it almost has the shape of a nose. And we are currently producing out of the central fault block. But there is fault blocks to the north and to the south of our current productive fault blocks. So we do think that they hold a great potential on not only gas, but oil as well. On that same note there has been wells drilled early on in the various fault blocks back in the early 60s that proved at the oil sites. Keep in mind, that in those days, we weren’t really looking for gas.

Kim M. Pacanovsky – MLV & Co

Right. Okay.

Scott M. Boruff

And it’s interesting to note Kim, as we bring on RU-3 and RU-4 gas. RU-3 was a gas that was produced for the previous operator and then stopped producing, they stopped – there was a reservoir issue. David and our team saw it was a mechanical issue. Obviously we’ve been successful in bringing that well back on line. And in another zone, on 4, again behind pipe gas opportunity that was ignored by previous operator. Quite frankly, we are much more interested in sidetracking for oil, but what became obvious to us at the beginning of this winter was with the changes.

Kim M. Pacanovsky – MLV & Co

It’s a test.

Scott M. Boruff

Yes, exactly. We should, (inaudible) book we’re buying both Chevron and Miller that the availability of gas and it was necessary to drill both of those wells, which we are happy to seek those. We think there will be multiple opportunities on some of these sidetracks if you want to produce additional gas, drilling into completion. But our primary focus on the read out structure is going to be for oil.

Kim M. Pacanovsky – MLV & Co

Okay. And then on RU-7, do you have any indication that well will come on above the 230 barrel a day rate that it went off on. At least tell us any more about your expectation and I know it’s cleaning up and it’s premature, but…

Scott M. Boruff

Yeah, that’s early to have any indications as of yet. It’s following the same pattern that it previously followed when we brought it online and when we brought RU-1 online. So we think that it was a good chance to produce at the previous level and there is a decent chance for producer at a higher level. Our expectation is to put that information out, once the well cleans up we will put a press release out. It should be in the next two weeks.

Kim M. Pacanovsky – MLV & Co

Okay, great. Well congratulations guys, a very good news. Thanks a lot.

Scott M. Boruff

Thanks for calling in.

David M. Hall



Thank you. At this time, there are no additional questions. I would like to pass the call back to management for closing remarks.

Scott M. Boruff

Great. Thank you for joining us this afternoon to provide you with an update on Miller Energy’s operations over the past several months. As you can see, we are very excited about Miller’s future and the potential of our properties. We are trying to keep you updated on our operations and our future calls, and look forward to you joining us. That concludes today’s call. Have a great day.


Ladies and gentlemen, that does conclude the Miller Energy Resources operational update call. We thank you for your participation. You may now disconnect.

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