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Executives

Derek Gradwell – Senior Vice President-MZ Group

Scott M. Boruff – Chief Executive Officer

David Voyticky – President and Acting Chief Financial Officer

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

Analysts

Kim M. Pacanovsky – Imperial Capital LLC

Chad L. Mabry – MLV & Co. LLC

Evan C. Richert – Sidoti & Co. LLC

Raymond J. Deacon – Brean Capital, LLC

Miller Energy Resources, Inc. (MILL) F2Q 2014 Earnings Conference Call December 12, 2013 4:30 PM ET

Operator

Good day, ladies and gentlemen, thank you for standing by. Welcome to the Miller Energy Resources’ 2014 Second Quarter Earnings Call. During today’s presentation all parties will be in a listen-only mode. Following the presentation the conference will be open for questions. (Operator Instructions) This conference is being recorded today, Thursday, December 12, 2013.

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

Derek Gradwell

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

Mr. Boruff, Mr. Voyticky and Mr. Hall will review and comment on financial and operational results for the second quarter of 2014. And they will be available to answer questions after the presentation.

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

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 M. Boruff

Thank you, Derek. Good afternoon and thank you for joining us today for Miller Energy's 2014 second quarter earnings conference call. To begin, I will provide a brief overview of our accomplishments during the second quarter of 2014, which ended on October 31, 2013. Following my overview, David Voyticky, our President and acting 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 fiscal 2014. Upon completion of management presentations, we will open up the call for your questions.

We continue to see substantial increases in production and reserves during the second quarter of 2014. We completed our second sidetrack on the Osprey platform, RU-1A which is averaging approximately 650 barrels a day and our third sidetrack RU-5 which is averaging approximately 230 barrels per day. Subsequent to the quarter end, we brought our Sword #1 well online.

Combining our new production in Alaska with our production in Tennessee, we’ve increased our production to just over 4,000 BOE per day, which is about half in the company’s history. We are pleased to report that our latest reserve report issued by Ryder Scott Company showed the substantial increase in the value of our reserves. This morning we announced an increase in our proved developed reserves PV-10 from $32.8 million as of April 30, 2013 to $297.8 million at December 1, 2013.

This increase can be directly attributed to the successes we’ve had in our drilling program over the past several months including the Sword #1 well with recoverable reserves of 898,000 barrels of oil and a PV-10 value of $63.4 million. RU-2A, with recoverable reserves of 1.5 million barrels of oil and a PV-10 value of $78 million, RU-IA with recoverable reserves of 1 million barrels of oil and a PV-10 value of $52 million and RU-5A with recoverable reserves of 516,000 barrels and a PV-10 value of $25.1 million.

We also received a new reserve report dated as of December 1, 2013 on the North Fork reserves, which we’re in the process of acquiring. While the actual North Fork acquisition reserves will be effective as of the closing date of transaction, the report showed a proved developed PV-10 of $67.9 million giving us a pro forma combined proved developed PV-10 of $365.8 million and a total proved developed reserves of approximately 8.4 million barrels of oil. Because lenders focus on proved developed reserves, we saw the new report to update the value of our proved developed reserves based upon our recent drilling successes so that we can access cheaper capital and future financings.

With respect to the current drilling projects we have two rigs running in Alaska. We’re using our own rig, Rig 34 at Otter, a gas prospect and the Patterson owned rig, Rig 191 at our West McArthur River Unit, #8 well. In addition, Rig 35 is currently being prepared to drill 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 we did in the Sword #1 well.

In Tennessee we continue to be focused on acquiring additional working interest in the existing wells as well as learning about how to better drill, complete and produce our horizontal wells. We’ve brought online our third horizontal well, the Brimstone H-1 on October 15 and it just produced a total of 1,600 barrels of oil to the end of November.

We also received our gas reinjection permit from the EPA, which will allow us to begin our reservoir pressure maintenance program on our first horizontal well, the CPP H-1. David Hall, our Chief Operating Officer at Miller Energy, will discuss our drilling program for fiscal 2014 in more detail later on this call.

We also offered a new class of publicly-traded preferred stock this quarter, our Series D Preferred Stock, which has initial dividend rate of 10.5%. Owned and after December 1, 2013 the dividend rate will become a floating rate tied to the LIBOR rate. We made the decision to designate and issue this class of preferred stock in order to reduce our cost of capital as we continue to develop our Alaskan properties.

Finally, as I briefly mentioned before, we have entered into an agreement to purchase the North Fork Unit from Armstrong Cook Inlet LLC and several other companies. The North Fork field is primarily a gas target with current production of approximately 7 million cubic feet of gas a day or 1,167 barrels of oil per day. These additional assets will complement CIE’s other oil and gas properties in Alaska and it’s CIE’s first operating field on the east side of the Cook Inlet.

Both David Voyticky and David Hall will offer some additional detail on the financial production impacts we expect in the North Fork Unit. We are currently excited about this acquisition and the production, reserves and the well bore diversification that brings.

In addition to these operational highlights from a personal standpoint we have added John Brawley from Guggenhiem Partners to our management team. John brings as a senior advisor and will lead our financing efforts as we continue to execute our development and acquisition strategy. John was previously co-head of Guggenhiem Houston-based energy mezzanine lending group and was part of the original team which provided Miller its initial institutional loan in 2011.

Given the high regards of both Guggenheim and John are held in, we feel incredibly fortunate to have added him to the Miller Energy team. John’s early contributions strongly suggest that his skill set and relationships will add considerable value to our company.

It’s an exciting time to be a part of Miller Energy and we are really looking forward to continuing to develop our resource and growing our shareholder value over the remainder of this fiscal year and beyond.

At this time, I’d like to introduce David Voyticky, President and Acting CFO and he will go through our financial results for the quarter.

David Voyticky

Thank you Scott. We saw a substantial increase in our revenues from the prior period up 74% to $18.8 million compared with $10.8 million in the second quarter of fiscal 2013. This is directly related to the new production we have brought online since last quarter.

Our total net production increased to 193,261 BOE compared with 78,145 BOE in the second quarter of last year. This was an increase of 67% in the Cook Inlet, which relates primarily to new production from our RU-3, RU-4A, RU-2A, RU-1A, and RU-5A wells. We saw an increase of 9% in Tennessee as well because of increased ownership in many of our wells there and as a result of our production from our horizontal wells.

Broken down by region, Alaska contributed 95% of our net production and Tennessee contributed 5%. Our average realized sales price per barrel for oil for the quarter was $102.65, which is a decrease of $3.03 or 3% over the same period last year.

Our operating cost for the second quarter increased $1.3 million or 27% to $6.2 million compared with $4.9 million for the same period last year, reflecting our increased pace of activity in Alaska. The increase in operating cost is directly attributable to five new wells being outlined and produced on our Osprey platform.

The increased production from these wells resulted in an increased oil transportation cost as well as variable operating costs. Although our operating costs have increased on a gross basis, most of our operating costs at Alaska are fixed and have to time substantially on a per barrel basis.

For the quarter ended October 31, 2013, our lease operating expense declined to $19 per BOE produced compared to $47 in the same period last year. We expect to see our lease operating expense continue to decline on a per BOE basis as we add production from our offshore and onshore prospects.

G&A expenses increased by approximately $900,000 or 15% to $7.1 million in the second quarter of 2014 compared with $6.2 million during the same period in the prior year. Salaries increased 59% from the same period in the prior year, as we continue to expand our corporate accounting staff in the prior period, additions to our engineering and support staff in the Cook Inlet region and as a result of salary increases for our named executive officers.

Professional fees increased 39% over the same period of last year due to an increase in accounting, capital raising, legal, and investor relations activities during the quarter.

Stock-based compensation declined 33% due to the expense associated with rewards that became fully vested, exceeding the expense associated with the newly granted rewards. The increase in other expense resulted from an increase in liability insurance premiums due to our increased drilling activities and an increase in office rent related to the addition of office space in both Tennessee and Alaska.

Depreciation, depletion and amortization expenses, which include expenses related to leasehold costs and equipment, increased to 194% from $3.0 million in the second quarter of fiscal 2013 to $9.0 million in the second quarter of fiscal 2014. This increase in DD&A was primarily the result of increased production from our Alaska properties and Rig 35 being in service during the period this year.

Our second quarter results included other expenses of $5.6 million compared to other expense of $3.9 million for the same period in fiscal year 2013. The increase in other expense since last year was primarily due to an increase in our loss on derivatives as compared to the prior period.

As I noted in past calls, our derivative instruments results in earnings volatility as a result of Miller not using hedge accounting for our commodity derivatives. This results in Miller effectively recognizing all realized and unrealized gains or losses associated with derivatives in our earnings each quarter.

Our net loss attributable to common shareholders for Q2 was $8.2 million or $0.19 per share. Our net loss increased from the same quarter last year due to our increased operating expenses, which reflects our increased production and pace of drilling activity and an increase in other expenses, partially offset by higher revenues and increase in income tax benefits.

We ended the second quarter of fiscal 2014 with $21.9 million of cash and cash equivalents, $733,000 of unrestricted cash and approximately $78 million of debt outstanding. Operations provided $4.4 million of cash from operations, down from $6.7 million of cash provided by operations in the prior year in the same period last year.

Our net cash used in investment activities increased from $16.9 million to $59.6 million from the same period last year. This is a result of our increased drilling activity in Alaska. Our cash flows provided by financing activities increased from $10.6 million to $74.8 million, primarily due to additional proceeds from our Apollo credit facility and the issuance of preferred stock.

Now I want to comment briefly on our expectations for Q3 of fiscal 2014. First as noted, our Board had approved $297 million in drilling projects and acquisition CapEx and we’ve allocated $65 million of this to the Armstrong acquisition and we spent approximately $67 million year-to-date and we don’t expect to start all the projects approved by the board before year-end, but we can expect to continue spinning at the same rate that we spent last quarter.

With Sword #1 coming online in late November, we expect to see increased Q3 revenues as a result. With respect to the status of Alaskan tax credits, we received 12 million in tax rebates during this fiscal year to date and at the end of November we filed two applications for tax credit totaling $21 million.

I’d like to take a minute to discuss the North Fork acquisition and the financial impact we expected from it. Purchase price for the North Fork Unit is approximately $65 million with $5 million in our Series D preferred stock.

As Scott mentioned, the current production from this deal was approximately 7 million cubic feet per day. We’ve also acquired a multi-year firm, natural gas sales contract with ENSTAR, the largest natural gas utility and Alaska is part of this transaction.

That contract has a commitment of approximately 4.8 bcf remaining to be provided at a price of approximately $7 per mcf. We expect to generate up to an additional $20 million in annual revenue from the current production from this deal. There are six existing gas wells which we intent to optimize and we plan to fully develop this deal by drilling up to 24 additional wells. We believe there is considerable potential left in this field.

Finally, we remain with a strong capital position as we continue to have access for the capital market through our Series B and Series D preferred stocks. Our asset market sale agreements of these two class of stock have provided and continues to provide us with flexibility to raise fund as needed. We are also in talks with multiple lenders regarding our financing options going forward.

We expect an increased value of our proved developed reserves as set forth in the new Ryder Scott reserve report along with both the increased well-bore diversification and increased revenues as a result of the pending North Fork acquisition to provide us with the ability to secure less expensive capital than as previously available to us. We are excited about that the financing opportunities that are opening up as we successfully execute our development and acquisition strategies.

Before I end just to give a little guidance, since bringing the Sword #1 well online, our total production per day is approximately 4,000 BOE. With the announcement of our tenth super purchase of North Fork Unit and its current production, we expect to add approximately 1,100 BOE in additional productions from that acquisition before our fiscal year end.

And that would increase our estimated year and production level to over 7000 BOE per day, if you include the expected production that would come on from new wells under way, like West McArthur River-8 and RU-9 which we expect to begin in the next 30 days, as well as potentially finishing West McArthur River-9 and increasing the production on North Fork above its current 1,100 BOE per day level.

Now I would like to introduce David Hall, our Chief Operating Officer to discuss the progress we made in the second quarter of fiscal 2014 and what’s in store going forward.

David M. Hall

Thank you, David. First I’d like to update you on our production numbers. During the second quarter we produced 182,887 net BOE in Alaska and 10,374 net BOE in Tennessee making this our largest producing quarter till date with a total of 193,251 BOE.

Due to fluctuations in our shipping schedule this does not equal the oil we sold this quarter, as some of it is held or drawn from inventory. Our average daily production in Alaska was 2,876 BOE a day growth for Q2 putting our Alaska growth production for the quarter at 264,632 BOE. We averaged 3775 BOE a day growth in Alaska at the end of November. In Tennessee, we averaged about 236 BOE a day growth in November.

While I get to discussing our Pacific drilling plans and latest results in a moment, I want to emphasize the impact that our drilling [indiscernible] in the last half of 2014 and have on our reserves. Yesterday we received our newest reserve report conducting by Ryder Scott Company. We saw an increase in total approved developed reserves from 1.6 million BOE to approximately 6.1 million BOE with at TV-10 value of $297.8 million.

The bulk of the increase is a result of the success of Sword #1 well with an approximate recoverable reserves of 898,000 barrels and PV-10 value of $63 million. RU-2A with a recoverable reserves of 1.5 million barrel and a PV-10 value of 78 million and RU-1 with a recoverable reserves of 1 million barrel and a PV-10 value of 52 million as well as RU-5A with a recoverable reserves of 516,000 barrels and a PV-10 value of 25 million.

With respect to new production, we brought online our second sidetrack RU-1A on August 17. It’s another sidetrack on the Osprey platform that is currently producing at approximately 650 barrels of oil per day with an average water cut of 5%. We brought this well online. It’s under budget and expect to receive approximately 40% of our comps back from the Alaska’s tax credit program.

In our economic evaluation, we assumed an IP of 400 barrels oil per day, recovering approximately 600,000 barrels of oil with a PV-10 value of over $30 million. The well actually came in online considerably higher now with post contract production history. The recent reserve report shows recoverable reserves of 1 million barrel and a PV-10 value of $52 million.

After completing RU-1, we moved Rig 35 over to sidetrack RU-5 oil well. RU-5, a sidetrack which is similar to RU-1A and RU-2A as we are using a similar approving process. The sidetrack consisted of abandoning of the lower part of the old wellbore setting a setting a whip-stock, milling a window through the casing and drilling into an approximate final measured debt of 15,750 feet.

While drilling the well, well showed oil throughout the entire Hemlock and we showed we were meeting our objective by gaining structural superiority to that of the original well. The project came in about 90% of budget, it’s been an approximately $9.2 million growth out of $10.3 million approved and the well has produced an average of 230 barrels oil per day for the month of November.

Production came in a little lower than expected, but the project is very well economical at present rate with recoverable reserves of 516,000 barrels and a PV-10 value of $25 million. However, we do plan to increase crude oil production rate through minor, immediate work on the well during the next E&P replacement.

We also completed a cleanout on RU-D1, our injection well which was needed prior to drilling RU-9 as there will be a lot of cuttings to dispose off. RU-9 is a new branch root well with a bottom hole location in the southern most part of the read out structure.

We are preparing to split RU-9 by reconfiguring Rig 35 with the addition of a high-torque top driver to assist in the drilling anticipated extended reach well and a few other improvement. We expect to spud between the next 30 days. RU-9 is an exciting well that is designed to drill and to improve out in the South Step Out structure. Their proposed well intended to capture oil reserves from a large hallway structure located approximately 2.5 miles southwest in the Osprey Platform.

Our primary objective for the well at the Hemlock formation which is the primary producing formation in the readout showing field. The South Step Out fault block structure accomplishes approximately 679 acres up to previously seen lowest known oil from the structure. Recent third-party reserve report shows approximately recoverable reserves of 966,000 barrels and a PV-10 value of $47 million factoring in the receipt of the Alaska tax rebate.

We assumed an IP of 750 barrels of oil per day and expect this further in January, as well as expect drilling to take about 90 days. The South Step Out structure which is saddle separated from the current producing fault block and with the expected approval of a lot more reserves upon the success of RU-9.

The other significant point related to read out, step out structure, there were two wells drilled into the structure in the 60’s. One was reported a flow test and redeemed final stage of Alaska as they are well capable of commercial bank quantity, the other was held confidential.

We are also pursuing onshore targets in late November. We’re brining online our Sword #1 well with an initial production rate of 833 barrels of oil equipment per day. This well is an extended reach well ads well as directional grow from an onshore location at the West McArthur River production facility pad to an off shore location approximately 17,500 feet measured depth.

The bottom allocation is in adjustment to wall black to the West MacArthur river unit. During drilling we encountered the expected productive zones, Hemlock oil sands, the Tyonek-G oil sands, and the Tyonek gas sands. We are currently producing the well from the Hemlock oil sands.

We have designed the completion to allow testing and production through multiple additional oil and gas zones. We are in the process of submitting a comingling application to the Alaska Oil and Gas Conservation Commission to allow for Hemlokc and Tyonek-G formations to be produced at the same time. Once we have the approvals in place we will start to test Tyonek-G zone. This is expected to take over the next 60 days.

One thing I want to point out is the third well that’s the stage for our Sabre prospect, which is immediately to the north. Sabre is a fault separated to the north and design and engineering for our first well is already underway.

Moving on to West McArthur River Unit, there’s no real change in production, which continues to be constant with a minimum decline with a current daily production of approximately 600 barrels of oil per day. We’ve already split our new WMRU well, which is WMRU-8 and have drilled to an approximately 3,500 feet well casing and is diminutive in place. WMRU-8 planned final depth of 17,000 feet measured depth. WMRU-8 is one of three identified in-field development wells in the West McArthur River field. We believe West McArthur River has a lot left in it, especially considering the fault separated opportunities to the north, Sword and Sabre.

WMRU-8 primary objective is the Hemlock formation and secondary is the test of a drastic formation. However, we will be evaluating the Tyonek horizon as we drill through

them. The proposed well is intended to provide a cake point on the Hemlock reservoir previously seen, but not tested in the WMRU-7 original well. Recent third-party reserve report showed approximately recoverable reserves of 795,000 barrels and a PV-10 value of $32 million, factoring in the receipt of Alaska tax rebate. The AFE is for $18 million and assumes an IP of 750 barrels of oil per day.

We’re also continuing to pursue our Otter and Olson Creek gas prospect. As you know, we’ve suspended drilling on our Olson Creek #1 well due to conditional approval of the Otter unit where we needed to finish drilling Otter #1 to a permanent depth of 7,000 feet by specific time. This deadline required us to move Rig-34 over to the Otter prospect.

Just within the last few days we have drilled the wells on approximately 7,000 feet and are preparing to lock the well followed by running completion. Upon finishing Otter well #1 we plan to demobilize Rig-34 from the west side of the creek over to the east side in preparation to spud total Creek well #1 and February timeframe depending on temperature due to the ice trail needed to access the drill site.

Silver creek prospect located in the Susitna Basin, covers 3,100 acres and is expected to encounter natural gas and is estimated to hold 60 Bcf of gas. We also plan to mobilize a rig back Olson Creek and Otter in summer of 2014 to resume drilling there.

Now onto Tennessee operation, we continue to prove the horizontal well concept and our third horizontal well, the Brimstone H-1 has been brought online and it’s been producing approximately 35 barrels of oil per day. The well came online on October 15 and has produced a total of approximately 1,500 barrels of oil through the end of November. This is a natural well that is fully on its own, did not require any stimulation.

We also have received a gas reinjection permit from the EPA that we intend to use to maintain the reservoir pressure in our first horizontal well, the CPP-H-1 well. We are continuing to work on both that well and the Maynard H-1 well and we’re looking to drill another horizontal well, a Cromwell H-1 well in the near future. In addition, to work on the horizontal well concept we continue to work on small recompletions in Tennessee and we’re also looking to increase our gas sales there.

Finally, I’d like to take a few minutes to provide some more detail on two major prospects we’re working on. One is the North Fork Unit acquisition and the second will be the Trans-Foreland Pipeline.

Starting with North Fork, I’ll provide a summary of the field location, which is located in the Cook Inlet on the Kenai Peninsula, east of Anchor Point, which is an onshore operation. The assets include six natural gas wells, 15,465 acres of fee simple property, one drill site, pad and production pad, gas processing equipment, highly automated production equipment, requirement in staffing with estimated recoverable reserves that range from approximately 20 to 120 Bcf accounting proved, probable and possible.

Also included is Anchor Point Energy, LLC, which holds two four-inch nine-mile Fiberspar composite transmission pipelines from North Fork Unit to interconnect the in-store gas company transmission pipeline weighted at 22 million cubic per day capacity. The pipelines are regulated by RCA [indiscernible] and it was put in service in April of 2011.

Out of the total of six wells drilled four are currently online and producing. 2013 daily production peak at 13 million cubic feet per day and we’ve identified 24 additional possible well location and so we developed the deal. First production commenced in April 1, 2011 and there is a multi-year firm gap contract with Mstar, which is about 4.8 Bcf remaining commitment with a gas price of $7 an Mcf.

We see the North Fork gas field as a good bit. We’re already on assets in production. This acquisition provides production and assets on the east side of the Cook Inlet. Once we have officially closed the acquisition, we plan to immediately takeover operation and continue producing gas as well as increase production through remedial well work and through drilling of new wells. With an approximately 24 wells needed to fully develop the field we think this provides a strong start to becoming a significant gas producer in the Cook Inlet.

Lastly, I’ll close with a summary on the status of the Trans-Foreland Pipeline. Many know we were the pioneers of the concept of linking the west side to the east side with a steel pipeline and tying directly into the local refinery operated by Tesoro, effectively eliminating the need to move oil on tankers across the Cook Inlet, reducing the transportation expenses and environmental risk. To-date we have completed 70% of the design and engineering and are in the final engineering stages.

Tesoro pipeline group has funded the activities today and as we are in negotiations with Tesoro now the funding, the construction and the operations and the pipeline details cannot be fully disclosed, but presumably the pipeline will have a very positive effect on us as a company. We have been aggressively pursuing the construction of a subsidy pipeline directly connecting us to the east side in 2010. Currently all west side crude oil must be moved by tanker from a tank farm located at the base of an active volcano.

This new pipeline would be a major achievement and would lower the transportation expenses and eliminate the risk of business interruptions due to the ice condition or volcanic activity. After completing a feasibility study in 2011, we entered into an agreement with Tesoro where Tesoro would agreed to fund all the development work for the line plus pay project management fees in exchange for an option to build the pipeline.

Over the last two years all companies have worked together to advance the permitting and engineering of the project. Tesoro has indicated they intent to exercise their option and we believe that a final agreement will be reached with Tesoro by the end of the year. As contemplated in our agreement, the agreement contemplates a sale of CIE’s eight-mile Saskatoon pipeline to be incorporated under the new Trans-Foreland Pipeline system. The net result of the deal would be that we would be paid millions in order to lower our operating cost and increase our security of our operation. The return on the investment is basically infinite and I wish I could do this deal every quarter.

Scott, I’m now turning the call back over to you.

Scott M. Boruff

David, thank you and your team for the excellent work both in Alaska and Tennessee. We plan to continue to provide investors with regular updates regarding our operations, financings and the acquisition as news develops. We continue to be excited about their current production and our drilling plans going forward. We believe that the North Fork transaction is a strategic acquisition. It provides great cash flow, well-bore diversification and a huge development inventory and we look forward to seeing better financing options as well as great operational results from that property.

Before we open up the calls for questions, as usual we have to remind you we cannot comment on pending litigation. That concludes the formal remarks of today’s call. Operator, we would like to open up the call for questions.

Question-and-Answer Session

Operator

Thank you, sir. Ladies and gentlemen we will now take questions from Miller Energy Resources equity [indiscernible]. (Operator Instructions) Our first question comes from the line of Neal Dingmann with SunTrust. Please go ahead.

Unidentified Analyst

Hi, guys, good call. This is Will for Neal. Just quick question on – since you’ve added the new – with the Armstrong acquisition that’s developed 1100 BOE a day, mostly gas. What is your – if it takes you through about seven by the end of the fiscal year? What is the 7,000 BOE a day look like with your well program. If you can kind of walk through a composition of the wealthy or have coming on line, so we can kind of get a better idea for simple oil within that mix?

David M. Hall

Sure. Will, it’s Dave. I’ll take the questions. As you know we are at the 4000 BOE per day right now. Our gas component to that are the RU-3and RU-4 gas wells as well as our West Foreland 2 gas well which comprise little less than 600 BOE per day. The Armstrong acquisition adds 1,100 BOE per day which is all gas.

And then our drilling program between now and the end of our fiscal year, we’re going to have West McArthur River # 8 well which we are drilling currently. We as David mentioned approximately 3000 feet into that well and have an expected time frame on it which would put us towards the end of January if we don’t have any delays in drilling. And that is primarily targeting the oil sands of the Hemlock in our reserve report. Yes, we have that expected to IP in the 750 barrel a day range.

But like the Sword #1 well we will also have targets in the Tyonek and as David mentioned, we are planning to take that well down into the Jurassic as well which is a well bed bearing source rock for the Hemlock. After that well is complete, we’d expect to drill the West McArthur River 9 well, which was largely the same set of targets, so mostly oil. And again about 750 barrel oil per day IP in production rate.

On platform we still have a few weeks to go before we begin drilling the South Step Out which we refer to as the readout # 9 well. And that’s again primarily targeting the Hemlock sands and has a expected IP rate of 750 barrels a day. So if you take where we are and add those three wells which we would expect to complete before the end of our fiscal year, you mainly be adding oil production from those wells but there is the potential for some additional gas.

With respect to the gas activities while we are finishing up our Otter #1 well, we wouldn’t be bringing that on to production, we’re just going to test it. Spread wouldn’t be adding to current production and the same thing is true with our Susitna project at [indiscernible] Creek. We just be drilling and testing.

With the Armstrong acquisition though we do have a field, which we can drill and produce immediately and we’d expect to do some work in the Armstrong field before our fiscal year-end and we’d expect that to immediately add to production. And we think that there is the ability to potentially increase production by about 600 to 1,000 BOE per day of gas. And that would be the makeup of our additional production before fiscal year-end if we’re successful on those projects.

Unidentified Analyst

Okay, thanks guys. It’s great that Armstrong deal looks like a great deal.

David M. Hall

Yes, we’re very excited, we were kind of fortunate in terms of our timing and it’s a nice field and the sellers has better opportunities for their capital up on the North Slope, so it was a good deal for all parties.

Unidentified Analyst

That’s great, all right. Thanks guys.

David M. Hall

You bet.

Operator

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

Kim M. Pacanovsky – Imperial Capital LLC

Hi, guys, how are you?

Scott M. Boruff

Hi, Kim.

Kim M. Pacanovsky – Imperial Capital LLC

Hi, okay. I have a couple more questions on North Fork. First of all, in the release that was on the initial release for the acquisition, is it sort of the PV-10 was $95 million, and then in the release that you put out today with the 12-1 reserves, it’s $68 million?

Scott M. Boruff

It’s correct. The release we put out initially, Ryder Scott to the full 12 and 3P reserve reports for us on the acquisition.

Kim M. Pacanovsky – Imperial Capital LLC

Okay.

Scott M. Boruff

And the release we put out today was really just the byproducts of the fact that we’re working on our financing. And so as we’ve been working on our financing, quite frankly, we’ve been pushing very hard to get a Ryder Scott reserve report in our PDPs primarily.

Kim M. Pacanovsky – Imperial Capital LLC

Okay.

Scott M. Boruff

Because we want to do a bank financing, and that’s what the banks focus on.

Kim M. Pacanovsky – Imperial Capital LLC

Right.

Scott M. Boruff

And so with the addition of the Armstrong assets what we believe is that we’re now an RBL candidate, because we have 15 producing wells and that could get with good well for diversification, and certainly extends for us to push very hard to get a Ryder Scott number to what the banks were focused on. And so in the release today, we just put out what our proved develops was.

Kim M. Pacanovsky – Imperial Capital LLC

Okay.

Scott M. Boruff

And do a full blown 1, 2 and 3P report on our own assets, it’s something that we could see that doing before the end of our fiscal year.

Kim M. Pacanovsky – Imperial Capital LLC

Okay. So…

Scott M. Boruff

Financial activities today, that’s what we needed in order to move into that lending market.

Kim M. Pacanovsky – Imperial Capital LLC

Okay, great. And then David Hall has mentioned some PUD reserves of some upcoming wells based on third-party engineering and so those numbers would be roughly data. So is that correct?

David M. Hall

Yes.

Kim M. Pacanovsky – Imperial Capital LLC

Can you provide us with that numbers?

David M. Hall

I mean for the most part, we’re using ramping data as our reserves that we put out at the end of our last fiscal year and so you can look back at our 430 report and I think we have historically included what those are by well.

Kim M. Pacanovsky – Imperial Capital LLC

Okay, terrific. And then now in your drilling plan, between now and the end of the fiscal year on the North Fork, how many wells will be drilled for that 600 barrel a day to 1000 barrel a day of incremental gas target and what is the CapEx that is dedicated to North Fork between now and the end of the fiscal year?

David M. Hall

Before the end of the fiscal year we’re going to make a decision whether or not to deploy a rig to drill and work over the existing wells. We actually think that we can increase production on these wells to that level with minimal CapEx, if any at all.

Kim M. Pacanovsky – Imperial Capital LLC

So that incremental, 600 BOE to 1,000 BOE a day is work over if it’s not any new drilling?

David M. Hall

It’s simply turning the wells up.

Kim M. Pacanovsky – Imperial Capital LLC

Okay.

Scott M. Boruff

Just getting more production out of the existing well to be very clear. We’ll have the ability, but as soon as we procure a rig to start working on that infield drilling program that David Hall had talked about. And I’ll let David talk about that program. David, do you want to mention what our plans are? And let’s do it and we’re going to switch on here from fiscal year to calendar year, but David why don’t you just walk her through what our plans are for calendar year 2014 for the Armstrong field.

David M. Hall

Well, certainly. I have alluded to already. Out of the six different gas wells there’s only four that’s online now. So there is one that can be placed online quite simply as David mentioned, simply starting it up and putting it online. The last well actually needs some remedial work, either sidetracking or re-drilling the well. So that one would require drill rig.

Kim M. Pacanovsky – Imperial Capital LLC

Okay.

David M. Hall

There is some other behind pipe gas and some of the existing producers that we would intend to try and access at some point in the very near future, which would require pulling the tubing and adding additional preparation in the existing wells.

Kim M. Pacanovsky – Imperial Capital LLC

Okay. All right. And then, David on RU-9, you guys finished the injection well quite a while ago. What is responsible for the long time period between Rig 35 finishing up that well and commencing RU-9?

David M. Hall

That’s a good question. There was a fair amount of work related to moving the rig from one leg to the other.

Kim M. Pacanovsky – Imperial Capital LLC

That’s right and having those legs. Okay.

David M. Hall

In addition to that we actually needed to move things around on the deck of the platform, for example the pipe rack and some other significant pieces of equipment. We’ve also took the opportunity to put a more high torque top drive on the drill rig itself to use the rig better for these long extended reach directional wells.

Kim M. Pacanovsky – Imperial Capital LLC

Okay. All right. And then, David Voyticky, can you give us a ballpark of what size of a credit line is in the ballpark for you with the reserve report that you’ve just announced today?

David Voyticky

Sure. We’re right now in the middle of that process. As you know, we have excellent relationships with both the folks at Guggenheim and we’re thrilled that John Brawley has joined us and we haven’t enjoyed sitting on the other side of the table for him. But with the amount of folks we would hope to be in a position where we can go lower interest rate and more capital combined with the traditional RVL lender or to explore the sub-debt market in general over the next two months.

And as you can see from our total proven developed reserves, we are in that $360 million range and we’d expect that whatever size we get, it’s going to be a combination of those two things. We expect that it’s going to be lower cost financing from an RVL lender and something that’s a little bit higher from the sub-debt market. But we feel very confident that it’s going to be enough in size to give us enough capital to complete the Armstrong acquisition, which would be in the $60 million range and to have enough availability to not only complete our entire CapEx program for the calendar year of 2014, but to give us additional capital to consider similar size acquisitions like Armstrong.

Kim M. Pacanovsky – Imperial Capital LLC

Okay. And Apollo has first right of refusal, is that correct?

Scott M. Boruff

That’s correct.

Kim M. Pacanovsky – Imperial Capital LLC

On any capital arrays?

Scott M. Boruff

That’s correct.

Kim M. Pacanovsky – Imperial Capital LLC

And they would presumably, if you had a certain cost of capital with another lender or to offering debt, they would have to match that rate, is that correct?

Scott M. Boruff

That’s right. They want to see and then have to match that rate.

Kim M. Pacanovsky – Imperial Capital LLC

Okay.

Scott M. Boruff

And our routine here has been bankers at certain point and on the private equity side and we very much valued the relationship that we’ve had with Apollo, they’re a very good partner for us as was Guggenheim. So we think that that’s a key part of our strategy going forward, but at the end of the day, we are focused on lowering our cost of capital.

Kim M. Pacanovsky – Imperial Capital LLC

Yes, okay, great, all right.

Scott M. Boruff

This is a big moment for us. I don’t think we’d have normally put out the reserve updates, but I think in combination with the lending process that we are going through right now and really is a reflection of the significant value that’s been created and we want to share the information with our investors. And we’re highly confident that we’re going to be able to complete that financing transaction in the timeframe that we are talking about.

Kim M. Pacanovsky – Imperial Capital LLC

Okay, great. Well, I will let somebody else ask some questions. Thanks a lot guys and congratulations.

Scott M. Boruff

Thanks Kim.

David Voyticky

Thanks Kim.

Operator

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

Chad L. Mabry – MLV & Co. LLC

Hi, Scott, good afternoon.

Scott M. Boruff

Hey Chad.

Chad L. Mabry – MLV & Co. LLC

Just a few follow-up there on the North Fork acquisition, just curious there what your NRI are and then if you could provide any PUD reserves that you had in the initial booking to correspond with that PV-10 in the initial release?

Scott M. Boruff

Chad, will you repeat the first part of your question.

Chad L. Mabry – MLV & Co. LLC

Yes, your net revenue interest, I was just curious. I am assuming that 10 million a day is a gross number, just curious what that NRI is?

Scott M. Boruff

It’s slightly over 80%. So David, correct me if I am wrong, but I think it’s 80.6%, is that right?

David Voyticky

Yes, it’s approximately 80%.

Scott M. Boruff

So that’s our NRI and the way to look at the North Fork reserves is, if you go back to the first press release, as the date change, but the PUD reserves wouldn’t change at all from the press release we put out. The deals that we reached with the folks at Armstrong was in exchange for moving quickly. We reached the deal that we did and so they will get the key, the production and the revenue from the production until we fund the acquisition and so that’s that 7 million a day that’s been produced and we expect to fund it soon.

So the PDPs will go down. For each day it takes us to close the acquisition, with PUD’s we’ll not change from the previous release. So the total PUDs that are being put would add up to slightly over 90 million with the 67 million that we announced today.

Chad L. Mabry – MLV & Co. LLC

Okay. Got it, that’s helpful. And then maybe a follow-up for David Hall. Just curious on the production, I’m assuming that’s a sales number, was there any variance there versus your production for the quarter, and I guess to ask it in other way were there any differences due to listings on the barge in the quarter?

David M. Hall

Yes, our quarter production was sent to Drift River facility then loaded on to a ship to the total refinery, but our ship have been loading – the ships have been moving around just a little bit depending on the condition in the Cook Inlet primarily due to the weather. And that’s why the production volumes don’t quite match the volume sold.

Chad L. Mabry – MLV & Co. LLC

That’s helpful. Thank you. That’s all from me.

Scott M. Boruff

Thanks, Chad.

Operator

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

Evan C. Richert – Sidoti & Co. LLC

Thanks. Could you start off just talking about Sabre. Is there anything, I guess from Sword that would make you think Sabre wouldn’t be just that strong, if not stronger.

Scott M. Boruff

David, do you want to take that question?

David M. Hall

Sure. I mean Sabre is another exciting prospect, just like Sword, that is just immediately fall separated to the north of Sword. And it’s another structure that’s had a well that was actually drilled into that structure back in mid-60, 64 and 65. They had drilled and tested a well that actually had a successful DST drill stem test on the well. Through that we entertain those results and the various logs, mud logs, need logs. In addition to that we have 3-D seismic over the prospect. So we feel our risk has been greatly reduced.

Evan C. Richert – Sidoti & Co. LLC

Okay. Great.

Scott M. Boruff

From that standpoint you’ve got productive. Now Sword field south of that is the West McArthur River deal that’s productive immediately to the east of the Hill Corp operated asset that’s very productive as well.

Evan C. Richert – Sidoti & Co. LLC

Okay. Great. And can you kind of get your thoughts on the Tyonek sand for Sword #1, any expectations there?

Scott M. Boruff

I will say that the launch was extremely well, the mud logs, need logs over the Tyonek-G zone and we just decided to test that. And as I’ve mentioned earlier, we’re in the process of trying to entertain a co-mingling approval from the AOGCC in Alaska. Once we have that then we’ll pave the new proliferations in that zone and conduct a well test.

Evan C. Richert – Sidoti & Co. LLC

Okay, great. And maybe think for Dave Voyticky. Can you just talk about your thoughts on bringing on another rig, you just kind of want to get the financing done out of the way first or how often would you like to attack on another rig, is that just daily production rate have a certain target, what are your thoughts on that?

David Voyticky

Yes, it’s really a combination of things. First of all the team that we’ve built and David has built up in Alaska and Tennessee, as they’ve been really growing and adding just very qualified people to handle the increased amount of activity and we certainly wouldn’t increase our drilling activity beyond the capabilities of our current staff and we’re very proud of the folks that we have working. But we do feel that we can add some additional rigs.

We have our Board approved budget of almost $300 million of projects and acquisition over the first six months of this year and we have the projects that we’re not going to complete this year like Sabre that were in that budget and those were some big $30 million wells as a reason that we did not drill Sabre because we couldn’t find a rig that we found would be suitable in time to be in addition before the ice moved into the Cook Inlet.

So that won’t be drilled in our 2014 budget, but we felt that we have the capability to handle it. With the Armstrong acquisition, we certainly feel that we have the ability to drill four wells a year and the team in place to do it.

So there are a number of things that could affect our CapEx, but we’re certainly not going to go beyond our capabilities as the expected increase and available capital is really into the business, is usual for us because we have not changed our development plan because of lack of capital. We’ve always found the capital that we needed and we still feel confident we’re going to do it.

So for next year we expect to have Rig 35. So next five years, Rig 35 drilling into the Redoubt Shoals structure that’s just been moved to this new leg. So there is seven wells that can be drilled from where it currently sits and we’ll expect to do that over the next two years.

Rig 34, as mentioned, is going up to Susitna and we’ll keep that rig busy this winter. And we’re looking for two new rigs. We’re looking for rigs to drill into the North Fork Field, are looking for rig to drill the Sabre prospect. The Patterson 191-Rig will continue to drill into the West McArthur River Unit and the West Foreland Field for as long as we can hold on to that rig.

Evan C. Richert – Sidoti & Co. LLC

Okay, great. And then just on the cost side, how much do you expect LOE and D&A, I guess when North Fork closes, how much of an increase should we expect?

Scott M. Boruff

It’s really going to be quite marginal. The operation of the North Fork deal, and David will speak to this more, is handled by one person and all the infrastructure is in place to produce that field up to 13 million, 14 million cubic feet a day. So aside from drilling new wells, it’s not going to add much to our G&A or lease operating expense. David, is that correct?

David Voyticky

That’s correct. I mean operating cost is very well refined and very efficient on that field, but we would expect to see that continue.

Evan C. Richert – Sidoti & Co. LLC

Okay, great. That’s it from me. Thanks a lot.

Operator

Thank you. Our next question comes from the line of Ray Deacon with Brean Capital. Please go ahead. I think your line is open.

Raymond J. Deacon – Brean Capital, LLC

Yes. Hey, David. Sorry, I was on mute. Just wondering if you could just talk a little bit about North Fork in terms of average target there in terms of reserves and cost per well and maybe a little bit of color around the 20 to 120 days of 3P reserves you see there. Is it one large exploration target or kind of what are the sizes of that?

Scott M. Boruff

That’s a good question. I’m going to have David Hall answer, but we’ll expect to go into more detail on the field when we do our next presentation where I’ll look at more details, but David, why don’t you go ahead and give us much color as you can?

David M. Hall

Be glad to, yes. As previously mentioned, we identified up to 24 possible new well locations. That’s why we developed the deal. Those additional new wells are expected to cost anywhere from $7 million to $8.5 million growth CapEx. We would also assume that we would be eligible to get Alaska tax credit rebate from those wells as well.

Raymond J. Deacon – Brean Capital, LLC

Got it.

David M. Hall

As far as EUR, the EURs, the typical expectations for gas recoverable per well range dependent on where you’re at on the structure, but they range anywhere from 2 Bcf to 5 Bcf per wellbore.

Raymond J. Deacon – Brean Capital, LLC

Okay, got it. Okay, great. Okay. And then, I just had one quick one on Sword. It seem like the IP rate, it’s a little less than what you’re expecting. I’m just wondering how reserves looked relative to your expectations and what maybe accounted for that variance?

Scott M. Boruff

I think we expected 750 on Sword.

Raymond J. Deacon – Brean Capital, LLC

Okay.

Scott M. Boruff

So the IP has been slightly higher than what we were expecting for reserve report and that does not include any increases in production that we may get from the G-0 sand. We’re not going to be able to produce the oil and the gas at the same time, but we’ll also test the gas sample as well. So I think, David can speak to it better, but I think we are pleased with the results of the Sword well.

Raymond J. Deacon – Brean Capital, LLC

Okay, got it. Okay. Thank you.

Scott M. Boruff

The other thing that I’ve mentioned as you’re asking about North Fork is, we are intending to pay for this through our new debt financing. So that’s been a question we’ve been asked before. And if you look at our press release today, it should be fairly clearly laid out what our increase in our proved developed reserves has resulted organic activity versus the North Fork acquisition as we went from about $32 million of proved developed reserves in April of 2013 and without Armstrong we increased that to about $297 million just through drilling activities. It’s been a good six months for us.

Raymond J. Deacon – Brean Capital, LLC

That’s right. Appreciate it.

Scott M. Boruff

You’re welcome.

Operator

Thank you. We have a follow-up question from the line of Kim Pacanovsky with Imperial Capital. Please go ahead.

Kim M. Pacanovsky – Imperial Capital LLC

Thanks. Boy, I’m cracking up here. With your asset, you mentioned that your asset in Susitna, if that is successful what are the implications for the broader area?

David M. Hall

Well, we’ve identified other opportunities when we could drill and test into the Triassic, not only from the West McArthur River and Sword area, but also from readout structure. So this is a good proving ground to try it out and see. I mean, as you know there’s many or several operators now that are pursuing, trying to drill and test the Triassic with the jack-up rig.

Kim M. Pacanovsky – Imperial Capital LLC

Okay. And David, WMRU-9, was that in this fiscal year’s plan?

David M. Hall

Yes, our expectation is that we’ll try to drill that well immediately after finishing the West McArthur River-8 well.

Kim M. Pacanovsky – Imperial Capital LLC

Okay.

David M. Hall

So it’s depending on, if everything goes according to schedule the answer is yes.

Kim M. Pacanovsky – Imperial Capital LLC

Okay, great. That’s all I had. Thanks.

David M. Hall

You’re welcome.

Operator

Thank you. And I would like to turn the conference back over to management for closing remarks. Please go ahead.

Scott M. Boruff

Yes. Thank you for joining us this afternoon to provide you with an update on Miller Energy’s recent accomplishments, future plans and financial results. We are very excited about the future of Miller and the potential of our properties. We plan to keep you up-to-date on our operations on future calls and look forward to you joining us. Thank you and have happy holidays.

Operator

Ladies and gentlemen, this does conclude our conference for today. Thank you for your participation. You my now disconnect.

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