Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Miller Energy Resources, Inc. (NYSE:MILL)

F3Q 2014 Results Earnings Conference Call

March 13, 2014 04:30 PM ET

Executives

Derek Gradwell - MZ Group

Scott Boruff - Chief Executive Officer

David Voyticky - President

John Brawley - Chief Financial Officer

David Hall - Chief Operating Officer

Analysts

Neal Dingmann - SunTrust Robinson Humphrey

Chad Mabry - MLV & Co

Kim Pacanovsky - Imperial Capital

Evan Richert - Sidoti & Company

David Barcus - Brean Capital

Operator

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Miller Energy Resources’ 2014 Third Quarter Earnings Call. During today’s presentation all parties will be in a listen-only mode. Following the presentation the conference will be opened for questions. (Operator Instructions). This conference is being recorded today, Thursday, March 13, 2014.

And I would like to turn the conference over to Derek Gradwell with MZ Group. Please go ahead.

Derek Gradwell

Thank you, operator, and good afternoon, everyone. Joining us today for Miller Energy’s 2014 third quarter earnings conference call are Mr. Scott Boruff, company’s CEO; Mr. David Voyticky, company’s President and Mr. John Brawley, company’s Chief Financial Officer; and Mr. David Hall, Chief Operating Officer of Miller Energy.

Mr. Boruff, Mr. Brawley, Mr. Hall will review and comment on financial and operational results for the third quarter of 2014. Mr. Voyticky will join them to answer questions after the presentation.

I would like to remind our listeners that this call prepared remarks may contain forward-looking statements which are subject to risks and uncertainties that management may make additional forward-looking statements in response to your question. Therefore, the company claims the protection of the Safe Harbor for 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 to 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 can be 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 received 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 have an audio replay that will be available. The call is also been webcast, so that you can log on via internet. And all of the information was provided on the conference call announcement and in the earnings release today.

At this time, I'd like to turn the call over to Mr. Boruff, the Chief Executive Officer of the company, and he will provide opening remarks. Mr. Boruff, the floor is yours.

Scott Boruff

Thank you, Derek. Good afternoon and thank you for joining us today for Miller Energy's 2014 third quarter earnings conference call. To begin, I will provide a brief overview of our accomplishments during the third quarter of 2014, which ended on January 31, 2014. Following my overview, John Brawley, our CFO will provide additional details on our financial results.

After a review of the financials, David Hall, our Chief Operating Officer will provide more detail on our drilling plans and our outlook for the rest of 2014. Upon completion of management’s presentations, we will open the call for your questions.

Fiscal 2014 continues to bring significant increases in revenues, reserves, productions and well bore diversification for Miller. As well as a decrease in cost of capital, our revenues increased from $8 million in third quarter of 2013 to $16.6 million for the third quarter of 2014.

We also saw major increases in our proved developed reserves in our new Ryder Scott reserve report that we announced back in December 2013. The increase was directly attributable to our drilling successes over the past several months and we believe this serves as a third-party independent assessment of the value created by our drilling and completion strategy in Alaska.

We also brought our Sword #1 well online, with results at exceeded expectations. This well showed three productive zones two oil and one gas and had initial production rate of 883 barrels of oil per day.

Early last month, we closed on a new $175 million credit facility with Apollo Investment Corp, our long time lender and High bridge principal strategies. The new facility structured as a second lean facility and we are currently in discussions with the potential of senior lenders, who will provide us with up to a $100 million of senior debt.

With respect to our current drilling projects, we are in the process of bringing our new West McArthur River Unit, #8 oil well online and expect to announce initial production rate in the near-term. In addition, Rig 35 [has spudded] our RU-9 grassroots oil well, which targets the South Step Out structure of the Redoubt field. We believe RU-9 will be another great opportunity to prove up additional reserves much like our Sword #1 well.

We’ve also began moving to Patterson 191-Rig over to West McArthur River Unit 2b well which is our next onshore oil target.

Following the end of the quarter we’ve closed acquisition of the North Fork Unit. The North Fork field is primarily a gas field which has averaged approximately 7.7 million cubic feet a day or 1,280 BOE per day since the date of the acquisition. These additional assets complement Miller’s other oil and gas properties in Alaska and is Miller’s first operating field on the east side of Cook Inlet. We’re certainly excited about this acquisition, its production, its reserves, drilling locations and wellbore diversification.

In Tennessee we continue to be focused on acquiring additional working interest in existing wells as well as learning how to better drill, complete and produce our horizontal wells. Our third horizontal well, the Brimstone H-1 has produced a total of 2,982 barrels of oil through January 31, 2014. It came on line on October 15, 2013. We are preparing to drill our fourth horizontal well and hope to see similar results to the last one.

David Hall our Chief Operating Officer at Miller Energy, will discuss our upcoming drilling plans in more detail later on this call. In addition to these operational highlights from a personal standpoint we have added John Brawley from Guggenhiem Partners as our CFO. Since joining us as a consultant in November, John has led our financing efforts as we continue to execute our development and acquisition strategy. John was previously co-head of Guggenhiem’s Houston-based energy mezzanine lending group and was part of the team that provided Miller its initial institutional loan back in 2011.

Given the high regard of both the Guggenheim and John are held in we feel incredibly fortunate to have added them the Miller Energy’s team. John’s leadership has already added significant value to our company through the successful refinancing of our Apollo credit facility last month. He has also along with new hire Jeff McInturff, our new VP and Director of Financial reporting already made great strides in improving our accounting controls. We will continue review and improve on these systems that we believe John is the right man to lead that process.

We are excited to have further strengthened our team with addition of Jeff and his nearly 15 years of public accounting and SEC reporting experience. We are also happy to note that we have made strides in resolving several law suites that have been pending. First we want to dismiss all the federal derivative actions and that dismissal was upheld by the 6th Circuit Court of Appeals. We also have an agreement place for the [plan] and the similar derivative action that filed in the State Court in Tennessee that requires they dismiss our claims as soon as the federal case is dismissed. We also reached terms on the settlement of our lawsuit with CNX which we settle for 1.25 million and we believe we have reached terms with another dispute of Voorhees Equipment and Consulting where we have an agreement in principal to settle the matter on a cash flows basis. We are still working on the settlement agreement with Voorhees documenting the specific terms.

We also had good reason to believe that there are certain other legal matters that are pending to maybe resolved on favorable terms in the next few months.

At this time I would like to hand the floor over to John, who will go through the financial results. John.

John Brawley

Thanks Scott. We saw a substantial increase in our revenues from the prior period up 108% to $16.6 million compared to $8 million in the third quarter of fiscal 2013, this is directly related to the new production we have brought online in fiscal 2014.

Our total net production increased to 225,377 barrels of oil equivalent compared with 82,327 barrels of oil equivalent in the third quarter of last year. This relates primarily to new productions from our RU-2A, RU-1A, RU-5A and Sword #1 well.

Looking down by region, Alaska contributed to 95% of our net production and Tennessee contributed 5%. Our average realized sales price per barrel of oil for the quarter was $94.58, which is a decrease of $4.19 or 4% over the same period of last year.

Investors will notice that during the period, inventory increased by approximately 57,000 barrels. In our most recent 10-Q, we have added a detailed reconciliation of gross production and the inventory.

It is important to understand that our point of production is the point at which oil enters the Cook Inlet pipeline systems, the CIPL system which is earned by Hill Corp. However, our sales point is a point at which the ship is loaded at Drift River at the [Technical Difficulty] oil produced into the CIPL systems, but not shipped [Technical Difficulty].

During the period, additional storage was opened at the Drift River facility which increased the need for additional working inventory at January 31, 2014. We report inventory internally each week and we are nominating additional volumes for shipment in the fourth quarter. Thus we expect that some of the revenue associated with the inventory build of 57,000 barrels will be shifted into the fourth quarter of fiscal 2014.

As the side note, if we have filled the increase in inventory during the period and excluded some additional legal costs, our adjusted EBITDA would have been close to the $10 million mark.

As I mentioned earlier, we're in the process of working this access inventory down and as of yesterday March 13th, our CIPL inventory balance was down by 32,103 barrels from 86,080 barrels to 53,977 barrels. Our operating cost for the second quarter increased $1.7 million or 41% to $5.8 million compared with $4.1 million for the same period last year. This reflected our increased production and associated cost in Alaska.

For the quarter ended January 31, 2014, our lease operating expense declined to $17 per BOE produced as compared to $29 per BOE produced in the same period last year. We expect to see our lease operating cost continued to decline on a per BOE basis as we add production from our drilling project.

Given the majority of our operating cost effect, we expect that our operating cost per barrel will continue to decline as we put more production online. An example is our Kustatan and Osprey facilities which process volumes from a readout field. Those facilities can process up to 25,000 barrels per day and at current rate or fixed costs are more than covered by our current production. So as we add incremental production there is very little incremental cost. Those costs remain similar as production grows and LOE per barrel will continue to decrease.

G&A expenses increased by approximately $1.9 million or 37% to $7.5 million in the second quarter of 2014 compared with $5.5 million during the same period in the prior year. Most notably, during the quarter, professional fees increased by almost $2 million over the same period last year primarily due to an increased in PR and legal cost associated with recent shareholder activities, accounting work associated with the acquisition and capital raising activities during the period.

DD&A expense, which includes expenses related to leasehold costs and equipment, increased a 129% from $3.3 million in the third quarter of fiscal 2013 to $7.6 million in the third quarter of fiscal 2014. The increase in DD&A was primarily as a result of increased production from our Alaska properties.

Our second quarter results included other income of $1.3 million compared to other expense of $2.8 million for the same period in fiscal year 2013. The change was primarily due to a current period gain on derivatives as compared to a loss on derivatives during the same period last year. We also recorded in other expense during this period, another expense of $1.25 million, which was entirely related to the settlement of the CNX lawsuit for $1.25 million.

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

During the period, we added approximately 550 barrels of oil per day of swaps through December 2016 at an average price of approximately $101.70 per barrel. Our net loss attributable to common shareholders for Q3 was $6.8 million or $0.15 per share. We ended the third quarter of fiscal 2014 in a healthy financial position with $13.1 million of cash and cash equivalent, $4 million of current restricted cash and $75.3 million of debt outstanding under the Apollo [line].

With respect to the status of our Alaska tax credit, during Q3 we collected $6.7 million from an application filed in July relating to work performed on our redoubt wells earlier in the year. We also collected $2.2 million on settlement of an appeal related to previously disallowed credit in 2010 and 2011 application. In addition to the cash collections, we filed a $22 million application credit primarily related to work completed on unused Sword #1 well.

Tax credit receivables on our balance sheet increased from $5.4 million at October 31, 2013 to $19.8 million at January 31, 2014. Furthermore, we expect to file for additional tax credit as we continue our drilling program.

Based on activity already completed to-date, we expect that we will file for up to an additional $20 million to $30 million of tax credit, which will include our NOL credits which are filed annually, as well as additional quarterly investment related credits.

These are not carried on our balance sheet until filed. Therefore, the $20 million to $30 million of additional applications that I referenced earlier will be incremental to the $19.8 million on our balance sheet at January 31, 2014. We generally expect to receive the credit within six months of filing.

Subsequent to the end of the quarter on February 03, 2014, we closed our new credit facility with Apollo, with rates that are competitive with other syndicated second lien transactions in the market during the 12 months prior. The terms allow for the insertion of up to $100 million of first lien credit.

We’ve closed the facility with Apollo, a long term supporter of Miller and we also brought in Highbridge for 50% of the new facility. The continued commitment of Apollo and new relationship with Highbridge indicate the quality of investors Miller continues to attract.

There are really three items investors should focus on with respect to our GAAP. Those are the [rate], the debt level of us is the value of the asset and lastly the debt versus cash flow or EBITDA.

First, with regard to the rate, we were pleased to increase the size of our credit facility from $75 million to $175 million and at the same time reduce the rate from 18% to 11.75%. Investors should note that overtime our average cost of debt should come down below 10% as we add $50 million to $100 million of first lien credit at a meaningfully lower cost than our second lien facility.

Second, with regard to the amount of debt we carry versus our assets, our current debt level of $175 million is less than 50% of the previously released Ryder Scott proved developed reserve with a PV-10 of $365.8 million. Many comparable companies showed leverage well beyond total proved developed PV-10 and in some cases beyond total proved PV-10, whereas our ratio is less than half of proved developed PV-10.

Additionally we have infrastructure with an estimated replacement cost of over $300 million and meaningful tax receivables, which further de-risk our leverage from a loan-to-value standpoint. Our leverage metrics look exceptionally strong from a loan-to-value stand.

Lastly, from a cash flow perspective, with the North Fork acquisition which has great operating margins from low operating cost and a fixed sales contract of $7 per MCF and even without additional production from West MacArthur River Unit No. 8, the Sword G0 stand RU-7 or RU-9, we would expect our debt to EBITDA to fall within the 3 to 4 range. With additional production from our drilling program, we expect debt to EBITDA ratio to reduce even further.

We believe, we have added leverage to the company very responsibly by reducing the rate, allowing for additional cheaper debt and keeping our loan to value and debt to cash flow metrics within reasonable levels and at more conservative levels than many of our peers.

In conjunction with the new financing, we refinanced the preexisting Apollo facility of $75.3 million, added almost $40 million of cash to our balance sheet and closed the acquisition of North Fork. We also issued $5 million Series B preferred stock in conjunction with the acquisition of North Fork. This will be held in escrow pending state approval of our operatorship of the North Fork midstream assets.

From a capital resources standpoint, we added almost $40 million of cash in the Apollo and Highbridge financings, and we are also working on a first lien financing, which we would expect to close prior to the end of our fiscal year. We expect that facility to be in the $50 million to $100 million range.

Lastly, we have almost $20 million of tax receivables which we expect to receive over the next six months and we are applying for an additional $20 million to $30 million of credit which we will also expect to receive over the year.

Finally, with regard to personnel, we added [Jeff Mackintosh], as Scott mentioned earlier, our new Director of Financial reporting. He joins our controller Charlie Lobetti and me are senior members of our accounting staff.

Jeff’s experience includes nearly 15 years of public accounting and SEC reporting positions including his previous position as director of financial reporting at (inaudible), director of financial reporting of several other companies and experience as an audit manager at Deloitte & Touche.

We believe that with this addition to our accounting staff, over time we will be able to remediate the material weakness in our control as we integrate Jeff and myself into the accounting process.

Now, I’d like to introduce David Hall, our Chief Operational Officer to discuss the progress we made in the third quarter of fiscal 2014 our plans going forward. Go ahead, David.

David Hall

Thank you, John. Well, first I’d like to update you on our production numbers. During the third quarter, we produced 213,321 net BOE in Alaska and [12,056] net BOE in Tennessee which beating our record second quarter production and making this quarter our largest producing quarter to-date with a total of 225,377 BOE, a notable increase.

As John mentioned earlier, due to fluctuations in inventory and shipping schedule, this does not equal the oil we sold this quarter, as some of the oil is held in or drawn from inventory. Our average gross daily production in Alaska was 3,239 BOE for Q2, putting our Alaska gross production for the quarter at 297,989 BOE. Our gross average production was 4,295 BOE a day in Alaska for February.

Following the North Fork acquisition. In Tennessee, we average 238 barrels of oil equivalent per day of gross production in February. And today, I want to walk you through on our onshore progress with WMRU-8 and Sword #1 wells, as well as offshore progress with RU-7 and RU-9 wells.

In addition to our plans for onshore gas prospects including what was stored with our newly acquired most North Fork gas field. I’ll also provide an update on our Tennessee operations and the planed Trans-Foreland Pipeline. Onshore in Alaska, currently recently brought WMRU-8 online and are currently waiting for the well to finish cleaning up and establish stabilized production. We expect to release an initial production rate for this well, once production is stabilized.

The well’s final measured depth was approximately 16,500 feet and is one of three identified infield development wells within the West McArthur River Field. WMRU-8 primary objective is the Hemlock formation with secondary target and Atomic formation as well as the Jurassic formation.

We were successful in locking the Jurassic and were very encouraged with what we saw and plan to further evaluate the Jurassic, after we have attain additional logs from the nearby West McArthur River to be our next planned well at West McArthur River Field as we expect to spud that particular well within the next few weeks.

We also recently received critical permits for our Sword #1 well that will allow the testing with of the additional zones. The Tyonek gas zone and the Tyonek-G-0 oil zone as well as a comingling permit that allows the Tyonek-G and the Hemlock oil zones to be produced together.

We are already making preparations to take the well offline to perforate and test the Tyonek gas zone, then isolate the zone followed by a perforating the Tyonek-G-0 oil zone which will produce along with the Hemlock from which we’ve been producing today. This well has been an enormous success for us and we’re very optimistic that we’ll see a nice increase in production once the new zones are perforated and put on line.

Moving to offshore, we recently replaced the ESP and RU-7 oil well and is now on line and is already producing more than what it was before it was shut-in prior to the rework. We also recently spud our RU-9 grassroots oil well, on March the 2nd. And as we mentioned in our last call, we needed to make some upgrades to Rig-35 and on the platform before the commencement of drilling with extended reach well.

With those modifications have been complete and drilling is well underway, we’ve already drilled approximately 3,000 feet measure depth, installed 13.375 casing followed by (inaudible) in play. RU-9 is designed to drill into and prove the southern step out and the Redoubt structure by capturing well reserves from a large hallway structure located approximately 2.5 miles southwest of the Osprey Platform.

Our primary objective for this well is for the Hemlock which is a primary producing formation in the Redoubt Shoals field. We expect that success at RU-9 will prove up additional reserves for us. And we’re very excited about the huge potential of the most southern point of the Redoubt structure.

With respect to natural gas prospect, we’re planning to secure an additional drill rig to accommodate not only the North Fork deal but also other prospects such as Olson Creek and Otter. As we produce from the North Fork field, we will continue to optimize existing wells through perforation adds, velocity strings, and other techniques, looking for ways to increase production.

We have already done some of these things to-date and production is increased well over 10% since the acquisition. In addition to optimizing the existing wells, we have identified a significant number of other wells that we are evaluating in our efforts to fully develop the field.

Moving on to Tennessee, we continue to focus on increasing our working interest percentage in our wells and on our horizontal drilling program, in October we brought our most successful horizontal well on line to-date, the Brimstone H-1 whose current production is over five times greater than our typical vertical well’s production. So, we see it as a very successful in concept. And as such, we are already making preparations to drill our next target, the Willoughby H-1, another horizontal well.

Our efforts to design permit and implement reservoir pressure support in nearby vertical well to the horizontal wells are ongoing, and we believe these efforts will result in increased production rate and ultimately higher recoveries in addition to continuing to rework the existing wells to optimize production.

Finally, I want to take a minute and update you on our continuing work with Tesoro on the Trans-Foreland’s pipeline. In February, we executed a definitive agreement with Tesoro Alaska Company. And Tesoro Alaska has exercised its option to pursue development of the Trans-Foreland’s pipeline, which will connect crude oil transportation systems on the west side of the Cook Inlet to the Tesoro refinery in Nikiski.

Currently all crude oil produced on the west side on the Cook Inlet flows through a 42 mile pipeline system a tank farm and a loading facility operated by Cook Inlet pipeline a wholly owned subsidiary of Hilcorp. From CIPL terminal crude oil is located and loaded onto tankers and shift across the narrow body of water, where it is off-loaded at a different terminal from which it can flow into the Tesoro, Alaska refinery in Nikiski.

The Trans-Foreland’s pipeline system will connect the west side to the east side of the Cook Inlet directly into refinery affectively eliminating the need to move oil over an active volcano and on tankers across the Cook Inlet reducing transportation expenses on the environmental risk.

With that Scott, I will turn the call back over to you.

Scott Boruff

Thank you David. Junior teams continued to deliver great result in both Alaska and Tennessee. We plan to continue to provide investors with regular updates regarding operations financing and the acquisitions as news developed, and we continue to be excited about our current production and our drilling plans going forward. As part of our long standing practice of engaging and listen to our shareholders, I have met with many of our shareholders in fiscal 2014.

In the past six months several shareholders have suggested we will reevaluate our options grants that the Board and our compensation committee approved as part of senior management’s compensation in July of 2013. I took those concerns back to other members of management and we all agree they will be best to amend our employment agreement to cancel those options.

As for the consulting with the conversation committee and with the board and sharing the terms of the proposed amendment, we signed that already this week. Finally I want to take and minute to update you on certain changes that we are making to our Board of Directors and executive compensation.

This morning without our preliminary proxy statement and announced the nomination of two new highly qualify candidates for election to our board. Dr. Bob G. Gowers, the current Chairman of Ensysce Biosciences, Inc. and former CEO of Lyondell petro chemical company and Joseph T. Leary, is the Chief Financial Officer of Tarpon Operating & Development, LLC. Both of these gentlemen have many decades of business management experience and have served on boards of companies across multiple industries including financial services, Energy, oil and gas exploration. We are very excited about the skills and experience they will be bring into Miller.

In addition our Board has decided to reduce its size from 10 members to seven with five of those members being independent. In addition to Dr. Gower and Mr. Leary, the slight of the company, the nominees include our founder and Chairman Deloy Miller, Gerald Hannahs, Marceau Schlumberger, Charles Stivers and myself.

We believe that reducing the size of Board is consistent with the best practice in corporate governance and will allow the Board to more efficiently carry out its duties. Both David Hall and David Voyticky will remain in their capacities on our senior management team.

Before we open up this call to questions I need to let you know that we will not further comment on the proxy contest or on pending litigations on this call. That concludes our formal remarks for today’s call, operator we’d now like to open up the call for questions.

Question-and-Answer Session

Operator

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 Robinson Humphrey. Please go ahead sir.

Neal Dingmann - SunTrust Robinson Humphrey

Hi good evening guys. Good details. Maybe for David Hall, first. Just David, you mentioned that the rig going to RU - you already started to drill at RU-9, can you give us an idea both on RU-9 and then over on the WMRU-2B, as far as just sort of timing and general timing on when you can potentially see some production there and in addition to cost of each of those wells?

David Hall

I'll be glad to, as I mentioned we've already got a pretty good start on RU-9. We've already drilled it to approximately 3,000 feet set casing and cemented in plays. As far as to the extent of the timeline to drill and put that well online, we estimated that to be about a 90 to a 100 day program. As soon as we're done with the drilling program on that well, they should not take but about a few days to a week to put it online.

As far as WMRU-2B, that one is a shorter project, we estimate that one to take about 60 days, 40 to 60 days I should classify. Similar to RU-9, that one would not take much to hook up and put on production as soon as we're done drilling on it.

Neal Dingmann - SunTrust Robinson Humphrey

And David, what's the cost of those?

David Hall

WMRU-2B which is a sidetrack, which is according a growth CapEx number, which is approximately $13 million. RU-9 which also included quite a bit of capital associated with rig modifications and platform modifications. So, all includes those modifications plus the drilling of the well is $26 million.

Neal Dingmann - SunTrust Robinson Humphrey

Got it. And then just one last one, on the tax credit, it sounds like maybe for John or Scott for you. There is a couple of different tax credit sides, I know what that’s couple that are not on the book sheet. Can you walk me through again the potential amount of those tax credits? And any idea on timing, I know it’s tough to detail and maybe past how long those credits have taken in the past and kind of where we are on the timeline now on those?

John Brawley

Hi Neal, it’s John Brawley speaking. So we have $19.8 million of tax credits on our balance sheet at 01/31, those were associated. So how works this, we applied for credits once the quarter. And then after we apply we can put those on our balance sheet as a receivable because we have a very, very high rate of receiving those something like $0.98.

So, we put those -- we applied for those in that quarter in the 01/31 quarter and we’d expect to receive those within 6 months post the date of application. Because we only apply once a quarter there was quite a lot of drilling activities that are incurred after the date at which we filed our last application and there was a second type of application one is the investment tax credit, the other is net operating loss tax credit.

The net operating loss tax credit is only filed once a year. So, there is two things that remain unfiled as of 01/31. The first is additional investment tax credit made after the date of the filing of the last application. And the second is the NOL tax credit that are applied for at the end of the year. The NOL credit work on a field by field basis and are separate to those investment credits. So in addition to the 19.8, 131 that we expect to receive before the end of our first fiscal quarter of the next fiscal year, we will also apply for another $20 million to $30 million which is a combination of additional investment tax credit and NOL credit and we would expect to achieve them at different times through the year depending on which particular credit it was, but over the past over the summer and into the autumn.

So that’s kind of an overview of where we are with those, and that $20 million to $30 million that we talked about applying for is just based on CapEx that’s already been spent. So as we continue to spend more CapEx that number will continue to increase.

Again as I said, we only put those on our balance sheet once we have actually filed them though technically we have incurred the ability to file them as soon as we spent the dollars which are applicable.

Neal Dingmann - SunTrust Robinson Humphrey

That’s perfect. Thanks John.

Operator

Thank you. Our next question is from the line of Chad Mabry with MLV & Co. Please go ahead.

Chad Mabry - MLV & Co

Thanks guys. I had a quick follow-up to Neil’s question on West MacArthur 2; I don’t see that on your proved reserve schedule. Is that, I just guess to clarify is that on book and then is your EUR there similar to what you have on the 8 and 9 kind of 400 and 800 MBOE?

David Hall

Yes, you are correct with that statement. It’s project we identified that we think we can capture undrained oil at WMRU-5 and WMRU-6 would not otherwise produce. So it’s [attic] structure play to those wells. The anticipated IP you know what our economics will use 400 to 500 barrels a day.

Chad Mabry - MLV & Co

Okay, great. That’s helpful. And David, I appreciate to walk through earlier. I think I missed your gross production from Alaska last quarter in February rather. Is there any way you could kind of walk through maybe really the high level, how you expect to get to that kind of six plus MBOE a day by the end of next month?

Scott Boruff

Sure. So I got an idea for you chat. If you look at our gross production overall for the month, we were at 4,600, about 600 of that came from West MacArthur River side and six on oil, about 600 came from Sword #1, the Hemlock area and about 1400 came from oil off the platform and our gas wells were slightly under 2,000 BOE per day plus Tennessee which brings you at 4,800 level.

In the next two months or 45 days, we are expecting to have West MacArthur River 8, which we think will be at least 500 BOE per day.

RU-7 which recently brought back online and typically what you have seen is that that takes about 45 days to stabilize and we’re expecting that to go above 100 barrels a day. And then we are testing two additional zones from Sword of which will coming to oil zone from G0 with the current producing Hemlock and we think that that will add at least another 100 to 300 barrels a day.

On the North Fork field as David mentioned, we are going to be working those wells and our expectation is to increase production another 1,000 to 2,000 Mcf a day. That brings us to approximately 6,000. And then as we had expected to be at 6,000 without North Fork, we have some timing differences. So depending on when RU-9 and West McArthur River to be or complete, we now expect those to be slightly after our year-end. The production from those wells would bring us to our target.

Chad Mabry - MLV & Co

Very helpful, I’ll get back in queue. Thanks.

Operator

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

Kim Pacanovsky - Imperial Capital

Yes. Hey David, just continuing on Chad’s question, so RU-9 which will wrap into the following quarter that is an expectation of about 800 of barrels a day?

David Hall

I think we use 750 in our economics.

Kim Pacanovsky - Imperial Capital

Okay. And then you -- let’s say when did the North Fork acquisition close, because I recall in November you were at about 4,000 BOE a day, is that correct?

David Hall

That’s correct, at the end of November we were slightly over 4,000. North Fork closed during this quarter, in the first week of February.

Kim Pacanovsky - Imperial Capital

Okay, I forgot it was recent. So you’re actually -- RU-7 came, I’m just trying to figure out why the production was so low this quarter aside from the inventory issue? RU-7 came offline for work over in EST replace that took I think a lot longer than you anticipated. What was that well producing when it came off? And what is it producing now?

Scott Boruff

RU-7 was producing slightly over 100 barrels a day.

Kim Pacanovsky - Imperial Capital

Okay. It’s pretty good, minimal.

Scott Boruff

And we have just recently brought that well back online, so just cleaning up we’re starting to see [oil cut] increasing, but we expect to return to the same level, you wouldn’t have seen any production from it for the last part of the quarter.

Kim Pacanovsky - Imperial Capital

Okay. What did you spend on the replacement and the work you did on that well?

Scott Boruff

David, do you have an exact number on that work over?

David Hall

I sure do. And keep in mind the CapEx that we spend on also included some additional rig move and rig modification work. So in total, counting that was roughly $4 million.

Kim Pacanovsky - Imperial Capital

Okay.

David Hall

Growth CapEx, assuming we're going to get from the last rebate back.

Kim Pacanovsky - Imperial Capital

Okay. All right.

John Brawley

And Kim one more thing to add on that is that remember that the Sword #1 well came online right at the end of November, so that was only on for half of the period.

Kim Pacanovsky - Imperial Capital

Okay, great. Right, okay, yes.

Scott Boruff

And you also can model in some declines if you’d work that really well with production off the platform.

Kim Pacanovsky - Imperial Capital

Okay.

Scott Boruff

We were done probably 300 or 400 barrels from the November timeframe to the end of the quarter.

Kim Pacanovsky - Imperial Capital

All right. And then on the cost side, and I know that on a unit basis it’s so hard to be able to predict what the operating costs are going to come in depending upon the production and there is timing issues, et cetera. But you mentioned that you expect another drop in operating expense. Can you give us any guidance for that number? I mean that number is just so hard for us to predict?

Scott Boruff

Yes. I think what we've seen internally, I think a conservative number would be to expect that we have a 15% variable cost with increased production and 85% fixed cost. And so of course it's going to depend on what increases we have in production. But we internally see ourselves for cost for about $3 a barrel lifting for each additional barrel that we have to lift, [running] out oil from water so you need to know total fluid has been lifted.

Kim Pacanovsky - Imperial Capital

All right. And then just switching over to Tennessee with the Brimstone well which is your best well to-date, can you kind of give us a feel for how the curve looked on that and what did it come in at, what is it producing now and what do you think just I know you only have a few months of production, but can you give us any more thoughts on that well?

David Hall

I’ll be glad to. And as I mentioned, we’re very excited about that well and just the huge improvement compared to the existing vertical wells and related production that we see. But that well is currently producing approximately 20 barrels of oil per day. We have the initial flush production that was considerably higher, but it seems to have stabled around the 20 barrels oil per day.

Having said that, we are very optimistic that the production could perhaps increase once we implement the gas injection or nitrogen injection into the nearby vertical well that would push the oil into the horizontal leg of the Brimstone well.

Kim Pacanovsky - Imperial Capital

And is there a local source for the nitrogen, what is the cost of that and…?

David Hall

We’re evaluating that now looking at it from whether be gas injection or nitrogen injection. So we are trying to see what’s most cost effective. And it maybe even be a combination of both depending on the availability of gas on the nearby vertical wells.

David Voyticky

David, maybe worth commenting on the difference in cost of drilling at putting this well versus our previous horizontal.

David Hall

Well the Brimstone H-1, I believe cost approximately about 650,000 to 700,000, so compared to some of the CapEx that we see for vertical well which isn’t too much -- less than that. Some of the vertical wells would cost anywhere from 350 to 550 per inch.

Kim Pacanovsky - Imperial Capital

What’s the length of your lateral?

David Hall

The lateral is typically from what we have done to-date, range anywhere from 2,000 to 2,800 feet.

Kim Pacanovsky - Imperial Capital

Okay, alright. And what was your average gas price for the quarter?

David Hall

Well, I have to look and see and it depends on if you’re referring to gas prices in Alaska or Tennessee.

Kim Pacanovsky - Imperial Capital

Well, both. You could send me an email if you don’t have that, or I will talk to David after the call.

David Voyticky

Yes, I think all the gas we sold in Alaska was at $6 an M during the quarter. And I think as you see the quarter going forward, as we bring in most of our production from the North Fork field, it’s going to be very close to $7 an M.

Kim Pacanovsky - Imperial Capital

Okay. And just because of the contract. And they had pretty mild winter up there, correct?

David Voyticky

That’s right, the mildest that we have seen.

Scott Boruff

And Kim, oil realized price was $94.58 per barrel and then we sold gas under a $6 per MCF contract but had some transportation and marketing cost.

Kim Pacanovsky - Imperial Capital

Okay, alright. Okay guys, thanks.

David Voyticky

Thanks Kim.

Operator

Thank you. Our next question is form the line of Evan Richert with Sidoti & Company. Please go ahead.

Evan Richert - Sidoti & Company

Good afternoon, guys. Just a follow up on one of Kim’s questions, I know the 4,000 number you quoted for November, that didn’t have that much Sword impact, I think came out on 20th if I right. Just wondering, if you could walk through what kind of the average daily rates were for December and January; I guess, I thought it would have been a little bit higher?

David Voyticky

Sure, if you look at the end of the quarter, we were producing on average about 600 barrels a day with the Sword well. We were holding fairly steady, slightly over 600 barrels a day at West McArthur River five and six well, and off the platform, and we were in the 1400 to 1500 barrels of oil a day. And off the platform as well from gas, we have been holding those pretty steady, around 1,800 mcf to 2000 mcf a day, primarily used for our own consumption.

Evan Richert - Sidoti & Company

Okay. And then as far as the inventory schedule goes, I think in the filing you said something about you had a requirement to maintain higher inventory levels. I was wondering if you had any color you can add on that, if you expected going forward what kind of inventory, I know it depends on the shipping times, but…?

David Voyticky

The inventory depends on two factors, one is the shipping schedule. So if the ship comes closer to the end of the quarter, we will have opportunities to reduce our inventory otherwise that production from the last shipment to the quarter we’ll be added as inventory. The other factor that greatly impacts inventory is as we increase our share of production going into the Cook Inlet pipeline, we get a higher allocation of the oil that’s stored in the pipeline.

John Brawley

And you’ll note that our, the CIPL inventory balance, as I mentioned in my comments, went down from 86,000 barrels to 54,000 barrels between January 31, and as of yesterday. So realistically, we probably need, we’re working on what the exact number is, we have to get back from CIPL, but it’s -- we're working on that but historically we’ve carried more like 30,000 to 40,000 in inventory versus the 86,000 that we have. So most of the excess inventory that we showed during this period, we should be able to sell during the fourth quarter.

Evan Richert - Sidoti & Company

Okay, great. And then turning to I guess another one on Kim’s question, you mentioned cost per barrel coming down, as you add additional production. Should we kind of assume that the wells you have in North Fork are roughly in line on LOE with the rest of your production is?

Scott Boruff

I think they’re a lot lower, the cost of production that because we don’t have the large scale fixed cost that we have with the big production facilities we have at Kustatan or West McArthur River. So over there, it’s a very simple operation, it’s a one man operation, largely automated, that’s probably going to add, we hope $18 million to $20 million in cash flow over the next year.

So that should be very cash flow accretive, low operating, good acquisition for us.

Evan Richert - Sidoti & Company

Okay, that's it for me. I’ll hop back in the queue.

Operator

Our next question is from the line of David Barcus with Brean Capital. Please go ahead.

David Barcus - Brean Capital

Hi guys. My question is more related to future acquisition prospects, kind of what you guys are seeing and thinking in terms of other prospects out there that you could add into what you got in Alaska, can you comment a little bit?

David Voyticky

Sure. I think acquisitions are something that’s more and more important for us as a business for two reasons, one is that as we have more capital availability that we have a lower cost of capital, acquisitions looked more attractive to us in the past, because of our reluctance to issue equity, we’ve had less ability to be competitive in acquisitions. We are very excited to add North Fork. And I think as you see our story developing over the next few years and we see a very big opportunity in the gas market up in the Cook Inlet.

But as we’re talking about earlier in terms of taking advantage of our infrastructure and our team, part of our strategy is going to be to continue to grow not only through acquisitions in the Inlet, but also to add to our land base as well.

And I think in general, as Scott and Deloy have really transformed this company along with David Haul, we’re going to continue to look for other acquisitions throughout the 48 Lower State as well that could add good production basis and good management team.

David Barcus - Brean Capital

Thank you.

Operator

Ladies and gentlemen, that is all the time we have for questions today. At this time, I would like to turn the conference back to Mr. Scott Boruff for closing remarks.

Scott Boruff

Thank you for joining us this afternoon to provide you with an update on Miller Energy’s recent accomplishments, future plans and financial results. As you can see, we’re very excited about the future of Miller and the potential of our properties. We plan to keep you up-to-date on our operations on future calls and look forward to you joining us. That concludes today’s call.

Operator

Ladies and gentlemen, this concludes the Miller Energy Resources 2014 third quarter earnings conference call. Thank you for your participation. You my now disconnect.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Miller Energy Resources' CEO Discusses F3Q 2014 Results - Earnings Call Transcript
This Transcript
All Transcripts