Miller Energy Resources' CEO Discusses F1Q13 Results - Earnings Call Transcript

Sep.21.12 | About: Miller Energy (MILL)

Miller Energy Resources, Inc. (NYSE:MILL)

F1Q13 Earnings Call

September 20, 2012 4:30 p.m. EDT

Executives

Scott Boruff – President and CEO

David Hall – CEO of Cook Inlet Energy

David Voyticky – President and Acting CFO

Analysts

Neal Dingmann – SunTrust

Jonathon Fite – KMF Investments

Tim Griffith – Rockwood Investment Partners

Jason Harris – Kendall Square Capital

Operator

Good afternoon and welcome to the Miller Energy Resources fiscal 2013 first quarter conference call. This call is being recorded.

At this time, all participants have been placed on listen-only mode. A question-and-answer session will follow the presentation by the company's CEO Scott Boruff.

Before we begin, I would like to call your attention to the customary Safe Harbor Disclosure in the company's press release regarding forward-looking information. Today's conference call and webcast may include forward-looking statements. Forward-looking 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, Miller Energy'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.

Additional information on these and other factors which could affect Miller's operations or financial results are included in Miller Energy Resources' reports on file with United States Securities and Exchange Commission, including its most recent filings of its annual report on Form 10-K as amended. To obtain copies of Miller Energy's SEC filings, please visit their website at www.millerenergyresources.com. Miller Energy Resources' actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors including those discussed in the periodic reports that are filed with the Securities and Exchange Commission.

All forward-looking statements attributable to Miller Energy Resources or to persons acting on its behalf are expressly qualified in their entirety by these factors. Investors should not place undue reliance on these forward-looking statements which speak only as of the date of this conference call. Miller Energy assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change, unless otherwise required under securities law. Miller Energy is not responsible for changes made to this call by the conference call company or internet services.

At this time, it is my pleasure to turn the call over to Miller Energy's CEO, Scott Boruff. Please go ahead, sir.

Scott Boruff

Thank you. Thank you today for joining us this afternoon to review the results of our first quarter ended July 31, 2012. I am very excited about the progress Miller has made since our last conference call.

To begin, I want to provide a brief overview of our accomplishments during the first quarter. Following my overview, David Hall, CEO of our Alaska subsidiary, Cook Inlet Energy, will present an update on our Alaska operations, and David Voyticky, our President and Acting CFO, will provide additional detail on our financial results. Upon completion of the management presentations, we'll be accepting questions.

Before I review our accomplishments during the first quarter, I want to highlight the S3 filing that we made early in September. This filing was a very significant event in Miller in several key areas. First, it highlights our having cured any remaining deficiencies in our other public filings and signals that we are again eligible to register our securities for sale to the public. Second, access to the public markets will allow us greater flexibility in financing Miller's operations and potentially do so at a lower cost of raising capital. Finally, being eligible to use the S3 demonstrates the improvements that we achieved in our financial reporting. We worked closely with our auditors at KPMG to achieve these improved results. We're pleased that we received the clean opinion from KPMG regarding our audited financials for the past two years.

We also recently hired Catherine Rector as our Chief Accounting Officer. She's a certified public accountant and brings years of high-level experience to Miller. She has increased depth to our accounting and financial reporting [inaudible] process. We work closely with our audit committee in KPMG in making determination to her a Chief Accounting Officer, and we are thrilled to add professional of Catherine's caliber to the Miller team.

Now I want to turn your attention to the first quarter's financial and operating highlights. We continue to gained traction on a number of fronts in the first quarter that will be the key to accelerating our development and drilling programs in Alaska. First, we closed on a new credit facility that provided the funding to pay off the previous credit facility, redeem the preferred stock we issued in the last quarter of 2012, and provide additional funding for us to pursue our drilling programs in 2013.

Second, we completed the installation of Rig 35 on the Osprey platform during the first quarter and the Alaska Oil and Gas Compensation Commission granted approval to start our first rework project in August. As we previously announced, we immediately deployed Rig 35 to start reworking RU-1. Purchasing Rig 35 was a central part of executing our strategy to transform our operations to more production-driven company. Our ownership of Rig 35 frees us from being dependent on the availability of someone else's rigs. We will be able to focus our development and drilling of our assets in Redoubt Shoal field, our single largest reserve base, on our own schedule. In addition, it is part of our strategy to become more vertically integrated in our own development program. David Hall will provide an update on our progress, not only on RU-1 but subsequent plans for keeping Rig 35 very busy in the coming year.

In addition to Rig 35, we also deployed Rig 34 this first quarter. It was initially tasked to rework KF-1 in the Kustatan field and then moving on to drilling Otter-1, an exciting exploration gas play just a few miles north, west of the prolific well-known Beluga gas field that had produced over Tcf of gas. With all the modifications and improvements to Rig 34, we were able to drill a 5,680-foot well. The mud logs reported two significant hydrocarbon gas shelves in the zone of interest. We're very hopeful Otter Well No.1 will prove to be a great success as our Alaska team completes a comprehensive analysis of the field and conducts a hydraulic fracture that David Hall will report on later in the call. Rig 34 will be very instrumental in fulfilling our Alaska onshore drilling program, including exploration prospects on our Otter and Olsen Creek leases and others.

David Voyticky and I had mentioned in previous calls how Miller continues to monetize the midstream assets we purchased in Alaska. We believe these assets will have significant value as we utilize both as we grow our Alaskan operations in the near term by renting, selling our excess capacity to other operations in the region. In our first quarter, we sold an electrical generator from our Kustatan production facility for $2 million with the mindset of increasing our power generation ability to better serve the believed growing demand. We believe there are additional opportunities to leverage these significant midstream assets as we go forward.

Earlier this month we announced that we acquired the Tennessee assets of PDC Energy, Inc. This acquisition increases Miller's working interest in oil and gas wells in the Appalachian basin of East Tennessee. This acquisition increases our current production in Tennessee by about 10%.

Three years ago when we reported one of our growth trajectories with focus on developing new oil and gas opportunities in the oil-bearing Mississippi lime in the prolific Kennedy shale formations, in 2009 we had interest in 20 producing oil wells and 32 producing gas wells. Over the years we've grown our base of business through acquisitions like the recently announced purchase of the assets of PDC, and now Tennessee includes having over 180 producing oil wells and over 180 producing gas wells.

In the coming months, we plan to begin a program of aggressively reworking many of these wells to increase our Tennessee production. This effort will be led by David Wright who was recently promoted to Executive Vice President of our Tennessee operations. In fiscal 2013, David and his team have planned an aggressive rework program and horizontal drilling program in the Mississippi lime, which will be more valuable to us now that we have greater interest in those wells. We expect to increase our daily production about reworks and recovering old oil left in place with our horizontal well program.

I'm very pleased with the progress as we continue to make -- across the country. I'm also very excited about the potential of increasing our production in fiscal 2013 as we benefit from the deployment of Rig 34 for onshore drilling and Rig 35 for offshore drilling.

With that overview, I want to turn the call over to David Hall to provide you more detail on our operations and production plans in Alaska. David?

David Hall

Thank you, Scott. Well, I will start with an update on Rig 34.

As many already know, Rig 34 recently drilled our exploration gas well, Otter Well No. 1 to a depth of a little lower 5,600 feet, with two significant hydrocarbon [shelves] indicating the presence of natural gas. Since then we conducted a series of tasks to further evaluate the Otter structure. Those tasks include the following: petrophysical, geochemical, lithology, porosity, water saturation, permeability, density, and sensitivities, just to mention a few. Through those comprehensive efforts and further understanding of the Otter structure, we felt it was necessary to move forward with the design and implementation of the hydraulic fracture.

Current status on Otter Well No. 1 is we will be mobilizing the hydraulic fracture equipment two sides over the next two weeks and hope to commence with the frac shortly thereafter. Following the hydraulic frac, we plan to conduct a flow test which may require a coil cleanout as a result of the hydraulic fracture. We would expect to know the results over the next three to four weeks. We're very optimistic about the Otter prospect.

Moving on KF-1 well post rework, an attempt to stimulate the gas production was devised to de-water the well by way of hydraulic lift. We commissioned this de-watering effort nearly two weeks ago and are now seeing small amount of continuous gas production. We plan to continue this process for a sufficient amount of time to see if the gas production will increase. If not, then we'll activate the disposal well option which will complement our existing disposal wells by providing redundancy as well as could provide support for our ongoing grind-and-inject operations.

Moving on to Rig 35 and RU-1, Rig 35 is currently reworking RU-1 crude oil well. We have been utilizing the brute strength of Rig 35 to remove the old LDFPs and associated down-haul components, commonly known as [fish], something the previous owners were unsuccessful at. We have removed well over 50% of the fish and are very hopeful we'll get it all out. We strongly believe that the fish create a treacherous flow path for production fluids restricting flow rate. We would expect to see significant improvements in flow rate compared to when RU-1 last produced 270 barrels of oil per day, even if we were to stop fishing today and run completion.

In conjunction with well-bore optimization, we plan to implement other leading-edge technologies to increase effective well-bore permeability. We deployed some of these same techniques on RU-7 nearly a year and a half ago, and continue to see outstanding results where we have exceeded nearly double historical flow rates and bottom-haul flowing pressures. All of which indicate the Redoubt field is very strong and has many opportunities.

One other point worth mention is even though RU-7 is outperforming above historical trends, it is currently running at a reduced rate and could be increased at any time. The reason we haven't to date is due to our conservatism, that is, until we get more wells online.

Moving on to RU-3, our previous intent was to go right to RU-2 sidetrack after RU-1, but our view has shifted to push RU-3 next due to the heightened concerns about our gas needs will be met as a result of the ongoing gas shortages in the Cook Inlet. With that said, it's prudent to secure significant gas source believed RU-3 can help provide. We're also hopeful Otter as well as Olsen Creek will be a success and not only serve as a potential gas source to maintain operations but also be a net exporter as well.

RU-3 is a previously producing gas well out of the [G-Zero] [inaudible] gas sands at a measured depth of about 14,000 feet. It was a very strong producer with a well test of over 8 million cubic feet of gas a day, and flowed for only a few short months and recovered just under a half Bcf of gas. Well was under our internal recovery estimates. Production dramatically fell off and the previous operator thought it was a formation matter. We believe it's not a formation problem but rather a surface mechanical issue due to the high pressure with nearly 4,000 psi without a sufficient pressure-reducing device in place to keep the well head and associated piping from literally freezing off.

So, the work-over plan basically consists of removing all the old completion, reaccessing the zone of interest, followed by installing the necessary device to effectively reduce the high pressure without freezing. The work-over is a straightforward procedure and expected to take two to three weeks.

Moving on to our West MacArthur unit, production continues to perform as expected, with an average daily production approximately of 750 barrels of oil equivalent per day. We're currently conducting work on WMRU-1A, a crude oil well, and is expected to have back online next week.

Also our team has been working on putting together a detailed well plans for new development wells, West Forelands No. 3, a new gas well, WMRU-8, WMRU-9, and Sword, which are oil wells, as well as a sidetrack plan for WMRU-7A, another gas opportunity. All of which we have high hopes will be very significant wells.

Moving on to a construction project underway at West MacArthur building unit, we're currently building a road in the pad for a Cook Inlet operator in support of their prospect just a few miles west of our West MacArthur River camp. If they're successful, we would hope to come to an agreement to process our fluids either at West MacArthur River Unit or Kustatan production facility.

Moving on to the onset of winter, we're taking all the necessary steps to prepare for winter to not only maintain production but to also support the drilling activities.

Now, moving on to the [Tuxedni] basin, we have several exploration license related to the [Tuxedni] basin, but the largest one is exploration license number 2. As you may be aware of, we were able to obtain a three-year extension on our [Tuxedni] Basin No. 2 exploration license in 2010, extending the term of the 471,000 acre license until October 31, 2013. Our Alaska team and Miller senior geologist, Dr. Gary Bible, who led the group, undertook a thorough review of the field as well as various data, seismic, magnetic surveys and others, as well as conducted a comprehensive field program in 2011.

Throughout those efforts, we have identified the acreage within the license area that is prospective for conventional and non-conventional gas, including several identified structural leads. Now that we have a good understanding of the prospects where they're located, we anticipate [relinquishing] the non-productive acreage within the license by the end of October 2012, followed by submitting a plan of operation this winter for drilling an exploration gas well within the [Tuxedni] License No. 2 area by October 2013.

Moving on to another exciting opportunity, the Sword and Saber prospects which are located north of the prolific West MacArthur River field. I'm very pleased to announce the execution today of two farm-out agreements with Hilcorp Alaska LLC. Upon Cook Inlet Energy's acquisition through Miller of the Pacific assets, acreage within two of these leases covering the Sword and Saber prospects was on 70% by Cook Inlet Energy and 30% by Union Oil Company of California, recently acquired by Hilcorp Alaska. Through these farm-out agreements, Cook Inlet Energy will earn Hilcorp's 30% working interest in this acreage upon the successful completion of a commercial well within each of the farm-out areas.

Both prospects have identified hydrocarbons for multiple zones defined by previous drilling. As interpretated, both prospects cover a significant area with potential estimated reserves ranging from 3 million barrels of oil up to 20 million barrels of oil, as well as gas ranging from 3 Bcf all the way up to 14 Bcf. We're currently evaluating exploration plans for these two prospects and would hope to drill at least one of these prospects within the next 18 months. Upon earning Hilcorp's interest in this acreage and the execution of the assignments, Cook Inlet Energy's net acreage will increase by 504 acres.

I will now close by touching on a project that is near and dear to us, has such a huge environmental and economic benefits, the trans-Forelands pipeline. The trans-Forelands pipeline is a pipeline that would connect the west side of the Cook Inlet to the east side, delivering crude oil to the Tesoro refinery on a continuous basis. The trans-Forelands pipeline is a project we saw the need for several years ago and as such launched into design and engineering and feasibility studies. We believe the trans-Forelands pipeline will not only reduce loss of production risk as a result of Mount Redoubt volcanic activities, but also reduce environmental concerns by reducing super-tanker traffic in the Cook Inlet, especially in the winter months.

Permitting is underway for the project. Permit applications have been submitted to the US Army Corps of Engineers, State Pipeline Coordinator's Officer, the US Coast Guard, and the Kenai Peninsula Borough. The Alaska Department of Transportation has been engaged to determine the width of the right of way along a portion of the pipeline corridor. In addition, informal consultation has begun with the US Fish and Wildlife Service, National Marine Fisheries Service, and the State of Alaska Office of History and Archeology. Basically, they concluded that the pipeline project is not likely to adversely affect threatened and/or endangered species or critical habitat. So far we're seeing great support for the pipeline and plan for installation in fall of 2014.

Additional benefits, according to our internal economic analysis shows that tariff will dramatically be reduced if the existing Cook Inlet pipeline throughput was to be put into the proposed trans-Forelands pipeline, effectively increasing the economic limits of the field and ultimately increasing recoverable reserves and adding more value to the shareholders.

So with that, Scott, I'm turning the call back to you.

Scott Boruff

Thank you, David. I want to thank you and your team for your continued support and excellent work at Alaska, and especially for your work on Rig 35. We plan to provide investors with an update on Rig 35 as we move through our drilling program of the Osprey platform.

Now I want to turn the call over to David Voyticky to provide a more detailed update on our financial results for the first quarter. David?

David Voyticky

Thank you, Scott. We made significant progress during our first fiscal quarter in strengthening our financial foundations. As Scott noted, we closed on a new $100 million credit facility with Apollo Investment Corporation in late June that will provide increased funding for our oil and gas development and drilling plans in fiscal 2013. I wanted to highlight that this funding was straight debt deal, so that we would not dilute our existing shareholders and no options or warrants were granted in conjunction with it. The new credit facility has a lower cost of funds than our previous credit facility and has cash management provisions that are improved from the previous facility.

I want to highlight that, since we had postponed its repair until Rig 35 was operational, our first quarter's results reflected the impact of RU-1 being offline during the quarter. This had an effect on our revenues production and certain expenses this quarter. The good news is that we do expect RU-1 to be back online during the second quarter.

Total revenues were $8.3 million for the first quarter of fiscal 2013 and were down slightly compared to $8.9 million in the first quarter of the prior year, an increase in the price we received under our renegotiated Alaska sales of oil contract partially offset the decrease in our oil production.

Our total net production for first quarter of fiscal 2013 was 77,079 BOE compared with 92,008 BOE last year. This decrease was due to a normal decline curve fluctuation and shipping schedules and RU-1 being offline during the first quarter 2013.

Broken down by region, Alaska contributed 90% of our net production and Tennessee contributed 10% in the latest quarter. Our average realized sales price for the quarter rose 4.1% to $99.59 per barrel compared with $95.69 per barrel in the same period last year.

Our total operating costs and expenses for the first quarter increased 5% to $13.3 million compared with $12.6 million in the same period last year, reflecting our increased focus on exploration and production activities. The higher operating costs were partially offset by lower general and administrative expenses and lower depreciation depletion and amortization due to the lower production this quarter compared with last year.

G&A expenses were $5.3 million compared with $5.8 million in the first quarter of 2012. G&A expenses declined for every major line item except for professional fees. We have experienced a significant increase in professional fees due to higher litigation costs, the implementation of our stocks compliance programs and the subcontract internal audit fees that were previously not required.

Our first quarter other income more than doubled to $8.7 million compared with $3.3 million in the first quarter of fiscal 2012. The increase since last year was due to an $8.9 million gain on derivatives compared with a $3.8 million gain in the first quarter last year. The 2013 results included a $4.3 million gain from the termination of a commodity derivatives contract. We booked the $4.3 million gain on hedging swaps that we have in place for our crude oil in Alaska. We were able to take advantage of the recent changes in crude oil pricing that coincided with the change in the pricing index for oil we sell to Tesoro in Alaska.

We sold the old hedging swaps that were based on a NYMEX WTI Cushing Index for profit, then replaced them with new hedges against the BRENT Index, which historically closely tracks the ANS pricing that is now used for our sales to Tesoro.

Our pretax income for the first quarter of 2013 was $3.7 million compared with the pretax loss of $430,000 in the first quarter of last year. Our net income for the first quarter of fiscal 2013 was $189,000 or zero dollars and zero cents per diluted share, compared with a net loss of $183,000 or zero dollars and zero cents per diluted shares for the same period of 2012.

Our 2013 results include a $1.1 million provision for income taxes and a $2.4 million charge related to the accretion of the preferred stock. In the first quarter of last year we did not have a charge for accretion on the preferred stock since no preferred stock was outstanding at that time. Also last year's first quarter results included a $247,000 provision for income taxes compared to this year's $1.1 million.

Regarding our cash flows, we generated $3.6 million in cash from operating activities in the first quarter of fiscal 2013. This is up 28% from the $2.8 million in the first quarter of fiscal 2012, primarily due to the increase in our net income compared with last year.

Before I turn the call back over to Scott, I want to briefly comment on our expectations for the second quarter of fiscal 2013. We expect our second quarter revenues to be about even with the second quarter of last year due to the expectation of RU-1 coming back online late in the quarter. We expect our revenues to benefit from the new pricing we received on Alaska crude oil sales. Since February 2012 we've received the Alaska North Slope minus $4 a barrel for crude oil as compared with previously receiving West Texas minus $1.72 under our Alaska oil sales contract with Tesoro.

With that overview of our financial results, I'll turn the call back over to Scott.

Scott Boruff

Thanks, Dave. Before I open the call to your questions, I want to comment on a few other matters.

Today I want to close by saying how excited we are about the progress we've made over the past year. Our entire team has worked very hard to achieve these results, and I believe that we have positioned Miller to accelerate our growth in fiscal 2013 due to the deployment of Rigs 34 onshore and Rig 35 offshore in Alaska, and our plan to rework wells in Tennessee. Our Osprey platform is the newest platform to Cook Inlet, of the 16 platforms in the Inlet. Rig 35 is the newest drilling rig to come online in the area. Our initial plans are to rework the five wells that were previously producing on the Osprey platform. As David Hall mentioned, we expect to target RU-3 gas completion as our next project due to the increase on the short supply of natural gas in the Cook Inlet region.

We also believe we have financial resources to fund our development and drilling programs this year from our ability to access the public markets as well as our new credit facility. We also expect to generate more cash flow from oil sales as we successfully rework wells on the Osprey platform and work over existing wells in Tennessee to increase our production.

Finally, I want to welcome Gerald Hannahs as a new Board Member. He replaces Jonathan Gross who resigned from the Board to focus on his consulting business. Gerald has over 30 years of experience in investment business in the oil and gas industry. He is the co-founder of Texarkoma Crude & Gas Company which drilled wells in Tennessee and Alabama. As we're in an aggressive drilling phase in our company's business plan, Gerald's oil and gas background, along with his depth and experience in the business world, is a welcome addition to our Board, especially at this exciting time at Miller. With the addition of Gerald to the Board, we once again have the majority of the Infinite directors on Miller's Board.

Before we open up the call to questions, our counsel has advised us not to comment on the pending litigation and certain questions relating to the SEC filings, discussions with the SEC, or lawsuits themselves.

That concludes our formal remarks for today's call. Operator, we would now like to open up the call for questions.

Question-and-Answer Session

Operator

Thank you. [Operator Instructions].

And we'll take our first question from Neal Dingmann with SunTrust.

Neal Dingmann – SunTrust

Morning, boys -- or afternoon, guys. Say, one, on David Voyticky, first question, was just, what was the expectation you said as far as -- could you repeat that again, as far as kind of what you're expecting? Was it second quarter rev? I'm not sure if I caught that.

David Voyticky

Yeah, it's going to be similar to last year's second quarter revenue. Flat.

Neal Dingmann – SunTrust

Okay. And so I mean, again, I guess the question that go with that, what's -- are you all able to say kind of what current production is currently and then what you're expecting production to exit the calendar year? Anything, you know, can you give some guidance around that?

David Voyticky

Sure. We're averaging about 1,000 barrels of oil up in Alaska, about 100 in Tennessee, and then, on a BOE basis, another 100 barrels of production on gas. As we look at the timetable for ending the calendar year, we'd expect that RU-1 would come online sometime during the second quarter. After that we've had a slight change in our development. As we mentioned, originally we were planning to sidetrack RU-2 for oil. Given the cost, the current cost of gas in the Cook Inlet, we're going to go ahead and rework RU-3, as David mentioned. We'd expect that that would come online in this year as well, and that would be, on a BOE basis, something around 600 for RU-3. And as David noted, the last production numbers for RU-1 were 270 barrels, and our expectation is going to be somewhat higher than that.

After that we'll go back to sidetracking RU-2. Our expectations are that we'll get it done before the end of the calendar year. That was a well that was previously producing at 600. So those are the numbers we're using for our internal projections for the end of the year. That's an additional 1,400 BOE a day for the end of the year. If you want to take it out through April of 2013, we would expect to sidetrack RU-4 and RU-5 before the end of the fiscal year and add another 1,000 barrels of oil a day production.

As David mentioned, we fracking Otter and we'll be drilling Olsen Creek before the end of the year. Those wells, if they're successful, we'd expect to initially produce in the 3 million to 4 million cubic feet a day range, with actual production being able to be delivered in the springtime with the completion of the gathering pipelines.

In Tennessee, we're going to have some opportunities to add to production as well. We'll be continuing to spend money on reworking our stripper wells as well as before the end of the year drilling a horizontal well or two into the Mississippi lime, which could add significantly to our production. I think those are the bases that we would use for guidance. And we're also, as you know, always in various discussions with different groups about JV and other opportunities where we can look to accelerate our development program, in particular, as David mentioned, as activity near our West MacArthur Redoubt unit field, and that could lead to several other opportunities during the winter.

Neal Dingmann – SunTrust

And what do you assume, Dave, it would cost around I guess at least just looking at the next, like you said, the next two on the Osprey and then the RU-4 -- or I'm sorry, basically RU-2, 4, 5, and then for Otter, and also what kind of -- give me relatively an extent if I assume, just because mostly sidetracks, et cetera?

David Voyticky

It'd be relatively inexpensive, but we're always adjusting our [AFEs] as -- especially as we're getting data from operating the rigs, and it looks like Rig 35 is operating within or below our expected costs, daily cost expectations, so that's positive. And so we wouldn't have any significant adjustments to the guidance that we've given with respect to the sidetracks in RU-2, 4 or 5 on the $10 million gross cost, which there's about a little over $2 million of actual rig time cost and other equipment that we -- that Miller Drilling owns.

And with respect to Otter and Olsen, the costs on Olsen may be slightly higher than Otter just because of the winter. But the initial wells for those fields, we're looking at [AFEs] in the $7 million range.

Neal Dingmann – SunTrust

Okay. And then a couple of, if I could, either next one I guess for David Hall or Scott, just wondering, the farm-outs that David Hall mentioned, was that Sword and Saber? And then was wondering exactly how does that work or what's the timing of those?

Scott Boruff

Go ahead, David.

David Hall

Yes. We've got executed farm-out agreement, I mean it's active now. So now we just need to fulfill our part of the agreement.

Neal Dingmann – SunTrust

So, and what was that? You would earn the 30%? Or how -- remind me again, David, how that works.

David Hall

Yeah. Upon the drilling and completion of a well, we would earn the 30%.

Neal Dingmann – SunTrust

Got it.

David Hall

We need to drill by a certain time for the contract.

Neal Dingmann – SunTrust

Okay. And then just two more if I could. For Scott. Scott, just wondering, you all didn't mention too much, I know you still have a ton of infrastructure up there, just wondering what's going on along the lines of sort of either monetization or third-party agreements with infrastructure. Anything that we can look for here in the next few quarters?

Scott Boruff

Yeah. I mean, Neal, as David mentioned, we literally just signed that farm-out agreement today, literally got signed this morning, so we're very excited about that. That's a deal we've been working on for about six months. And if you heard earlier on our call, we'd sold a generator earlier in the year. In terms of increasing our power generation, we see the needs from clients that we're dealing with up there in the Cook Inlet and increasing our megawatt power to handle their needs.

And so as our midstream start to evolve, as we talked about, we're very excited about the trans-Foreland pipeline. I mean, if you can -- we're modeling out about $12 transportation for oil right now, and when we get those permits, we'll have that pipeline in place by 2014, which would reduce our transportation to the $3 to $4 range. And we have funding in place lined up for that as well.

So as the large independents move in to the Inlet, this makes it better for everybody, more services available, and we're providing lots of those services as well with our midstream, with our grind-and-inject, with us being able to house those guys as they need help in these as well. So you'll see our services revenue grow as well.

Neal Dingmann – SunTrust

Okay. And then lastly, Scott, for you, or maybe David will take it, just wondering again, remind me what as far as commodity price differentials up in the Inlet right now, what they're averaging.

Scott Boruff

Yeah, we get Alaska North Slope which is -- trades real close to BRENT, and about a $110 has been what we've been averaging. And you've seen this quarter or the last quarter I think our average was about $100, is actually what we got, but -- and we're hedged again for the next two years on about 70% of our production.

David Voyticky

And what we're seeing on the gas side is a continued tightening of supply. Two of our providers that were previously purchasing gas from at $7.20 [NM] did not have any additional supply at that price, and we went around the Inlet, and David Hall obtained a new contract and the pricing is in the $12 to $14 [NM] range. So that almost doubling of prices reflects what we see as a tightening supply, and quite frankly, that's one of the reasons why we changed our plans and are headed towards RU-3 next.

Scott Boruff

And we actually, Neal, have contracts that we could execute this as soon as we bring all those onshore gas wells online that we're drilling and/or the offshore RU-3. So we're excited to get one of those gas wells online and be able to sign a contract in the next six months with somebody.

Neal Dingmann – SunTrust

Perfect. Great update. Thank you all.

Scott Boruff

Thanks.

Operator

And we'll take our next question from Jonathan Fite with KMS Investments.

Jonathon Fite – KMF Investments

Hey, good afternoon, fellows. Thanks for your time today.

Scott Boruff

Hey, Jonathan.

Jonathon Fite – KMF Investments

Hey. Just a couple of follow-up questions from the previous speaker. Earlier this summer we talked about once the offshore rig was certified by Alaska, that RU-1 would be kind of a pretty quick turnkey two to three-week effort. Am I still hearing, David, right, that we're kind of two to three weeks out from that --

David Voyticky

Yeah, that's -- I mean that's a very good question. And David, I'll start and you can add in. We modeled that well out at a 270 barrels of oil a day, which is what it was producing at both for Pacific Energy last and for us last summer. And the two to three-week quick project really was to obtain that 270-barrel target, which would really be going in taking out the first ESP and retrieving it, putting a new ESP and running completion. Now that well-bore is a story unto itself, but this is a well that originally [IP'd] greater than 2,000 barrels a day. Forest Energy had put a liquid level control valve in this well-bore down at the bottom, which is a 6-foot subsurface blow-up preventer that draws the oil through something the diameter of a pencil. And on top of that, they put ESP. That failed. And then when they couldn't get it out, they put another LLC on top of that and another ESP. And when that failed, they put yet another ESP on top of that.

And so, to get the 270, which is what it was it was previously producing, we figured we go and take the top stuff out, do a little bit of cleanup, and then try with no expectation of succeeding in trying to get the ESP that they previously couldn't get out. Through David's team's efforts and help from all of our engineering groups, we retrieved that ESP, the second ESP. And then we spent time going and trying to clean out the rest of the well-bore and take out that top liquid level control valve.

And when we went in to go and try to latch on to this 3.5-foot long neck, we found ourselves blocked by about 20 feet of debris, solid debris, in the well-bore. We spent a good part of a week having to correct deformed casing which had been [crimped in] about an inch, and retrieving about 20 feet of junk from the well-bore. And we were successful in removing that second LLC which we think greatly enhances the potential flow path for this well.

So, while it's taking a little bit longer and while we still have at least -- the longer it takes, the better we are on this because it means we're removing more stuff. And if we can remove all those obstructions and optimize the well-bore the same that David's team did on RU-7, we obviously expect to see much better than 270 barrels a day.

Jonathon Fite – KMF Investments

That'd be great. Just as you guys look at kind of investor communications, I think we'd much rather see you guys continue to under-promise and over-deliver rather than the other way around. Or as there are delays in kind of assumed schedules, you know, articulate some of that detail. And I guess we're having that conversation today, which we appreciate.

But let me turn to just the reserve base and do some quick verifications. When we look at the kind of P1 reserves, kind of in the 400 million, 440 million range, and we've got -- Apollo basically said the midstream assets worth another 150 million to 200 million. Is that based on their kind of --

David Voyticky

Well, that's -- Apollo didn't say that, but -- that wasn't Apollo that said it. There was a third-party appraisal company that they hired, [Hedco], that did appraisal of our hard assets up there.

Jonathon Fite – KMF Investments

Okay. And so we're looking at somewhere kind of $600 million range in proved and hard assets. There's kind of possible and probable assets beyond that. I mean, what were you guys are hitting at Olsen and Otter aren't even on the books, right, from an existing asset base?

David Voyticky

That's correct.

Jonathon Fite – KMF Investments

So when we see some news this week from Hilcorp Energy divesting $500 million out of the Gulf of Mexico with the explicit intention to direct those funds into the Cook Inlet, from a shareholder perspective, if they are reaching out to you, the management team is actively reaching out to them to engage in perhaps some transaction discussions that might see some fruition before the end of the calendar year where tax consequences go up for shareholders? Kind of comments? I mean obviously [inaudible] of any type of due diligence discussions, I wouldn't expect you to reveal that, but just any kind of general comments or perceptions regarding the Hilcorp transaction and the relationship with a cash-rich neighbor?

Scott Boruff

David -- this is Scott. I can take, and then, David Hall, you can comment as well. What I can tell you is, A, we're very proactive in talking, in dealing, in negotiating with all of our neighbors, because again we have the pristine infrastructure that, from housing to grind-and-inject, to power needs, to everything. So, yeah, we're, you know, you should see -- we hope to see something, like we announced earlier today with the farm-out, we're -- we hope to see more of that coming from all phases of it and help monetize our midstream assets for everybody in the Cook Inlet, because not only Hilcorp by Apache has announced they're spending several hundred million dollars shooting 3D seismic, and we house their people, so it's good for us, good for them. And when they find those significant hydrocarbons and it's going to be good for them. So we're excited.

I mean, two years ago up there, you'd see a helicopter fly over once a day, once every other day. Now they're everywhere for everybody.

David Hall

Yeah, Scott, one point I'd like to add. I mean this is, you know, living here and just seeing all the action here in the Cook Inlet, I mean this is clearly Alaska's Bakken. There is just an enormous amount of interest in the Cook Inlet, and we see ourselves well-positioned. We just got enormous facilities, resource abilities, not only oil and gas reserves but just the enormous infrastructure from over 42 miles of pipeline and just a huge array of processing ability. But as Scott mentioned, we are in very detailed discussions with many operators in the Cook Inlet to see if we can assist in any of their needs and identify the synergies and be a very active player in the Cook Inlet.

Jonathon Fite – KMF Investments

We appreciate that effort on behalf of the shareholders. I know that your interests are very much aligned with ours. We know that there are some very specific tax implications to things that could happen prior to December 31 versus after, and so we hope you take that in consideration, and we just look forward to continued momentum and progress on the execution schedule. Thanks, guys.

Scott Boruff

Yes. Thank you. And on another note, we haven't done this much in the past, but now that we have two rigs running, one onshore and one offshore, we will be giving operational updates as we get them to you guys, in the future, so, instead of waiting for the quarter to end. That's the only reason we put this call off seven days is we hope we'd have some good operational updates on RU-1. But the good news is we're getting more out of it. So when we know what that well is doing, we'll get on and update everybody and will be as excited as you guys. But thanks.

Jonathon Fite – KMF Investments

We appreciate it, Scott. Thanks.

Scott Boruff

All right, buddy.

Operator

[Operator Instructions]. And we'll take our next question from Tim Griffith with Rockwood.

Tim Griffith – Rockwood Investment Partners

Hi. Good afternoon, guys.

David Voyticky

Hi, Tim.

Tim Griffith – Rockwood Investment Partners

I've got a question about the new credit facility with Apollo. It references reserve report from Netherland, Sewell. I'm just curious, is that a different report? And how does it differ from the Ralph E. Davis report that you guys have filed an exhibit to the K?

David Voyticky

Right. As part of both Guggenheim's and Apollo's due diligence, they hired Netherland, Sewell to do an analysis, PDP analysis of our PDPs, and on a few of the wells that we're sidetracking. So it's their report. The numbers are very similar to the Ralph E. Davis report.

Tim Griffith – Rockwood Investment Partners

Is that something that you guys plan to disclose publicly?

David Voyticky

That's not our report and we're not going to look to disclose it. But what I will say is that every year we look at the different reserve engineers, and we find it helpful to get the perspective of the multiple reserve engineers that we've seen, and we're happy with the work that Ralph E. Davis is doing.

Tim Griffith – Rockwood Investment Partners

Okay. And then moving on, what is the current monthly CapEx spend with the rigs running?

David Voyticky

Yeah, the way we look at it, now, Rig 34 is currently not running. It's waiting for the frac to be completed, and we're mobilizing it to our Olsen prospect. But as we are running that rig, we're looking at about a $3 million a month.

With respect to Rig 35, we look at the sidetracks as being 45 to 60-day projects. So it's effectively spending about $5 million a month.

Tim Griffith – Rockwood Investment Partners

Okay. So, about $8 million total.

David Voyticky

Eight million total.

Tim Griffith – Rockwood Investment Partners

Okay. And what are the plans to kind of make up the difference with the balance sheet situation?

David Voyticky

Yeah. I think our, you know, as you can kind of read through when you -- and read between the lines with the Apollo agreement, we have -- we're going to go out and raise an additional $15 million of some sort of investment. That's what the Apollo agreement contemplates, its equity or preferred equity. As Scott mentioned, our [shelf] became effective this week, which was very important and a big milestone for the company, something our internal team has been working very hard on for the last two years. And as part of that, we'll have the ability to have Apollo lend us an additional $15 million under the facility.

Now, the reason we had structured that way, and we were in agreement with Apollo with this point, is that we see the Redoubt structure, the sidetracks, the reworking of RU-1 and RU-2, as fairly certain outcomes in terms of production. These wells have produced before, the reservoir characteristics are well-known. The big risk being the potential overruns.

As can happen in this business, to lose a bottom-haul assembly or drill-bit, or whatever the case may be, you may end up having some significant cost overruns. And we view the principal risk at this point in time as not having the capital in case something bad happens during those activities. And so the thought process behind that was raise an additional $15 million which would literally be in reserve and allocated specifically towards overruns on our first set of activities on the platform. And that we think addresses some of the risks that's inherent in those activities, and quite frankly, will ensure that we get those wells online. If we get the wells online, we believe we'll be in a cash flow position as well as a reserve base position to continue using the Apollo facility. They've been great partners so far. We've been utilizing a drilling engineer that has been very helpful in our process. And I think that's the way our capital plan is going to look going forward.

Tim Griffith – Rockwood Investment Partners

Okay. And then one more question with the Apollo. It seems like 1031 as kind of your first covenant hurdle with the interest coverage ratio. Is that something that you look to see a waiver, or what's the plan for meeting that? Because it looks like production is a little bit lower at 1,200 BOE a day to get there.

David Voyticky

Yeah. We actually had a comment in our Q indicating that there was a likelihood that we wouldn't make that set of covenants. And the reason that we're not, I mean, again, the covenant package was designed specifically to bring us to the table in case something with our expectations that we're different than where we were, and our expectations were based on a rig that would have been ready to go at the end of June, were actually all on the platform at the end of June and received certification, written certification, from the rig builder that it was going to be done by the end of the month. And yeah, seven weeks later, it was done. So that affected that ability to meet that covenant. But it doesn’t really reflect the change in expectations in terms of cost or performance once the wells are online.

We've had discussions with Apollo and we've reached an agreement in principle to push those covenants out a quarter. So that's where we are. We don't expect that it's going to be an issue.

Tim Griffith – Rockwood Investment Partners

Okay. Great. Thanks, guys.

Scott Boruff

Thanks for your questions.

Operator

And we'll take our next question from Jason Harris with Kendall Square Capital.

Jason Harris – Kendall Square Capital

Yeah. Just had a quick question about the covenant issue. Is that the only covenant you expect to violate in October? Is there EBITDA covenant that you might violate as well?

David Voyticky

The whole covenant package gets pushed out a quarter.

Jason Harris – Kendall Square Capital

And there's no penalties for that?

David Voyticky

No penalties.

Jason Harris – Kendall Square Capital

No increased rates or anything?

David Voyticky

No increased rates.

Jason Harris – Kendall Square Capital

And you mentioned that CapEx is $8 million. So what will the CapEx actually be in the October quarter? Will it be close to $24 million or?

David Voyticky

Well, it's going to be less than $24 million because we're not going to have Rig 34 working the entire quarter. So it's probably going to be working for a very brief period of time. So you can eliminate all of that from the quarter.

In terms of Rig 35, the activities that we're doing with RU-1 are much lower costs than the $5 million number that I gave you because the sidetracking is literally drilling, which is much more expensive. Right now we're just fishing. So we're seeing daily costs in the $60,000 to $70,000 a day range. And we've been -- $60,000 to $70,000.

Jason Harris – Kendall Square Capital

So the quarter is only going to be $6 million in CapEx presuming?

David Voyticky

Yeah, it's going to be a lot lower. It's hard to say exactly, depending on the activities, but I'd say $8 million is probably a good number, somewhere around that.

Jason Harris – Kendall Square Capital

And RU-2, you mentioned that there's been a change, you're going to do RU-3 first. RU-2, you still expect that to be online by the end of the calendar year though?

David Voyticky

Yeah, that's the hope and expectation. If there's a change to that, we'll --

Jason Harris – Kendall Square Capital

So, 60 days, so you're going to start that at the beginning of November?

David Voyticky

Here's, again, Scott mentioned, we would -- we were almost giving up on removing the LLC valve from RU-1 when we finally got it out. So we were expecting that we would have given up on it and had an announcement in this call what production was going to be. They actually got it out, and so now we've got another two to three weeks of work to do. But at any point, we may find that we can't get something out and then we run our completion. But the way we look at it right now is best case scenario we get all the fish out of the haul on 1, takes about three weeks. We would give -- we would have an update on that for our investors. At that point we have about a two-week project on RU-2 -- on RU-3. There may be about a week of downtime to service the rig, move the rig. And that's about a two-week project. And then after that we'd start on RU-2, and that's a 45 to 60-day project.

Jason Harris – Kendall Square Capital

Okay. And then just I noticed right before, I think it was in June, the Chairman of the Board sold a large stake, more than half of his stake, 2.5 million shares. And it looked like he sold it in a private transaction. I was just wondering if you could give us any detail on that or -- and that's, you know, it looks like that it should be a filing position. I don’t see anyone filing as a new holder. Can you tell us more about that transaction or?

Scott Boruff

Yeah, I can take that transaction. Deloy Miller, the founder in full disclosure, it's Scott, Deloy had never sold a single share for his 45 years in the business, 12 years public, and as part of his estate planning, made a private -- a private transaction to a group that have filed. And as you noted, it was about a 2 million, 2.3 million number, and that time it was a private transaction to private individual at above the market rate, at about $1 above the market of restricted shares.

Jason Harris – Kendall Square Capital

And they filed as holders?

Scott Boruff

They have, yup.

Jason Harris – Kendall Square Capital

I don’t see them listed as holding.

Scott Boruff

It should be in the 10-K. It's not our responsibility to make sure they filed, but they, you know.

Jason Harris – Kendall Square Capital

So, it's a private transaction a dollar above the market?

Scott Boruff

Yeah.

Jason Harris – Kendall Square Capital

And also, just one last question, I saw in your 10-Q that it sounds like you've assumed the debt of a real estate company, [Palosepi Point]. Can you tell us about that? Are you now on the hook for the $5 million they owe or?

Scott Boruff

No. It was two buildings that Miller Energy Resources bought out two partners. We spent about a year and a half looking for office space to consolidate our operations. And if tracked our other transactions, we always like to get good deals on a property, so it was a deal that we actually found and bought two owners. And Miller owns a 48% working interest in the partnership and two buildings that are 100% full and cash flow about $60,000 a year.

Jason Harris – Kendall Square Capital

Okay. And Apollo is okay with that?

Scott Boruff

They are.

David Voyticky

Yeah, that transaction took place a year ago. We actually purchased the interest. I think what you may be referring to is a little bit of a refinancing.

Scott Boruff

Yeah, and it's actually we're only 55% responsible of $5.2 million note. It's about -- I think we've looked at our books at about $2.7 million of potential liability, but --

David Voyticky

I think that's an improved position from last year.

Scott Boruff

Yeah. You're correct. Last year, with Guggenheim, we were actually on the hook for the whole $5.2 million, and when we refinanced the building, we limited our liability to our percentage of ownership. So, Apollo liked that.

David Voyticky

That was part of due diligence. There's no surprise there.

Jason Harris – Kendall Square Capital

Okay. Great. Thanks a lot.

David Voyticky

You're welcome.

Scott Boruff

Thanks for your questions.

Operator

And it appears there are no further questions at this time. I'd like to turn the conference back to our speakers for any additional or closing remarks.

Scott Boruff

This is Scott. Thank you for joining us this afternoon to provide you with an update on Miller Energy strategy and financial results. As you can tell, we are very excited about Miller's future and potential of our properties. We plan to keep you up to date on our operations on future calls and look forward to you joining us. That concludes today's call. Okay. Thanks.

Operator

And that concludes today's conference. We appreciate your participation.

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