Miller Energy Resources' (MILL) CEO Scott Boruff on Q4 2014 Results - Earnings Call Transcript

| About: Miller Energy (MILL)

Miller Energy Resources Inc (NYSE:MILL)

Q4 2014 Earnings Conference Call

July 15, 2014 4:30 PM ET


Derek Gradwell – Senior Vice President, Natural Resources-MZ Group

Scott M. Boruff – Chief Executive Officer

John M. Brawley – Chief Financial Officer

David M. Hall – Chief Operating Officer and Chief Executive Officer-Cook Inlet Energy, LLC


Kim M. Pacanovsky – Imperial Capital LLC

Neal D. Dingmann – SunTrust Robinson Humphrey

Adam K. Fackler – MLV & Co. LLC

Evan C. Richert – Sidoti & Co. LLC

Phil Juskowicz – Casimir Capital LP

Kurt J. Caramanidis – Carl M. Hennig, Inc.

Steven Baughman – Divisar Capital Management


Good day, ladies and gentlemen. Thank you for standing by. Welcome to the Miller Energy Resources Incorporated Fiscal Year End 2014 Earnings Conference 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, Tuesday, July 15, 2014.

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

Derek Gradwell

Thank you, operator, and good afternoon, everyone. Joining us today for Miller Energy’s 2014 fourth quarter and fiscal year end earnings conference call are Mr. Scott Boruff, the Company’s CEO; Mr. David Voyticky, the Company’s President; Mr. John Brawley, the Company’s CFO; and Mr. David Hall, Company’s Chief Operating Officer.

Mr. Boruff, Mr. Brawley, Mr. Hall will review and comment on financial and operational results for fiscal year ended 2014 and it’s fourth quarter and Mr. Voyticky will join them 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 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 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 can be profitably produced in the future, the need to enhance Miller Energy’s internal controls, operating hazards, drilling risks, fluctuations in 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 of you who are unable to listen to the entire call, we will have an audio replay that will be available. And the call is also being webcast, so that you can log in via the Internet. All that information was provided on the conference call announcement and in earnings release.

And at this time, I’d like to turn the call over to Mr. Boruff, the Chief Executive Officer of the Company, and he’ll be providing opening remarks. Mr. Boruff, the floor is yours.

Scott M. Boruff

Thank you, Derek. Good afternoon and thank you for joining us for Miller Energy’s 2014 fourth quarter and fiscal year-end earnings conference call. To begin, I’ll provide a brief overview of our accomplishments during fiscal 2014, which ended on April 30, 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 fiscal 2015. Upon completion of the management presentations, we will open up the call for your questions.

During 2014, we made significant increases in revenues, production, well-bore diversification for Miller, and we made major strides in decreasing our cost of capital. Our revenues increased from $34.8 million in 2013 to $70.6 million for fiscal 2014. That’s right. Our revenues doubled. This massive increase is a result of doubling our oil revenues and increasing our gas revenues significantly from $468,000 in fiscal 2013 to nearly $5 million in fiscal 2014. In addition, our oil production more than doubled from 295,483 barrels of oil produced in fiscal 2013 to 684,701 barrels of oil produced in 2014.

We saw an increase in natural gas production from 132 million cubic feet in 2013 to 793 million cubic feet in 2014. These huge increases in production are a direct result of our drilling successes as Sword and the Osprey platform and of our acquisition of the North Fork Unit during our fourth quarter.

Early last month, we closed a new $250 million senior revolving bank loan with KeyBanc and the syndicate of lenders, including CIT Finance, Mutual of Omaha Bank, and OneWest Bank. The new loan has a current borrowing base of $60 million and bears interest on a sliding scale based on LIBOR plus 300 basis points to 400 basis points on an undrawn commitment fee depending on the level of borrowing.

The First Lien RBL is an addition to the Second Lien Credit Facility that we closed with Apollo and Highbridge in early February, which gave us access to $175 million at an interest rate of LIBOR plus 9.75%, subject to a 2% LIBOR floor.

John Brawley, our CFO, will address these new facilities and our other options for accessing capital later on the call, but I wanted to emphasize that we have continued to decrease our cost of funds while obtaining more available credit. On this capital intensive business, obtaining this kind of financial flexibility has been crucial to our ability to execute on our development plans.

Operationally, we’ve had our best year ever at Miller. During 2014, we brought online several new oil wells including side tracks on the Osprey Platform, RU-1A, RU-2A, RU-5B, as well as our new onshore Sword #1 well. We acquired the North Fork Unit and have increased production there to approximately 10 billion cubic feet per day.

In early fiscal 2015, we brought on our West McArthur River Unit #2B oil well online. We continue to work on RU-9 oil well on the Osprey platform, which we expect to bring online this summer.

Subsequent to our year end, we also entered into an agreement to acquire Savant Alaska LLC, a company with operations in the Badami Unit on the Alaskan North Slope. We expect that acquisition to close by December 31, 2014, with an effective date of May 1, 2014.

We also purchased one drilling rig and entered into an option to purchase another, which puts us in great shape to continue our aggressive drilling program in fiscal 2015. Finally, we recently announced that we intend to divest our Tennessee assets in order to focus on our Alaskan operations and more favorable investment opportunities. David Hall, our Chief Operating Officer at Miller will discuss our drilling results and plans for fiscal 2015 in more detail later on this call.

We are also happy to note we resolved several law suits that had been pending. First, we won a dismissal of the federal derivative action and that dismissal was upheld by the Sixth Circuit Court of Appeals. A similar derivative action that was filed in the State Court of Tennessee was also dismissed. We settled the lawsuit with the CNX for $1.25 million, and we settled our dispute with the Voorhees Equipment and Consulting on a cashless basis.

Another lawsuit against us was withdrawn. Most recently, we reached a proposed settlement with the plaintiffs in the class action lawsuit for an amount that is within our insurance coverage. The proposed agreement is not an admission of wrongdoing or acceptance of fraud by us or any of the individuals named in the complaint, and we are settling this matter to eliminate the uncertainties of risk, distractions, and expenses associated with protected litigation. The proposed settlement remains subject to the court approval, a class notice administration. As a result of these legal victories and settlements, you should note that only three of the cases listed in our 10-K are still active.

We are excited about the tremendous year that we’ve just completed and the foundation it lays for fiscal 2015. Building on increased production, revenue, less capital, less expensive capital available for our development plans, the right people in place to further strengthen our internal controls, the favorable resolution of some significant lawsuits, a substantial inventory of drilling targets and reserves, we firmly believe that 2015 will have great things in store for Miller Energy Resources.

At this time, I’d like to turn the floor over to John Brawley, our CFO, who will go through the financial results. John?

John M. Brawley

Thanks very much, Scott. Well, before I get started, just a quick administrative point I’ll note for those on the call that a 10-K/A was filed just probably in the last few minutes. We had a cable cut off in one of the exhibits. That was not a required disclosure, but it was just a scanning error in disclosing the table related to our reserve report.

So in the K/A, which we’ve just filed, the full supplemental information is included. We weren’t required to file a 10-K/A, but we wanted to make sure we have the full disclosure of that by the Scott reserve report included. So for investors I’ll note that’s now available.

As you all know, I joined the Company as a consultant in November 2013 and I transitioned from Guggenheim to Miller. In February 2014, I was appointed as Chief Financial Officer. Since I joined in November 2013, the Company has undergone a tremendous change in many different respects. From when I joined we have brought new wells online to almost double production from approximately 2,700 barrels per day equivalent growth, 2,000 barrels per day net to current production of approximately 5,100 barrels per day growth, 3,800 net and that does not include the Savant acquisition.

We’ve acquired and closed North Fork, announced intent to acquire Savant, and signed up to purchase two drilling rigs in West Tennessee. Beyond operations, we’ve tripled the capital available to the Company and at the same time reduced our average interest rate below 10%, all without diluting shareholders.

We did this by refinancing our 18% $75 million debt facility with Apollo to a new 11.75% facility with Apollo and Highbridge and a new RBL, which together gave us a blended interest rate of approximately 10% on $235 million of available debt. The change in the company’s production, assets, management and capital structure has been truly transformational since I joined.

I’m going to walk through what I believe are the key drivers of our business and point out a few things that we’re presenting more clearly and with more detail in this year’s 10-K. The first item we’re working to clarify is what we have previously reported gross production to the market. As we acquired Savant and provide more clarity on our production numbers, I want to bridge the gross production numbers we previously reported to the net production numbers we reported in our filing.

Gross production is the production of any given well at the wellhead i.e. the total volume coming out of the ground. Net production is our share of that which is referred to as our net revenue interest. Our net revenue interest is currently an average of about 82%, but varies well-by-well. The balance of the revenue interest is applied to royalties and other working interest owners.

After taking out net revenue interest and applying it to gross production you’ll have our net production. After that there’s one more adjustment. We use some of our gas productions of fuel gas to power our facility. That amount is about 2 million cubic feet per day while we’re drilling and closer to 1 million cubic feet per day when we’re not drilling. So to fully bridge from gross production to net production, take grow production multiplied by our current average 82% net revenue interest and subtract 2 million cubic feet per day of fuel gas that will give you an approximate net number.

So we’ve gone through kind of some of the math of exactly what the difference is, but note that we will provide both numbers wherever we can to make sure that the point is clear and that there’s no confusing of the gross versus net. If you’re looking at the contribution for a well that we bring online just apply that net revenue interest of 82% to the gross production number.

Companies often report gross numbers for well IP rates as the gross number is more comparable when evaluating production performance versus other wells and other company. However, we’re talking about company-wide production. Net production after fuel gas is a number which will relate to our financial statements and what I’m trying to do is make sure everybody has a clear bridge from the numbers we announced to what will appear in our financials.

Previous targets and release numbers have often been gross and as we transition to net numbers please make sure you’re comparing apples-to-apples. Again, we’ll try to be very clear for any number’s gross or net and in general we are going to try and provide net production as well as gross production so that you can more closely tie to what we will see in our financials.

The last point I’ll make is that there is a difference between net production and sales volume and that volume difference is inventory. And as we mentioned on prior calls, we shifted our oil from Drift River to Tesoro on the other side of Cook Inlet once or twice a month. Our oil is only counted and sold and accounts towards revenue once it is shipped. So any difference between our sales volume and our net production volume is held in inventory. So I typically will find to spell it out where possible. We’ll try to write both numbers as often as we can as we transition here to this custom, which most of our peers use.

So going back to performance, I believe the company is headed in the right direction and our increased production revenue and EBITDA during the last quarter as compared to the third quarter is strong evidence of our progress. When you look at the annual numbers the transformation is even clearer as we saw tremendous growth in production, revenue and EBITDA year-over-year.

We increased net production by 157% year-over-year and by 25% in the fourth quarter versus the third quarter. That’s very impressive to me. Total revenues for fiscal 2014 doubled versus 2013 to $70.6 million compared to $34.8 million for fiscal 2013.

Total revenues for the fourth quarter increased by a third to $22.1 million compared to $16.6 million for the third quarter. In understanding revenue, the majority of the increase came from increased oil production as realized oil prices actually decreased by 1% and North Fork only contributed $4.1 million in revenue in 2014. So the results are from our performance, not commodity prices or acquisition.

And looking at expenses, I’ll quickly discuss a few high level items. Note that instead of oil and gas operating costs in our financial statement we have now broken it down into LOE and transportation cost separately.

Note that transportation costs are increased by a temporary $1.95 per MCF pipeline tariff we obtained in conjunction with the North Fork acquisition only while we wait for RCA approval for the midstream company. When RCA approval is granted we will collect 60% of what we’ve already paid in gas transportation cost to North Fork and going forward the $1.95 transportation cost will effectively be eliminated as an intercompany expense. In the fourth quarter there was $1.4 million of this non-recurring expense, which we added back to adjusted EBITDA.

Next, looking at LOE, while on the surface LOE decreased year-over-year, it is important to note that 2013 LOE included $7.5 million of workover expense. A large portion of our LOE is fixed as we operate large facilities with capacity in excess of current capacity, current production. And so we expect the LOE will not go up proportionally with production and our LOE per barrel should come down as we increase production.

G&A has been a focus of the Company lately and management is committed to reducing cash G&A expenses by up to $5 million per year. When I look at G&A, I focus on cash G&A as non-cash G&A is quite volatile depending on stock price.

Cash G&A for the year was approximately $23.1 million compared to $15.9 million in the year prior. I will comment that only $6.8 million of the $23.1 million of cash G&A was related to salaries, bonus and benefits. G&A for the Company is driven by professional fees, not compensation. Much of these fees relate to legal and other professional services, which are no longer needed given the revolution of shareholder issues and legal cases.

As Scott mentioned, there are only three remaining actives that were listed in our 10-K. Continuing in G&A previously that was from tax credit NOLs, as a production related tax credits which were credited against G&A. We now break those out separately because the numbers have become much larger and we want to make sure it’s presented clearly to our investors and separately identified.

In the past, investors had always some confusion over tax credits. So we’ve broken up tax credits out separately and add notable team to our financial statement. This note should make our tax credits much clear for you.

We received two types of tax credits: expense related operating loss credits and investment credits. Once a year as an ordinary course of doing business we applied for a carried loss credit as we did in the fourth quarter of 2014. This credit is associated with field level operating losses and flows through our income as it’s effectively an offset to an expense or subsidized reduction in expenses.

Previously this amount was small and was consolidated into G&A. This year the amount was much larger at $16.3 million. So we decided to make sure it was very clear and break it out separately in the face of our financial as Alaska carried-forward annual loss credits, which you’ll see in our income statement.

We also received investment-related tax credits, which relate to capital spending versus expenses. These credits do not flow through income and show up as an offset to CapEx on the cash flow statement under cash flows for investing activities. We apply to these credits every quarter.

Both of these credits are received in cash approximately four to six months from application. As we spend more capital, you will notice that both our carried-forward annual loss credits and our investment credits increased. At April 30, we held $49.1 million on our balance sheet as credit receivable. We have already received $21.8 million of this in June and expect to receive another $20 million in August. So we’re collecting on that accounts receivable balance very well.

Also understand that we only book these credits when they apply for and subsequent to any application which we can only file once per quarter we have spend additional CapEx so that any given time their additional credits which did not make it into the most recent application cut off and which are therefore not reflected on our balance sheet and we’re potentially understated the total credits we could receive at any given time versus our balance sheet.

Exploration expense and ARO accretion expense was not fairly significant in 2014, exploration expense relates to delay rental payments for undrilled exploratory leases and ARO accretion expense increased as a result of the North Fork acquisition.

DD&A is our largest expense item and I’ll point out that this is a non-cash expense. DD&A increased as a result of increased drilling activity production and the North Fork acquisition. If we’re doing our jobs this number should continue to grow as we capitalize more successful well and deplete them through higher production levels. DD&A increases are a sign that we’re growing which is our mandate.

Interest expense increased as a result of our increase in total debt as we refinance our prior debt funded the acquisition of North Fork and funded our capital budget or without diluting shareholders.

Moving along I believe adjusted EBITDA is a good metric to judge our health. As I said you how much cash we’re generating on a run rate before the impact of our capital structure, and that can be used to compare company from performance between companies with different capital structure. Then this use this metric above all others because they believe it to be most partnered equity holders are focused on this metric as well because it is a good indicator of health.

For fiscal 2014 adjusted EBITDA increased to $37.8 million, compared to adjusted EBITDA loss of $5.2 million for fiscal 2013. Adjusted EBITDA for the fourth quarter which I’ll note included $16.3 million of production carry forward loss credit increased 516% to $26.5 million, compared to $4.3 million for the third quarter. This positive trend in adjusted EBITDA is very encouraging answer sure we’re increasing production, increasing profitability, and overall financial outlook. Adjusted EBITDA increased as a result of increased production.

I would also like to make some comments about net income and earnings per share, investments for large companies focus on these metrics very closely and a number of our shareholders focused on this number. I would comment that for a growing E&P company these metrics are subject to non-cash items, which moves the numbers but may not indicate the true welfare of out business.

For example in 2014, net income was impacted by $15.1 million loss on debt extinguishment. This was associated with a pre-payment penalties for paying off the follows all to 18% loan. Clearly that was a very positive event but it negatively affected net income.

In addition net income was affected by a $10.2 million derivative loss, which was as a result of an increase in oil prices from the time that we entered into the hedges. Our business is hedged through dues of commodity price risks and when we lose money on our hedge portfolios the effect of raising prices which cause that loss is much more meaningful to our total asset value.

As an oil and gas company I would suggest that toward prices go up the impact to our company is very positive, so if there is a loss on hedging it means prices went up since we put the hedges in place and what probably wants more as a company. Further a large portion of the hedge losses are non-cash of our $10 million hedge expenses, $6.4 million was non-cash and related to the change in the future value of our hedges not in cash received.

So again this is a positive event raising at as oil prices rise. Lastly, our tax provisions can also cause expenses. We are not currently a tax payer and probably won’t be for sometime given our NOL position. So, I believe changes were flowing through the tax provisions and others relevant for judging our companies health.

In summary, I think net income and it on extra share of difficult measurement by which they judge us because both are impacted by large non-cash expenses many of which such as increased DD&A, loss on refinancing debt and derivative losses indicate generally positive event that reduce net income.

In my mind better metrics by which to judge us are production, revenue, adjusted EBITDA and cash flow. From a capital resources standpoint subsequent to the end of the fiscal year we close the reserved baseline with KeyBanc. Previously this lowest cost part of our capital structure was missing. In closing this facility with a high quality syndicate of banks including KeyBanc, OneWest Bank, Mutual of Omaha and CIT. We have demonstrated to the market that we can attract high quality conservative institutions including not only Apollo and Highbridge but also Commercial Bank.

The revolving credit facility provides us an additional tranche of capital at the lowest possible cost to fund our drilling activities without diluting shareholder. As we looked to 2015, we expect that we will spend approximately $130 million net adjusted for tax credit or $200 million grows before tax credit. We believe we can fund this with available resources but we made you to raise additional capital to fund acceleration of our capital plan or other new acquisitions.

Sounds roughly, we have also identified a number of joint venture partners for both Sabre and Savant which may reduce our capital budget. For us the key is that we had operator and controller of drilling scheduled for all our meaningful operations and as such we can accelerate or decelerate our developments well. We currently have approximately $14 million of cash, we have $30 million available to draw under the revolver and we expect to receive another $20 million in tax credits in August. So we have approximately $64 million of near term liquidity plus revenue.

Lastly, I would like to address our material weakness and our audit opinion. We have had this since 2011. We have associated with Miller’s historical insufficient complement of accounting personal. With the addition of myself and our director of financial reporting I believe that we can remediate our material weakness. There was not sufficient time with us in place during fiscal 2014 to remediate the weakness for this fiscal year.

I have been working with the board and our audit committee to ensure we are implementing a right control and documenting and testing inappropriately so that we may resolve our material weakness prior to our next 10-K which is the next time it is officially tested.

I have engaged new procedures, policies and control I have additional personnel, removed personnel and changed staff whose responsibility to improve the control environment and we will continue to improve our controls until the material weakness has been eliminated.

Further, as stocks requires not just a particular control environment, but also adequate documentation and testing of the environment. The audit committee and I have engaged Grant Thornton to review and test our controls to provide us the mechanism to certify when we believe the material weakness is fully remediated and documented.

We have also hired a junior accountant with big four accounting experience as to self-coordinate and to help us. We are hoping, we are conveying today to our shareholders it is the major focus of management and the board to remove this material weakness.

In summary, I am amazed of the changes inside Miller since I joined from doubling production, to acquisitions, to the major increase in adjusted EBITDA, to management and board commitment to improvement. We have grown the company remarkably over the last year without diluting shareholders, reduced our cost of capital, closed accretive acquisitions and continue to capitalize on an exciting inventory of drilling opportunities.

I am happy to be part of the Company, positive about the Company’s future and thank our board and our shareholders for the opportunity. Now after that long winded discussion which I hope was helpful, I’ll turn over to David Hall, our Chief Operating Officer.

David M. Hall

Thank you, John. First, I would like to update you on our production numbers. In 2014 we produced an average of 2,283 BOE a day net versus an average 870 BOE a day net in 2013.

And in 2014 we saw only 132% increase in our oil production with most of that increase in Alaska which increased production by a whopping 139% as compared to last year. Tennessee also had its production increased by 29%, so we saw an improvement level of placement.

We also had an impressive increase in our Alaska natural gas production with the acquisition of North Fork. We are very proud of the progress we’ve made in ramping up our production over the last year, which is a result of drilling our RU-2A, RU-5, Sword, WMRU-8 and WMRU-2B as well as acquiring North Fork.

Currently our company wide production is approximately 5,100 BOE a day growth and 3,800 BOE a day net. And that’s not include production related to the Savant acquisition, which is an increase of 24% over our four month quarter average rate of approximately 3,000 BOE a day net.

Our year-over-year total proved reserves have increased in both volume and PV-10 with notable increases through the year of proved developed. However, we will note our investors that Ryder Scott reserve report brought along with the 10-K is lower than the Ryder Scott report we released on December of 2013. The 04/30/14 Ryder Scott report includes proved developed reserves that approximately $245 million versus $366 million reported on December. Both are based on SEC pricing.

Here are some significant points to note. First, we have produced similar reserves in December, which will negatively impact the PV-10 value. And secondly, they are a number of wells online since the report effective data which are not included. Most notably the report does not include WMRU-2B which is currently online and producing approximately 650 BOE a day growth in 540 BOE a day net. Nor does it include the third zone and the Sword #1 well, from which we have now received a comingling permit and is now online.

Lastly within the next few weeks, we will have completed West Foreland #3 and RU-9 wells and brought them online. RU-9 is a nice particularly exciting well whereas it is designed to prove out to southern step out and the Redoubt structure by capturing well reserves from a large hallway structure not to hold approximately 50 million barrels of oil. We have already encountered potential viable pay on both on the well and are looking forward to bringing it online.

Currently, we are only producing from two out of the six all blocks of the elongated nine miles long Redoubt Shoals structure. RU-9 is the first step out well in which we are proving up reserves in the most Southern part of the Redoubt structure of which two wells that were drilled in the 60s, of which one for hydrocarbons to the surface and the second one were designated by the State of Alaska as a well capable of producing and paying quantities at a time when oil was approximately $2 a barrel.

We also have good 3D coverage over the entire Redoubt area. RU-9 is designed to be drilled structurally high to the wells which produced oil in the 1960. The drilling of RU-9 shows that we can drill in and to the first of multiple additional targets at Redoubt and each of the step out wells could be very impactful to the company’s reserves.

Following the step out well at RU-9, we plan to drill our next step out well, which is RU-12 and to the Northern Fault block. Also positive from a value standpoint we collected $21.8 million from the State of Alaska drilling repaying credit in June and another approximately $20 million to $30 million is expected on August.

I’ll now going to more detail after where we are with our wells, but I wanted to emphasize we are at an all time high as far as production which is already increased by 24% from our fourth quarter average net production rate and that there are multiple wells not accounted for and the reserved for which are already online or in the final stages of drilling.

Now onto the well-by-well update. Starting with our onshore progress at WMRU-2B, Sword West Foreland #3 and WMRU-8 wells, and once in store for the newly acquired North Fork gas field and offshore progress with RU-9 and RU-7 as well.

I will also provide an update on Tennessee operation and the Savant acquisition. Onshore in Alaska the non-producing WMRU-8 well, now called WMRU-2B was recently fine tracked and completed using the Patterson 191-Rig. We are pleased to announce WMRU-2B is currently produced approximately 650 BOE a day growth and 540 BOE a day net and has exhibited strong and stable production rates. This well is producing wonderfully and we are excited about it and I’ll emphasize again this is not included in any category the 04/30/2014 reserve report.

Moving along to our Sword well, I should start with a point to clarify, that point of clarification in our earnings release the April 30, 2014 rate the 403 gross barrels of oil per day given per Sword was an average gross rate for the month of April as reported to this day. During the month the well was offline or producing at reduced range for two weeks to be clear Sword had been producing 600 to 650 barrels of oil per day growth since January and is holding nicely at that rate.

As I mentioned earlier, we received critical permits for our Sword #1 well that allowed the comingling of the Sword – Tyonek-G zone with the Tyonek-G 0 and Hemlock well zones. Recently we comingled the three zones and they are currently producing all three zones together. We didn’t have these plates these permits in placed produced all three zones in hand because we expect that the upper zones the zone to be predominantly gas, but when we test we found primarily oil.

So we are very pleased to go back and apply for the comingling permit for the upper zone as well as the lower zones. This well has been an enormous success for us and we have already started to increase production as a result of comingling of three zones. With the Tyonek-G tested and now comingling in online as it expected that the ultimate oil recovery will increase as a result. Only from the two bottom zones were included in the current reserve report.

Moving on to West Foreland three gas well which we are currently drilling using the Patterson 191-Rig which previously drilled with WMRU-2B well. Today the well has been drilled to a final measure depth of approximately 11,000 feet long casing installed and cemented in place. Completion and testing preparations are currently underway we’re excited about this progress and we’ll provide results in the coming week.

Following the successful completion this will move from a prior to a PDP well upon completion of West Foreland’s three, we plan to mobilize the Patterson 191-Rig to Beluga area and commence drilling in Olson Creek #2 well.

Olson Creek #2 is designed to not only penetrate and evaluate the Beluga formation but also the Atomic formation, upon completion of Olson Creek #2 we plan to reenter Olson Creek #1 well located on the same drilled side path. Depending on the success of Olson Creek wells we plan to commence drilling in other field. We believe the Patterson 191-Rig is better suited to drill to the (indiscernible) in that area. Rig 34 remains stacked and is currently scheduled to be used to drill shallow gas wells in Susitna Basin.

We’ve recently brought WMRU-8 online well rates were lower than expected and we’re evaluating follow up drill work likely needed to have certain higher production rates from the well.

Now that has been drilled is classified as proven behind pipe in our 04/30/2014 reserve report. From well log and petrophysical analysis we believe a reduction in permeability and the perforated intervals located in the Hemlock are a result of an impeding fault then they ultimately require sidetracking and lower part of the wellbore to further distance from the fault.

The daily oil rate is sporadic and ranges from 20 barrels to 100 barrels of oil per day growth. WMRU-8 was drilled to a final measured depth approximately 16,500 feet with the Hemlock and the most westerly and then the western – most western part of the West McArthur River field. As we firm up our plans to rework the well will provide an update thereafter. As we look at our future onshore drilling activity the next significant well in West McArthur River area is a Sabre #1 well. Sabre #1 well is the well in a large perspective prospect offsetting Sword in the same way Sword offset WMRU-5 and WMRU-6.

Sabre #1 wells intended to capture oil reserves from a four-way structure immediately north of the Sword field. The well will be drilled from a new path north of the West McArthur River production facility and approximate measured depth 22,000 feet. We estimate the Sabre #1 well contain gross recoverable reserves of approximately 1.1 million barrels of a PV-10 value of approximately $40 million, and an estimated 25 million barrels of oil in place for the entire Sabre Field, which does not include possible like gas camp.

Upon the success of Sabre #1 well, we expect it will create a number of offset in private locations. We will use a newly acquired Rig 36 to drill Sabre #1 well. Since his purchase, it has been mobilized to our yard in Nikiski and has undergoing modifications, inspections, and new certification. And is expected to be completed and ready to mobilize to the West McArthur River production facility area to drill Sabre #1 in early October.

Still onshore, but on the other side of the Cook Inlet at North Fork, we recently announced the intent to purchase an additional drill rig. The Glacier rig to accommodate not only development as the North Fork field, but other prospects such as Olson Creek and Otter, the Glacier rig will be called Rig 37.

As we produced from the North Fork field we will continue to optimize the existing wells through perforation and velocity string and other optimization technique looking for ways to increase production.

As a matter of fact, we are currently in the process of installing a gas velocity string on one of the wells 1425 in an effort to increase production. We’ve already done some of this already in overall production at the North Fork field it has increased approximately 30% since the acquisition.

In addition to optimizing the existing wells, we have identified significant number of new wells that we are evaluating in our efforts to fully developed the field. The North Fork field is approximately 10 million cubic feet of gas per day, 8 million net and the supplying our gas contracts. As part of the rework of 1425, we took the opportunity to evaluate the presence of Hemlock oil with initial encouraging preliminary results. We will announce the results of that when completed.

Moving to our offshore operations, we’ve recently replaced the ESP and RU-7 well and is now on line and has already produced more than what it was when it was shut-in for the rework. We also recently spud RU-9 grassroots well on March 9. And as we mentioned in our last call, we needed to make some upgrades on Rig 35 and on the platform before the commencement drilling for the extended reach well, but those modifications are complete and drilling is well underway.

We have already drilled to approximately 17,100 feet measured depth, in case followed by cementing in place. We’re currently preparing to drill the final approximately 2,000 feet section of the well that will take us to the primary target to Hemlock, which is the primary producing formation in the Redoubt Shoals field. To date while logging the well, it has already exhibited several intervals in the lower tonic that appear perspective.

RU-9 is designed to prove up the southern step out and the Redoubt structure by capturing well reserves from a large four-way structure to hold approximately 50 million barrels of oil in play. We believe that through the success of RU-9 we’ll prove up significant additional reserves for us.

After the completion of RU-9 we plan to immediately start drilling in other grassroots well, RU-12, located in the Northern Fault block, adjacent to the main producing area. RU-12 estimated gross recoverable reserves are approximately 1.1 million barrels with a PV-10 value of $41 million. As mentioned in the past, our plan is to drill in all of the four additional fault blocks along it elongated Redoubt structure proven up reserves as we go.

Before I turn to Tennessee, I want to provide an update on the Savant acquisition. The acquisition closing is directly tied to obtaining regulatory approval and as such all the necessary applications have been filed with an approval date expected by the end of the calendar year 2014. Our team has been working very hard with the Savant team to compile a comprehensive drilling programs starting this winter season. We are very excited to close and realize the approximately net 600 barrels of oil per day current production and then lost a huge potential of Badami.

Moving on to Tennessee, in Tennessee as we started marketing – as we start the marketing process for the operations, we still continue to focus on increasing production through well reworks in conjunction with other optimization technique. With the current Tennessee production at approximately 235 barrels of oil per day growth and 130 barrels of oil per day net lots of rework opportunities and with the potential of the horizontal wells we think Tennessee has a lot to offer. We’ve already had several interested parties since the announcement to the divest Tennessee operation.

In summary, we are at an all time high in production. We have many exciting wells underway and very near completion. And lastly, we have an impressive inventory and future drilling opportunities at the Redoubt fields, the Sabre structure in the North Fork and Savant.

And with that Scott I will turn it back over to you.

Scott M. Boruff

Well, thank you David, that was great. You and your team continued to deliver great results. As we plan to continue to provide investors with regular updates regarding our operations and acquisitions as news develops. And we will continue to be excited about our current production and our drilling plans going forward. We are excited to build on a success of last year as we enter fiscal year 2015, which began on May 1, 2014 with our additional rigs, new financing and inventory of drilling and work over targets as well as pending acquisitions, we believe fiscal 2015 has extraordinary things and store for Miller.

Before we open up the call to questions I need to let you know we will not comment on any pending litigation on this call. That concludes our formal remarks for today’s call. Operator with that I’d like to open up the call for questions.

Question-and-Answer Session


Thank you. (Operator Instructions) And we will go first to Kim Pacanovsky with Imperial Capital.

Kim M. Pacanovsky – Imperial Capital LLC

Hi, good morning everyone, good morning and good evening.

Scott M. Boruff

Hi Kim.

Kim M. Pacanovsky – Imperial Capital LLC

Hi, I have a couple of questions on the well summary that you gave, about the six new wells being brought online. Can you go through each one of those wells RU-2A, RU-1, RU-5B, and just give us the drilling complete cost for each well and gross and then what it would be net after rebate if indeed you have received the rebates back -- the full rebate back for each particular well or what you would expect to get back?

Scott M. Boruff

Yes, as far as the rebate, I mean, we’ve been submitting applications to department of revenue on a regular basis, and so far average return on our applications that we submitted is approximately about 99% of the original amount, so we’ve had very good success on getting Alaska tax rebate on the wells that we drilled. As far as…

Kim M. Pacanovsky – Imperial Capital LLC

Yes, I know that – there is a quite a large range of what you get back for each well. And so, I guess really what I am looking for is just to get a snapshot of the economics for each one of these wells that there have been varying rates of success with the wells, I mean most of these on this list have been hugely successful. But I would love to see a production curve in an IRR and cost just really, so we can look at each one of these wells and see economically how each one is doing? Am I explaining myself?

Scott M. Boruff

We can add some of that data to our next presentation, so we’ve been talking about a few pieces of information that would be helpful in that regard, and I think what we would do is put that in our next presentation in the appendix, so you can have that data, and everybody else.

Kim M. Pacanovsky – Imperial Capital LLC

That would be terrific. Okay, next question on the Savant acquisition, can you give us a scenario of what your activity level would be both with and without a joint venture partner?

Scott M. Boruff

Sure. We actually just approved spending our 2015 budget at our last board meeting, and what we see a lot of opportunities this year would be the amount of capital that we expect on an [8/8] basis is something around $55 million. As you know, the properties already have a built-in joint venture partner with ASRC. We own 67.5%. They is significant exploration potential in the properties like all of our wells and all of our prospects, and we go through a process internally that includes talking to joint venture – potential partners on all prospects.

So, we can’t tell you today what percentage of our activities out there will take place with the joint venture partner, but we obviously are very excited about that property, and we’re prepared to advance it with or without a joint venture partner, but we will talk to potential partners on those properties just like we do on all the wells that we have.

Kim M. Pacanovsky – Imperial Capital LLC

Okay. And would you say the same about Sabre – Sabre will be drilled regardless of whether or not you have a joint venture partner?

Scott M. Boruff


Kim M. Pacanovsky – Imperial Capital LLC

Okay. What’s the AFE on Sabre?

Scott M. Boruff

35 million.

Kim M. Pacanovsky – Imperial Capital LLC

And that’s gross, correct?

Scott M. Boruff

That’s gross.

Kim M. Pacanovsky – Imperial Capital LLC

Before rebate?

Scott M. Boruff

We are having discussions with folks on Sabre. We’ve had joint venture discussions and all of our prospects and wells, and if we have something that’s attractive enough, we will in all likelihood JV some of those prospects in 2015.

Kim M. Pacanovsky – Imperial Capital LLC

Okay. And can you remind me what was the cost of Sword, gross?

Scott M. Boruff

Sword was I think a little over 35.

Kim M. Pacanovsky – Imperial Capital LLC

35, Okay. And do you know if you received everything back on Sword from the state, can you just tell me what it will net out to be ?

David M. Hall

Yes, Kim, I believe we have received everything that we have submitted for Sword.

Kim M. Pacanovsky – Imperial Capital LLC

Okay. And do you know what that netted out to be, David?

David M. Hall

No, I don’t.

Scott M. Boruff

Kim, we have that specific – that level of granular information available like well-by-well what the AFE was, always spend what we have. That’s something we would look to release in a future presentation. With regard to Sabre, what I would say is that’s a well into a new fault block. So that would qualify for the 60% higher tax level credit.

One of the things we evaluate when looking at JV partners is we’re already effectively subsidized by 60% in that well. So we have a JV partner as in the state already built-in. So that’s one of the factors we consider in looking for JV partners. David Voyticky mentioned approval by the Board of the capital budget. He meant specifically with regard to Savant. The Board approved a portion of the capital budget, just to clarify.

Kim M. Pacanovsky – Imperial Capital LLC

Okay. And just last quick question. What you anticipate additional G&A will be with the Savant acquisition? I’d imagine there would be a considerable bump up just in the additional people and the travel and additional environmental regulations to deal with. Is that correct?

John M. Brawley

We do obviously expect the G&A increase as a result of the Savant acquisition. We’re still working through that now, but…

Kim M. Pacanovsky – Imperial Capital LLC

Okay. Okay, great.

Scott M. Boruff

I’d say even with that, Kim, our total G&A will come down. As I mentioned in my remarks, if you go back in last year, it was 10 plus million of G&A associated with professional fees largely related to legal cases, shareholder issues et cetera. So we’ve got an easy way to attack G&A and bring it down. So I would not model higher G&A. Even with Savant I think that we can reduce G&A.

Kim M. Pacanovsky – Imperial Capital LLC

Okay, great. Thanks a lot guys. Appreciate it.


We’ll go next to Neal Dingmann with SunTrust Banks.

Neal D. Dingmann – SunTrust Robinson Humphrey

Afternoon, guys. So a couple of broad questions Scott for, I guess, maybe for you or David, maybe one of the Davids and that is, first, just kind of give an overall view of just overall wells coming out. I know David gave a lot of details. So I’m just wondering if you could just kind of walk us through more from a higher level now recall with the four rigs in place what were you looking at sort of for, let’s say, the next four quarters on average as kind of not a well by well necessarily, but just from as I said a 50-foot view how many wells maybe in total within each of those areas?

Scott M. Boruff

So, Neal, I think the way we’d look at it and the way we divided up our last presentation is look at Redoubt as one area. As David Hall mentioned, we’re expecting to complete RU-9 towards the beginning of August and we’ll expect to drill three more wells during the course of fiscal year 2015. And what would tell you to model out is probably one well every four month. So if you do that we’ll finish two and we’ll start the third new wells and that’s an addition to RU-9.

West McArthur River, we are working on refurbishing with Rig 36. We expect that to be completed and deploy by the end of October, beginning in November. And then we’ll expect to start and finish one Sabre well and if successful we’ll drill a second, probably not finish it before the end of our fiscal year. And the first well is successful and we’ll use that rig to drill then the Sword well.

We also, as David mentioned, plan on doing a little sidetrack into West McArthur River number #8, the last couple of thousand feet of that well. North Fork, as we’ve announced, we’ve intend acquire the Glacier rig. We expect to do some work on that rig and have that ready in the same timeframe as Rig 36. And once that’s up and running, we think we’ll drill three wells in the North Fork field before the end of fiscal year 2015.

We also have some exploration wells that we’re drilling on the gas side. So the Patterson rig is going to go and drill Olson, Otter, and depending on success it could drill more there, but I think two to four, and David also mentioned, Rig 34 will go up to succeed net. The last winner was too warm up there, but we’ll drill at least an exploration well up there. And then with respect to the North Slope, we’re planning to have a rig commitment shortly and the ability to drill two wells before the end of 2015.

Neal D. Dingmann – SunTrust Robinson Humphrey

Got it. And then, also from a higher level, I think David Hall mentioned about current production of plus 24%. Again, remind me, number one, what’s current production? And then, how you all see production whatever you can say about production growth same way maybe over the next four quarters? If you can give us, and I’m looking for maybe the range for the next fiscal year or how you can outline that a little bit.

David M. Hall

Sure. As mentioned, we’re doing approximately 3,000 barrels of oil a day at a gross basis in the Cook Inlet and we’re doing gas production of approximately 12 million cubic feet a day on again on a gross basis. So those are the average and the gas is at 80% NOI. The oil is in the low 80s. We’ve not included our numbers because we haven’t closed on the deal yet, the North Slope acquisition, but legally we’re entitled to the cash flow starting on May 1 and that adds another 1,000, 100 barrels a day gross and we have about a 59% NOI on that.

So going forward I think that you can look at the oil wells that we’re going to drill and it’s approximately eight wells. The average expected IP is in the 750 range. Those are slated to come on essentially one this summer and then the second one would come on, would be three months after that. Post fall we’ll have three rigs drilling for oil; one the North Slope, one the platform and one West McArthur River field. So the production is going to be slated towards coming on towards the second half of the year, but we expect to have two wells coming on before the end of fall.

On the gas side, we have our West Foreland #3 well, which we have booked our economics and it’s 2 million cubic feet a day IP. We’re expecting that would be coming on this month. We’re doing two reworks. With our North Fork’s wells we’re expecting to add on average 1,000 MCF for those reworks. So that’s what we’ll see in the near-term. Once we have the Glacier rig we expect that we’ll just drill three wells, again start sometime in November, see one well every two into three months. Each one of those we’re expecting to have IPs in the 2 million to 3 million a day range.

So that’s sort of, I think, our timetable and expected IPs and we’re expecting that our current production we’re seeing overall yield decline in the 20% to 25% range with our existing stuff. And on the new production, it varies a little bit by field, but what we’re seeing is something close to 50% on new wells and then carrying out towards 30% at the end of year one and then leveling out towards our field average, which is in some place around 20%.

Neal D. Dingmann – SunTrust Robinson Humphrey

Got it. And then, Dave, if I’m going to repel that up, I mean be the only thing as far as just sort of CapEx and cash flow, I guess if I look at that and see obviously a pretty sizable ramp in cash flow and I guess John and yourself mentioned that G&A and other things maintaining – at least going down and maintaining. I guess it’s safe to say that that cash out spin should to continue to decrease through this next fiscal year. I mean again I don’t want to paint on a cash flow number, but just trying to get overall, if you could just lastly talk about that.

David M. Hall

Yes, so I think back to the envelope, if you look at the ads – we’re expecting our gross production range between 8,000 and 9,000 BOE per day on a gross basis before the end of our fiscal year. If you had that on top of where we are we expect that by the end of our fiscal year, and if you include the tax credits, to be pretty close to being able to finance the same level of activity the following year through cash flow and tax credits.

Neal D. Dingmann – SunTrust Robinson Humphrey

Got it. Very good. That’s great. That’s what I was looking for. Thanks and I look forward to all the activity.

Scott M. Boruff

Well, thanks.


We’ll go next to Adam Fackler with MLV & Company.

Adam K. Fackler – MLV & Co. LLC

Good afternoon, guys. Couple of quick question on reserves, first one on the negative revisions. Saw on the filings that there was, I guess, a change in professional judgment regarding some PUDs. I was hoping you can maybe provide some additional color around maybe which book innings were revised and rationale behind it, if you would.

David M. Hall

Yes, it’s David Hall. I can start with that. I think the change that we – the drop that we’ve seen as the difference was mainly due to RU-9, for example. RU-9, as I mentioned earlier, was a well that we’re drilling into the South Step Out into the Redoubt structure, but it was not included in the 430 2014 report. If you look at what was estimated by the reserve for the company prior it showed 1.1 million barrels of recoverable oil and a PV-10 value of $48 million. And really the same goes to WMRU-2B that was also not included in the most recent report. So that’s nearly $100 million of PV-10 value.

Adam K. Fackler – MLV & Co. LLC

Okay. And those were the ones that accounted for that revision that you’re saying or the vast majority?

David M. Hall

The vast majority, that’s the difference.

Adam K. Fackler – MLV & Co. LLC

Excellent. Thank you, guys. I appreciate it.


And next we’ll go to Evan Richert with Sidoti & Company

Evan C. Richert – Sidoti & Co. LLC

Hi, guys. Good afternoon. Most of my questions have been answered. I just want you to touch on, I guess, the shift in production. We saw the spike in gas with North Fork. How do you guys see that changing throughout 2015, obviously drilling for both oil and gas? Do see that coming back toward oil?

Scott M. Boruff

Yes, it’s going to continue to be more oil heavy. The vast majority of our drilling is oil related. The two wells in the North Fork, all the Redoubt wells, the West McArthur River wells. The North Fork wells will be gas and the West Foreland wells with be gas. If you add them all up, it’s going to be less gas than oil in terms of our current ratio. So I think you’ll see our ratio continue to be increasing from an oil perspective this year significantly.

Evan C. Richert – Sidoti & Co. LLC

Okay. And I missed one. Do you think that Glacier rig will be ready for drilling?

Scott M. Boruff

I think at the end of the October.

Evan C. Richert – Sidoti & Co. LLC

End of October. All right, thanks. That’s it for me. I’ll hop back in queue.

Scott M. Boruff



And we’ll go next to Phil Juskowicz with Casimir Capital.

Phil Juskowicz – Casimir Capital LP

Hi, guys. Following up on the previous question, regarding the reserve revision, were you saying that the RU-9 was previously included in that December 1 reserve report and it is now been taking out?

Scott M. Boruff

No, I was saying that it was previously included in the 430 2013 report and was not included in the 430 2014 report.

Phil Juskowicz – Casimir Capital LP

I am trying to reconcile the 12/1 report with the PDPs versus what we got today. So for example the 12/1 report talks about, give specific RU-2A kind of figures with PV-10 for several wells. And I kind of was wondering if you could give us an update on where those wells stand. For example, the RU-2A seems to have dropped off significantly in terms of production in PV-10?

Scott M. Boruff

It did drop off some and we’ve seen initial declines on that to be a little steep at first until the well leads to what we call radial flow. And as such we see the declines has been reducing month-by-month ever since that has been achieved.

Phil Juskowicz – Casimir Capital LP

I mean if I could….

Scott M. Boruff

Once again that really kind of across the board on the Redoubt, keep the mind readout field is relatively a new field if only came about 2 to 2.5 barrels today. So, this is really the first time in history we’ve been able to produce the wells for any period of time without any mechanical failures like the previous operators had.

Phil Juskowicz – Casimir Capital LP

I mean just tell if my math is wrong, but if I take really 12/01 reserve report there was 8.4 million BOE and then I add back to production in the interim and if I can add back production entire years production and it can still come up with like a PDP figure that’s today’s PDP figure kind of seems a little low as well. So there was 8.4 million BOE and then reduction for I’m trying to get that in BOEs.

John M. Brawley

Well right, I mean there is a lot of that was due to some of the wells that I previously mentioned WMRU-9 or 2B for example some of the decline on the RU-2A. The things that leveled out production is actually looking very nicely on Redoubt now.

Scott M. Boruff

Okay. I think just follow up to sort of some of the information that Kim asked for as we have been going through some additional information we’re putting on next presentation I think we’re going to end up putting in some of the decline curves and ability in the hyperbolic nature of the declines both in the production and in the bottom offline pressures and we’ll go to do that on the whole field, but David give you a preview of what that looks like right now.

David M. Hall

Yes, just to give you an example from the Redoubt field from November 13 to basically February 14, the annual decline of Redoubt was about 75% from February to where we are today the decline is 31% annually, as well as you can see things are reducing less than less by month also wells have reach the radial flow we see that trend to continue with that be in a hyperbolic field and getting back in lines with what we as nearby field at the West MacArthur River unit.

John M. Brawley

So I think that what we expect also from reserve standpoint that happen as you have more data it’s really possible that we’ll see some increases in the next reserve.

David M. Hall

But if you like at the December report it still shows RU-2 for example recovering over 800,000 barrels.

Phil Juskowicz – Casimir Capital LP

Okay, thank you very much we appreciate.


We’ll go next to Kurt Caramanidis with Carl M. Hennig, Inc.

Kurt J. Caramanidis – Carl M. Hennig, Inc.

Hi, guys. I guess congratulations just on the last 12 months quite a lot of development that I’ve kind of set the table for the next 12 to 18 months that should be quite exciting so again congratulation I know it’s been a roller coaster but things look pretty exciting David, I just had a question on the last 2,000 feet on the RU-9 is that a smoother sailing as far as drilling if you made it through the tough parts or how are you looking at that?

David M. Hall

Well, we believe so, we definitely have some test drilling at first keep in mind, that sound step out and totally different direction than what certainly existing wells were so that was a little bit of learning curve we have to find the right drilling parameters I think affectively drilled out without getting stuck and mitigate some of the callous. But to answer to your question we do believe that we have worked thorough the hardest part so we are just about 500 feet away from the primary target which is the Hemlock.

Scott M. Boruff

Kurt, that the things remember there, that the first that came 1,000 feet are cased, so as David mentioned earlier on the call. We are very excited to find that the logs that we’ve seen already showing more potential fee to pay than we ran in our economics and we are not into our primary target yet. So it’s everything that very exciting what seem so far.

David M. Hall

These are pretty well if you look at the history of the wells drilled on the Cook Inlet RU-9, is probably either the third or the fourth longest well ever drilled Cook Inlet. And save her number one well will be that so long.

Kurt J. Caramanidis – Carl M. Hennig, Inc.

Yes, that’s exciting. So you are thinking early to mid-august we may have an idea on flow or is it too early to calculate that yet?

Scott M. Boruff

Hope the answer is – if things go according to plan and the rest no issues and we have few days of drilling left then we looked to run the final stair casing, have to do a clean out run and then we had to try it out on our preparation plan, if the rich man’s problem is that we found an extra 200 feet of potential pay just like on Sword, we have inside which zones we are going to test first, we have extra testing to do, because we have more than we have expected.

And ultimately depending on others what we decided to it, it could take as little more than two weeks (indiscernible) three or four weeks. So once we have the rest of the data we will make a decision on that, I think that early August timeframe is conservative as with every well that we drill and if they can’t let it if there is an issue it would take longer, but the nice part is that, if there is an issue and we are only starting over with 18 feet up and starting over and drilling extra 9000 feet its they it’s an early August expectation but it could change based on drilling.

Kurt J. Caramanidis – Carl M. Hennig, Inc.

Okay great yes, that seems very exciting and particularly well and good success in the future appreciate it.

Scott M. Boruff

Thanks, Kurt.

David M. Hall

Thank you.


And next we’ll go to Steve Baughman with Divisar Capital.

Steven Baughman – Divisar Capital Management

Thanks for taking the question Michael. My questions has been answered though, thanks.

Scott M. Boruff

Thanks Steve.


And that does conclude our question-and-answer session. I would like to turn the call back over to our speakers for an additional or closing remarks.

Scott M. Boruff

Well, as you’ve heard, now we are excited. We’ve taken five year to set the table to where we are now. An exciting time at Miller and the most production we ever had in Miller’s history the most revenue we’ve ever had by doubling it again this year as well as cost of funds we’ve ever had and so as you leave the call. Leave with one thing, we are trying to get several story four fields, four rigs and to have six rigs, capital execute plan, people execute plan and that’s our story looking forward.

So, we are excited about the year that we had, but we are really excited about the year fixing ahead. Thank you for joining us this afternoon to provide you with an update and our recent accomplishments, future plans and financial results. We are very excited about our future and the potential are properties. We will keep you update on our operations in future calls and look forward to you joining us. That concludes today’s call.


And once again ladies and gentlemen that does conclude today’s call. Thank you all for your participation.

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