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Magnum Hunter Resources (NYSE:MHR)

Q3 2013 Earnings Call

November 08, 2013 10:00 am ET

Executives

Chris Benton - Assistant Vice President of Finance & Capital Markets

Gary C. Evans - Chairman and Chief Executive Officer

R. Glenn Dawson - Executive Vice President and President of Williston Hunter Inc

James W. Denny - Executive Vice President of Operations and President of Appalachian Division

Joseph C. Daches - Chief Financial Officer and Senior Vice President

Analysts

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Gabriele Sorbara - Topeka Capital Markets Inc., Research Division

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Irene O. Haas - Wunderlich Securities Inc., Research Division

John C. Nelson - Citigroup Inc, Research Division

Stephen F. Berman - Canaccord Genuity, Research Division

Chad L. Mabry - MLV & Co LLC, Research Division

Operator

Good morning. My name is Keela, and I will be your conference operator today. At this time, I would like to welcome everyone to the Magnum Hunter Resources Third Quarter 2013 Earnings Conference Call. [Operator Instructions] I will now turn the call over to Magnum Hunter Resources.

Chris Benton

Good morning. Today is Friday, November 8, 2013. This is Chris Benton, Assistant Vice President of Financing Capital Markets at Magnum Hunter Resources Corporation, and I would like to welcome everyone to today's conference call. I will be the moderator for the conference call.

The principal purpose of today's call is to discuss our third quarter 2013 financial and operating results, among other matters of interest regarding the company. We announced these results in a press release, which we issued earlier this morning. The press release is posted to the company's website.

Before we begin our presentation, I would like to advise you that today's call will include forward-looking statements within the meaning of the federal securities laws, specifically Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Our presentation will include statements regarding our projections, estimates, expectations, beliefs, assumptions, intentions and future strategies. These forward-looking statements will relate to, among other things, the company's revenues, production, capital expenditures, liquidity, drilling results, estimated reserves, anticipated sales of noncore assets and other upstream and midstream operational matters.

These statements are qualified by important factors that could cause the company's actual results to differ materially from those reflected by the forward-looking statements, including those factors set forth in the risk factors section of the company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012, and our other SEC filings.

The 2012 Annual Report on Form 10-K also includes a glossary of certain industry terms that may be used in today's conference call. The full forward-looking statements disclaimer is included in the company's press release issued this morning. This disclaimer is in effect for the duration of this conference call.

Our press release also contains, and our presentation today may include, statements regarding certain non-GAAP financial measures. As part of the press release, we provided reconciliations of these non-GAAP financial measures to their most comparable financial measures calculated in accordance with GAAP. We refer you to our statements in the press release and in the related Form 8-K we filed today with the SEC with respect to the press release regarding these non-GAAP financial measures, which statements include our reasons for providing these non-GAAP financial measures.

I will now turn the call over to Gary C. Evans, our Chairman and CEO.

Gary C. Evans

Thank you, Chris, and thanks to all of you for dialing in this morning. We did announce our results for the third quarter early this morning. We'll be filing our Form 10-Q for the quarter by the end of the day today.

Oil and gas revenues for the quarter were up substantially, 80% to $54 million compared to the third quarter of 2013, where our revenues at that period were only $30 million.

Our midstream division continues to grow, obviously, due to the growth in our Marcellus and soon-to-be Utica production over in Ohio, and it was up 148% to $12.5 million for the third quarter compared to revenues of $5.1 million last year.

Our adjusted EBITDA was up substantially as well, to $28 million, almost 30% compared -- 100% compared to $16.7 million last year.

Our adjusted net loss was $0.17 per diluted share for the third quarter. Production of 10,049 barrels of oil equivalent and, adjusted for all the shut-ins we had, was 13,700 barrels a day equivalent for 2013.

Just to touch a little bit about what the adjustments were, we highlighted in some 8-Ks earlier in the -- before the end of the third quarter that we had been shut-in the MarkWest, which is our only outlet for our Marcellus, as well as our Eureka Hunter Pipeline at this point, in West Virginia around the mid of the quarter. So around mid-August, we'd lost about 45 days of significant production to the tune of about 4,000 barrels a day; if you averaged out the quarter, about 2,000 barrels a day. So that's what hurt us to a large degree.

We also made a decision, because we have moved to divest so many properties that we deem to be noncore, to go ahead and write down assets and put those -- kind of clean the house and be prepared for the growth that we see coming in this coming quarter, the quarter we're in today, as well as 2014. So we really wanted to clean up the balance sheet, and as we continue to accelerate these divestitures, which I'll touch on in a bit.

So all in all, it was a noisy quarter, as I put in my quote today and I think some analysts are picking up. But that's really not the company. The company going forward is production growth that's substantial. And we're going to talk about the new wells that are coming online just this month and next month that will push us to that 23,000- to 25,000-barrel-a-day equivalent at the end of the quarter.

So I want to give our 2 operating heads an opportunity to talk about what they've been doing in their divisions. Glenn Dawson, who runs our Williston Basin division based out of Denver, is on the call and will update us on his operations. Glenn?

R. Glenn Dawson

Good morning. Thank you, Gary. That was a very busy quarter for us up in the Williston. We drilled 13 gross, 5.1 net wells. Of those, we operated 2 gross, 1.8 net. So we've got the 3 rigs active, and we are operating at double on 1-mile laterals. We're also moving in a new state-of-the-art triple next week to start drilling 1.25- and 2-mile lateral wells in the Bakken and in the Three Forks. So we're looking forward to that event.

On the quarter, we did complete 11 wells in the Middle Bakken, which is our -- is a big focus for us in our new Middle Bakken play. And those wells average an IP24 rate of 600 -- 768 barrels equivalent on a 24-hour basis. We also completed 12 Sanish/Three Forks wells, and those wells on average for 24 hours did 640 barrels equivalent.

Our production for the quarter was fairly lumpy as we're doing a lot of ECO-Pad drilling and ranged between 4,500 and 5,500 barrels a day. Our current production capacity is around 6,000 barrels a day, and we are forecasting an exit of 7,000 barrels a day equivalent. And I'm confident we will make that based on the number of wells we have to bring on this year, which Gary mentioned earlier is around 20 gross wells.

We're super focused on cost control. I believe that's really what it's all about to improve our rate of return. We are seeing AFEs from our operators in the $6.5 million to $6.7 million range and execution as low as $6 million on some of the 2-mile laterals.

Our current AFE for our first 2-mile lateral well is $5.95 million, and we think we can execute on that AFE. So certainly, quarter-on-quarter, cost reduction over the past 2 years. Other areas of cost-focused reduction would be in the ancillary services area, specifically with natural gas conservation. The ONEOK system, which was delayed for the startup of April of this year, is now up and active. In the Samson-operated area, we have 51 of 95 wells currently tied in and we project 75 wells to be tied in by the end of 2013.

In the Baytex-operated area, 33 of 76 wells are currently tied in and we project 45 wells to be tied in by the end of the year.

We expect all wells will be tied in that are on the line system by the end of the first quarter 2014.

So what is the magnitude of this production? On a gross basis, those parties are moving 9 million to 10 million cubic feet of gross gas through that system, and about 5 million to 6 million is still currently being flared. We have between 10% and 50% of the total throughput on this stream.

Some other things that are worthy of mentioning is that the anticipated Btu content of 1,450 has been upped based on gas analysis. We're now thinking on average last month's plant statement saw about 1,500 Btu content, and we know we have wells up as high as 1,700, which will give us more liquids from that stream.

Other notable events coming in 2014 will be the addition of an oil-gathering system that we're currently negotiating with a third-party in Divide County. And we anticipate this will reduce our costs in the bottom line of about from $2.50 to $3 a barrel on trucking savings.

So really, that's it, other than the pure focus on getting the remaining 20 wells on production for the exit numbers.

Gary C. Evans

Thanks, Glenn. And I want to emphasize something that Glenn mentioned, just to make sure our listeners understand the gravity of it. When we started drilling wells up in the Williston Basin 3 years ago, we were approaching total AFE cost of around $9 million. We're now approving AFEs at the $6 million level, some at $5.9 million. So we believe that the substantial reduction in cost up there with commodity prices still in the $93, $95 per barrel range provide an exceptional return in this region.

And I think all operators in the Williston Basin are learning how to cut cost. We're getting better at what we do, pad drilling and using triples for rigs and just doing things much more efficient. And that obviously drives IRR. So that's what's got us really excited. And then you take all that, and we've concentrated in the Ambrose Field, where we've got hundreds of drilling locations and we're getting to higher EURs that cause us to get excited. So that's what has led us to sell off some of the French properties.

We announced early in the year that we sold leases over in Burke County to Oasis for $32 million. We announced that we're going to divest the Canadian operations. That's in the process of closing. So really homing in on the highest rate of return properties in North Dakota, and using a much lower drilling and completion cost gives you a much better return.

With that, let's jump to Glenn -- to Jim Denny, who runs our Appalachia operations. Jim?

James W. Denny

Good morning. Thank you, Gary, and thanks to all for joining us on this call.

In the Appalachia and the Marcellus, we drilled 14 gross and 9.5 net wells for the quarter. We currently have 2 rigs running, 1 operated and 1 nonoperated. The operated rig is on our Stalder Pad, where we have already drilled a Marcellus pilot and a Marcellus horizontal well. And we are in the latter stages, maybe a day away from having the pilot on the Utica well down, and we will log that well and then plug back and then drill a Utica horizontal there. Both the Marcellus and the Utica, we plan to test here by year end. The nonop rig has drilled the top hole and is currently waiting for the big rig to drill the lateral.

We have moved heavily into -- their drilling rigs are down, but we've moved heavily into a completion phase. We are now zipper-fracing 8 gross, 6 net wells across our Marcellus acreage. Of those, 4 are on our -- and 4 gross and 4 net are on our Collins Pad, where we should be finished in the next few days. We have about 15 stages, total stages remaining on that pad. And then that spread will be moving to our WVDNR pad in Wetzel County, where we have 3 gross and 3 net to frac.

And then, of course, we have 3 that we have stimulated earlier in the year and are waiting for a sales line in our Ormet area.

On the land side, so we're bringing on a number of wells in the next 30 to 45 days. On the land side, notable for the quarter was our MNW transaction, which was previously announced, whereby we have 32,000 acres under contract and the closings are -- will be staged over the next 12 to 16 months and at a very favorable price, and we've already had 2 small closings on that acreage. So moving forward very nicely. That brings us to about a total of 112,000 net acres in the Utica, and that including that 32,000.

So that was the highlights for the quarter from Appalachia, and I'll be happy to take questions a little later.

Gary C. Evans

Thanks, Jim. So to summarize the drilling of the company in all divisions, the company currently has 5 drilling rigs running, 3 operated, 2 nonop. And these wells are drilling Marcellus and Utica, as well as up in the Williston Basin, the Bakken and Three Forks Sanish. So for the quarter, the company drills participated in a total of 28 gross wells, 9 of which were operated by the company, and we had 100% success rate on that drilling.

I would like to -- I'm going to come back to the Utica here in a minute, but I'd like to now give Joe Daches, who is our CFO now here, what, 4 months and running, probably seems like 2 years, and let Joe kind of update everybody with respect to our accounting department and what he's been doing since coming on board. Joe?

Joseph C. Daches

Thank you, Gary, and good morning, everybody. During the third quarter, we have made significant progress in improving our accounting and financial reporting processes and procedures. It is notable that not only have we filed -- we're filing our 10-Q a day early, but we have reported that management believes that 4 of the previously reported material weaknesses have been remediated during the third quarter. I also expect to be able to report additional progress on the material weaknesses by the end of the year.

Our external auditors, BDO, have challenged us to improve our processes. And during the third quarter, BDO has worked a lot of long nights side-by-side with my accounting team to ensure the integrity of our financial statements. The accounting concerns previously reported are a thing of the past. We are in the process of not only remediating all of the remaining material weaknesses, but we are committed to building a best-of-class accounting and financial reporting season [ph].

Gary C. Evans

Thanks, Joe. And I can witness what's been going on, and it's just a -- this incredible change. The accounting department has now finally given our management team the type of support that we need to properly manage the company.

Let's jump back, though, to the Marcellus and Utica, and I just want to talk generally about some things because I feel many times these numbers are kind of overlooked, and I want our investing public to understand why we're so excited about what we are seeing over in the Marcellus and the Utica and Appalachia.

When we started accumulating our acreage position, going back to February 2010, we did it through the acquisition of some companies. The first one was a company out of bankruptcy called Triad, and then we subsequently bought properties from other companies, ended up buying all the southern acreage from Chesapeake in Ohio at $2,000 an acre. We bought a company called Berco [ph]. And we kept building the position. It was all homogeneous, it was all interconnected, it all made sense.

And we were -- while we were, I wouldn't say excited, I think we were pleasantly surprised that the play on the Utica kept coming as far south as it was. We were really looking at Marcellus, especially along the Ohio River.

So what has happened here recently that has really kind of turned up the Dow [ph], we've had some discoveries by offset operators. The first is a private company called Eclipse. Eclipse discovered a well called -- well, I'll think of it here in a second. Jim, help me out here. What's the...

James W. Denny

Tippens.

Gary C. Evans

The Tippens well is located 9 miles north and east of our Stalder Pad, which, as Jim has indicated, we're drilling the pad hole and will soon drill the lateral section. We're tying that well into our Eureka Hunter Pipeline System. It will be tied in by mid-December. And that well tested at 23 million a day of dry gas. And it maxed out the production equipment that was on location. We believe the well will do better than that, and we'll know as we tie it into the Eureka Hunter System. So there's data point #1.

Data point #2 was a well just announced here over the last couple of days called the Irons well by Gulf Port. It's located just due north of our Stalder Pad and North and East of our Farley Pad. It tested at 30 million cubic feet of gas a day. So let me remind you, 30 million cubic feet of gas a day is equivalent of 5,000 barrels a day on a 6:1 ratio.

So now let's go to the south and the east. The Garvin well, owned by PDC, was announced. That well went on production about 3 weeks ago, and it's located south and east of our Farley Pad, and Jim, correct me, it was around 3,000, 4,000 barrels a day. Is that correct?

James W. Denny

That's correct.

Gary C. Evans

So here we've got 3 new data points that we didn't have 60 days ago. And now -- and then we put our Farley well on, and granted, we only have 10 of the 26 stages open. But the combination of the pressures and the combination of the things that we see from that well -- and as you know, it was basically a blowout of that well and a natural fracture. So that had got us highly encouraged that we have something that's really unique here.

And so we are working on our budget. We're working on our plans for 2014. And I think you'll see some significant improvement in our ability to get some wells down here in the Utica. It's all these shale plays are a learning experience, and we're sharing a lot of data with our offset operators and learning how to better drill these wells.

But we are dealing in a different environment. We've had to go to 15,000-pound wellheads, double BOP, double Rams. I mean, we're dealing in, basically, a geopressured environment that you would see in South Louisiana. And so we're very excited, and that's the one reason we took the Eureka Hunter pipeline system off the block to sell at this point, is we need that system to get this gas out. And we're concerned having that system controlled by other third parties that we don't necessarily manage.

So a lot is going to change with Magnum Hunter over the next 60, 90, 120 days, and we think it's all for the good. So we've made the decision to really accelerate our noncore divestitures. We've sold already to date 7 different packages. I mean, 7 packages that have closed approaching $500 million of actual cash received. We have another $200 million of transactions that are in various stages of letter of intent, definitive agreement negotiations that plan to close tomorrow. I mean, I negotiated last night a sale of another property yesterday. So we will have these done, we believe, by the end of the year. Some may leak into the first week or 2 of January. That's another couple hundred million dollars of cash.

So we're really moving as fast as we can to get rid of what is the noncore, and we've made a decision to sell our Kentucky properties here over the last few weeks. And we're putting them on the block immediately.

So we are going to be a well-oiled machine with respect to being able to put on Williston Basin, Bakken, Three Forks wells, Marcellus and Utica. That is our core. We got tons of acreage. We don't need to go anywhere else. This is our company today. And I think the focus is really going to show with respect to significant production increases.

We've already announced this morning a production exit rate for 2014 of 35,000 barrels a day. That's 2 Utica wells at 30 million a day. So it doesn't take a rocket scientist to figure out that we could hit that number pretty easily. And so we've got to get these wells on. We've got to get them tied in, getting Eureka Hunter. We've got to get more crews to get the system built faster so that we can get this stuff on. And we're very, very excited about what we're seeing.

Now let's talk about commodity prices. We've all seen oil come down over $10, $11 a barrel here over the last month. That's not something we didn't expect. We did a ton of hedging, $93, $94 a barrel. And then natural gas, every time it creeped over $4 over the last 6 months, we've hedged, $4.02, $4.05, $4.10, $4.12. So we're pretty well protected for '14.

Now as we bring on this new production, obviously, that's unhedged. But whatever we have currently, we're hedged about as much as we can be at prices that are significantly above the current market. So we tried our best to protect our downside with respect to the volatility that we'll likely see in commodity prices as we go forward.

So I think, again, this was a noisy quarter. We felt like it was great to clean house, get everything on the table, get it done so we can have very clean quarters going forward. And that's what Joe and his team have helped us to do, and so we've moved a lot of assets into discontinued operations so that -- because we know we're going to sell them. There's no reason to reflect them as a continued operations any longer.

So I know we have a number of questions from listeners. So operator, with that, I'd like to turn the call over to specific questions from predominantly our analysts that follow the company.

Question-and-Answer Session

Operator

[Operator Instructions] The first question is from Neal Dingmann of SunTrust.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Maybe starting with either you or Jim on the Stalder Pad. Give us a couple of things there, just the timing, I think, and your thoughts. Are you going to just drill the 2 wells and then give us a test rate? And will you be able to hook those up? And then sort of secondly on the Stalder Pad, you mentioned that Tippens well. I'm just wondering, maybe from Jim, why he's had -- kind of his thoughts on if he has confidence that, unlike the Tippens well, that you all could see some Marcellus liquids as well as Utica dry gas there?

James W. Denny

Yes, Neal. Our Marcellus well on the Stalder Pad looked excellent. The logs were every bit of what we expected, compared very favorably to our Ormet area. We have flowed the one well in that area. So I expect a similar, very wet Marcellus, 100 barrels per million type, 1,400 Btu gas.

And won't have the rates that we see over in West Virginia as far as gas rate, probably will be 2 million to 3 million a day. But you'll have very liquid-rich results when you -- especially after processing because I would expect NGLs to be maybe 120 barrels per million based upon the gas analysis on our Ormet area. So no reason to think that we won't have a good Marcellus test there as well.

The Utica, I think, is going to be deeper, even more pressure than what we're seeing on the Tippens well. And have every confidence that we'll know more about what we see when we build our shale logs off of the log run, which we anticipate being this weekend. But everything that we have seen so far would indicate that we're in the similar pressure environment than the Tippens. And there's no reason to think that we won't be in the same hydrocarbon environment as well.

And then we intend to move the rig off and test those 2 wells. And we'll be testing to sale, so we do have pipeline in the area. So we'll make a decision on the lift that we produce once we see the results and the pressures. We may need to produce these wells, the Utica well, longer than we might normally do to pull the pressures down in order to be able to drill subsequent wells once we stimulate and begin producing the first well there. So that may be a consequence.

We'll be moving -- continuing on the Utica. I did not mention that we'd be moving the rig into -- with parts of the rig are already on location on the Farley Pad. We will shut that well in over the weekend, the first well, the 1305, and then we will drill. I think the decision was made yesterday to go ahead and drill 2 Utica wells on the Farley Pad to give us some concentration to bring in the pipeline.

The biggest thing I think I learned off of the Farley was a confirmation or a reconfirmation of the bottom hole pressure, and that we had a pretty good indication through the kill cycle. But our best indication was the shut-in pressures through the test cycle. And I'm now thinking that we have a grading of -- pressure grading of about 0.68 to around 0.72, which is really the only thing we had missing.

We had logs, we had shale logs, and remember, we took whole cores there. So we're pretty confident in the presence of the hydrocarbons, but what was missing is pressure. So that gives us the confidence to go in and drill a couple of more wells.

And I think you'll see that these early results with the 10 stages is nowhere near what we will be able to produce once we have a full 6,000-, 7,000-foot lateral with 25 and more stages. So that's where I'm taking my confidence now, and I think I've answered your question.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Yes, you have. And look, can I do one thought here on the Farley comment, Jim? Does that mean you'll drill this different? Or again, you certainly, I think, mentioned on what you've learned on this. I'm just wondering, going forward, will you drill it different, complete it different? What ultimately would be the difference?

James W. Denny

The difference will be that we will not take a kick like we did on the first well. It's inexcusable what occurred there. We took a 300-barrel kick and we did not cut a fracture, as first thought, as the kick was taking place over almost an hour period. And telltale signs were ignored. And we'll also -- now that we have this pressure data, we'll prepare better.

Generally, you drill these wells underbalanced because the matrix unstimulated is not capable of delivering full volumes. You get cuttings volume and just some leaking into the wellbore. But we'll be looking at checking for flow much more often.

We will have a heavier mud weight. And the downfall of the first well isn't -- the fracs went well -- is that we didn't have isolation behind the -- between the 5.5-inch casing on the outside of the 5.5- and the inside of the 9 5/8-inch casing. So we kept having to circulate and are having pressure on the backside, which is not -- is a very dangerous situation. So we did 2 remedial squeezes, and it allowed us to get away the 10 stages that we were able, but it still is not sufficient. I don't think it's indicative of what the reservoir is capable of doing.

So the casing program, the fact that we were able to kill a well and get case in the bottom, I think the casing program is sound. We just need to not stress the well, so we're not losing any circulation through the cementing process, and I think that's very doable and look forward to having a clean result on the next 2 wells.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. One last one if I could, maybe for Gary. Gary, just you mentioned about your Eureka Hunter Pipeline. I was wondering 2 things on that. One, sort of proprietary, what kind of control does that give you? You seem to be the only game down there in town right now as far as takeaway. So besides just the obvious throughput earnings on that, what other do you see from that? And then what do you see -- give us an idea on throughput, how you see that ramping up next year?

Gary C. Evans

Well, obviously, as we start adding on both the Marcellus and Utica wells, throughput goes up significantly. And so right now, all the gas that goes into Eureka ends up going to Mobley. And taking 30-million-a-day gas wells that are dry gas in the Mobley to be processed is crazy. So we are working with other pipeline companies to have interconnects that we can take the dry gas elsewhere.

Since we're on the Western side of the Appalachia Basin, we're closer to some of the truck lines that we can -- we actually are acquiring firm transportation on so that we can begin connecting Eureka and be going West with this gas. So just to kind of give you an idea of throughput, 2012, we averaged 23 million cubic feet of gas a day.

We're currently producing about 120 million, 126 million a day, anticipating with the new wells that Jim has coming on, plus some of our other third-party gas that just went into Eureka, could be at 200 million a day in the next 30, 45 to 60 days. So that is officially maxed out the pipe. But we've added compression, especially down at Carbide, which is our central facility there, that can take this pipe up to 350 million a day in capacity.

Now remember, we own the right of the way here, so if we need to lay another line, a dual line, we have that capability. So if we max out this system here in 2014, 2015, we have the ability to lay other lines in the area. So it's not very usual that you take a system of this size and get it filled this quick, but because of prolific nature of the wells in this region, that's likely going to happen.

Operator

The next question is from Gabriele Sorbara of Topeka Capital Markets.

Gabriele Sorbara - Topeka Capital Markets Inc., Research Division

Can you provide some color on the inputs to hit that 2014 exit rate?

Gary C. Evans

From the standpoint of what it's going to take to get to that?

Gabriele Sorbara - Topeka Capital Markets Inc., Research Division

In terms of rig count, CapEx.

Gary C. Evans

As I mentioned in the press release, we haven't formally approved a CapEx, but I can tell you it's a minimum of $300 million and likely closer to $400 million. So -- and you're likely going to see a greater proportion of that budget in Appalachia, which will allow Jim probably go to up to 4 drilling rigs. So we have to -- we actually are hiring new staff as we speak to beef up the drilling and operations division of Appalachia to be prepared for a higher budget and more activities.

So again, it doesn't take, what, 3 or 4 wells and you add 10,000 barrels a day equivalent in the Utica. We're not going to just only do the Utica, though. We are very active in Marcellus. We're planning to drill our first Utica well, though, in West Virginia near our Marcellus acreage. But I was in Ohio yesterday talking to Jim and some of his people, and we'll drill 3 Marcellus wells and drill a Utica well. And so that's kind of how we'll do it.

And that's what makes, I think, the green -- the Magnum Hunter portfolio so unusual, is that it has the ability to have both Marcellus and Utica on the same pad. Not many companies have that. And it's just because of the physical location of our acreage being along the river, both on east side of the river and the west side of the river. Nobody knows how far east the Utica really goes.

We've announced that we're going to drill a Utica well over in West Virginia, Antero has announced that they're drilling a well over in West Virginia in the Utica and Cabot has announced they're drilling a well in the Utica. So I don't know who will be first to the table, but our plan is, as soon as we can get a rig over in an area in Tyler County, we will begin drilling these.

Gabriele Sorbara - Topeka Capital Markets Inc., Research Division

And thinking about the liquids mix for that exit rate, any sense of direction there on a target?

Gary C. Evans

Well, I'd have to believe that our liquids component would go down some if you start adding the high-volume dry gas wells. So I've been, in my mind, thinking, while we're close to a 55% liquid component today, 45% dry gas, of a 45% liquid, 55% dry gas at the end of next year.

Gabriele Sorbara - Topeka Capital Markets Inc., Research Division

Okay, great. And just one question for Jim. Just thinking about this Farley well, if you kind of normalize that, you get like a 10 million a day IP. I'm not sure if that's the right way to look at it. I just want to try to get a sense of the real potential of that well. And were all of those 10 fracs really open? Or I guess, were they all effective?

James W. Denny

Well, every indication was that the 10 fracs that we were able to perform had no interference between them. They each had unique breakdown pressures. They treated very, very well. They treated on recipe. So I've got to think that they're open. We have not tried to do anything from a production logging standpoint to ascertain that. I think the result of multiplying by 3 is probably conservative and that we have -- we don't have any heel fracs.

All of our fracs are at -- are near the toe. So we don't have that usual lifting capacity, where you have the early contribution from your heel fracs to get water off the formation and then for your toe fracs and your middle fracs to start kicking in and really evacuating the hole. We're still producing right at 800 to 1,000 barrels of water a day.

So I don't think we're seeing -- even though we gave you kind of a peak rate there, I think we're not seeing what the formation is capable of. I think our expectations would remain 8 million to 10 million a day of gas and 200 to 300 barrels of condensate. And in NGLs, a like amount of NGLs. So I haven't changed my expectation in that space on logs or cores and the pressure gradient.

Gabriele Sorbara - Topeka Capital Markets Inc., Research Division

That's very helpful, Jim. And then it looks like you added some acreage here recently. You're at 91,000. How much of that this is in the wet gas space?

James W. Denny

Most of the MNW is in the dry gas window. Most -- but, however, some of the near-term acreage that we added, about 10,000 acres, and I would say that 6,000 of those are in the wet gas and that, that's where we've been concentrating and filling in, in the Farley area and just south of the Farley area. So south and east. So I would say that near term, the bulk of it is in the wet window. Longer term, as we bring in MNW, a lot of that will be in the dry window.

Operator

The next question is from David Deckelbaum of KeyBanc Capital Markets.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Gary, just I know that you've taken the Eureka Hunter monetizations sort of off the table for now. Now you've talked about a lot of the enthusiasm you see for sort of all the offset upstream operations and potential to tie in there. You talked about potentially needing to add a second line to expand the system further down the way, adding compression. Is there still a consideration here, as you go into 2014, of looking for a partner to shoulder some of this growth CapEx?

Now how are you thinking about sort of financing any growth on the Eureka Hunter system? And do you still see this as something that you would like to monetize in the future as sort of an ongoing piece of the company?

Gary C. Evans

Good question. Fortunately, we've been kind of anticipating some of these needs, and we went to market and solicited a number of banks and just recently executed a term sheet with a bank for a $100 million loan facility for Eureka. Now that Eureka has its own EBITDA and is growing at the rate it's growing, it can get traditional financing that it couldn't get as an embryonic pipeline. So that is in process of closing and will allow, to a large degree, the ability to fund our 2014 budget. So that kind of takes us away from the standpoint of being the upstream owner of 60% of that pipeline and having to fund our pro rata share.

I don't mean we won't be putting some capital in. We likely will. It just won't nearly as much as we would have -- would have been required otherwise. So long term, there's -- I don't think upstream companies should really own midstream companies. There's too much of a parity difference between how upstream companies trade versus midstream companies. I mean, you guys all know that.

So the idea is, if we could get the pipeline into the hands of a midstream partner, that would give us the flexibility that we need to continue to meet the demands of our upstream drilling and new wells, then that would be great. We haven't found that partner yet. I think there is one out there, and we're continuing to look. So I don't want you to think that we've completely closed the door. It's just got to be the right kind of partner.

And we're getting unsolicited offers all the time on we'll do this, we'll do that. And so we've been pretty vocal about what we're willing to do, and I think there will be an opportunity to exit Eureka Hunter for the benefit of our shareholders. It's just not in the immediate future.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Okay. And I know that you had the prior target, and I hate to put you on the spot, but I will, was at $1 billion. So is it fair to conclude that you had firm offers at $1 billion or greater?

Gary C. Evans

We had firm offers of a percentage of the pipeline that valued the whole at $1 billion. I think if we put on these new wells that we believe we'll be adding here over the next 90 to 120 days, that number goes up because everybody looks at a pipeline system on its forward-looking EBITDA, 2014, 2015. So really, the past means nothing. It's the future. And we're in an area where all the operators are putting on huge [ph] wells, and we've got commitments from other offset operators. We don't even -- today, Eureka Hunter is 55%, 60% third-party gas.

So what does that tell you? I'm -- we're telling you all these new wells we're going to be putting on. So the demand is not just coming from Magnum and Triad in our own wells. This is third-party gas that's wanting to get in the system. So that growth is something that is very, very appealing to midstream operators. And we think that as time goes by, as we add more gas, exponential value of Eureka Hunter continues to go up.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

I appreciate the answers. Just one quick one, should be a quickie here. Jim, what was the Btu content on the Farley?

James W. Denny

Yes, we're taking a gas analysis now. I would expect it to be -- we've been expecting all along that it'd be north of 1,200, so 1,250 to 1,280, something along in those range. But I honestly can't answer that today.

Operator

The next question is from Irene Haas of Wunderlich Securities.

Irene O. Haas - Wunderlich Securities Inc., Research Division

I just kind of wanted to explore the number that you throw out for 2014, about 35,000 barrels a day. Is that adjusted for divestiture? Or is it an all-in number?

Gary C. Evans

It's been adjusted for all divestitures. That's a net number left remaining at Magnum Hunter after everything is gone.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Okay. Great. And then just sort of -- one thing I would like to come back to, early or midyear, at some point you mentioned sort of a 0 net debt kind of goal, and of course we know that everything fluctuates and things move. Where do you want your capital structure? Where would you like to land at year-end 2014, an ideal world sort of where would like -- you like your debt level to be? Can you give us a little color on that? And then what's the possibility of calling some of the preferred shares?

Gary C. Evans

It's -- yes, we've always said that when you're a small, embryonic company, my business model is you leverage up, you buy lots of properties, you determine over a period of time which properties are the key ones and which ones are not. You divest the others, which is what we're doing now, which you get into a deleveraging mode. And then, as you move forward, you clean up the balance sheet. So we're in a deleveraging, "clean up the balance sheet" mode. We've been saying that all year, and I think we're demonstrating that.

So where do we like to be? We'd like to be 2.5x EBITDA or less; 25%, 35% debt-to-cap. We want to lower the leverage. Now what allows you to do that? Obviously, share price improvement, which we've had, but we don't think it's enough. We've got some abilities, though, in the near future to change the balance sheet. As a stock approaches $9 to $10 a share, we can call in our $8.50 warrants. That's $150 million, $160 million. That will delever us.

We have the ability to call in our 10 -- or it's actually 10.25% of Series C Perpetual Preferred. That's $100 million. As our stock approaches $10 to $11, we have the ability to convert our Series E Preferred. That's another $100 million. So all of a sudden, you start doing these things and you change up the balance sheet remarkably. Also, as this new production comes online, our liquidity improves drastically because the senior bank credit facility, when we do our borrowing base at the end of this year, will go up.

We're booked -- we're working really hard to book additional reserves. Kip Ferguson and Debbie Funderburg and our team are working with Cawley, Gillespie on looking PUDs because we don't think we booked nearly enough PUD reserves in both the Williston Basin, the Marcellus, and obviously, we've booked nothing in the Utica yet. So those reserves get added, increases your borrowing base, improves your liquidity, allows you to do other things.

So it all kind of goes hand-in-hand, and it's a giant [indiscernible] as you well know, Irene. But we believe that we're doing all the right things to get us there and then be in a position in 2014, if the stock does well, we can raise equity to grow like our competitors do as well. But at this point, we're -- we feel comfortable with where we sit and allow the stock to continue to perform, and the next step would be to call in our $8.50 warrants.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Okay. May I ask one more question? And on the operational end, you guys have done everything you possibly can really to connect up West Virginia. But it just seems like one hinge point really has to do with MarkWest plan. You only have one plan. So my question for you is, as you kind of project forward to 2014, have you worked in enough of a cushion just in case that the plant will go offline and things of that nature? That's sort of a little outside of your control.

So I just want to get a little feeling for that because I think a lot of the production that got knocked off is really nothing that Magnum can do anything about, and I'm just kind of trying to get a sense of whether things would improve, whether pipeline would slip upslope and things like that. So can you give us a little color on it?

Gary C. Evans

Well, it's a point that is very well taken. Remember, we're the ones that sold them the plant. It was our plant to begin with. So had our capital structure been different, we would have kept it. So the issues with MarkWest really began with the delay in getting the permits because of the location they chose. So they, obviously, had plans to put in 600 million cubic feet of gas of cryogenic processing.

We had just a 200 million-a-day plant. So that is what created delays, which were really 7 months of last year. And then, of course, the issue this year was the landslide that knocked out the liquids line behind the plant. Obviously, none of us can control those things. I feel, today, things are a lot smoother. Any new plant has its start-ups and issues, and I feel like those are hopefully resolved.

Now -- but are we a one-trick pony with MarkWest today? Absolutely. So we are doing everything we can to not be the case. And as I mentioned, these dry gas wells in Utica is no reason to be taking dry gas to a cryogenic processing plant. So we need to have direct interconnects with the pipelines to move that gas to Chicago and the Gulf Coast or wherever it's got to go. So we are working feverishly through Eureka Hunter to do that.

As I mentioned, we're also buying firm transportation. It's very likely Eureka is going to have to put its own cryogenic processing plant or joint venture one with another midstream company in Ohio sometime in 2014. That's being looked at. That would obviously give us another outlet so we wouldn't be stuck just with MarkWest. But what you brought up is a very good point, and we're trying to diversify so that we're not just stuck with one place to go.

Operator

The next question comes from John Nelson with Citigroup.

John C. Nelson - Citigroup Inc, Research Division

Help us now that noncore operations have been moved into discontinued operations. And given that 3Q was obviously a noisy quarter, how should we think about LOE sort of on the go-forward basis and trending over the next few quarters?

Gary C. Evans

We've put a fair amount of detail of LOE in the press release because it has been abnormally high due to a number of reasons. One of it had to do with the Williston Basin division. One of the operators that we work with, actually 2 of our operators, were in the process of electrifying the field versus using field gas, and that created a higher LOE cost on the field gas use than electrification would. So that is something that we've definitely noticed is trending down. It affected our reserves at June 30, and we've noticed the trend dropping since June.

And then over in the Appalachia, we had some higher LOE costs as well associated with some of our new properties, and we're working hard to drive those down. So the Utica dry gas wells, by the sheer nature of being a dry gas well and not having to have to deal with liquids at the surface and liquids at a cryo plant, will drive your LOE costs down. And there's nothing cheaper in the oil and gas business than a dry gas well because you have a wellhead and a pumper. And so that's -- I think, as we put more of these wells on, that will obviously gravitate down, and that's the goal.

John C. Nelson - Citigroup Inc, Research Division

So from a modeling purpose, it should still stay rather elevated for the next few quarters, and then around mid '14 is kind of a way to think about it as more of the Utica gas comes on?

Gary C. Evans

I would say you could probably -- you'll see a drop in the fourth quarter. You'll see a drop in the first quarter. And I think you're correct by kind of using midyear as a place of -- objective of where we should be going forward.

John C. Nelson - Citigroup Inc, Research Division

Great. And then I just was wondering if you guys would be interested in disclosing what leasehold spending was in the quarter and if you could break out what the 2 packages for MNW were, just so we could think about how much is left there to buy.

Gary C. Evans

Well, we've only spent on MNW, I want to say, of the $142 million, less than $10 million. And so we're just at the very beginning of the lease purchases there. And really, the reason that it's taking longer, which is great for us, is because, for liquidity reasons, is that title in this part of the world is a bear.

So we send out our land people. They do their work. We present what we consider to be good title, what we consider to be bad title and is part of the agreement. They then go fix the bad title or replace it with other acreage. So it's a process that, about every 45 to 60 days, we present them and they review and then we close. So that'll be a continuing effort, as Jim said, for the next 12 to 16 months.

Now we're continuing, though, absent the MNW transaction, picking up leases. We picked up a number of leases around the Farley Pad over the last 6 months. We've picked up some leases in Northern Washington County around this MNW property. In fact, Jim, you might have mentioned the little barbecue we had just here over the last week with all the MNW landowners and kind of what makes us a little different up there.

James W. Denny

Well, yes. MNW, which is comprised of several -- primarily is comprised of several smaller operators who banded together to put together a very significant acreage block, well, these other operators have been working alongside Triad for many, many years. Remember, the only 2 new people up here are myself and Rick Farrell. So we've kept the staff, we've grown the staff, we've -- so they see our trucks, they see our people. And not to be naïve, as long as we're paying close to market or a little under market, then they -- preferentially, they want to do business with us.

Well, I think that all culminated in quite an event last weekend where almost 500 people showed up. It'd be a combination of mineral owners, landowners, local businesspeople. Political types, when -- knowing that people would be coming around, showed up. County commissioners, Marietta City council. And it was -- and the proprietors with MNW actually made speeches touting the way that we've done business, that they've done background checks and they've looked at the way that we've handled other operators, the way that we've handled our suppliers, et cetera. And we're very pleased, in other words, that they had done their due diligence before doing business with us.

And we participated by having t-shirts and hats and -- et cetera. And it was just a really up event that really positioned -- I wish we could do more of that because we all came away with it with the understanding -- because we've got to deal with these people with regard to roads. Remember, in Ohio, you have 3 levels of roads.

There's a township road, there's a county road and then there's the state roads. So it becomes problematic if you don't have grassroots efforts to support us, and I think this was a great event to show that we're building in the communities, we're supporting them in their fire departments and their schools, et cetera, and it's working. They're responding to us, they showed up, they participated, they clapped, they were excited. And that makes us feel good as well.

Gary C. Evans

And just so everybody knows, when we file the Q later today, there's a Subsequent Events note about the Utica acreage in the MNW that gives all the specific details of that.

Operator

Question comes from Steve Berman of Canaccord.

Stephen F. Berman - Canaccord Genuity, Research Division

Gary, maybe to eliminate a little bit of the noise, can you say what current production is? I thought I heard on the webcast the other day a 16,500 number. And whatever that number is, can you make sure we know it if that's -- includes anything discontinued and/or shut in?

Gary C. Evans

Yes, the 16,000, 16,500 number is correct. We have a number of pads that are coming on here over the next 2 to 3 weeks. And remember, some of the pad drilling that we do over in West Virginia, we have to shut in the other wells on that pad. So not only are you bringing on 4, 6 brand-new wells that are 100% owned, you're bringing back on wells that you had to shut in on that pad.

That's the negative side of pad drilling, is you have to shut in your current production to fracture-stimulate your existing wells. So it's a -- that's why you see such a huge boost in a lot of these areas. So Jim, you might just kind of give a little highlight, like on the Collins and some of the other pads, how those will happen here over the next 3, 4 or 5 weeks.

James W. Denny

Okay. Well, we have 3 100% wells that are stimulated and waiting for a sales line. We'll have -- in the next 4 days, say, we'll have 4 additional 100% wells on the Collins Pad that will be fracture-stimulated. We'll still need to drill those out and flow them back, which will occur at about, say, 2.5, 3 weeks.

Gary C. Evans

When you say drill them out, you mean the plug?

James W. Denny

Drill out the plugs. Yes, just drill out the plugs. And that's about a 2- to 3-day operation, not a long period of time. And you can -- we'll just move the rig from wellhead to wellhead and then probably keep the other well flowing as we drill out plugs in the subsequent well. So it's kind of a continuous operation there that occurs in a very compressed amount of time.

The frac spread will go to West Virginia -- I mean, to Wetzel County. And we will -- it'll probably be -- those are a little shorter laterals, so we think in 3 weeks of frac-ing we'll be ready to drill those out and begin producing those. So that's 3, 4, 7, that's 10 that we have there. And then Stone is frac-ing 4 as we speak, which would be 2 net. So that's 12 net that I can see are directly on schedule, assuming we get sales into the area, on the Ormet area.

And then, of course, the [indiscernible] would be the Stalder. Particularly the Utica, we may need to produce that on a longer-term basis. So that will be going to the sales line. Because of the wet Marcellus, it may not make sense for us to bring in temporary equipment to handle all the liquids even though we could sell the gas down the sales line. So that's how we intend to get there.

Gary C. Evans

Yes, that -- what Jim was saying on that Stalder Pad, Steve, is that what the thinking was, we've kind of decided this over the last few days, because we'd like to get that Utica well on and test it by year end, is to go ahead and just fracture-stimulate the Utica only, not the Marcellus, because it does have different kinds of equipment-ing and delays, so that we can the Utica well on and producing. So we'll come back and frac the Marcellus well a little later.

Stephen F. Berman - Canaccord Genuity, Research Division

Understood. And is there any discontinued production in that 16,000, 16,500 number? Is that just continuing operations?

Gary C. Evans

There is a little. I think it was mentioned in the press release on the first page. Adjusted production, which has got to do with the Williston Canada, is 1,875 barrels of oil per day. So that is -- that 16,500 is without taking out the 1,875 of Williston and the Kentucky profits.

Stephen F. Berman - Canaccord Genuity, Research Division

All right. And another clarification. I think I heard you mention $500 million of sales so far. Your presentation has about $450 million. Have you closed any of these, the Pearsall or the water floods or any of the Canadian stuff since then? I mean, is going to -- anything in the Q that's going to come out that, say, you might have closed some of this in-process stuff?

Gary C. Evans

Well, we've closed some smaller transactions. I'm just looking at a list here of 7 transactions we've closed, that 250 here, 1,000 there, just little dogs [ph] and cats. The Canadian stuff, we hope to have a definitive agreement executed here within days. It's going back and forth to lawyers. And we'll announce that, I'm sure, with an 8-K.

And then the Pearsall stuff, we're on the final -- I mean, I can't tell you how many rounds of PSA that's have because that's going to a foreign buyer, and that should be executed in the next few days. So collectively there, you're well over $100 million.

Stephen F. Berman - Canaccord Genuity, Research Division

Got it. And then one for Glenn. I don't want to forget about you. There's been a little bit of a blowout in Bakken differentials lately. Where -- how is your pricing looking up there as we speak?

R. Glenn Dawson

Yes, it's definitely trending negative. We're looking at about minus $8 a barrel last month. And the near months, they trend towards minus $15. And if you go back last year and look at -- the trend is very similar based on how the refining -- that system works. It's almost becoming seasonal. You can almost predict when you're going to have more volatility and more negative volatility on your crude spreads. So that's kind of where we're at today.

Operator

The next question is from Chad Mabry of MLV & Co.

Chad L. Mabry - MLV & Co LLC, Research Division

A quick follow-up on the 2014 CapEx range that you put out there, kind of $300 million to $400 million. Is that all E&P? Or how much do you have modeled in there for Eureka?

Gary C. Evans

It's all upstream only.

Chad L. Mabry - MLV & Co LLC, Research Division

Upstream only. And then as a follow-up, just kind of looking at expectations for your Utica program next year, is that going to be focused mostly on some of the pads? Or are you going to be delineating your acreage at all? And then if you could provide any color on kind of how many 100% wells versus how many are not equipped, which would be lower?

Gary C. Evans

Okay. Good question. We made the decision after we completed this Farley well and saw the results that Jim and I have -- we actually, I think, decided this yesterday, to -- the rig that's moving in now, to go ahead and drill 2 more wells at the back because we think that will tie in with the -- we've got about 2 miles of pipe to lay to get to a interstate pipeline. So we would frac those wells simultaneously, obviously, in the first quarter of '14 and be able to put 2 big wells on at once. And those are both 100%-owned wells.

The only things that we are doing that are not 100%-owned wells, both in the Marcellus and Utica, have to do with our 50-50 relationship with Stone and our 50-50 relationship with Eclipse. And that's strictly the Stalder Pad and the -- I forget the name of the Stone pads that are over in West Virginia. And those are pretty much drilled up. So everything else is 100%.

So if you'll go to our presentation, you'll see a number of other pads that we are preparing and getting permits and going through all the regulatory requirements to be able to drill in this area. And the things that are becoming of greater concern going forward is air permits because we're having -- when you have 10, 18 wells on a pad, your emission can go up significantly. So we're having to wrestle with all that in our planning stages going forward. So the beauty of drilling Utica wells, though, back in West Virginia, which is the plan in 2014, is that the Eureka Hunter Pipeline system is already there. So we can get immediate access and throughput on new wells in that area.

So it's a bit of a moving target. A lot of it depends on timing of getting permits, timing of getting construction done. And of course, we don't want to drill a bunch of wells out in Timbuktu, where there's no pipeline, because we don't want wells that'll sit in [ph] and have to wait 6 months to 1 year. So a lot of it has to be coordinated around Eureka Hunter's ability to get pipe there, the number of crews they have. So it's a constant planning scenario that we have to go through. So that's why you'll see changes. We make changes all the time in order to try to be efficient.

All right. Thank you, operator. And we thank all the listeners today for taking the time, and we look forward to updating everyone as we continue to put new production on. And we appreciate your support.

Operator

Thank you. This concludes today's conference call. You may now disconnect.

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