Miller Energy Resources, Inc. (NYSE:MILL) Q2 2015 Results Earnings Conference Call December 10, 2014 9:00 AM ET
Derek Gradwell - SVP, Natural Resources, MZ Group North America
Carl Giesler - Chief Executive Officer
Scott Boruff - Executive Chairman
David Hall - Chief Operating Officer
Jeff McInturff - Chief Accounting Officer and Interim CFO
Kurt Yost - General Counsel
Deloy Miller - Founder
Neal Dingmann - SunTrust
Kim Pacanovsky - Imperial Capital
Curtis Trimble - Brean Capital
Jonathon Fite - KMF Investments
Kurt Caramanidis - Carl M. Hennig, Inc.
Jim Collins - Portfolio Guru, LLC.
Good day, ladies and gentlemen. Thank you for standing by. Welcome to the Miller Energy Resources Incorporated Fiscal Second Quarter 2015 Earnings Conference Call. During today’s presentation all parties will be in a listen-only mode. Following the presentation, the conference will be opened for questions. [Operator Instructions]
This conference is being recorded today, Wednesday, December 10, 2014. I would now like to turn the conference over to Derek Gradwell, for MZ Group North America. Please go ahead.
Thank you, Operator, and good morning, everyone. Joining us today for Miller Energy’s 2015 second quarter earnings conference call is Mr. Carl Giesler, the company’s Chief Executive Officer.
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, that management may make additional forward-looking statements in response to your questions. Therefore, the company claims the protection of the Safe Harbor for forward-looking statements that is contained in the Private Securities Litigation Reform Act of 1995.
Forward-looking statements related to the business of Miller Energy Recourses and its subsidiaries can be identified by common use forward-looking terminology. These statements involve risks and uncertainties including, but not limited to the implied assessment that the company’s oil and gas reserves can be profitably produced in the future, the need to enhance Miller Energy’s internal controls, operating hazards, drilling risks, fluctuations in the prices received for the sale of oil and gas, litigation risks and changes in government regulations.
The company’s filings on Form 10-K, 10-Q and 8-K with the SEC contain more detailed descriptions of these risks and uncertainties. Investors should not place undue reliance on such statements, which are qualified in their entirety by the risk factors contained in Miller Energy’s SEC reports.
For those who are unable to listen to the entire call, we will have an audio replay that will be available. The call is also being webcast, so that you can log in via the Internet. That information was provided on the conference call announcement and in the earnings release.
At this time, I’d like to turn the call over to Mr. Giesler, the Chief Executive Officer of the company, and he’ll provide opening remarks. Carl, the floor is yours.
Hey. Thank you, Derek, and good morning. I appreciate all of you are making the time for this call and thank you for interest in Miller Energy Resources. With me this morning are Scott Boruff, our Executive Chairman; David Hall, our COO; Jeff McInturff, our CAO and Interim CFO; and Kurt Yost, our General Counsel; as well as Deloy Miller, our Founder.
Upfront let me apologies for the late release, we were finalizing some signatures with our recent credit agreement amendment. I want to make sure we had everything all the eyes dotted and t’s crossed before we put it out. Also upfront, please be patient with us on the call, we will probably go bit longer than normal with the prepared remarks, there is lot to talk about.
As you know, our new management team has been in place for less than three months. You haven’t heard much from us before this call. Also as you know a company the situation has been to put it mildly dynamic.
We have a handle on it and more importantly, we have a plan to deal with it. So in addition to the quarterly review we will share that plan. We also endeavor to address most of the questions we sure you have. So with that mind here is the agenda.
First, we will review our fiscal second quarter financial and operational results, as well as subsequent events. Given that our earnings release get out a bit later this morning than we would liked I will go into a little bit more detail than we normally would.
We will then have a candid discussion of where we are, including our hedge position and review in some detail our plan going forward. We will address our well plan, as well as the meaningful organizational and process changes.
We will also describe uniqueness in the Alaskan oil and gas market. To our mind that uniqueness, particularly the state financial supported drilling via cash tax credit, as well as the structurally high i.e. $6 to $7 per Mcf gas prices is particularly important in this oil market. After our prepared remarks we will take questions.
Let start with our fiscal second quarter. From both the financial and operational perspective the quarter was disappointing to put it mildly. Here are the key numbers, upfront, adjusted EBITDA was $9.4 million, down 33% from the $14 million last quarter and up 60% from the $5.9 million in a year ago quarter.
The decrease from last quarter was mainly related to increase nonrecurring lease operating expense which we will detail later on and a reduction in Alaska carry-forward annual loss credits recognized during the quarter.
Net production averaged 3,273 boe/d, down 1% from the 3,213 boe/d last quarter and up 56% from 2,101 boe/d in a year ago quarter. The hydrocarbon mix was about 70% oil and 30% gas, roughly the same as last quarter and more than less oil weighted in a year ago quarter, which was 94% and 6%, respectively.
Our realized pricing was $87.27 per barrel and $6.75 per Mcf, down from the $100.44 per barrel and $6.83 per Mcf in the last quarter, as well as from $102.65 per barrel and $3.91 per Mcf in a year ago quarter.
Note that we have been selling most of our oil at approximately ANS minus $4 and most of our gas under a term contract at a current contractual price of $7.03. We should note that this contract isn’t substantially above market. This gas prices in the closed loop Cook Inlet are generally north of $6 per MCF and are largely unrelated to Henry Hupp. We believe it’s a big distinction for our company.
Our revenue was $24.2 million in the quarter, down 5% from $25.4 million last quarter and up 29% from $18.8 million in the year ago quarter. The decrease in last quarter was mainly related to declines in prices received for crude oil. Note that beyond our own oil and gas sales, our revenue include the small amount of gas that we market through other producers.
Lease operating expense was $29.77 per boe or $9 million in aggregate. We’re well aware that that was up 37% from $21.74 per boe last quarter and up 11% from $26.78 per boe in the year ago quarter.
The increase from last quarter was mainly related non-recurring underwater inspection performed on our Osprey platform as well as pipeline pigging and tank refurbishment. To put in perspective, those three activities accounted for most of the delta and they occur every two to five years.
Also note that we recognized a lower cost of market non-cash charge of $1.3 million in the quarter which negatively impacted our LOE. Essentially given negative oil price moves, we had credit inventory debit LOE. Transportation cost was $1.2 million this quarter, excluding $1.6 million refund of transportation costs we received back upon the closing of the Anchor Point Energy Pipeline acquisition. That was down 59% from the $3 million last quarter and up 20% from $1 million in the year ago quarter.
Cash G&A, it was $10 million, up 86% from the $5.4 million last quarter and up 87% in the $5.4 million in the year ago quarter. The increase in the last quarter is mainly related to management changes, non-recurring legal and stock related expenses. Total G&A was also impacted by severance and onboarding equity payments related to the management changes.
As noted before, adjusted EBITDA was $9.4 million, down 33% again from $14 million last quarter. DD&A was $20.1 million, up 18% from $17 million last quarter and up 123% from $9 million in the year ago quarter. The increase last quarter is mainly related to increased productions from the Cook Inlet.
Here, let’s pause to talk about the non-cash impairment charge that was applied against the book value of Redoubt properties during the fiscal quarter. The non-cash charge predominantly related oil price moves and was approximately $265 million. Expense overruns in the recent wells also factored into the impairment.
Beyond the Redoubt, we also had a non-cash exploration expense of $13.3 million related to uneconomic exploratory well Olsen Creek #2, which includes the effect from the tax credit. As we’ll discuss later, we are not going to drill over the near-term. Any such exploratory wells don’t offer the prospects of immediate production in cash flow. Olsen #2 is not going to happen again.
Operating loss was $305 million compared to a loss of $9.6 million last quarter and a loss of $4.3 million in the year ago quarter. The increase in the loss last quarter was mainly related to the earlier noted non-cash write-down on the Redoubt field in the uneconomical Olsen Creek #2 well in relation to the increased G&A and LOE that we went through.
Loss before income tax was increased to $285.7 million compared to the loss of $19.2 million last quarter and the loss of $9.8 million in the year ago quarter. Again, increase in loss last quarter was mainly related to operating losses noted earlier offset by the riveted mark-to-market gain. Speaking of which, we reported a non-cash gain of $23.1 million at that quarter end and think about what that might be now related to a favorable crude oil derivative position as we will stress more later. Our hedge position is strong and particularly important in this oil market.
Cash expenditures for capital projects and expenses were $47.9 million, up 4% from the $46.3 million last quarter and down 6% in the $51.1 million in the year ago quarter. Total debt was $219 million, up about $14 million from $205.3 million at the end of last quarter. And as you know, our debt is comprised of $36 million drawn on our revolver and $175 million Second Lien month.
On the topic of our debt, we’ve reached agreement actually just this morning on amendment to First Lien and Second Lien Credit agreement. The amendments were required to cure technical default related to a recent management changes as well as suggest leverage and interest coverage covenant given our financial performance in the fiscal second quarter.
Among other elements in line with a lower risk driven strategy we intend to pursue that we outlined in detail, the lenders have included in the approved plan of development or APOD into our credit facility. A new drilling strategy focused primarily on PDNP and PUD drilling target. Again we’ll go through the drilling plan in more detail later.
Additionally, given the recent down draft in oil prices as well as frankly through our drilling results. The Second Lien Lenders have increased their rate under loan to us by 100 basis points cash pay or 200 basis points we agreed to pick or decide to pick.
Our preferred series B stands at $49.8 million, up from $26.7 million at the end of last quarter. This is important to preferred holders. We should know that we consider the payment as the dividend sacrosanct.
We have many liquidity and other options before having to touch them, either in the timing or the amount of payment. As we talked about CapEx, it was generally discretionary and is the biggest lever to pull. Following at the end of the quarter, our cash stood at $14.8 million.
Let’s shift to operations. As we’ve announced, RU-9 was disappointing. Prior to experiencing electrical failure with the pump, sort of cherry on the sundae in my opinion, the well was producing approximately 100 barrels of oil per day with an increasing oil cup.
We currently are testing the optimal way to return RU-9 to production, including a more capital efficient options, drilling the well via hydraulic jet pump versus the current electric submersible pump or ESP. But this is still realigned RU-9, we learned some significant operational lessons about how more effectively and efficiently to drill an extended reach directional well through call and other challenging rock condition.
It has also forced our operations and financed teams to coordinate much more tightly and much expensively. At Redoubt, we believe that we are currently capturing only 3% to 5% of the oil in plays and believe that by conducting more hydraulic fracturing, we can significantly reduced the coverage to half to 10% to 15%.
RU-7 is a first plan well to conduct a hydraulic fracture and if that proves successful then we’ll move to conduct the same treatment on another well. Consistent with our reduced CapEx plan, we decided to conduct a rigorous type workover on the West Mac eight oil well instead of moving Rig 36 across the Cook Inlet to sidetrack that well. That approach cost about $200,000. Moving Rig 36 over to sidetrack the well would have cost about $7.2 million.
The workover increased production to approximately 200 barrels per day compared to less than 40 barrels per day prior. Our attempted workover WF-3 failed to isolate the water and was deemed non-commercial. The well has been plugged and suspended. Our exploratory well Olsen 2, as referenced earlier did identify the present gas but was unable to produce in commercial paying quantities
We are unlikely to drill further in the area. Again, we want to be clear, we will not be drilling any wells that can't immediately return to production and cash flow. Our new management team is more closely focused on cash flow and cash on cash returns than reserve accretion.
To be sure, our Iniskin peninsula remains quite attractive in all of the oil fleet. Beyond the minimal commitment to hold the acreage, however, we will wait to develop it until we are in a stronger financial position. We also have other attractive prospects, but in general, we are actively seeking JV partners in all our exploration prospects.
Related point is that we are not keeping rig that we don't need. We released the Patterson 191 rig and bringing Rig 34 to the lowest 48 for sale. Additionally, given the deferrals any high risk extended reach drilling, we are actively in discussions about leasing Rig 36.
Away from the drill bit, we’ve had some organizational changes during the quarter. Effective in early August, we reached a Separation Agreement with a former President, David Voyticky and he left the company. In mid-September, the Board appointed me CEO and the former CEO, Scott Boruff to Executive Chairman.
At the same time, the Board added Haag Sherman as an Independent Director and a Founder and Former Chairman, Deloy Miller resigned from the Board. Just before the end of the quarter, our CFO resigned. He left company on November 14th. Upon his departure, Jeff, McInturff, the CIO became the Interim CFO.
Jeff was instrumental in lower our cost of capital, expending our access to capital and improving our controls. Indeed this quarter, we perhaps had the smoothest flows in company history. We’ve engaged national search firm and believe we are near securing a high-quality CFO to complement our existing strong finance and accounting team. Stay tuned.
Now it’s a fair question. So what, what do this management changes mean? Miller started the family contract of drilling business and evolving to an NYSE listed E&P capital. Management changes are part of that evolution into an increasingly investable stock.
Long story short, this management changes are part of the deliberate plan to institute operational financial governance processes and policies that will make Miller more disciplined. And we think we are attractive vehicle for investors to participate in Alaska’s oil and gas resource opportunities.
To clarify any confusion, we have one CEO. Yet Scott remains the key part of our Senior Management team. Both he and Deloy are fully on board with the significant changes we are implementing and are actively involved, using the knowledge and history and judgment would be a mistake.
Let’s turn to a recent A&D event. As we’ve announced to close the sales substantially all of our Tennessee assets, Tennessee is where the company had started and with the sale we are saying good bye to some talent and loyal employees. We believe the buyer will do well. We’ve got good assets and even better people.
Still the divestiture was absolutely right for the company. Financially, the sales generated about $3.8 million in proceeds, including the sales of our remaining Tennessee oil inventory and we’ll increase our cash flow by about $800,000 annually, when you account for the CapEx that we will no longer spend.
More importantly, completed the company's transformation to an Alaska pure play. We believe firmly that Alaska is one of the best places to develop oil and gas from really two reasons and these reasons really resonate in this oil market.
First, commodity price is particularly gas as favorable relative to other areas. The structural reasons related to its remoteness and close with nature, gas in the Cook Inlet area trade for $6 to $7 per Mcf and that pricing isn’t tied to Henry hub. Our current $7 per Mcf contract isn’t above market. Think about this. Where else in this oil market can an E&P pivot gas as we’ll talk about since can get $6 to $7 per Mcf.
Second, Alaska partners with operators, not only from the safety perspective, but frankly, from the cash, financial and risk sharing perspective, depending on the type of well, the State finances with cash tax credit to 35% to 65% of well cost. The divestiture of our Tennessee assets, Millers become the most direct way for public shareholders to invest in Alaska’s hydrocarbon resources.
Beyond Tennessee, we also expect to close this month our acquisition of Savant Alaska LLC to what we believe will be a net price of approximately $6.5 million after considering adjustments to the May 1st effective date.
Remaining regulatory items are being finalized. This acquisition will immediately increase our production by approximately 600 barrels of oil per day net via 67.5 operating interest in the Badami unit on the North Slope.
Our new working interest partner Badami is one of the States largest employers. That partner is well anchored on the North Slope and we’re started to work with them done a lot to potential at the Badami field.
With the purchase, we also received 67.5% ownership and an operational control to 25 mile, strategically locate oil and gas pipeline, as well as state-of-the-art processing facility rated for 38,500 barrel bopd, that was built by BP in the mid 1990s at an estimated cost of approximately $300 million.
The facility is currently the easternmost active infrastructure on the North Slope of Alaska and is well-suited to accept third-party fluid. Importantly, we will also inherit a very strong team. We look forward to integrating the Savant team and planning our summer drilling program there.
As we noted in our press release, there is potential that we may need to raise modest amount of incremental capital, in order to finance the acquisition and ensure adequate liquidity, including the service of our debt and the payment of dividends on our preferreds.
Again, making sure we service our preferreds and our debt is paramount. It would be remiss not to update you on the Buccaneer bankruptcy situation. Long stories rewarded lenders ultimately credited the assets and are working to become certified operator. We’re monitoring how the situation develops.
At the very least we’re in the process of pursuing in bankruptcy all remaining claims that we had against Buccaneer under existing contracts and based on private negotiations with Alaska, we believe that we can get access to North Cook Inlet leases that Buccaneer loss during the bankruptcy process due to failure to meet its work commitment.
It’s important to note that soon our asset based will be stable to really the first time in the last year. We have plenty of opportunity with our asset and planned to focus our attention on responsibility and profitably developing them, particularly, our lower risk gas asset at North Fork.
So now the fiscal second quarter, thank God is behind us. Where are we? The management team were eyes wide open to our situation. To our mind, there’s 77 selling element that we’d like to address. First and most obvious, oil prices had a step change down over the last three year so much in the mid 90 to the low 60.
That only impacts the stock price for product that also frankly increases the fear element in the market, both with our investors and our lenders, which leads to a second point. We’re well hedged. On October 31, we had approximately 390,000 barrel hedged at $98.71 for the remainder of fiscal 2015. Approximately 788,000 barrel at $95.36 for fiscal 2015 and approximately 233,000 barrel at $93.97 in May 2016 through December 2016. Well, it spills into our fiscal 2017.
We also can sell the majority of our gas under term contracts currently priced at approximately $7 per Mcf. Currently more than 90% of our oil production is hedged. With a more gas focused drilling program, we believe that our oil production will remain more than 50% hedged through at least the fall of 2015.
Placing my third point, we get it. Our last well has not gone as planned. In retrospect, we perhaps took on too much risk with RU-9 to preserve the southern unit of our Redoubt field. We also in hindsight probably shouldn’t have drilled an exploratory well like Olsen 2 that given absence in Midstream infrastructure, we had no chance for new term production in cash flow.
Simply put, our operational credibility is low at best when we get that. That said, our team has drilled successive wells in the past. Most notably, Sword and WMRU-2B and we will do it again. We have a good team. We are adding two team and we are confident we will succeed.
Now let’s touch upon point four, liquidity. Company’s borrowing base remains $60 million. Our next re-determination is February 1. Currently the company has approximately $10 million in cash, $36 million drawn against the $60 million borrowing base and the cash tax credit application at approximately $21.2 million that we expect to receive in late January or more likely early February and the $20.6 million that we expect from July.
Additionally as we do in our normal course of business, we’ll be applying this quarter for a state NOL tax credit. Again, like every other E&P company, we got an eye on liquidity.
Our amendment to our credit agreement places some restrictions on our ability to access our full borrowing base as well as news of our near-term cash tax credit receipt. Additionally, we are well aware that our borrowing base re-determination in February -- January and February is downward revision risk, given run-off oil price moves in our recent drilling results. We have options. First, again our CapEx was substantially discretionary. You can dial back the plant we’ll outline shortly and I will tell you where we would.
Additionally, we have a 100% working interest in all our properties except the Dummies where we will have a 67.5% working interest. There are parts. Interested part of what we got and we are actively exploring those and other possibilities. Again, two of the thirds of dividend is sacrosanct. That’s not level we are looking to pull lightly. We take again our obligations to you and our lenders very seriously.
Business leverage, we are currently just under 4.5 times of LTM EBITDA as per the definition of the credit agreement. We plan methodically to work that down by growing the denominator, i.e. growing our production and cash flow. As noted earlier, we are shifting our operational priorities away from reserve growth into production and cash flow to ensure this. And we’ll also insure that our drilling risk was appropriate for our balance sheet.
Sixth, our stock volatility. We have a predominantly retail shareholder base. We are looking to grow an institutional asset base. When our stock pass below $3, post Thanksgiving OPEC decisions, we triggered substantial technical driven and let’s just call it spade a spade, margin call activity.
Our volume to subsequent Monday, Tuesday and Wednesday was approximately 5.5 million shares, 2.4 million shares and 1.2 million shares versus an average daily volume of less than 500,000 shares 2014 to date. And as has been disclosed in Form 4s, the member of our current management had recent margin loan related sales.
While that executive continues to have loans against part of the shareholdings, he’s working on an agreement with the lenders to change collateral of those loans to prevent further margin call related selling. We expect there will be no further margin related stock sales by insiders.
Again, we expect there will be no further margin related stock sales by insiders. Moreover yesterday, our Board implemented the margin policy that will effectively prohibit insiders from marketing Miller shares otherwise borrowing against their share ownership.
Let’s talk about the path forward, my seventh and final point. Again, we are fortunate. We have a strong hedge profile, number one. Number two, we have a solid inventory of gas PUD. And number three, we have the ability to sell gas in a market in which gas trades for more than $6 per Mcf.
Because of those three things, we believe we are unique among U.S. public E&P. Accordingly, as we shared, we are going to dial back the risk and dial up the gas focus. So what that means specifically? First, we are going to focus on our North Fork onshore gas field on the east side of the Cook Inlet. While Scott identified more than six PUD locations and we believe drilling will prove out more.
The PUDs are approximately 5,000 to 9000 feet true vertical depth and are frankly fairly straight forward wells to drill. The existing wells targeting the same formations as our PUD have an average -- had IP rate in excess of 3.5 million cubic feet a day, the declines in the mid to high teen.
We spud a North Fork 24-26 well on November 26th. It should come online considerably by the beginning of February. We plan to bring another North Fork well online every two months over the course of the next 12 months. These wells will average in drilling cost about $9 million gross and approximately $6 million post the Alaska cash tax credits.
The structural gas price in the Cook Inlet area again is a substantial part of the story that we believe is overlooked. We think it would be hard pressed to find any other E&P company that can pivot their CapEx spending the gas and get $7 -- $6, $7 net. It’s a real advantage that we have particularly given the recent down dropped oil prices. We can overstate this. That pricing coupled with our inventory of lower risk onshore gas locations is the foundation of our path forward out of what we find ourselves.
Second, we are going to lower our risk at Redoubt. We’ll focus on lower risk sidetracks and other opportunities. Specifically we plan to drill RU-7, and the RU-6, RU-5, and RU-3 and RU-4 with one well about every two to three months.
Meet our return hurdle at current oil prices excluding our hedges, these wells need average an IP of approximately 260 barrel oil per day. We are looking to do well in excess of the return hurdle.
These wells are expected to have average drilling costs of about 12 million gross and 7.5 million post the Alaska tax credit. We expect to receive the appropriate permit for RU-7 in January, after RU-7 we are still assessing the order at which we will drill the other well.
Now, again, as we noted earlier, we have the ability to ratchet down our CapEx. That is the key lever to ensuring our liquidity in this oil and credit environment. And if we need to, we’ll defer indefinitely the Redoubt oil drilling to maintain adequate liquidity. Again, doing right by our preferred holders and lenders is of high important step.
Let’s not forget Badami, that’s key too, we plan on once we close that, drilling two new wells there this summer that needed IP of approximately 500 barrels oil per day to meet our return hurdle.
The nine producing wells at Badami IP between 600 and 900 barrels oil per day. We expect to have the wells that we plan will average -- have average drilling costs of $16 million net to Miller. In addition, we are also looking at a couple well workovers. The small portion of the CapEx will be near-term as logistics on the ice road in the North Slope require longer lead time.
Given our recent operational results, as well as current oil prices, our lenders have tightened as we mentioned the operational parameters in the credit agreement. In our APOD we are pre-approved the four Redoubt wells and four North Slope PUDs. As we demonstrate success, we set to have further wells approved in both areas. We are also in the process of educating our lenders about Badami and its wells, and believe they ultimately will be approved.
At bottom, we believe our lenders and our interest are aligned in pursuing logistically efficient lower risk wells. We both want more results and less risk. We had a strong relationship with our lenders and expect that that relationship will continue and they will continue to work closely with us.
Now it’s important to share what we are not going to do in the near-term. First, we are going to defer extended reach wells like RU-12 and Sabre until we have a few solid lower risk wells behind us and our liquidity and balance sheet are sufficient to weather the risk.
Second, as noted few times earlier, beyond minimum investments to hold acreage we are not going to drill exploratory wells like Olson Creek that have no near-term production or cash flow potential.
Don’t get us wrong, we like the risk reward of RU-12, particularly having RU-4 be at the fall back greatly reduces the risk drilling RU-12 and RU-12 extents our company to a fourth Redoubt fall structure and is substantially up our reserve both PDP and PUD. It’s now simply not the time to drill it.
We also haven’t forgotten Sabre. This is significant prospect adjacent to Sword and part of the prolific West McArthur River Unit anticline system. Indeed, we believe Sabre is one of our best prospects with the potential of approximately 40 million barrels oil in place and also a significant potential for gas.
That said, drilling Sabre from shore would be a long well about 22,000 measured depths with extended reach. It might make more sense to drill it offshore and we are evaluating that and very likely would make sense of drilling in a JV, we are actively exploring those options.
Above the ground as you know we have substantial midstream assets of 50,000 barrel per day processing and storage facility that’s state-of-the-art at Kustatan, a 12,000 barrel per day rated processing facility at West Mac, a gas processing facility at North Fork and 38,5000 barrel a day processing and storage facility at Badami, as well as over 100 miles of pipeline that we operate.
These assets have value, especially in the lower cost of capital structures MLP. That’s not near-term however. To optimize that value we need to drive utilization either with our own growth and volumes or with third-party volumes and frankly, probably, both.
Stepping back, business focus that value boils down to three factors, cash flow, risk and growth. Right now we are going to focus on the first two, knowing that we have plenty of opportunity for the third layer. The key element of driving cash flow and minimizing risk will be the wells we choose to drill, as well as maintaining a conservative hedge profile.
So moving away from the drill a bit, you should be aware of some organizational and process changes at the company. Organizationally, we are going to beep up the focus and technical resources in our operations. In managing our operations dealing with everyone from the State of Alaska, the partners, investors, the lenders, our Board, David Hall is candidly been stretched them.
We are in the process of identifying a number two, who will be a core member of our senior management and focus day in and day out on our integrated operations and provide David the support he needs.
Additionally, we are in the process of finding a permanent CFO who will compliment our strong accounting team with a focus on capital formation, corporate development and Investor Relations.
We get lot of questions about Houston and Knoxville. We like both cities. Look, Houston is arguably the center of the energy world and potential partner, to customers, to vendors, to service provider, that make them for us to have a presence there.
At the same time, Knoxville is our home and we have good and loyal employees here, who easily serve our shareholders, disrupting that make no sense. Process wise we've augmented the independents of our Board and we will continue to do so when appropriate addition is actionable.
More day-to-day we have modified our processes and share all available information experience perspectives or incorporate into a well decision making. We are no longer rewarding yes men, particularly on the technical side.
Additionally, we have instituted appropriate checks and balances. It’s what we would like to call structural attention. We believe these changes will inject more realism, risk adjustment and contingency consideration into our planning, both technical geologic and financial.
We have also tightly expanded the coordination between our finance and operation teams. We will operate within our financial reality and proactively rather than reactively manages spend commitments.
We don’t drill well like RU-9 without finance keeping the money. To keep that stuff from happening we need to fix both our operations and our finance, and we are doing that, is really about processes.
So we are going to track more real time our progress against schedule and budget. We are also tightening the processes around purchasing, inventory management and related party transaction.
We heard that these are investor touch points loud and clear, especially the last one. Internal audit will be focused on ensuring these areas are arms length and appropriate with the rest and the internal audit will have direct access to the audit commit chair.
Externally, we will continue to improve the timeliness impropriety of our communication with our lenders, shareholders and market generally. Indeed, we believe 10-Q filed later today will have improved disclosures, particularly around our assets impairment and our long-term gas contract among other areas.
We don’t like surprises. We don’t expect you to like them. We tell you the good, the bad and the ugly. Now that said, we are not going to become a PR stock. We believe fundamentals will win at the end and for us this only help communicate what those fundamentals are.
A quick few points in G&A, first, we care about it. We will work to trim it in a smart fashion. Indeed, in the last three months we have severed less critical consulting relationships that together will save approximately 800,000 annually and that excludes the G&A saving from the sale in Tennessee.
That said, second, our issues in our operations and our ability to invest CapEx in a way that earns adequate return. So to improve operational efficacy and financial reporting processes and soundness, it’s going to cost the money, near-term, but we think will yield substantial value for our shareholders.
Now here let’s pause to talk about 8-K, we’ve been on pace to set a world record with 8-K. That will flow. Our Board and management changes will subside. Additionally, we expect to have little to no future needs of disclosures about advisors and other consultants and insider dealings.
So going back to high level, we are going to focus on being deliberate in deployment of capital to drill safely and responsibly wells that are solidly cash on cash value accretive. Bottom line, we know it. We need to drill levels in an appropriate risk for our balance sheet within an appropriate timeframe on an appropriate budget and within appropriate result. It’s more about locking and tackling than catalyst.
So with last year or so, we’ve had plenty of distractions, including shareholder activism, Board management changes, the CFO departure, the recent oil downdraft and margin loan entreated sale. Those distractions are, we expect largely behind us, so is our plant is being sold.
Stabilizing our management and Board have an asset-based both below and above ground affords substantial opportunity. Final point, we are going to strive the under promise and over deliver going forward and when we don’t, we tell you why.
So, thank you again for your interest in Miller Energy Resources, as well as for your patience with what has been a long prepared remarks. Operator, if time left, let’s take some questions?
Thank you. [Operator Instructions] And we will take our first question from Neal Dingmann, SunTrust.
Good morning, guys. Good detail call, I will say. Carl, can you walk through, I guess, you mentioned about obviously you are now focusing on the near-term launches and cash positive wells that can obviously generate the cash flow immediately? I guess, I’m struggling now just looking at sort of -- you mentioned the near-term having to raise some funds through preferred. I guess what I’m trying to -- without any guidance out there, trying to get an idea of either for, I guess looking at calendar ’15, CapEx versus if you drill some of these smaller wells, I still I’m showing a pretty severe outspend.
So, I guess I’m trying to wrap my hands around, number one, what you are showing as far as upcoming wells here I guess, call in the next six months, nine months, maybe potential production around that, I mean to wrap up into something too detailed there? And then the potential outspend that you are thinking about, let’s call it the next 12-months or so, especially given the current oil environment?
It’s a fair question, Neal. Maybe clear, it’s not clear to me. We need to raise preferred. So we spend a lot of time with the management team and Board talking about is what are our downside self-help ways. What can we do to work way to a much more cash flow positive company over the next year without realigning on any external capital?
Let me walk you through downside scenario, okay. And this could be a little bit of cartoon map, but I think it will be instructive to give you comfort that we can get through this. All right. Let’s just start with what we currently have. Mostly it’s the Dummies to decide somehow, okay. Our current net NIR production is approximately 3.3 thousand barrels of oil equivalent per day that excludes the volume.
Roughly, it’s 50% oil and 40% gas, okay. So that production on the oil side is our hedged distributor price. So we can model our hedges in another world. On gas, it will be about $7 and as I mentioned, again, on an incumbent gas production. Now, additionally, we are bringing on a North Fork well every two months as we mentioned, starting the 1st of February to be conservative.
We’ve also told you in the call that represented wells at North Fork [indiscernible] greater than 3.5 million cubic feet equivalent a day. We think we can sell their gas at 650. We have discussions and actually contracts in place to do that. The well cost $9 million gross and $3 million with the tax rebate that will get about five months post completion.
So all the wells located assume roughly 15% to 20% annual declines. They are incumbent and do that on the new North Fork wells. And just obviously make that monthly. The OpEx will not be 29 going forward. It will be closer to 22 on a Boe basis. The cash G&A were not going to be $10 million a quarter. It will be closer conservatively $2 million a month next quarter.
If you do the math, by calendar year end you should see our net NRI exceeds 5,000 barrels of oil per day equivalent and you will be nearly surprised by our EBITDA. Now when you do this math, you’ve got to make sure you get this tax credit mentioned, both the 21.2 to 20.6.
You got to give yourself a $3 million lift from the state for five months in order to drill each of these wells. And then you’ve got to think through -- trying to assume what will be the same NOLs tax credit we got last year. If you do that, we will be a radically different company a year from now, just doing that. That doesn’t require any external financing, doesn’t require any Redoubt wells.
Got it. No, that makes sense. That makes sense. And then two more questions and I will turn it over. Just on acquisitions, obviously you guys have been active now. Is it suffice to say that you are just going to sort of keep to what you have after having the Dummie, the North Fork and the other acquisitions, you guys have set pretty much now and you will try to just obviously operate what you have?
As a company, we have had ATD. We are going to take a little in, okay. We are going to focus. We need the lock and tackle. We have plenty of opportunity on our play with the assets we have. Now we are going to dominant, if a great deal comes by, another Buccaneer comes back that fits like a glove and we can buy for three times cash flow that it’s quite accretive, absolutely.
We are not an M&A company. We are a production company.
And then lastly, it’s evident, I think everybody looks at the assets, the sea as you mentioned above ground what you have in infrastructure and others. Is there anything in the near-term what we’ve heard for a number of quarters, the potential about some sort of deal around this? But, again, is this anything that’s realistic that we could see in the next couple two, three quarters? Or is it just something that, again, we understand the potential value of these assets, is there anything in the near-term that we could see, I don’t know either through a JV or at least some of the use in some of your infrastructure as a third party?
So let me break that up in two parts. I mean, it makes a lot of sense for someone else use our infrastructure and that’s something I think you could see in that timeframe. JVs are unpredictable candidly. People don’t want to see how we work on our own before they help us out. So, I’m counting on JVs right now. But we are actively in dialog with them but we will see where they go.
All right. Very good. Thanks Carl.
And we will take our next question from Kim Pacanovsky with Imperial Capital.
Hey Carl. Good morning. Just back to the approved activity that was approved in lending agreement, what would that come out to be in CapEx?
I’ll hand it to Dave. He will be there for you here in a second.
Okay. All right. Great. And then also you mentioned the couple of one-time….
Kim, I think we are going to answer -- I don’t want to give the specific wells. What I might do is -- let's just do it this way. If you go back -- I’m starting to interrupt here and I’m looking back in my prepared comments. If you go back to a plan, we kind of gave you in average, $9 million for North Fork, $6 million again for those, if you do that math. And then we gave you the average cost for the Redoubt wells that we named so just to four of those. I think that would get you to the CapEx number.
What we are trying to do is give people guidance. We need to understand what we are investing in. At the same time, we don’t want to have overemphasis on any one well like we’ve done in the past. The e whole cult of RU-9 was not particularly helpful.
Okay. Great. All right. That’s helpful. And then on the LOE side, you spoke about underwater inspections and pigging. And I think there was one other item that was not a regular occurrence. What is the -- you said these things are every two years. Pigging is ongoing all the time. What’s the difference between the pigging that you did now and ongoing pigging you are doing and also on the cost side?
Yeah. Kim, this is David and that’s a good question. As far as pigging and this is like your normal everyday pigging which we do as well. The pigging that Carl’s referring to is smart pigging that’s required every five years.
Yeah. There were some additional work too. For example, we did some sub sea sections on the platform legs as well. That’s normally done every three to five years.
Okay. Great. And then, your last winter was fairly mild and as I recall and tell me if I’m wrong you didn’t have really huge spikes in the gas market. What was the variation in the gas market, spot market last winter in pricing?
Yeah. As far as pricing, I mean, the overall average pricing for the Cook Inlet things remains between I would say 650 and 700.
Okay. That’s very stable. And then can you just give us a little bit more detail about your ability to lock in pricing. You had mentioned that you are working on some of that. Can you just add a little bit more color there? I think that’s quite significant to be able to lock in pricing as you’re drilling?
Yeah. We signed a contract earlier this week, right, David, with the significant industrial user. What’s interesting about that contract is it will grow with our growth in North Fork. We are very excited about that contract in terms of volumes.
We’ve been talking to Neal and giving him some color. It wasn’t hope on the pricing.
Okay. Great. I’ll turn it over to someone else. Thanks a lot.
And we’ll take our next question from Curtis Trimble, Brean Capital.
Thanks. Good morning everyone. Just looking at the tax credit in relation to the outstanding borrowing base, understand that $21.2 million receivable has started to pay down the $36 million. Is that going to be the case for the time being with subsequent tax credit as well or are you more proactive?
No. Look, as I’ve mentioned, we’ve been negotiating with lenders, I want to say for the last month and for better or worse and it’s just wise. Oil markets got a little bit scarier in the last two weeks, okay. The level of determination and as we don’t want to be over extended and our banks don’t want to be over extended. So the way that works is we get that $21.2 million before the determination and we have immediately paid down but then we can draw back up.
And then if that tax credit comes after our borrowing base is redetermined with no impact. That will become clear that when we get that agreement filed. But it will definitely be today. 8-K, that will be good 8-K. It will be clear. Nothing funky.
Good deal. Then looking at the Badami, where you can sit with the 500 or so with AIP and required rate of return, can you ensure the required rate of return that you’re looking in that is…
I mean, the way we’re trying to look at things, we’re just trying to say okay and looking at all the great cost of capital on different times, it probably varies. What do we need to get 20% cash-on-cash return? What’s the minimum? And obviously, we expect something significantly higher than that internally. But we’re just going to go and start giving guidance and kind of what we need to make the well economic and online.
And that’s part of what we hope will be the path to kind of under promise or over deliver. And now as I was telling we can, we need to give you guidance. We don’t want to start telling people whether we think this will be 750 or that will be 600, that will be 900, that will be 200, no, we’re not doing that.
Hope that will allow you to model and give some clarity of the evaluation that we think you can drive with this plan but we do have to execute. And I think we will.
I appreciate it.
You bet. Thank you.
[Operator Instructions] And we’ll take our next question from Jonathon Fite, KMF Investments.
Hey, good morning, Carl. Carl, thanks for your time this morning.
Thank you for your interest and being patience.
Actually, I really appreciate the candor not only about the kind of updated focus of the organization but also from the process changes and organizational control that have been put in place. We really love to hear that. A couple of clarifying questions based on what we heard from you this morning. You outlined kind of a downside scenario, right. This was kind of -- you believe what you guys can fund within your existing cash flow envelope. Walk us through an upside scenario, what does that look like? Is that something you don’t really want to touch today just because we want to focus on basic blocking and tackling?
Yeah. I mean -- I haven’t got to think about the upside thing since I got here. Jon, more of it is joke. I don’t have an answer. So first, let me -- before I give that questions, it’s a good question and I’m going to think about to give you hopefully deepen answer. And on this process changes, this is not Carl Giesler riding in on a white horse with some bull whip. I mean, everybody on this company from Scott, Deloy, David, Jeff, I mean everybody, Kurt, is onboard. I mean, onboard. This is one of the refreshing things about my three months here is just the alignment. Yeah, we know we need to do, let’s do it.
This is not someone coming in and changing things. We see someone coming in, have the capability, they really want to do. So I think that’s important to know we are not yet resistant. And I think that you will find it no matter, who you talk in the organization. So once that’s been cleared, it’s not a Carl Giesler thing, it’s the management thing.
Now more to your point -- hold on one second, I can give something that can help you answer your question better. Bear with me for one moment.
Okay. Let me kind of walk you through what we’d like to do we could, all right. I got APOD, I know it. I got capital constraints, I know it but look all those factors and gosh, we probably do listen for adding. We got North Fork 24, 26 going. Then I’d look to move RU-7 sidetrack and frac that and everything got really worse. That does really opens up, frankly everything we drill in the Redoubt, kind of, we get to do it again and do it better.
Then our new couple of more North Fork PUD, then maybe RU-5 and another North Fork PUD and then late June, sometime maybe Badami well, maybe RU-3, another North Fork PUD, RU-6, North Fork, maybe Badami well, Badami frac and by then, hope you got some success and got some confidence and done all. We are aiming to try and extend RU-12 with a fall back with 4B.
We actually think RU-12 should be lot easier, which will be angle and azimuth and frankly we restored a length in RU-9. But again we’re not doing it soon. And then we try to do another North Fork PUD and Badami frac and then entire RU-4. And immediate to that, we went through variable assumptions, given what I’ve told, you can probably create your own model. And you know our NRIs, et cetera et cetera. And we think we could be well north of 7000 barrels a day equivalent net NRI. And or by the way those wells that I outlined, because number of them are gas, there are still 40 hedged on oil. We run the numbers on that and why does stock have one handle on it. But anyway, we got to prove it to folks.
So a lot of what I heard there was really the incremental Badami, some of the stepouts are long-reach Redoubt wells, right. But the North Fork…
That’s not what you heard. Basically, you heard what I said, I mean, most of what I said is North Fork PUD and low-risk Redoubt. I mean, there is only extended reach of Redoubt RU-12 and then we will think that Badami wells are actually kind of more extended to the North Fork wells. Now, we got to hear lenders walk through that in front of what we messed on the APOD that he was having, given the information, shame on us.
Are those North Fork PUDs are different from those four existing North Fork wells you are planning this in the kind of down type material?
Yeah. I mean, listen to this. Think about it from a lender’s perspective. They’re limiting to us to four. I mean, generally we can drill a well there. They don’t want to get really talent on. They want just offshore thought. Do you know what that mean? I hear it but we don’t form its own and then we say keep on going baby. We are trying to make wells.
In that downside scenario, kind of a four by four, the four North Fork wells and the four modest things on Redoubt. Does that basically just burn through kind of ADP?
That’s from a downside. That’s from our downside scenario. That’s APOD.
That’s what we’re currently [indiscernible]. The downside, he is down with that. He is like, you just don’t get capital or field stocks and we just stay away from Redoubt and we’re just going to walk over block and tackle on our North Fork PUD, build our cash flow, build our production and then get a little bit more liquidity, little bit balance sheet because we just can really give much more liquidity to our lenders. They are timing up. The preferred market is closed. We can’t do anything to accelerate. That’s our downside.
Great. And that’s basically -- and now basically just goes through or takes advantage of the kind of the PDP stage that doesn’t necessarily growing in those reserves for these other things, we’d not only drive the cash flow but would be reserving for you?
I don’t think it’s entirely true. I do think as we’ve driven our success. We’ve developed some PUDs and move PUDs because I know, you’re not -- you're right. That’s not going to be a game changer. Let’s just think about what we’re doing here, okay.
All right. I mean, we’ve just gone through shock therapy over the last three months. Okay, now I think it’s a pretty viable plan. If things stay like they are, we have a pretty good plan. And things go how we would like them to go base case and once we’re doing that, we’re up the production, up the cash flow, lower the leverage, got credibility back, become investable company. If the CFO leaves and I’m not sure about our material weakness disappearing this year, but it’s hopefully, frankly functionally, I think well in our way. I mean, all that feels good and then for years now, we’re just kind of getting back to be regular company. And then never get to start talking about fun stuff.
I mean, here we have been talking about Sabre and that kind of stuff or Badami, what the heck means to have a eastern most processing unit over there. I mean, that’s all good stuff that has lots of growth. Like I said, we’re focused on risk and cash and we got growth later. I’m not really worried about doing reserves in next year and reserves of our cash flow and production.
We love the change your focus and we love the unified approach. I know as a management team and the board, we look forward to the execution plan bearing out over the next 12 month. Thank you, guys.
Maybe, thoroughly. Thank you.
And we’ll take our next question from Kurt Caramanidis with Carl M. Hennig, Inc.
Very good. Welcome Carl. One of my questions is the RU-9. I’m wondering what looked good there early to give the indication of post drilling? And is there anything left there? We’ve got now the electronic failure different pump. But I’m just wondering what we’ve seen and where we are now a little more specifically?
Yeah. Let me deal with that. First of all, look, think about we had a really good WMRU-2B and Sword and frankly in WMRU-2A initially. And we needed to reserve that southern unit for the Redoubt structure. And really third party review the prospect, the decision was made to have a little bit restrospect excessive confident to drill RU-9.
All right. Now what happen is we’re drilling and logging, we saw potential loans in both the Hemlock and Tyonek. First, we perforated test with deeper Hemlock and we found a really high quality oil with an extremely low water cut. And frankly, the initial flow rates are necessarily pretty eye popping but then they became variable, which indicated some formation damage around the well below which can happen.
So after some initial encouragement, the formation management said we’ve got to deal with that to decide to re-perforate the Hemlock and run a reasonable analysis. I know you were at it. We said also perforate the Tyonek before running completion. Somewhere as it occurs, they are running a good bit of water because all cut went way down. We’re still kind of think 1000 barrels of fluid a day with increase in oil cut.
And actually the properties look a lot like the stabilization pattern of RU-7. I don’t want to get too excited by that. Because right now we’re about 100 barrels a day before the thing shut down. And we expect that it will start to go up. RU-9 ever been did well, no. Okay, well, but there is no big -- yeah, we’ll do that again, no.
And right now frankly with our capital, we’re just not go back there and fix it until we can find a way that will be very efficient. And frankly convince the lenders that we can do it efficiently and that make sense on cash-on-cash return. I’m happy do that because I convince myself that make sense and our board to make sense a little basis. So I hope that answers your question.
Yeah. No, that does, I appreciate.
I was hoping next quarter was -- are you not going to fix that, it’s actually 500 barrels a day.
Yeah. No, I appreciate. That does clearly make sense. The only thing that I’m looking at is the uncertainty you did a very good job explaining the runway, the cash flow and things. We kind of have the remaining to raise capital overhang. How long might that be going on?
Well, we not say, we raise capital, I mean, a band aid that preferred that market opens up.
Right. But I mean, will there be a time in the near term that whether it’s the February deadline or the date you got coming up where we might have some clarity that that’s not needed right now. It’s a potential band aid and that I just know that typically that can be an overhang if it’s just left out there for ….?
We kind of confounding words, I mean, sometimes my son does is when he needs and what he wants are really different things. We really don’t need capital. With the way, our lenders are giving us, we’ve worked with them and they timed it and that’s workable. We can do that North Fork only plan that I laid out and get through it and cash and grow away out of it.
And again, the transcript, or call replay to listen carefully what I was saying every two months, do you need historical wells and just making some assumptions like analyst do. And I think you have a decent picture. So I don’t think we’ve need if you will more capital. All right. And I do think in the plan that was asked earlier what will be upside case or even your base case. Yeah, we need to bring in more capital liquidity kind of get that going and that’s what the growth with E&P companies do.
And if we don’t get that, I think, it will be fun. And the other thing you got to understand is, I mean, at the end of the quarter and the end of October, our hedge book was $23 million and we look what has happened to oil since then and I am kind of kicking myself for not having calculate it but I would not be surprised if it starts before hand.
Well, that’s good. I appreciate that clarification.
No. I just want to be clear our hedges we don’t look at that, but the worse time are worse as liquidity needed…
Okay. Well, that…
… we’re not going to do that, but there are options again.
Yeah. Thank you. I appreciate. You are hard work and crop shall.
There is a lot of people working hard. We appreciate you are working with us and I need if you guys either.
No. It’s not.
And we’ll take our next question from [George Gasper] [ph], private investor.
Yes. Thank you. Good morning. Carl, got a couple of questions here. First, this might require some thought process by your staff there. The drilling equipment side of the investment debt the company has? Can you highlight what the platform drilling equipment, including the rig is worth and then go through the land rig that have been acquired? And you mentioned in your presentation that there’s going to be some movement of one rig potentially back out of Alaska? Can you highlight where the land rigs are going to be used and what the investment is in this whole situation at this point time both land rig and the platform offshore rig?
We are bifurcated. I’m going to take a couple of part and David Hall can take some parts.
The rig 34 stacked one venues you kind of look at, why is it here if we are not using it. So bring it to down to Tennessee with lot of founders [indiscernible] can do things. He can eat stake and he can sell rig. So he used to do that here in Tennessee. Is not going to be a big number, is the better than we get stacking up there, that’s number one.
Number two, in terms of investing in rigs going forward that can happen anytime near-term. We’ve invested in rigs and we’ve got good rigs and we are going to work it. So I think we’ve done investing in rigs. And with that, I’ll turn it over David talk to you about the value of the platform and Rig 36 and Rig 35, which I think are two big ones right now and 37 place.
Yeah. Happy to, of course, Rig 37, previously known as a Glacier Rig that we acquired recently and then conducted some refurbishment to the rig and recertification. It is in tip-top shape working at North Fork drilling our first well 24-26. It’s pretty valuable in our mind if they had replace it today would imagine it would fetch over $10 million.
As far as turning to the Osprey with that Rig 35, which is a 2,000 horsepower and National 1320 Rig that we actually had installed in 2012, that rig too is very valuable to us as well. And I think it is well-suited to drill any of our plans that we’ve identified at Redoubt.
As far as the value of the rig, I would estimate that rig as probably can replace today with cost at least $20 million. I think, we’ve got good iron, good rigs and good people to run those rigs.
As far as the platform itself, that is the newest platform in the Cook Inlet installed in 2001, put online in 2002, that’s a single day platform. I believe, if you had replace it today with cost to several hundred million dollars. The thing about the Osprey platform, it has lots of room for expansion, with that at least 13 slots on the platform that we could drill.
And David, let me just clarify something someone in room here just had little confusion. When I was talk about four hand I’ll talking about the value of our hedge book. Now, well I think all is going to, like a predicted price all have been doing some else.
Okay. Could I just -- can I just clarify on rig view. You are talking about Rig 35 and 37? Is there not a third land rig or am I confused on this now?
No. You’re absolutely right, there is a third rig that we acquired last year, I’m sorry, this year. Rig 36, we required last from Baker. Since we acquired it, the rig has been undergoing some renovations and modifications and is about 95% complete with that work. The rig is currently in the Nikiski and our North Yard and right now we are soliciting to try and lift the rig out to others.
I got you.
We originally acquired the rig, so it could be capable of drilling Sabre prospects, but as Carl mentioned, we are looking at all of our opportunities there.
And what was the cost on that particular rig?
It was approximately $8 million.
Okay. All right.
It’s got about 2,400 horse power rigs that can drill some extended reach wells.
Okay. All right. And then Carl just another question on the Savant closing, which is still targeted, I assume by the end of the month. You can clarify that if that’s incorrect assumption. Looking at the accounting on it, that closing is supposed to back date to May and that production that’s been accumulating, you haven’t accounted for that. How will that be reported once the acquisition is concluded? Can you relate that?
Yeah. I mean, essentially -- actually, we expect to close it this month. We are working through the various filed regulatory approvals. The way it works is cash flow is generated from that production is netted out as technically a purchase price adjustment. That’s why when I mentioned in the prepared remarks that we expect approximately 6.5. If we go back to the May announcement, it was 9 million. The delta is that the cumulated net cash flow, that approves us for the May 1st effective date.
Okay. And so you are saying $2 million net cash flow to Miller?
Yeah. And I will just be clear. That’s just the cash flow that this particular year since May 1st, when we expect to close, we think that will be accumulated that it will take nine to deduct that over to 6.5.
Yeah. That’s full quarter.
I see. I see. Okay. All right. And is there any question about this closing by December 31?
As far as M&A, there’s always questions. We will tell you what we expect in good faith and we think the regulatory hurdles are small and it’s just not that big of a deal. So we think we will be able to finance it.
Including sales out there.
Now the indication was 600 barrels a day, if I recall, you can correct me if I am wrong. Now that we’ve got a lot of months that have passed since this agreement was made. And as you look at this at the end of this month, what’s the variable mix in terms of the net production? I knew that you would expect on closing versus what was originally when the deal was cut?
I mean, it is pretty close to one yet. In my prepared remarks, I very deliberately mentioned that we are getting a talented team along with this acquisition and you asked me what does talented mean. It means they keep that production flat.
Got you. Okay. All right. Okay. So we can assume that it’s pretty much and even plane across the…
In all. And its reservoirs declined but they keep it pretty flat.
Got it. Okay. Thank you.
You are welcome.
And we’ll take our next question from Jim Collins, Portfolio Guru, LLC.
Good morning, guys. Thanks for taking my questions. Just a follow-up on the last question. You mentioned, Carl, 6.5 million as the closing price for the Dummies. And in the press release you mentioned, possibly having to exit the capital market to get that 6.5 million. So can you just tell us what I am seeing the fleet forward at 24% yield at Sabre had one handle, where do you get that 6.5 million that you’ll presumably need by year end?
We likely do not need to raise capital. We think we can do it with the options that we have afforded to us with self-help, okay. In this credit market and this oil market and with our recent history, we are working with our lenders on what levers they’re going to let us pull. And we think we have some very viable options that self-help and don’t require raising preferred on a marketed deal and certainly don’t require selling the month 20 or whatever it is equity that we can do. And at the same time, we will be responsible for our balance sheet and believe me, if the preferred market opens a little longer and hard of that, but we got to restore some confidence so that the pricing liquidity comes in. So, I would say that language with abundance of caution.
Yeah. So, I mean I am just trying to figure out obviously because there have been things where you said, when you talk to lenders you’ve got a PUD and that’s what you are looking at through 2015, when you talked about adoption, I’ll check with you after I write in the next couple of weeks, so that…?
We got liquidity. We can write that check. Again, I think we obtained that in cash right now. We had a bond base term back on. We could write that check. I just want to make sure that we can fulfill all our obligations that we’ve talked through, for example, what we do in various contingencies. That’s all.
Is there any conceptual way that you could just not close on Badami, walk away, if you will?
I want to do that.
Okay. So that’s not an option that you are considering?
That’s what I said is I want to do it.
Okay. That answers my questions. Thanks a lot, Carl.
That’s all the time we have for today’s call. Mr. Giesler, at this time, I will turn the conference back to you for any additional or closing remarks.
A - Carl Giesler
I think we’ve heard enough of me. So thank you all very much for your time and we’ll talk to you next quarter.
This concludes today’s conference. Thank you for your participation.
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