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Magnum Hunter Resources (NYSE:MHR)

Q3 2012 Earnings Call

October 25, 2012 9:00 am ET

Executives

Gabe Scott

Gary C. Evans - Chairman and Chief Executive Officer

Hershal C. Ferguson - President of Eagle Ford Hunter Inc

R. Glenn Dawson - President of Williston Hunter Inc

James W. Denny - Chief Operating Officer, Executive Vice President of Operations and President of Triad Hunter LLC

Ronald D. Ormand - Chief Financial Officer, Executive Vice President and Director

Analysts

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

William B. D. Butler - Stephens Inc., Research Division

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

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Operator

Good morning, and welcome to the Appalachia Basin Acquisition Conference Call. My name is Sarah, and I will be facilitating the audio portion of today's interactive broadcast. [Operator Instructions] At this time, I would like to turn the show over to Gabe Scott, Vice President of Capital Markets.

Gabe Scott

Good morning, and I'd like to welcome everyone to Magnum Hunter's conference call. The purpose of today's call is to discuss the Virco acquisition and our third quarter 2012 operating results, among other matters and interests regarding the company.

Before we get our presentation, I would like to advice you today that today's call may include forward-looking statements within the meaning of Section 27A of Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Our presentation may include statements regarding our expectation, beliefs, intentions or strategies regarding the future. Such forward-looking statements may relate to, among other things, the company's proposed exploration and drilling operations, production and revenue from those properties and estimates regarding reserve potential. 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 2011 annual report on Form 10-K as well as the company's first quarter and second quarter 2012 quarterly reports on Form 10-Q. Our 2011 Annual Report also includes a glossary of certain industry terms that may be used in today's conference call. The full forward-looking statement disclaimer is included in the company's second quarter 2012 operating results press release dated October 24, 2012, which is posted on the company's website under Press Releases. This disclaimer is in effect for the duration of this conference call.

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

Gary C. Evans

Thank you, Gabe, and thank all of you for dialing in this morning and giving us an opportunity to talk about our press release for the third quarter operational update that we released after the market closed yesterday, as well as our announcement this morning, our transaction that we closed yesterday for $106.7 million to acquire additional assets in the Appalachia Basin.

So we have, on the call today, the 3 division heads that run our 3 unconventional resource plays, as well as our CFO. And we're going to give each one of them a chance to talk about the division and their activities, not only for the quarter, but what we're currently doing.

So what I would like to do is maybe summarize a few things. The third quarter of 2012, from my perspective, was a bit of a transitional period for the company from the standpoint that we had some great production growth in the oil regions. The gas region was hampered and we released that information to the public in a couple of different press releases over the quarter, indicating that we were having curtailments in Appalachia, not only in Kentucky, but also in West Virginia related to our Marcellus production due to midstream and downstream bottlenecks.

As most of you know, we have been working feverishly for the past year to resolve those bottlenecks, and we anticipate those being resolved some time over the next 30 days. So the fourth quarter is really going to be the period that we have a shot in the arm and growth in production. We've been preparing that all year. Jim will talk about some of the wells he's drilled and plans to complete over the next 60 to 90 days, and that we continue to move forward in all the other oil plays.

Production for the third quarter was an average of 12,475 barrels a day. Well, that's a tremendous increase from the prior quarter in 2011 or 1 year prior was 137% increase. It was a slight decrease from the second quarter, again, due to these curtailments. If you factor in what we have shut in, what we currently have producing, we're a little over 15,000 barrels a day. And as we reiterated in this press release, we're standing firm on our 2012 exit rate of 18,000 BOE per day.

We did continue to improve our liquids mix to 55% in the third quarter. And we then announced, as I mentioned this morning, the acquisition of the Appalachia properties, a company called Virco. Virco is a 25-year-old entity. They actually office right across the street from where we office in Reno, Ohio. We've known the company for 3 years since we made our first entrée into the Appalachia Basin via the acquisition of Triad Energy, which was in February of 2010.

These 2 companies, Virco and Triad, had been virtually sister companies, competitors, friendly competitors for the last 20-some odd years. And we are -- worked hard to try to make this transaction come to fruition and we worked on it for over a year. And very much like the Triad transaction, this one has existing wells holding the leases. The leases fit Triad Hunter extremely well like a glove. And as we've negotiated this transaction throughout the year, the value of the lease equity position has continued to go up exponentially. And a lot of that acreage is in an area of the Marcellus that we're pretty excited about in West Virginia, particularly Ritchie County. And then there's another block of acreage over in Ohio, where we're seeing activity in the Utica that continues to encourage us about our existing acreage position, as well as what we've just acquired.

Everybody on this call is capable of doing the math. And you will see that we bought this acreage at an extremely attractive price. Now it's also important for you to note that the seller, who is a gentleman, a family called the Healey family, they actually are the owners of Viking Yachts, which is an offshore fishing fleet company -- boat company. These people took 65% of their consideration in convertible preferred of Magnum Hunter at an $8.50 per share conversion price. It's a huge testimony to our management team, our Board and our company that they would sell their 25-year-old company into a convertible equity into Magnum Hunter. They are big believers in what we're doing. They see what we've been doing in the immediate area and we've hired all their employees as of yesterday.

So I'm going to get into the Appalachia in greater detail with Jim here in a few minutes. But I'd like to turn the call over to Kip Ferguson, who's going to tell you what he's been doing down on the Eagle Ford with our 26,000 net acres of oil play. Kip?

Hershal C. Ferguson

Yes, good morning. Thank you, Gary. So in the third quarter of 2012, the Eagle Ford division placed on production 5 new gross wells, 2.3 net operating wells and 3 gross, 1.5 net non-operated wells in the Eagle Ford shale trend in South Texas, primarily all located in Gonzales County, Gonzales, Lavaca County area. Additionally, we were also in the process, during this period, of frac stimulating 2 gross, 1 net operated wells during the same time period through the third quarter ending.

We subsequently placed on production these new wells, these 2 wells that we were fracing and we actually have some reports on that. I'll get to it in a second. So looking forward, for the fourth quarter, we have 4 new gross wells that we anticipate and we have frac dates for prior to December 31, 2012.

I guess now, starting from the beginning, we also -- just on the operated wells, you'll know -- the 2 new wells that we just put online, 2 new gross wells were the Hippo Hunter #1 and #2 wells. Now just to make -- to give you, everybody an update on the operations, we only were flowing those wells back about 7 to 8 days and we had to establish an IP really quick. They hadn't really quick cleaned up yet, but they were pretty close.

So one of the things that we're doing in our operation at Eagle Ford, if you'll note, there was a press release out a couple of weeks back, where they were -- IP in their wells is 22/64 chokes and 1,200 barrels a day or whatever. We really don't do that in Magnum Hunter. So we try to typically stay around at 18/64 or 16/64 choke. We're -- we've actually cut our choke sizes back in recent months. We think it's a more unique way or a more cautious way of getting more fluid, more frac fluid out of the formation.

One note on the Hippo Hunter well, the 2 wells. This was a new fluid design we use called PermStim. It's a Halliburton product that we were using in the Eagle Ford and Halliburton has made a press release on the use of this new fluid. And we see this fluid as an opportunity for the Eagle Ford. And I think we're one of the first companies to run in the Eagle Ford to really recover more of this frac fluid and preserving more permeability in the formation.

The core [ph] has worked very well for us. Typical break, long well frac -- we've been very successful pumping that type of frac. However, it is a dirtier fluid and the PermStim is obviously a clear fluid and we're quite excited to see results from those wells. And we think that those results will be better identified and better seen as we get further down in the production's life cycle of these wells, 2 to 5 years down the road, because we think we're preserving a tremendous amount of ore permeability in the formation that you've created with these fracs.

Just to kind of finish up. We've also had some non-operated wells come online, which we reported to in the release. We continue to see improved results from our non-operated results. We're doing a few things differently there. We're being -- the flowback and the production of these wells, we're using a lot longer flowback period, even up to 2 months of carefully flowing it back on 12 and 13/64 chokes. And so we're kind of comparing flowbacks through the region. And as we see wells getting a lot lower decline and a lot stronger in 30- and 60- and 90-day rates, we're quite excited about some of our wells in this area.

So I think, over the next 6 months, we will continue to see improvements, our EURs, as you guys and everybody on this line have noted, that every 6 months, we do a reserve redetermination in Eagle Ford. We get an increase in our EURs. So we're quite proud of the fact that we're very conservative on our EURs. And we hope to continue to see improvement on those EURs on our existing wells.

I think that's about it for the Eagle Ford. And we'll turn it over to the Williston Basin and Glenn Dawson.

R. Glenn Dawson

Thanks, Kip. Well, we've had a pretty busy quarter at Williston Basin. We're hitting record production here, about 4,500 barrels equivalent, primarily oil, last week. We're still continuing to run the 6 to 7 rigs across the basin. Let's focus in on Tableland for a little bit here.

Last quarter, 8 gross [ph], 7.1 net wells, placed 6 gross, 5.4 net on. At the quarter-end, we're -- still had 3 behind pipe. So we've got the 2 rigs operating at Tableland, primarily 100%. But we do have some low working [ph] wells in the 70% range, continued to reduce the -- improve the operating efficiencies, joint costs are dropping, completion costs are dropping, our cycle time has improved, where typically -- despite the first production in 45 days for most of the wells.

We've also added some significant operational efficiencies on the ground by putting in additional pipelining of our wells. So we're bringing all of our emulsion gas, water and oil into our central battery facility, which of course, is driving down our operating cost significantly into the $9 to $10 range. We are active acquiring land across the Saskatchewan Basin last quarter, picked up 6,312 net acres for just over $570,000.

We continue to drill good wells. Our average IP is coming in around 250 to 300 barrels a day, IP30 and we're getting a lot of wells in the 500 to 700 barrel a day range IP24.

So current production in Tableland is about 1,500 to 1,600 barrels a day NRI, and we anticipate being at 2,000 barrels a day NRI shortly with the wells that we've got ongoing.

North Dakota continues to be very active. We're currently running 6 rigs in North Dakota, all non-op. We are focused in our North Divide, Ambrose area. We are using a 4-well eco-pad system in there. The cost have been dropping significantly. The cycle time, despite the production, has dropped significantly, and we're making better and better wells, as we bring in the new technology to this area of the basin with 30 to 35 stages per well. We're currently running about 15 to 20 tons per stage in a pretty sort of slick water type application.

Additionally, in North Dakota, we've been testing out of some the Middle Bakken formations. We've had a couple wells go down in Divide County that have been pretty good successes for us. We're just big on touch [ph] now for about a month and they're showing some pretty good rock properties. And this is a new area for us. We've typically been 3/4 producers to this point in time. And we'll be emphasizing that more as we move forward in our drilling program.

The oil situation, from a marketing perspective, has changed dramatically in the Williston Basin. Differentials of East [ph] and we've seen significant margin improvement in both Saskatchewan and North Dakota, so we stay flexible. We're moving our product into a rail or pipeline, whatever gives us the best price. Currently, in Saskatchewan, that would be pipeline.

We're making significant progress with the ONEOK. As you know, we're flaring a considerable amount of liquid-rich natural gas in the Divide County area. We're actually flaring close to 13 million cubic feet and 1 million in Canada. So we've got about close to 4.5 million to 5 million cubic feet of gas that's currently being flared as 1450 Btu, so you're looking at about 180 barrels a million of liquids recovery when we bring this into operation, which is going to commence March 2013 and then into the second quarter. So we're looking for a significant liquids and gas add to the Williston Hunter operation, which is probably close to 20% of our current production, if not higher. And of course, it will be higher by the time we get to that period.

So at this point, I have no more additional information to provide. I can turn it over to Jim Denny, President of the Appalachian Division.

James W. Denny

Thank you, Glenn and Gary. Do you want to go into introduction? Or would you like me to get into the operations?

Gary C. Evans

Why don't you go into operations and then we'll get into specific acquisition we announced.

James W. Denny

Excellent. I think Gary already mentioned the curtailments that we've experienced here in Appalachia that all, just a reminder, started with a very severe storm. We're had storms into the area on June 29, and we were without power for a number of days in the area. And ever since then, we've had increasing curtailments, which -- some of which we've been able to mitigate by secondary firm, as bottlenecks began to increase.

But we're really looking forward to having the MarkWest Mobley processing facility operational near the end of -- mid to end of November, which is a real milestone for us. That will allow us to produce our wells as efficiently as we would like and also get the liquids uplift associated with that, which will have impact, not only in our immediate cash flow, but will also impact our reserves in that we have not been able to brook [ph] liquids for our proved producing wells until we have a market, which would be defined by having the processing facility up and running.

As you remember, we drilled 4 wells in our Middlebourne Area of Tyler County and we needed the data point, so we frac-ed one of those in the second quarter of this year with excellent results, very liquids-rich, 80 barrels per million of 1,300 Btu gas, which we coined kind of the Magnun rich area. We have 3 different wells that we're currently frac-ing. We are on the final days of a 63-frac program on those 3 wells. And so they will go into their resting period and we'll bring them on to time with the MarkWest facility coming online.

We've also been very busy from a non-op standpoint over on our Wetzel County joint venture. We've drilled a total of 11 wells here in the second half and building [ph] case and we've begun frac on one of the pads, a 7-well pad, 3 of which we would anticipate that we'll have tested and flowed back, so it will have exit rates on 3 of the 7, so 1.5 net wells. So we'll be bringing on 4.5 net wells here in the fourth quarter of this year.

And we look forward to -- with this uplift in processing and the uplift on our liquids and our profitability. We look forward to picking up a rig and actively pursuing our Marcellus and begin to explore some of our Utica acreage here in early 2014 and through the year -- in 2013 and through the year.

That's it from an operational standpoint. Gary, you want to talk about the acquisition a little?

Gary C. Evans

Yes, let me make a few comments and I'll let you take over. The Virco transaction is the one that we believe was highly sought after in this region. And I think the best way to describe how we were successful in negotiating this was really personalities. I think the management team and the owners of the company really wanted to do a deal with us. We were far apart on price and it took us basically a year of negotiation to get this to a level that we felt comfortable and to get it structured in a form of consideration that was appropriate for our company's current financial position. And so for that, I'm very proud of what we've been able to accomplish and extremely excited about the acreage position and a future for drilling in this area.

As we all know, gas prices took a real hit in 2013 -- I mean, 2012, going down to $2 an mcf back to $3.50 now. And as this gas plant that we've been talking about, called Mobley, comes online in November, it's about $1.25 to $1.50 uplift for us. So in a $3.50 regime, we're approaching $5 in mcf. And there's not a better area in the country to be drilling natural gas in the Marcellus/Utica, and we are one of the few companies that has the infrastructure. We've taken the initiative to lay over 60 miles of 20-inch pipes that can move this gas.

As I mentioned on the Eureka Hunter before, we are working on getting our pipe into Ohio so that we can begin gathering new wells that we hope to drill in the first quarter. We do have 1, and most likely 2 Utica tests planned. One for sure in the first quarter, possibly 2 that we will make. And I've been in Ohio the last 3 days, meeting with management and they've got an excellent game plan for 2013.

So when you look at the capital budget for next year, which we have not formally established, but if you were to assume a similar budget as to what we used in 2012, I believe you would see Appalachia division getting almost half of that budget because of what we see as tremendous opportunities appear and what it can mean for value added to the company.

The one thing that was a real eye-opener, I think, for all of management this year was Jim only put one well on in the entire Marcellus play, and our production held up extremely well, which is very uncharacteristic of shale plays. Shale plays typically have significant production declines. And so we know we're in an area that likely has more reserves than what we are estimating and that we're excited about some of the newer completion techniques that we will be using.

We've also made a financial commitment to buy a new drilling rig. It's been ordered. It's a Schramm rig. It's one of the new robotic rigs that has a smaller footprint. We'll take delivery of that by January 31. And that rig, along with another rig, that Jim is contracting, we will be keeping basically 2 rigs busy full time in Appalachia, drilling both Marcellus and Utica wells next year.

So with that, Jim, why don't you get into a little more detail about the 51,500 net acres we've just acquired?

James W. Denny

Okay. Well, right there. That's a significant addition to our acreage, boosting both our Utica and our Marcellus by roughly 30% each, so -- which will bring us up to 85,000 for Marcellus and about 81,000 for Utica. The acreage is very well positioned. The Marcellus is anchored by a 20,000 -- just under 20,000-acre, mostly contiguous set of leases that are on strike within same liquids-rich as essential tighter wells, particularly the Middlebourne and the other leased wells. We have a number of -- just like with Virco, we have number of vertical penetrations where we have logs, we have excellent cross-section of control. We've been able to put together shale logs and we're very confident that we will be able to develop this area much like we've done in our other areas in West Virginia and mainly, Tyler and Wetzel County.

I'd also mention, we have some 9,000 acres of this 51,500 acres that are in the liquid-rich portion of the Utica. So right off, we get a step jump of about 40% of our liquids-rich portion of the Unica, which as you know, started to the North of us, and it's been steadily marching to the South. And I think you're seeing from press releases some of the offset operators like of Gulfport [ph] and Antero and HG and Anadarko were putting excellent results, north of 3,000 BOE a day, whereas some of the northern, it looks like the averages are considerably less and not making even as much as half of that.

We have a number of -- another great thing about this acreage position is that it's almost 100%, 98% is our estimate held by shallow production. So if things do turn around and we do have the ability to shift capital without losing acreage and as Gary had pointed out, all of this acreage is -- it complements our acreage exceedingly well. Also, as Gary was alluding to, this is a great fit with our Eureka Hunter Pipeline. As it expands, we've already -- we're planning a southern lateral to pick up some neighboring acreage to the north and we'll extend that pipe to the South to pick up the Ritchie County acreage, so we'll begin development there in late 2013, early 2014.

However, much like when we've made our Wetzel acquisition, we had, I think we had 5 wells on production within 7 months of that acquisition. Similarly and associated with the Eureka coming across the Ohio, we have a joint venture that is emerging. It's on for 3 unit to drill 12 wells, 11 Marcellus and 1 Utica. So we will have -- they will be starting, just at the end of the New Year. And so again, within 6 months, we will have significant production from results of this acquisition. And then, of course, we will be drilling in our Macksburg area, a vertical Utica well and a horizontal well, possibly 2 horizontal wells in that area in early 2013.

So we have a number of locations. I think in the press release, we alluded to 105. Those are wells that we have -- wouldn't require any additional leasing. And a big portion of those 74 Marcellus locations are in Ritchie County. The remainder are on the Ohio side, primarily right along the river in Washington/Monroe Counties. If you extend that to -- if you allow me to on an 80% of a unit type concept, which we often used for our P3-type study, the number goes to right at 200 wells. And if you look at resource potential, that's over 300 wells, so a very significant add-on to our inventory by making this acquisition.

Those are the things that come to mind as far as the highlights. I guess, we'll get into more questions. Or Gary, if you have something out that you wanted to emphasize, we can do that now.

Gary C. Evans

No. I think before we go to questions, I'd like to let Ron talk a little bit about what we -- we didn't release financial information yet for the third quarter, talk a little bit about our new convertible preferred, our borrowing base review and anticipated liquidity at year end. Ron?

Ronald D. Ormand

Thanks, Gary. I wanted to -- just real quickly, this is a pretty straightforward instrument, much like we've issued in the past. It's an 8% coupon, $25 a share. It's a perpetual preferred. It has no redemption provisions whatsoever other than we can redeem it at our option and also can be redeemed in exchange [ph] of control. Gary had mentioned the conversion price being $8.50, which is certainly a substantial premium in today's market, but an indication of the value that I think the seller sees in our property base in the company.

As Gary mentioned, we're currently undergoing a borrowing base redetermination. We've had very good success at the drill bit. Plus, as many of you know, we are -- the Mobley plant will be coming online here in the fourth quarter, which produces -- which automatically brings in quite a bit of reserves and cash flow to the company. So backing out the amount of cash, which is about $35 million or so that we'll have to pay for the vertical acquisition, we shouldn't be in about 150 million of liquidity. And that assumes that we don't use the series needed to pay any of the cash portion of the acquisition. And I think our intent is to do that.

So we should be between $150 million to $200 million liquidity, more than sufficient to get us for a very extended period of time. And as you've continued to see in our company, we continue to increase our borrowing basis and fund without diluting our equity shareholders.

So very comfortable with our position, very excited about having these new properties in our property base that gives us much -- a lot more optionality and the ability to capitalize on the assets, both on the upstream and the midstream side that we have in Appalachia.

With that, I'll turn it back over to you, Gary.

Gary C. Evans

Thank you, Ron. Operator, I think we're ready now to take any questions that our listeners may have for management today.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Neal Dingmann from SunTrust.

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

Say, Gary or Jim, just a quick question. Just on this acreage, now that you all have broke out the 85,500. Could you give me a better idea now, Gary or either one of you all kind of how this plays out as far as -- I know you've mentioned Monroe and Washington County. I'm trying to get idea of again, what parts -- how much is the 85,000 is in those 2 counties in Ohio? And then what parts of those counties? And then maybe where the remainder is? If could can break that acreage up a little bit.

Gary C. Evans

Jim, why don't you attack that?

James W. Denny

Yes, Neal, it's about -- this will bring us to about 27,000 to 28,000, 29,000 acres in the liquids-rich portion, as you've seen on our maps, which we haven't had to change in quite a while now for the gas condensate window. And will be located primarily for the big -- that will be counted as liquids-rich, would be primarily in central to northern Washington County and the very western portion of Monroe, southwestern Monroe County. The remainder would be considered dry Utica. And so if you subtract that away from the 81,000, then you can -- that will define our drivers as wet as we currently stand. Now, we're working on a number of different -- as always, trying to clean up areas, concentrate on areas and looking at a number of different submittals. So these numbers will be dynamic as we move forward.

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

Got it. Great, that helps, Jim. And then just one on top of that, maybe, Gary, just as far as giving the idea on the Utica midstream. You mentioned about the pipe coming -- may be again for you or Jim, or maybe even for Don or somebody, just the type of capacity we're talking about potentially down there at some point next year to give us an idea of the magnitude of your total midstream, Utica midstream.

Gary C. Evans

Well, the pipe that we're building into Ohio is the same size pipe we've built in -- on the West Virginia site, which is rated for 200 million a day, but with compression, can go to 350 million. So the real question for us as we get into the Utica and as we begin to tie in some of these wells that we plan on drilling, as well as others that have drilled or shut in, is what is the ultimate liquids component there? So we're convinced we will have to put a plant in Ohio, and we're still trying to determine where and how that goes about. But the first plan of action is to get the pipe in so that we can gather the gas, it will be wet gas, and figure out what we're going to do with the liquids. So now that Eureka Hunter continues to get its feet on the ground and we've got a strong equity partner with ArcLight and it continues to grow, and we'll have a huge shot in the arm when this MarkWest plant goes online in November, the likelihood of us doing another plant goes up significantly. And we would most definitely be an equity owner. We're not going to be a non-equity owner going forward in the plant's design. So the one thing I'd like to point out over here in Ohio is if you recall, Neal, we drilled one of the first horizontal Marcellus wells in Ohio, over in Monroe County called the Ormet. And you don't hear much talk about Ohio Marcellus, but we are very excited about the opportunity in the very eastern portion of Ohio, near the Ohio River, of the Marcellus potential. So the acreage that we've acquired today along with existing acreage, has dual opportunity: Marcellus and Utica. And we're working on another joint venture with another company that would allow us to drill both Marcellus and Utica on same pad sites. So we see that is -- has a lot bigger potential than I think most people in the public realize.

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

Okay. And then lastly kind of, Gary, going on with that, either a comment from you or Ron, just wondering when Ron touched on liquidity, Gary, kind of a comment if you would further maybe talk about that I think that people have a perception of that. And then on top of that, the potential, I know in the past, you've mentioned potential JVs or monetizations. Maybe if you could talk about sort of the 2 combined, or just an overall potential liquidity picture, which would include potential monetizations?

Gary C. Evans

Well, undoubtedly, our company is very asset rich and the market has not given us even close to the value of the assets if we were to sell them or joint venture them or what have you. So we are exploring other things to increase our liquidity substantially. And so it's one reason we're a bit safeguarding what our plans are for 2013 because if some of these events were to occur, they would change our profile dramatically. So we continue to believe that some of our plays may be better suited for others in their portfolio to have a cheaper cost to capital. And the Eagle Ford is an example, one that we've drilled over 30 wells. We've got excellent reserves and production. And -- but we have a limited amount of acreage. We only have 26,000 net acres. So that's a candidate. And so we continue to look for ways to improve the balance sheet, improve our ability to exploit the areas that we have large acreage positions and to grow our reserve base. So I think it's important that the market realize that this company, next year is going to be a 23,000, 25,000 BOE a day company. There's no doubt about it. And we're trading as if we're 8,000 barrel a day company. So it's a little disheartening for us. But we're keeping down the path, and we'll get the -- that will eventually happen.

Operator

You're next question comes from the line of William Butler from Stephens.

William B. D. Butler - Stephens Inc., Research Division

Do you all have a sense, and I apologize if I missed this on the prepared remarks, but do you all have an idea of where in the Utica you would first start your drilling program next year?

Gary C. Evans

Yes, we have identified an area. And Jim, you want to kind of summarize where we've talked in the last few days?

James W. Denny

Yes. We have identified an area where we have a very contiguous block of acreage starting with some legacy Triad production. It's in the very northern Washington County in southern Noble County. So we'll drill our first vertical pilot and our first horizontal on that acreage. It's very near several offset operators that have -- that we've been working with. And while this is a great key well, 2 key wells, that we should have production on very soon, we're very -- what we've seen as the results of those wells from a lot of core data suggest that, that's an excellent area for us to be drilling the well.

William B. D. Butler - Stephens Inc., Research Division

Okay, great. And then in terms of plans to fund that and some of the monetizations maybe you're talking about, can you all give us any better sense of timing when you would quantify a 2013 in CapEx and funding plans?

Gary C. Evans

I would say the next kind of news you'll see has to do with our borrowing base review and additional liquidity that we'll be announcing in short order. And then I would say by the end of the year, we would have a very good feel on other liquidity events in 2013 capital budget.

William B. D. Butler - Stephens Inc., Research Division

And then last question, if you don't mind. In terms of the Eagle Ford, and this might be a good question for Kip, you all mentioned higher EURs and expectations around that. When do you think we might be comfortable quantifying the higher EURs in the Eagle Ford?

Gary C. Evans

Well, we just went through a June 30 review with Colin Gillespie. We announced today, obviously, the results of these specific wells. So I would imagine when we do the 12/31 review with Colin, they will be looking at that. Quite frankly, I think the reserve upticks will be greater in the Williston Basin, both in North Dakota and in the Tableland Field and in Appalachia, than they will be in the Eagle Ford. We're booking 450,000 barrels of well. We might get to 475,000 to 500,000. But if you look at existing decline curves based on the type curve used by third-party engineers, the other plays have more potential for uptick on reserves than, in my belief, the Eagle Ford. But I may be wrong.

William B. D. Butler - Stephens Inc., Research Division

Okay, that's great. And then, lastly, on the pipeline infrastructure and gathering infrastructure coming with Virco, how important is that to the puzzle and where does that end up? Does that go into Eureka?

Gary C. Evans

That's a good question. When we bought Triad in February 2010, we told everybody we got 182 miles of right of way in pipeline. But the problem is the old-school of laying, gathering lines in this part of the world was 4- and 6-inch lines, low-pressure lines. And when you go in there and put a 20-inch pipeline that can move 200 million -- 350 million a day, it's a different animal. So we have found that in most cases, we have to go out and get new right of way. So yes, there's right of way, and there's value there. It's just very difficult to put a figure on it. But that's why we just really don't talk about it because we don't know really what it's worth until we get over there and start looking at every right of way determining, do we have to go get new right of way? Do we have to get it amended? Or is that the route we really want to go?

Hershal C. Ferguson

I would add to that, Gary, that some of the various right of way, especially in Ohio that -- where pipe has not been put in the ground, it may turn out to be quite useful for us. But again, it's hard to quantify, and agree with you. But Eureka -- we'll go to Eureka, and I think that's probably the near-term, greatest value that I see to Eureka.

Operator

Your next question comes from the line of Irene Haas from Wunderlich Securities.

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

I'm kind of curious. I have 2 questions. Firstly, if you're going to be exiting the Eagle Ford, are you still kicking around the catch-all shale trend and any kind of updates? And secondarily, this is really for Jim, I'm kind of curious with the new acquisition, what's your headcount now? It looks like you have at least 2 rigs for the Marcellus Utica. And how many wells can these rigs drill per month, sort of a spot to release date and spot to first production, if you have any feel for it?

James W. Denny

Yes, I'll take the second half of that. You can drill -- with a full calendar year, if you have permits on hand and first location ready, you can drill about 14 wells with 1 rig without top-holing or with minimal top-holing. So the short answer is, multiply that by 2. However, with the new rig coming, we probably won't have it out on the first location 'til early March. So I'm discounting that to probably 10 locations. So I'm saying between 20 and 24 on our plan. And it's still about 160 days from first moving it there to first production. If you look from drill time to first production, it's about 120 days, is what usually works out on a per chart. That answered your question, Irene?

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

Yes. And what is your headcount? What is your new organization look like? How many people do you have on the ground and operating midstream permitting assets? How is it shaping up?

James W. Denny

This will bring an additional 53 people, I believe, mostly field and -- field supervisory people. We are picking up geologists and some -- a new land person and a couple of administrative people to assist us with the permitting. We created a -- we have a position for that now. Actually, it's a 2-person position that spends most of their time, one in the office and gathering from the various disciplines so to meet the state requirements of both Ohio and West Virginia, and the other is in the field working with landowners and working with contractors. And I'm very, very pleased with the way that's going. So I wouldn't anticipate any additional needs there. We've also restructured our drilling site to be able to take advantage of this, mostly with not new headcount, at least not now, by contractors. So again, I'm comfortable that we have the people in place. Our total headcount for Triad will move to about 175-ish, something like that, and for all of Appalachia, it'll probably be right around 260, 270.

Operator

Your next question comes from the line of Amir Arif from Stifel, Nicolaus.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Just -- first question, really, on the Series E Convertible Preferred Stock. So I take it that this is going to be listed at some point, are you can maybe using this on a go-forward basis? Can you just give us a little more color on your callable rights in terms of when the stock is over the conversion price?

Gary C. Evans

Ron, you want to respond?

Ronald D. Ormand

Yes, it's once it exceeds 130% of the call price. It's roughly $11. It automatically -- you can automatically convert it.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And is there a time period before you have -- you can do that? Is it 3-year, 5-year wait?

Ronald D. Ormand

No.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. So once it's over 130% of conversion price?

Ronald D. Ormand

Correct.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

It's callable. Okay. And in terms of the earlier point of -- is this an as needs [ph] you will be using as a funding source on a go-forward basis?

Ronald D. Ormand

We're going to utilize -- our intent is to utilize this for the cash portion of the Virco acquisition. Beyond that, we don't give or announce any additional plans.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay, okay. And then just a quick question on the drilling locations that you put in the press release, the 31 Utica. I'm assuming that's just in the liquids-rich window, is that right? For the vertical acquisition?

James W. Denny

The liquids-rich portion on Utica will be just under 30,000, I think, currently.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

30,000 acres, and that's 31 Utica drilling locations within Virco, that's all liquids-rich?

James W. Denny

That's -- I think it's about 21 in the liquids-rich and the remainder, the other 10, in the dry.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

In the dry gas, okay. But I mean, just given the acreage and the number of locations, there's a disconnect of that these are just more identified specific locations?

James W. Denny

Yes, that's correct. That number, these are the ones that are 100%. So we could -- essentially, we need to do nothing new to be able to drill these locations. Of course, it will take us quite a bit of time to do that, but -- and then if you -- goes to where we have a controlling interest, say 80%, then the number of locations goes up dramatically. And if you just go to where we're going to need some trading or will be in part of someone else's unit or go out and create units with offsets, that's how you develop the full acreage, and that gets to about 340 wells.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. Gary, just a final question, more on the '13 capital outlook. I mean right now, in '12, you've only got $25 million of the $325 million allocated to Appalachia. It sounds like that has been fully picking up, but it also sounds like you have a lot of other potential opportunities for cash proceeds coming in. So are you thinking of keeping the capital spending roughly at the same level and allocating it differently? Or I guess it depends on a lot of other things that you're thinking about?

Gary C. Evans

It does depend on a lot of things that we are working, that we hope to announce before year-end. But I would, for argument's sake, keep the capital budget the same if you're going to try to budget something for 2013.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And that should be coming out late December, sounds like it?

Gary C. Evans

Yes, that's right.

Operator

Your next question comes from the line of Leo Mariani from RBC Capital.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

A quick question here on the Utica. You mentioned drilling your first well in early '13. How should we expect the Utica to progress? Will you just drill 1 well and kind of pause and monitor the situation, or will you drill kind of multiple wells? Just trying to get a sense how committed you are to a substantial Utica program in 2013.

Gary C. Evans

I'll put it this way. We have a joint venture we've been negotiating for about, I don't know, 60 days now, that we're pretty close to finalizing, that is predominantly Utica testing. So we're very committed to it.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And I guess the -- would the newly acquired acreage today be rolled into that JV as well as your...

Gary C. Evans

No, it's existing acreage which we already have. It's acreage that they have and acreage that we have. It's very similar to the Stone-type JV. It's a private company that has acreage that wants us to operate, wants our Eureka Hunter pipeline, wants our expertise. And so we're joining our acreage with their acreage to form a joint venture to more probably develop both Marcellus and Utica.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Got you, okay. I think individual division has mostly commented on lower well costs in all the areas. Could you guys kind of run through where you're seeing in cost in the Eagle Ford and Tableland and then in North Dakota?

Gary C. Evans

Well, I think, in general, you're seeing lower cost across the board just because of all the rigs that have moved from the gas plays to the oil plays. You're also seeing pressure pumping services, a lot of new equipment that has come to market. And so undoubtedly, we're seeing a better cost across the board. However, at the same time, we're drilling longer laterals and we're doing more frac stages. So a lot of that lower cost gets offset into more efficiencies downhole. So that's what I'm seeing. I don't know if the other guys have any comments there.

R. Glenn Dawson

Well, in the Williston Basin, clearly, we've upgraded our equipment profile. In North Dakota, we're using the best skidable rigs. When you drill 4 wells off a pad, you drill the top hole and you drill the build with one set of pipe, you're just skidding the rig each time. So before you drill one lateral, you've now moved out the heavyweight pipe, brought in the skinny pipe and you drill your first lateral. Then you drill the next 3, when you skid? You can skid the rig with a pipe and a derrick. So our cost in there are consistently in the $7 million range on these 4-well pads, which is down significantly. And we're also drilling the laterals much quicker in North Dakota, 2-mile laterals consistently getting drilled in 18 days versus what used to be 28, 30 days. So that's a big timesaver as well. We've got the cost in Tableland to about $3.2 million a well, consistently in the last quarter. And that's just a combination of what we're doing downhole, squeezing our suppliers, becoming more efficient, and we have changed our fracs a little bit, with using less water, which involves less trucking and cleanup. So there's a positive trend there. And there's been a lot of rigs dropped in North Dakota just because they're just inefficient. So a lot of operators are bringing in new equipment from these other gassier basins that are much better and efficient than what was working in there a year ago.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. That was very helpful. Do you have any comments in Eagle Ford as well or...

Gary C. Evans

Kip, do you got anything? Or you might have -- we have a big meeting this morning in Houston, so he might already be gone. Is he gone guys?

R. Glenn Dawson

Yes, Kip stepped out.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

All right. I guess maybe just switching gears a little bit. You all comment that you picked up 6,300 acres at Tableland. Could you give us some color on that? Is this pretty much contiguous to your current position? It seemed like a pretty cheap deal. Obviously, you guys have had a really good success there, so any color around that will be great.

R. Glenn Dawson

Well, it's not in the core. It's -- obviously, at that price, it's more peripheral. But we're the only guys in Canada pushing the Three Forks to this point in time. There only are a few other operators actually drilled 1 or 2 wells. So we're looking at areas that have, from old vertical wells, log indications that the Sanish Three Forks is present and thermally mature. So we're trying to expand our position to be opportunistic at very, very attractive pricing. Not to say that we're not continuing to grow in North Dakota, but this is something we've been able to focus on in Tableland and execute.

Operator

Your final question comes from the line of Kim Pacanovsky from MLV.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

As I look at the recent results on the Utica, I don't see anything in mid-Washington County, where you just acquired that acreage. So can you just go through geologically what you expect as the play moves further south and maybe what kind of liquids component you expect?

James W. Denny

Yes, Kim. We put together a shale cross-section that I've talked to. But without it sitting in front of us, it might be a little difficult to understand. But the point plus a target portion of the Utica, the lower portion of the Utica, is very consistent. It's about 125 to 150 feet, stretching all the way from Carroll County, all the way down to very southern Washington County. And it actually begins to cleanup say from northern Noble to central Washington, where you have -- you maintain your brittleness but your TOC increases and so does your permeability. So -- and if you were to look at the well results, that have been -- that tie and calibrate this shale cross-section, you begin to get a lot of confidence that when you see the target holding together and you see the results very consistent and consistent with what we're seeing in our target, I guess the closest well to our acreage is the -- actually producing is the HG well. There is no infrastructure in the southern portion of the Utica, which is an opportunity for Eureka, but it's also difficult for operators to get things going. Anadarko has a well joining our northern Washington County, which should come online in the next 30 to 45 days. We have -- PDC is drilling in central Washington. So that will be a key well for us. We've got the Miley well that Antero completed. And also the cliffs acreage in northern Noble, which we pretty much surround. So we're getting more and more comfortable every day that our play is being derisked in that area and that it will be -- it's the same as what you're seeing. It's all in the same depth contours and same Btu mapping that we have, the wells I just described. Gulfport [ph], Antero and Anadarko.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Okay, that's great. And then just to clarify on the joint venture that I think Gary mentioned that you're finalizing in the Utica. Is that -- would that joint venture be on the entirety of your Utica acreage prior to the recent acquisition, or just part of it?

Gary C. Evans

No, no. It's a very, very small piece. It's -- we're talking 8,000 acres.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Okay. And then...

Gary C. Evans

It's very, very contiguous. I think, Jim, how many total wells can be drilled on that block?

James W. Denny

We'll be looking at 12 each for Marcellus and Utica.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Okay. And then on the remainder of the Utica acreage, which is now quite sizable, are you still actively seeking a joint venture partner possibly an Asian company to come in and pay up on the front end?

Gary C. Evans

Say that one more time?

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

On the remainder of your -- on the rest of your Utica acreage, are you still actively looking for a joint venture partner to come in?

Gary C. Evans

We're always open. So the answer is yes. It's not absolute that we will do that. What I will say is that, our acreage cost in the Utica is so low compared to our competition that a joint venture in a $7,000 to $10,000 per acre range is about 7 to tenfold increase to our average acreage cost. So other companies that say, "Oh no, it's worth more," we might have a little different attitude. But at this point, we are talking to other parties. We just think it's prudent to scope the market and see what else may be out there. So we got, I would say, a lot of irons in the fire. We're going down a lot of different paths, and we're hoping to determine which path we want to take by the end of the year. And I think that any of them will be meaningful.

Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division

Okay. And then just one last big picture question, and then we can wrap it up. Are you at all concerned that you're putting more capital into the Utica and the Marcellus and obviously, there's a large gas component to these wells? Are you at all concerned that the industry is once again going to drill themselves into low gas prices?

Gary C. Evans

Well, that's a great question. And I've always -- I've been in this business over 30 years. I've seen about 5 cycles, and I've always said low gas prices will fix low gas prices, and when gas hit, too, I was -- became very bullish. So we've been positioning ourselves in the Appalachia division to get ready for this launch, if you will, which we've just begun. So I think what's so very different this go around is that we have the Marcellus. The Marcellus is a huge catalyst in the gas business today. And if you're not in the Marcellus and you're in the gas business, you're going to have a tough row because this is the lowest cost binding gas resource play in the United States, maybe in the world, and it will have activity way before all the other plays. So the Haynesville, the Fayetteville, the Barnett, they are going to be way behind the curve. In my opinion, they need $5 gas, consistently $5 gas. And so we don't need that. We are happy with $3.50, $4 gas. So -- because we've got the liquids component here. So the question is how fast and how much will the Marcellus meet that demand? We're dealing with the clients throughout all the plays in the United States. We're dealing with the lowest gas rig count we've had in many, many years. So -- and we're still in a recession. And we've had gas go from $2 to $3.50. What that tell you, we've had the biggest storage amount in the storage this year, when we ended the season we've never had in history. And we whittled a big part of it down. And it's because the industry is moving from coal to gas, and the industry believes that we do have this large amount of gas resource, which I believe we do, too. So the question is, where will gas go? I really believe we're in a $4 to $5 regime. I think 2013, it won't get much over $5. I think we're in a $4 to $5 regime. At that number, these properties we own already and the ones we just acquired yesterday are going to make money. So we are very excited about the position we're in. We're extremely excited that prices are back into a range that makes these properties generate 50% plus internal rates of return. And we can add bigtime production here. So we're extremely excited about 2013. And I don't think gas is going to spike to $7, $8, $10. I just don't think -- see that happening. I do think you'll see the other plays begin to show some activity over $5.

Okay. Thank you. Operator, we'll sign off. And I want to thank everybody for taking the time this morning to hear our third quarter update and discuss our most recent acquisition. Have a good day.

Operator

Ladies and gentlemen, that does conclude today's conference call. You may now disconnect. Thank you, and have a great day.

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