Derek Gradwell - Senior Vice President, MZ Group
Scott Boruff - Chief Executive Officer
David Voyticky - President and Acting Chief Financial Officer
David Hall - Chief Operating Officer and Chief Executive Officer, Cook Inlet Energy, LLC
Chad Mabry - MLV & Company
Neal Dingmann - SunTrust
Jeffrey Connolly - Brean Capital
Philip Juskowicz - Casimir Capital
Miller Energy Resources, Inc. (MILL) F1Q 2014 (Qtr End 07/31/2013) Earnings Call September 10, 2013 4:30 PM ET
Good afternoon, ladies and gentlemen. Welcome to the Miller Energy Resources' first quarter 2014 earnings conference call. (Operator Instructions) At this time, I'd like to turn the conference over to Derek Gradwell, Senior Vice President of MZ North America. Please go ahead, sir.
Thank you, operator, and good afternoon, everyone. Joining us today for Miller Energy's 2014 first quarter earnings conference call are Mr. Scott Boruff, the company's CEO; Mr. David Voyticky, the company's President and acting Chief Financial Officer; and Mr. David Hall, Chief Operating Officer of Miller Energy and CEO of the company's Alaska's subsidiary, Cook Inlet Energy.
Mr. Boruff, Mr. Voyticky and Mr. Hall will review and comment on financial and operational results for the first quarter of 2014. And they will be available to answer questions after the presentation.
I would like to remind our listeners that on this call prepared remarks may contain forward-looking statements which are subject to risks and uncertainties, and that management may make additional forward-looking statements in response to your questions. Therefore, the company claims the protection from the Safe Harbor forward-looking statements that is contained in the Private Securities Litigation Reform Act of 1995.
Forward-looking statements related to the business of Miller Energy Recourses and its subsidiaries can be identified by common use forward-looking terminology. These statements involve risks and uncertainties including but not limited to the implied assessment that the company's oil and gas reserves and profitably produced in the future, the need to enhance Miller Energy's internal controls, the company's ability to fund its operations and business development plans, operating hazards, drilling risks, fluctuations in the prices receive for the sale of oil and gas, litigation risks and changes in government regulations.
The company's filings on Form 10-K, 10-Q and 8-K with the SEC contain more detailed descriptions of these risks and uncertainties. Investors should not place undue reliance on such statements which are qualified in their entirety by the risk factors contained in Miller Energy's SEC reports.
For those who are unable to listen to the entire call, we'll have an audio replay that will be available and the call is also been webcast, so you can log on via the internet, and all the information was provided on the call announcements in the earnings released yesterday.
At this time, I'd like to turn the call over to Mr. Boruff, company's Chief Executive Officer, and he'll provide opening remarks. Mr. Boruff, the floor is yours.
Thank you, Derek. Good afternoon and thank you for joining us today for Miller Energy's 2014 first quarter earnings conference call. To begin, I will provide a brief overview of our accomplishments during the first quarter of fiscal 2014, which ended on July 31, 2013. Following my overview, David Voyticky, our President and acting CFO will provide additional detail on our financial results.
After a review of the financials, David Hall, our Chief Operating Office as well as our CEO of our Alaskan subsidiary, Cook Inlet Energy. Then, I will provide more detail on our drilling plans and our outlook for the rest of the fiscal 2014. Upon completion of the management presentations, we will open up the call to your questions.
Fiscal 2014 is all about the drill bed for Miller. We are well-positioned to aggressively pursue our 2014 strategic priorities with increased cash flow resulting from increased production, our Alaskan tax credit and our existing liquidity. In addition, if needed, we have ability to access capital market through our Series C Preferred Stock offerings and we will also consider joint ventures as the opportunities arise.
We currently have three rigs in place and are now able to fully focus on increasing production. During the first quarter, we continue to see big increases in production. We successfully brought online our largest oil well to date RU-2, which was the first of several planned sidetracks on our all three offshore platform in Alaska.
RU-2A had initial production rate of 1,281 barrels of oil per day and it averaged 1,307 barrels per day during the quarter. RU-2A well came online on June 20, about halfway to the quarter. So we are not saying the full quarter is worth revenue from the well in our results announced yesterday.
Subsequent to the end of the quarter, we completed our second sidetrack, RU-1A, which is averaged approximately 740 barrels a day, since coming online. We are continuing to evaluate optimal pump speed to maintain the reservoir integrity and pressure. Combining these two wells, with the additional new production from the Osprey platform and in Tennessee, we have more than doubled our production to about 3,300 BOE per day, which is the highest in our company's history.
We currently have three rigs running in Alaska. In addition to the Osprey platform sidetracks with Rig 35, we are using our Rig 34 at Olson Creek, a gas prospect and the Patterson owned Rig 191 at our Sword well number one an oil prospect. Rig 35 is currently sidetracking RU-5 and the new well RU-5B should be online within the next two weeks.
We are drilling our Sword number one well with the Patterson owned Rig 191 near our West McArthur River Unit. The well which is designed as an extended reach well was started on June 19, 2013, and we are currently sidetracking the well after running into a problem with the bottom hole assembly. Even with that set back the project is expected to be online within the next couple of weeks in October.
Rig 34, our onshore rig is drilling Olsen Creek number one well, which targets the natural gas. Due to the coal sticking issue, we had to sidetrack that well and oil core should completed within the next three to four weeks. David Hall, our new Chief Operating Officer at Miller Energy as well as our CEO of our Alaskan subsidiary Cook Inlet Energy, will discuss our drilling program for fiscal 2014 and more detail later on this call.
In Tennessee, we continue to be focused on acquiring additional working interest in existing wells as well as learning about how to better drill, complete and produce our horizontal wells. We are permitting our third horizontal well now and continue to make progress on the first two. These wells will require minimum CapEx to drill and provide a potential for very attractive returns and incremental cash flows.
Finally, in addition to our operational news. We secured substantially less expensive capital to further fund our drilling program by amending our credit facility with the Apollo in early August. That amendment allowed us to draw an additional $20 million at an interest rate of only 9% until January 31, 2014, by which time we expect to refinance the Apollo loan.
Through the increased cash flow from successful new wells over the past six months, this additional lower cost capital from Apollo and the expectation of receiving ACE's rebate in the next several weeks, we are in the strong liquidity position to execute our 2014 goals. We are excited about the increases in production we have made in the first several months of fiscal 2014, which puts us well on track to meet and even surpass our production goals of 4,000 BOE a day by December of 2013.
At this time, I'd like to introduce David Voyticky, President and Acting CFO, to go through the financial results. David?
Thank you, Scott. We saw a substantial increase in our revenues from the prior period up 57% to $13 million compared to $8.3 million in the first quarter of fiscal 2013. This is directly related to the new production we've brought online since the last year as well as the 5% increase in the realized price of oil compared with that with the first quarter of fiscal 2013.
Our total net production increased to 125,080 BOE compared with 77,079 BOE in the first quarter of last year. This was an increase of 68% in the Cook Inlet, which relates primarily to new production from RU-3, RU-4A and RU-2A wells. We saw an increase of 20% in Tennessee as well, because of increased ownership in many of our wells there and as a result of production from our horizontal wells.
Broken down by region, Alaska contributed 90% of our net production and Tennessee contributed 10%. Our average realized sales price per barrel for oil for the quarter was $104.57, which was an increase of $4.98 or 5% over the same period last year.
Our operating cost for the first quarter increased $2.3 million or 58% to $6.3 million compared with $4 million for the same period last year. This reflects our increased pace of activity in Alaska. The increase in operating cost was directly attributable to increased oil transportation, increased drilling activity, which created additional labor and camp facility cost as well as transportation doing from the facilities.
In addition, the increased drilling activity substantially increased the cost of control of well insurance. Approximately $1 million of the increase resulted from the sale of crude oil inventory that was reported in the previous period at a higher cost per barrel due to well workovers.
G&A expenses increased $1 million or 19% to $6.3 million in the first quarter of 2014 compared with $5.3 million during the same period in the prior year. Salaries increased 6% from the same period in the prior year, as we continued to expand our corporate accounting and legal staff from the prior period. Professional fees increased 56% over the same period of last year due to increase in litigation related expenses and fully recruitment during the quarter.
Stock-based compensation declined 23% due to the expense associated with rewards that became fully vested, exceeding the expense associated with newly granted rewards. Depreciation, depletion and amortization expenses, which include expenses related to leasehold cost and equipment increased 82% from $3.1 million in the first quarter of fiscal 2013, the $5.7 million in the first quarter of 2014. This increase in DD&A was primarily the result of increased production from our Alaskan properties and Rig 35 being in service during the period this year.
Our first quarter results included other expenses $5.3 million compared to other income of $8.7 million for the same period in fiscal 2013. The decrease in other income since last year was due to an increase in the interest expense and a loss on derivatives compared to $6 million gain on derivatives in the first quarter of 2013. The increase in interest expense over the same period of last year was a result of both higher debt levels and a lower percentage of interest expense being eligible for capitalization.
As I noted in past calls, our derivative instruments 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 derivatives in our earnings each quarter.
Our net loss attributable to shareholders for first quarter was $9.4 million or $0.22 per share. Our net loss increase from the same quarter last year due our increased operating expenses, which reflect our increased production and pace of drilling activity and an increase in other expenses, which were partially offset by higher revenues and an increase in income tax benefits.
We ended the first of fiscal 2014 with $3.1 million of cash and cash equivalent, $15.1 million of restricted cash and $57.6 million of debt outstanding. We used $4.4 million of cash from operations, up from $3.6 million of cash provided by operations in the prior years in the same period last year.
Our net cash used for investment activities increased from $7.3 million to $18.3 million from the same period last year. This is a result of our increased drilling activity in Alaska. Our cash flows from financing activities increased from $1.6 million to $23.3 million, primarily due to the additional proceeds from our Apollo credit facility and the issuance of preferred stock.
Before I turn the call over, I want to briefly comment on our expectations for the second quarter of fiscal year 2014. With RU-1A coming online in the middle of August, we expect to see additional revenue attributable to the increase in production. In addition, in Q2 we will see RU-2 online for the entire quarter and there is possible contribution from both RU-5A and Sword number one. So we expect to see additional increases in production that will translate the increases in revenue.
Now, I'd like to introduce David Hall, our Chief Operating Officer and CEO of Cook Inlet Energy to discuss the progress we made in the first quarter of 2014 and what's in store going forward.
Thank you, David. Well, first I'd like to start with updating you on the production numbers. During the first quarter we produced approximately 113,130 net BOE in Alaska and approximately 11,950 net BOE in Tennessee, making this our largest producing quarter to date.
Due to fluctuations in our shipping schedules, this does not equal the oil we sold this quarter and some is held in tank inventory. Our daily production in Alaska was 1,895 BOE a day gross for Q1. And remember, this only includes RU-2A for half of the quarter.
September production has averaged approximately 3,180 BOE a day in Alaska and Tennessee we're averaging 159 BOE a day net. Since bringing RU-1 online total production per day is approximately 3,300 barrels of oil equivalent a day, and are well on our way to meeting our goal of 4,000 BOE a day by December 31.
I am very excited to discuss the sidetrack on the Osprey platform and great results we're seen on so far to date. During the first quarter, we completed our sidetrack on RU-2A, our biggest oil well to date. RU-2A has produced approximately 100,000 barrels of oil since being brought online for an average daily produced amount approximately of 1,252 barrels oil per day for daily average, with a very low average water cut of 10%.
The sidetrack was a huge success for us with the results that exceeded our expectations with nearly doubled historical flow rate and significantly reduced water cut, our outstanding team and a sound based plan and a thorough understanding of the past and present operation. RU-2A was our first sidetrack and I think we've proven up we have the expertise to execute our plan successfully and the Redoubt Field structure still hold very much to offer, with the right team and the right technique, with better appliance.
The reevaluation of our reserves in the Cook Inlet will be an ongoing process, as we continue to bring on wells especially as they outperform our expectation. As we go through this process, we expect recoverable reserves to increase as already seen from RU-2A. As far as our budget versus actual spend scorecard, we show the project came in right at budget, which was $12 million. And keep in mind, we expect to receive approximately 40% cash back rebate from the state of Alaska as a result of the tax credit program.
After yearend, we brought online our second contract, RU-1A, another successful sidetrack that's been producing approximately 740 barrels of oil per day with an average water cut of less than 5%. Since the well is brought online, we have been running it at a reduced speed, where we analyze the formation response and we'll adjust the pump speed accordingly to maintain optimal formation stability.
We may settle on a higher production number if all goes wells, but we are very happy with nearly double the projected IP.
Much like RU-2A, the sidetrack consisted of abandoning the lower part of the oil wellbore setting a whip-stock down deep, milling a window through the casing and drilling to a new bottom hole location similar to, but more favorable than the original wellbore at a depth of approximately 15,500 feet measured depth. Completion included running a 5.5-inch production liner back to the original liner 5.8 casing, cementing, perforating and putting a new ESP in place.
RU-1A has a new online ESP that allow for a deeper sidetrack, saving time and money without sacrificing production. This AFE was approximately $10 million and we came in well under budget with our current cost tracking chilling approximately $6 million spent. Again, we expect to get approximately 40% cash back rebate from the state of Alaska for the tax credit program.
In the economic evaluation, we assumed an IP of 400 barrels of oil per day, recovering approximately 600 barrels of oil with a PV10 value of over $30 million. The well actually came in considerably higher at approximately 740 barrels oil per day. The revised internal economics were re-ran to reflect the higher IP and show an estimated oil recovery of nearly 1 million barrels of oil, which could mean over a 50% increase in recoverable reverses.
After completion of RU-1, we have moved Rig 35 over to RU-5 oil well, another sidetrack target. RU-5B sidetrack is similar to RU-1A and RU-2A, as we're using a similar but proven process. All the sidetracks have the same primary target the Hemlock formation, the crude oil productive zone. We'll also take the opportunity to evaluate the Tyonek gas intervals in RU-5B that's productive and RU-3 and RU-4A. We have great progress to report on RU-5B sidetrack, which is well underway, ahead of schedule, under budget and nearly complete and expected online date in about two week.
The sidetrack system of abandoning of the lower part of the old wellbore, setting a whip-stock, filling a windows through the casing and drilling to an approximate final measured depth of 15,750 feet. While drilling the well our log showed oil throughout the entire Hemlock, and showed we're meeting our objective by gaining structural superiority to that of the original well.
The approved AFE for RU-5B is approximately $10 million growth with a projected IP of 400 barrels oil per day with a reported PV10 value of $50 million. Throughout the planned sidetrack and even the new well, our engineering team started to design a well to penetrate the productive zones in the most favorable position to yield the highest return.
After we finished RU-5B, we plan to conduct a clean-out on RU-D1 our injection well. This is needed prior to drilling a new grassroots well as there will be a lot of cuttings to dispose. We can save time and money by the disposing them directly from the Osprey platform. After RU-D1 clean-out is finished, then we'll move the rig from leg three to leg two, and drill a new well called RU-9 with a bottom hole location in the southern most part of the Redoubt structure. We expect that RU-9 in November.
Third-party reserve analysis classifies RU-9 as a proved underdeveloped reserve well with approximately 1 million barrel of oil recovery and a PV10 value of $48 million, factoring in the receipt of Alaska tax rebate. We're so excited about -- exciting about RU-9 is that it would be drilled into the South Step Out structure which is saddle separated from the current producing pipeline. So this means we can prove that a lot more reserves upon the success of RU-9.
The other significant point related to the readout about Step Out structure is that there was two wells drilled on the structure in the 60s, one of which reported a protest and was deemed by the state of Alaska as a well capable of commercial payer quantities. The other well was held confidential.
Our production and drilling and engineering teams along with our corporate staff are doing an outstanding job that are keeping up with aggressive pace and running three rigs in Alaska. The second rig is the Patterson owned 191 Rig and is busy drilling the Sword number one well.
As previously mentioned the Sword number one well is an extended reach well designed to directionally drill seven onshore locations at the West McArthur River production facility pad to an offshore location approximately 19,000 feet. The target, bottom of location is an adjacent fault block to the West McArthur River unit. Even though we plan to test upfront fault closures, of the whole hydrocarbons in commercial paying quantities, there was a well already drilled into the structure back in the 60s that showed the presence of hydrocarbons.
Company owned 3D seismic shows a faulted four-way closure and an estimated 240-acre structure with an estimated EOR of approximately 8,000 barrels of oil at the Sword number one oil. We also think there is a very high probability we will get structurally high from the well drilled in the 60s and we can expect to see reported recoverable reserves increase as it evolved.
It also sets the stage for proving up a much larger prospect on the Sabre. Sabre is a fault separated prospect to the north. Design and engineering of the very first well is already underway. As far as the current status on Sword number one, as Scott mentioned, we had a setback and had to sidetrack the well.
We have previously drilled and set the second string casing approximately 10,100 feet and we're well on our way to TD the well and had drilled to approximately 16,500 feet when we encountered a mechanical defect in the bottom-hole assembly that became severed. During several attempts to fish, the severed bottom-hole assembly, it was decided to just sidetrack the well at approximately 10,000 feet in order to save time and money.
Since the sidetrack, the team has made great progress and has already drilled to over 13,000 feet. A very encouraging point to know is that prior to the sidetrack there was significant third-party hydrocarbon show reporting. The first one was at 8,200 feet, a gas shell. The second was at 9,800 foot, which was another gas shell and the third was at15,000 feet, which showed C1 through C5 liquid hydrocarbon. Even with the setback and having to re-drill the lower part of the well, we expect it will be online in October. And we look forward to updating you once the well comes online.
Moving on to WMRU, there is no real change in production. It continues to be constant with a minimum decline, with a current daily production of approximately 640 barrels of oil per day. Upon the completion of Sword number one well, we plan to drill WMRU-8, one of three identified in-field development wells within the West McArthur River field. We believe West McArthur River field has a lot of left in it -- lot of life left in it, especially if you consider the fault separated opportunities to the north, the Sword and the Sabre field.
Now onto Rig 34. It's busy working too and is currently drilling the Olsen Creek number one well, which is in the vicinity of the Otter prospect. We are targeting the Beluga gas sand as a primary objective in both the Olsen Creek and the Otter field.
Last week, we had to sidetrack the Olsen Creek number one well due to a coal sticking issue. Prior to getting stuck we had drilled to approximately 5,300 feet. Since the sidetrack, we have drilled to an approximately 4,300 feet and things are going well and coals are behaving. There were a series of thing we implemented to mitigate coal sticking and we're back on track drilling again without issue. We expect to be complete in three to four weeks.
Now on to Tennessee operation. We continued to make progress on the Tennessee during the first quarter of the fiscal 2014 with the purchase of outside working interest, our horizontal drilling programs and reworks on wells acquired from PDC. As a result of the increased working interest in PDC wells as well as successful minor reworks in the wells, we have increased our net oil production from three to 18 barrels of oil per day. That's a six times increase just from the PDC wells alone.
Comparing the first quarter 2014 to the first quarter 2013, we produced an average of 159 BOE a day compared to an average of 136 a year ago. In addition to going through our well inventory, and identifying relatively easy and low hanging fruit to increase production there with continuing effort to prove up the horizontal well concept. We believe we're on the right track as we continue to systematically implement changes to the completion and pumping system on the two horizontal wells we drilled last year, the CPP-H-1 and Maynard H-1.
In addition to the two existing horizontal wells we're planning to drill two additional horizontal wells. The Brimstone H-1 and the Cromwell H-1, which we are designing and engineering now and plan to spud the Brimstone H-1 in about a month.
We're excited about the opportunities that we have in Tennessee during the fiscal 2014 including our horizontal drilling program and our inventory of regular projects and an outside working interest purchase program. We have a very innovative team that is vigorously looking for ways to grow production.
Scott, I'm now turning the call back to you.
David, I want to thank you and your team for your continued excellent work in Alaska and Tennessee. We plan to continue and to provide investors with the regular updates regarding our drilling program as it progresses.
We continue to be excited about drilling plans going forward and our prospects in the Cook Inlet and the Susitna Basin in Alaska. We believe we our Osprey platform is now the single highest producing oil platform in the Cook Inlet. And it still has significant drilling opportunities for us going forward, in addition to the wells that are currently producing.
Before we open up the call to questions, as usual we had to remind you we cannot comment on pending litigation. That concludes our formal remarks for today's call. Operator, we'd now like to open up the call for questions.
(Operator Instructions) Our first question is from the line of Chad Mabry with MLV & Company.
Chad Mabry - MLV & Company
You mentioned in the earnings release that your year '13 exit rate target now can look conservative, just was wondering if you could walk us through your planned activity for the remainder of the calendar year and maybe the potential impact that you see on production.
This is Dave, I will answer that question, Chad. As we mentioned our RU-5A well is almost complete. And the initial long results make us feel confident that we'll be around that 400 barrel a day of oil. The log aren't as strong as RU-1, so we do feel comfortable with the 400 barrels a day. And with our average BOE companywide production for the last several weeks that being in that 3,300 range, that takes us right up to about 3,700.
And then the second part of your question, how do we see that hitting 4,000 being conservative looking at our activities for the remainder of the year. While we expect to complete Olson and we start the second Olson well that will finish before yearend, we're not going to see production from that, because we have to connect that to the six. But we do expect that we will complete Sword number one, sometime in October and that will immediately spud on West McArthur River-8. And so we think that we'll see increased production from that possibly both of those wells.
And then on the platform, once we're finished with five as David mentioned, we'll do some work on our dispose of well and then we'll move on to the South Step Outs, which we're calling RU-9 and that depending on when we spud that we can see results towards the end of the year, but most likely in January. So between those four additional oil wells in the next call it four to five months, RU-5A, Sword number one, West McArthur River-8 and RU-9, we think that that 4,000 exit rate is conservative.
Chad Mabry - MLV & Company
A just a little bit of clarity on the schedule there, actually we're seeing that the 3A, in the 4A sidetracks are just a burden to, I guess calendar '14 then?
It's a good question and this is -- we can't certainly make adjustments to our drilling programs based on our internal well work concentration, our need for gas and our capital availability. And I think what we're seeing in terms of not doing the RU-3A and 4A oil sidetracks was the decision that we reached looking at the credit that we're going to get from the reserve engineers.
We're going to have two wells into each of those fault blocks, the Southern and the Central fault block, the RU-5 and RU-2 and the RU-2A, RU-7. And I think that's going to allow us to optimize how quickly to get credit from fault blocks. And then we can go ahead and start drilling new wells into fault blocks where we're not getting much reserve credit.
Once we move the rig however, we probably look to drill as many wells as we can without moving it back. So those RU-3A and 4A sidetracks within all likelihood not be done for a period to time, possibly 2015. The other thing that that does for us is it please to existing producing wellbores online and the production that we're getting from a gas perspective, three and four are not only helpful in mitigate any risk of there being gas shortage, which we don't think there will be this winter. But it gives us better wellbore diversification, because we're going to leave those two wells online and go drill some new wells.
Chad Mabry - MLV & Company
And then a quick follow-up, if I could on the tax for that rebates. Have you received anything since the end of fiscal Q1 and/or maybe what are your expectations, for how that's going to hit here going forward?
Sure. The Cook Inlet Recovery Act as you know provides up to 40% credit on intangible drilling costs, IDCs and workovers and on top of that 20% credits for capital investments and 25% credit for loses. And since we started our work, we've applied for about $31 million in credits and we've received over $5 million and we've received notification from the state that another $12.7 million should be received this month. I think we're going to receive $6.1 million this week and the rest at months end. That $12.7 million was primarily for the acquisition cost of Rig 35 and the [indiscernible] cost of Rig 34 as well as the Otter well.
So we'll expect that number to continue increasing as we apply for these credits, quarterly for the wells that have been completed during that quarter and our projections with our current budget and we're now thus receiving at least as much as we've applied for to date over the next nine months, so it's something that just starting to ramp up for us we're ramping our CapEx budget.
Thank you. Our next question is coming from the line of Neal Dingmann, SunTrust.
Neal Dingmann - SunTrust
Scott, it's for you or for David Hall, just put it on RU-9, when you go to that leg, number one what's the cost for grassroots well like that and then when you go to that new leg how many slots or how many more can you do on so to follow up in that area?
Yes, Scott, I can take it. So as far as the estimated CapEx for RU-9 is estimated at $17.5 million gross, so again we expect 40% cash back for the tax credit program. As far as how many slots are available in that particular leg, there is six more brand new available slots in leg number two.
Neal Dingmann - SunTrust
And then for Scott, just wondering is it -- are you aware of the results non-determined, just how quickly then you'll continue to drill on the platform or in that particular leg or you know how fluid will your sort of CapEx be after that?
Our plan Neal is to drill well in the southern step out and then go to the northern fault block. As you know we've got six fault blocks within the readout structure and as we drill new wells in each of those fault blocks. Our expectation is that we'll going to get significant credits in addition to the wells that are drilled. For us our development plan will be fluid based on results, but we'll look to one in each of the fault blocks and then follow on development wells.
Neal Dingmann - SunTrust
And what do you think the [indiscernible] they really think the time on those are?
We think they're going to be in the 90 to 120 day, sort of our estimate. We think that's conservative. David can speak better to this because he was there, but the first set of wells that for us drilled average in that 90 day timeframe.
Neal Dingmann - SunTrust
And then just lastly kind of on plan for when you get to passed [indiscernible] some of the next step out there or some of the sub-salt. Well, firstly, I guess based on the production that you mentioned do you think the cash flow revolver, you should have enough capital to cover that?
Yes, for our fiscal 2014 plan, it doesn't have some of this in it, but we're going to continue to adjust our CapEx plan as we have success for a couple of reasons. One is we think the capital availability with our wellbore rustication and production is there for us to accelerate and the cost is continuing to come down and I think we're going to look to take advantage of favorable markets. And we can put that capital work, both on the platform as well as into the Sword, Sabre and West McArthur River plays over the next year.
In terms of cash flow, the way we look at the business is from barrel of oil perspectives. If we are slightly over 1,000 barrels of day production, we're covering our ROE and our G&A expenses and above that we're adding about $2.5 million of cash flow per month for each additional 1,000 barrels of oil per day of production.
And that gives us comfort that the significant portion of our CapEx is going to be covered by existing flow. Yes, I think as mentioned in the past, Neal, that each of these rigs that we're running approximately burn about 5 million a month to deactively drilling, so every 2,000 barrels a day of production we can internally support the cost of operating a rig. So while we're not there today to fully support the cash flow -- the cash flow support drilling, we think that we could be there before the end of our fiscal year and have three to four rigs running and supporting through cash flow.
And the other thing that we think about when we look at spending money is we also have that lag effect from the tax credit drilling rebates. And there are several lenders out there now who are in giving AR based facilities using a tax credit plus for advances. So I think we feel very good about our liquidity position. I think that the opportunities that will make us look to a couple of additional rigs to perhaps increase our spent for 2014.
And your next question is from line of Jeffrey Connolly with Brean Capital.
Jeffrey Connolly - Brean Capital
Can you give us any type of guidance or indication on where you see LOE coming in, I guess next quarter and then maybe for the full year?
Our ROE is not changing very much. LOE changed last quarter, because we had some workover cost that were put into LOE. I think the number of workovers that we expect to do over the next year are really minimal, so it's not going to impact it. Our LOE has been averaging between $1 million and $1.5 million a month depending on the activities.
As production increases, I think we said in the past $5 of incremental cost per barrel is probably the best way to look at our incremental LOE cost. We're also seeing some -- David mentioned in another call, we're seeing some additional cost just from the activities in the logistics, but that's not too significant. But I think the best way to look at is look at our average over the last year and as we add on production, add on about $5 per barrel of incremental production.
Jeffrey Connolly - Brean Capital
And on the Sword number one well, if that's successful, how many more wells could you drill into that 240-acres structure?
I would estimate, we will at least add another subs at well, possibly a third.
Jeffrey Connolly - Brean Capital
If this all comes in very good, which you still move to West McArthur eight or would you maybe drill that second Sword well?
I think what we're going to, Jeff, is look at the result. We're also currently looking at rig availability. And one reason we felt good about drilling the Sword well is we can use all of the existing well bore that we've cased. In the event it wasn't successful, we can drill into West McArthur River.
Similarly, if we're successful with Sword, we can do the same thing for Sabre. And we could essentially drill well that would be passing over Sword and into Sabre. And then if it wasn't successful in the Sabre, we could just complete into the development well on Sword. And as a result of that and we're putting ourselves in position to perhaps add a second rig, then we maybe drilling both of those at the same time, both West McArthur River eight as well as a Sabre well.
Our next question comes from the line of Philip Juskowicz of Casimir Capital.
Philip Juskowicz - Casimir Capital
Well, what percentage of your budget are you allocating to Tennessee?
From a CapEx perspective, it looks like we'll be allocating less than 5% of our budget to Tennessee. It's very similar to our production. I don't think that's going to accelerate too much over the end of our fiscal year. And we're taking things in deliberately slow manner that have optimized our completion techniques. So I'd expect that we could go anywhere from two as many as five wells by the end of our fiscal year, and those are costing about $1 million fees. So you're looking at some place between $2 million and $5 million.
And with respect to Alaska, if we continue to see success, we could, as I mentioned earlier to Neal, we could look to accelerate our development program.
Gentlemen, I'm showing no further questions at this time. I'll turn the conference back over to you for any closing remarks.
Well, thank you for joining us this afternoon to provide you with an update on Miller Energy's recent accomplishments, future plans and financial results. We are very excited about the future of Miller and the potential of our properties. We'll attend several investor conferences this fall. Please contact Derek Gradwell from our Investor Relations firm MZ Group, if you have any interest in meeting with us. Thanks again for your interest in Miller Energy. We plan to keep you up-to-date on our operation and future calls and look forward to you joining us. That concludes today's call.
Thank you, sir. Ladies and gentlemen, thank you for your participation. You my now disconnect.
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