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Magnum Hunter Resources Corporation (NYSE:MHR)

Q2 2012 Earnings Call

August 9, 2012 11:00 AM ET

Executives

Gabe Scott – VP, Capital Markets and Corporate Development

Gary Evans – Chairman and CEO

Ron Ormand – EVP and CFO

Kip Ferguson – EVP, Exploration

Jim Denny – EVP, Operations

Analysts

Veea Chan – SunTrust

Kim Pacanovsky – MLV

Jeff Hayden – KLR Group

Irene Haas – Wunderlich Securities

Joe Stewart – Citi

Hsulin Peng – Baird

Richard Tullis – Capital One

Steven Karpel – Credit Suisse

Operator

Good morning, and welcome to the Magnum Hunter Resources Second Quarter 2012 Financial and Operating Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions)

Thank you. Mr. Scott, you may now begin.

Gabe Scott

Good morning. This is Gabe Scott and I’d like to welcome everyone to Magnum Hunter Resources Corporation second quarter 2012 financial and operating results conference call.

The purpose of today’s call is to discuss our second quarter 2012 financial and operating results among other matters of interest regarding the company.

Before we begin our presentation, I would like to advise you that today’s call may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of Securities Exchange Act of 1934.

Our presentation may include statements regarding our expectations, believes, 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 its 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 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 statements disclaimer as well as reconciliation to certain non-GAAP financial information presented are included in the company’s second quarter 2012 financial results press release dated August 9, 2012, which is posted on the company’s website under press releases. This disclaimer is in effect for the full duration of this conference call.

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

Gary Evans

Thank you for dialing in today and hearing about our second quarter as well as our six months ended June 30 financial results we reported this morning before the market opened. The company reported a record revenues of $60.3 million for the three months ended June 30. We also reported record EBITDA of $41.1 million pro forma for the second quarter, which included our acquisition of the Baytex properties located in Williston Basin that was completed in May.

Average production rate for the second quarter increased to 162% and our liquidity continue to increase with combination of our high-yield offering, our perpetual preferred, our new borrowing-based increase and we presently have about $255 million of liquidity including what we can sell under our perpetual preferred Series D.

So, all in all, if you look at the quarter, we continued our game plan of exploiting predominantly our existing assets located in Williston Basin with active rigs running in North Dakota, five rigs today; two rigs running in Saskatchewan. And then we also continued our development efforts in the Eagle Ford of South Texas, predominantly Gonzales and Lavaca counties where we’ve had substantial success. We have two rigs running down there today.

So we made a decision, early part of the year, to refocus a significant piece of our capital budget to oil. Magnum Hunter is in a unique position of having a number of shale plays where we can redirect capital dollars and as operator, be in control of that and therefore change our production mix pretty rapidly.

So in the second quarter we now are over 50% crude oil production, which, as you know, with current crude oil prices around $93 to $95 a barrel have significantly better margins than what we’re experiencing on natural gas at around $3 an Mcf. So that is something that not many companies can do is direct their capital so quickly and change their production mix so quickly, which has allowed us to report these substantial results. That will continue throughout 2012.

Our capital of $325 million for upstream is geared to these two oil projects being the Williston and the Eagle Ford. We did announce earlier this week that we have moved into another region of the South Texas area called the Pearsall and we’ve actually spud our first well. That will be a test well to that formation. We will end up completing that well in the Eagle Ford.

We believe that there is some unique opportunities to pick up additional acreage and to expand our footprint in the Eagle Ford and we are looking at those opportunities with great interest. We also continued to expand our leasehold position up in Canada in Saskatchewan, where in the Tableland field we continue to have significant success with the way we are completing and fracking the new wells up there and getting much higher oil production and much less water production and therefore getting much better EURs.

Now, let’s – don’t leave Appalachia out because we are very high on our Appalachian division. We’ve intentionally delayed capital spending there this year predominantly because we do not have a gas processing plant up and running yet that can strip the very rich liquids that we have in that gas stream. Our plant is supposed to go live in November. It was supposed to go live in June and it is four months behind schedule. But we believe that it will happen before the end of the year and that’s a huge uplift for this company.

It’s about $1.50 an Mcf on top of the $3 gas price puts you about $4.50 an Mcf for the rich liquids gas sold in that division. Then you will see in 2013 a redirection of our capital again. The Appalachian division undoubtedly will get a much larger share of our future capital budget because this gas plant will be up and running and allow us to extract these liquids that we have yet to do on all of our Marcellus well activities in this region.

We also are active in the Utica. We have leased about 60 some odd thousand acres. There has been some recent results announced in and around our acreage by Anadarko – I’m sorry – by Antero, by Gulfport yesterday. And we are seeing some results from Anadarko as well. So we have at this point been watching others. Again this is an area where pipeline capacity is not prevalent, does not exist, so we are extending our Eureka Hunter pipeline under the Ohio River.

I think we actually bore under the river in September. We’ll get all the necessary permits in hand, which will allow us to begin developing our Utica acreage possibly even as early as later this year. The Eureka Hunter midstream division continues to grow, continues to build pipe, these predominantly 20-inch steel that can move 200 million the 300 million a day. We brought in a financial partner earlier this year ArcLight who is as excited as we are with respect to the future growth potential of that midstream division.

We’ve also, as you know, bought TransTex which a gas Amine/JT unit company that is continuing to contribute to our EBITDA and growth in that area. Their expertise is also enabling some of our other upstream divisions to look at areas that may have sour gas or other purifications in the gas stream that will allow us to move in the regions we may not have done otherwise. So, borrowing base increase was significant, just approved a few days ago from $212.5 million to $260 million.

And so with that I’m going to turn the call over to Ron who can give some specific details on our financials that I haven’t given, Ron?

Ron Ormand

Thanks, Gary. Yeah, it was a very significant quarter for us in terms of growth revenue, historic revenue and EBITDA for the quarter. We increased our revenue 104% to $60 million, $60.3 million compared to $29.5 million last year. That’s including the partial impact for Baytex.

The second quarter net loss was approximately $0.10 versus $0.16 on the second quarter in 2011. After we take out are nonrecurring, non-cash expenses predominantly the cash expense has been on the Baytex transaction, which was out at $8 million. We come up with $0.04 a share loss.

Couple things I’d note, our average realized price per barrel in the second quarter was only $45 compared to $57 last year, so we had a $12 drop in our realized price; however, our cash margins actually increased to $26.78 from $22 in 2001. That’s because we’ve had a dramatic decrease in our LOE and our cash G&A as we’ve grown our businesses and brought on newer, more cost-efficient production.

Our LOE has decreased down to around – about approximately $10 a barrel from $15 per BOE and our recurring G&A has increased – decreased, I’m sorry from $15.36, all the way down to $5.29; essentially as we have grown our operations into our G&A basis, which we’ve been saying for some time. As a result, our EBITDA was able to meet or exceed consensus. We were approximately $38.2 million in the quarter or $0.25 a share versus $12 million in the second quarter of 2011. Our adjusted for Baytex our EBITDAX was $41.1 million.

I also mentioned that I think if you look at our margins as they are improving, we would expect those to continue to improve as we’ve seen the improvement in oil price. Our cost remaining consistent if not declining down, so our cash margins should be increasing in the third quarter. As Gary mentioned, we’re now approximately 50% oil and liquids and expect to exit the year closer to 60%. So that’s going to have a dramatic impact, obviously, depending on oil price on our cash margins.

We also recently increased our borrowing base from $212.5 million to $260 million, which is 22%. This is all organic. This does not include anything from the Baytex because that was already, but previously baked into our borrowing base, so this is solely off our organic growth that we’ve had (inaudible), so that’s a pretty significant bump for one quarter.

We also have significantly added to our hedge position in the quarter, particularly on the oil side. As you’ll see we have a schedule in the press release, where we’ve added about 3,500 barrels a day in 2012, 1,000 barrels a day in 2013 and 4,000 barrels a day in 2014, protect the downside and give us the necessary cushion for our capital program and enable us to continue with those hedges on the downside. As we’ve already discussed previously, we’re well hedged on the gas side as well with about the $3.50 minimum there for the next two years.

So, we feel very good about our hedge position. At this time, our liquidity position is very strong. As Gary mentioned, with the increase in the borrowing base and our preferred availability we have about $250 million, so more than ample liquidity and cash flow to fund our remaining budget for this year and for the foreseeable future.

So, we feel very good about where we are. Our operations are ramping up quite nicely. The transition that we’ve made from 35% gas all the way to 50% in one quarter and switching over to 60%, I think, compares very favorably with anyone in the industry that has been attempting to do that and demonstrates that we are successfully doing that.

And the beauty that we have in having three resource plays. Okay. Sorry, increasing our oil production, I said gas production; substantially increasing our oil production up to 60%.

So, with that I’ll turn it back to you, Gary.

Gary Evans

Thank you, Ron. We’ve also got available, as we take questions today, the three division heads Jim Denny, Glenn Dawson and Kip Ferguson that run our three operating divisions, as well as Don Kirkendall, who runs our Midstream division. So, if we have specific questions about our activities in the field or some of our recent completions, these gentlemen are available to answer those questions.

I would like to emphasize again one of the things that Ron mentioned, and that is our cost structure. We have worked really hard this year in trying to control cost especially in the volatile commodity price environment, the oil and gas companies are experiencing just to kind of give you the idea, oil has gone from one $107 down into the $70s back to $93. And when you have that kind of volatility it definitely is something that directly affects us. So we worked hard in trying to reduce our drilling costs, our operating costs, our G&A costs and those reflected in these numbers, and that is what allows our cash margins to continue to expand.

And we believe there is more meat on the bone there as the months go by and we are continuing to work on that, becoming more efficient by drilling top holes with their own rigs.

We bought a couple – we actually bought three new rigs in the past year so that we can control that, drilling more pads, handling disposal wells more efficiently, owning some of our own equipment in the field that we typically would rent. When we know that we’re going to be repeating drilling wells and using the same equipment time and time again.

So all those things go into reducing your LOE and keeping our head count down, we’ve been very, very prudent and we’re actually growing into our reserves. And so as we reported at mid-year we had a huge increase in proved reserves over 50% increase. We anticipate additional reserve additions as we continue throughout the year.

So all-in-all, we think it was a great quarter. Staying the course, I think you’ll see greater production growth in the third and fourth quarter. We still are very confident with their 18,000 BOE exit rate. And hope to exceed that based upon some of the results we’re seeing.

So anyway, with that I’d like to take some specific questions addressed to the management teams. So operator, can we have our first question.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from line of Hsulin Peng with Baird. Hsulin, your line is open. That question has been withdrawn. Your next question comes from the line of Veea Chan with SunTrust.

Veea Chan – SunTrust

Hi. I was just wondering where some of your rigs currently are and where, yeah end do you think they will be?

Gary Evans

You’re talking about the drilling rigs?

Veea Chan – SunTrust

Yes.

Gary Evans

The ones that we lease or our company-owned. Which ones are you asking about?

Veea Chan – SunTrust

Both.

Gary Evans

Okay. Well, up in North Dakota, we have five non-operated rigs, those are with a combination of Samson and Baytex is operator of those. Up in the Tableland field we have two operating rigs. Then down in the Eagle Ford, we’ve got two rigs that we leased from Patterson. We have one rig with unit, which we’re getting ready to release. I didn’t really mention that but that rig is going back. And then we own at Alpha Hunter drilling four of our own rigs.

One is located down in the Eagle Ford, we just moved that about a month and a half ago and it’s actually drilling that first well in the Peter ranch property. And the other three are up in Appalachia, two in a long-term contract with EQT drilling Marcellus top-hole wells.

Veea Chan – SunTrust

Okay. And other then the acquisition in Atascosa you just made, are there any other place in the Eagle Ford you are looking at?

Gary Evans

We consistently look at new leases and opportunities. We are doing a fair amount of trading were we’re trading some of our acreage for other acreage that we like or maybe we can form a bigger unit to better develop the property.

We also are continuing to look at this Pearsall Play and where it might exist. And so we’ve been talking to a lot of the larger companies that have large acreage positions that might want our expertise to help develop those properties. So we’re hopeful that we’ll have some more announcements about acreage expansion, both in the Eagle Ford and Pearsall in the months to come.

Veea Chan – SunTrust

All right. Thank you.

Operator

Your next question comes from the line of Kim Pacanovsky with MLV Company.

Kim Pacanovsky – MLV

Yeah. Hi, Gary. I’m just wondering if Pearsall is wildly successful in the big picture, what are some of the infrastructure challenges as it applies to liquids handling?

Gary Evans

No question that the Pearsall has, in my opinion, more liquids handling issues than what we’re dealing with in the Eagle Ford over in Gonzales and Lavaca. And part of the problem is the Pearsall is going to be more sour, so it’s got H2S and there are not sufficient facilities in place in the areas that we’re drilling to handle that.

Fortunately, we bought TransTex Gas about three months ago and that’s right up their alley. So we have that group of process engineers looking at how we can put the infrastructure in place to handle sour gas that we anticipate with the Pearsall.

Kim Pacanovsky – MLV

So if – say, you drill a couple of wells, you see a lot of success there. What’s the timeline for getting that infrastructure in place? Is this really more like an end 2013 type of ramp?

Gary Evans

Yeah. I don’t see how anything would get accomplished in 2012. It may not be end, it could be the middle 2013. It depends on what we see – there’s some other companies that have drilled some wells in the area. This Peter Ranch leases were completely surrounded by EOG and now they’ve been drilling a number of Pearsall wells. And so I don’t know how they’re handling currently the gas stream. That’s something that we’re investigating right now.

But EOG has typically kind of done things themselves and not use third parties, so we’re looking at how we could handle the gas needs. We’ve been approached already by other companies on let’s join forces and see how we can handle this infrastructure.

Kim Pacanovsky – MLV

And now I see on your map of the new acreage that you’re adjacent to Marathon. Do they have results there yet?

Gary Evans

Kip, you’d be better suited to answer that question than me.

Kip Ferguson

Okay, great. Hi, Kim.

Kim Pacanovsky – MLV

Hi, Kip.

Kip Ferguson

We’ve had several meetings with Marathon. We worked with them in our Gonzales area. On the Eagle Ford, we actually operate a couple of joint wells together. And where they are right now, they’ve just finished a – they’re testing the Pearsall, I think, is the best way, but they don’t have any results yet.

Kim Pacanovsky – MLV

Okay, great. And then just one last quick question, can you just detail where the 14.7 million barrels of organic reserve additions came from geographically?

Ron Ormand

Broken out by area...

Gary Evans

The majority from the Williston Basin.

Ron Ormand

Yeah. Majority in the Williston Basin.

Gary Evans

We can provide you (inaudible).

Ron Ormand

Williston Basin. (Inaudible)

Kim Pacanovsky – MLV

Yeah.

Ron Ormand

...because we didn’t do much. We really didn’t do any drilling in the Marcellus.

Kim Pacanovsky – MLV

Right.

Ron Ormand

I don’t have all those figures. But we can give them to you.

Kim Pacanovsky – MLV

Okay, great, super. Thanks a lot guys.

Operator

Your next question comes from the line of Jeff Hayden with KLR Group.

Jeff Hayden – KLR Group

Hey, guys. How are you doing? Kim just got a couple of my questions about the Pearsall, but just when you guys kind of look at it, what’s the expectation of kind of the product mix that you guys are looking for out of the Pearsall on this acreage?

Jim Denny

Hi. This is Jim. I will help you with that. The Pearsall, there has been a number of Pearsall tests. Just to the South of us, there was a bunch of independent companies that had a couple of tests. And their results are – have been published in the 6 million to – 6 million a day and about 700 barrels of condensate a day. Now we’re up dip from them and as you go further up dip into Northern Atascosa County, there is some flat out 30 API gravity crude test.

So I think that we’re kind of in between. We really like our area because it’s the ideal depth, it’s kind of equivalent to where we are in Gonzales about 10,700, 10,800 feet deep. And we’re expecting a lot more condensate/oil-rich area. I don’t – I can’t exactly quote the GOR for you yet but we’re expecting quite a bit more liquids.

Jeff Hayden – KLR Group

Okay. And what do you think the well cost are going to run for Pearsall horizontals?

Kip Ferguson

Right now. I think, they are somewhere around $9 million to $10 million because there could be a one-off well and you don’t have the efficiencies of pad drilling yet. So I think the first initial wells might cost a little bit more just because you just don’t have that pad drilling efficiencies at that time.

Jeff Hayden – KLR Group

All right.

Kip Ferguson

Sorry, the typical Pearsall horizontal be about that. The first well, we are drilling is a vertical well and we’re just doing testing, logs and cores.

Jeff Hayden – KLR Group

Okay. Great. I appreciate it, Kip.

Kip Ferguson

Thanks.

Operator

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

Irene Haas – Wunderlich Securities

Hi, guys. One more Pearsall question. How does the rock look like in terms of TOC and percent brittle? Does it look any better or worse than the stuff in Maverick Basin, number one. And number two is you still looking at your yearend reserve of roughly 80 million barrels?

Kip Ferguson

I guess, I will handle the – this is Kip, Irene, hello. Good morning. I guess, I will handle Pearsall question for you first. One of the things we like about the Pearsall so much is about a 500 or 600 foot thick section, which really excites us but some of the results that we’ve seen and some of the logs that we’ve been working on and shale analysis logs, we’re looking about a couple of hundred feet of really good quality shale with 20% or less shale in there.

It’s mostly limestone with silica in there, so your shale content is about 20% or less over a couple hundred feet. So that’s significantly thicker than most of the Eagle Ford that we see in our Gonzales area, so that’s one of the reasons we like the Pearsall so much. It’s the right depth, it’s the right setting for us in Atascosa County and we like the thickness. So it could be interesting.

Irene Haas – Wunderlich Securities

Great.

Kip Ferguson

Can anyone answer the other question?

Ron Ormand

Okay, I...

Gary Evans

The question about the 80 million barrels of reserves, I think there’s a good chance, it’s going to be somewhere around that, a little bit lower or little bit higher but I would say that’s a good chance, we’re headed that way.

Irene Haas – Wunderlich Securities

Great.

Gary Evans

One thing that will allow us to book some really nice reserves is when this gas plant goes live in November we keep talking about that MarkWest is building. That it then allows us to book proved producing liquid reserves on all of those Marcellus wells we drilled that have never been booked before. So it’s a big number. And then of course we have another big gas pipeline going live in the first quarter, hopefully of 2013. That’s the ONEOK system up in the Williston basin, is gathering all those wells that NuLoch has drilled and Samson and Baytex and we’re also working with ONEOK to bring the Tableland gas out of Saskatchewan across the border (inaudible) so that will be another big hit for reserves early next year.

Irene Haas – Wunderlich Securities

Great. Thanks.

Operator

Your next question comes from the line of Joseph Stewart with Citi.

Joe Stewart – Citi

Hi. Good morning, everybody.

Kip Ferguson

Good morning, Joe.

Joe Stewart – Citi

Most of my questions have been answered, but I still have a couple left here. Gary, with a nice bump to your borrowing base and then, obviously, the cash on hand and the preferred stock, you have, like you said, more than enough liquidity to fund 2012 and most if not all of 2013. But could you maybe just give us an update on your thoughts regarding other liquidity enhancing options?

Gary Evans

Well, this company is asset rich.

Joe Stewart – Citi

Yes.

Gary Evans

The market doesn’t seem to understand that. We continue to prove it every quarter by putting on new wells, bigger and better than before. So I can tell you though the industry does recognize it. We are approached consistently with acquisition opportunities, joint venture opportunities, so, because we are so asset rich, we may very well do some JVs. And we’re talking to parties about that. So those would obviously be large liquidity events and those discussions continue. They’ve been going on for a year.

So I’m not making any promises about when something is going to happen, but as we continue to prove ourselves and grow reserves and grow production better than anybody in our peer group then, as you can imagine, the industry whether it’s local companies or whether it’s international companies looking to invest in United States we’re being approached having those discussions and somebody gives us the right number then they will own part of our properties.

Joe Stewart – Citi

Okay. And Gary, is possibly monetizing another portion of your interest maybe another 20% to 25% or so in your Eureka Hunter next year, is that still on the table?

Gary Evans

Undoubtedly. We continue to separate Eureka Hunter out of the Magnum Hunter as a division. We’re hiring more people directly related to that entity. We’re separating our accounting. And we’re on a goal to get Eureka Hunter public as an MLP sometime before June 30, 2013. And our partner ArcLight has that same goal in mind. So we – definitely that’s another obviously liquidity event for the company sometime early next year.

Joe Stewart – Citi

Yeah. And even, if you guys wanted to retain majority ownership of it, so you sold out about another 25% or so the ArcLight transaction would have valued at about another $100 million for you then right?

Gary Evans

Will, yeah, I mean we sold, in essence a quarter for about $100 million, so the remaining is worth $300 million plus. Of course, we believe the value of Eureka is going up as we continue to lay pipe and spend capital. And the real hit for Eureka happens, again, when this gas plant goes live. I personally believe Eureka Hunter pipeline system is going to full before anybody realizes it.

And we’re concerned that we haven’t saved enough capacity ourselves because there is so much demand for throughput in that system going forward, now that we are getting closer to having this plant up and running. So I think Eureka Hunter has got a very bright future. It couldn’t be better positioned of any play in the United States than where it is today and we have very little if any competition.

Joe Stewart – Citi

Yeah. Okay. And then, Kip, you mentioned $9 million to $10 million well costs for a typical Pearsall, obviously early days on that, but what are you assuming on the lateral length and frac stages for that?

Kip Ferguson

I think the initial lateral length would be between 5,000 and 6,000 feet and we look at somewhere around 20 stages to start with.

Joe Stewart – Citi

Okay.

Kip Ferguson

And then we kind of adjust from there.

Joe Stewart – Citi

Okay. All right. And then, I know it’s a small number of locations, but could you maybe just give us your expectations for those additional 10 to 13 net locations you picked up in the Eagle Ford with that transaction yesterday?

Kip Ferguson

That area is really kind of a – it’s a different area. We’re looking for – one of the things we see about that is really we kind of picked it up with Pearsall and we’re going to drill an Eagle Ford test there. But one thing we see about that whole area is a dual Pearsall and Eagle Ford combo because the pipe we set for the Pearsall is 7.625 inch pipe we set for the Pearsall, we get a behind pipe horizontal in the Eagle Ford. So it’s kind of a two for one, you spend a little extra money for drilling the Eagle Ford down the road, so we’re kind of looking at that type of operational procedure.

Joe Stewart – Citi

Okay. All right. So do have any thoughts on – can you may be just remind us what – like what the pressures will look like there and what the product mix is in the Eagle Ford?

Kip Ferguson

Yes. It’s going to be similar to what we have in Gonzales. We think it’s going to be somewhere around 600 or 700 GOR. So anywhere from – I actually don’t know, I think we’re somewhere between 600 and 800 barrels of oil a day and whatever the associated gas is.

Joe Stewart – Citi

Okay. Great. Thanks a lot guys, I appreciate it.

Operator

(Operator Instructions) Your next question is from the line of Hsulin Peng with Baird.

Hsulin Peng – Baird

Good morning. Sorry about the technical difficulty earlier. Just a follow-up question on Pearsall, so in terms of your – the well cost $9 million to $10 million in Atascosa County, is that fairly similar to the areas nearby based on their results and what you think that you’re seeing around there?

Kip Ferguson

Well, I mean, obviously the Pearsall is really early on. The results have been – the results in our immediate area, there just haven’t really drilled a lot of wells in our immediate area. But just to the South of us, I mean, relatively close, I mean, less than five miles, they have some results that they have announced, an independent company that they actually have on a road commission and there’s a couple of different people that follow that independent, I guess, and kind of released some information.

So we feel pretty comfortable as to the rates, we know that we’re up dip from that. We think that we’re going to have a different GOR mix. So actually I’m not 100% sure as to what that GOR is going to be unfortunately. I think it’s going to be much better in the liquids – favoring the liquids than what they had encountered already.

Hsulin Peng – Baird

Thanks. So – that sounds good. We’ll just wait to see. So then in terms of – assuming the initial core data comes out positive, how do you think about Pearsall’s development for the rest of 2012, meaning, because I think you mentioned you would shift CapEx to some – another region, so where would you – how much money do you think you will shift and how – and what region would you be shipping from?

Kip Ferguson

Well, I think it’s going to – I think the initial well is going to be kind of minimal, right. But – there is one other things we’re talking about is the lot of – we have partners that we work with that are kind of associated nearby our wells, our acreage and that we’re already discussing a joint well. So I think that the initial well might be a joint well, which would require significantly less capital. So I think we’ll just kind of shift some funds over from the Eagle Ford and into the Pearsall to kind of test the play initially. But, we think that we’re going to do that probably within the next six to eight months maybe even sooner.

Hsulin Peng – Baird

Okay, got it. Thanks. And then second – another question in your net year reserve report, can you remind us what your assumptions you’re using for Eagle Ford and for Williston Basin?

Kip Ferguson

Right now we’ve been using Cawley Gillespie, we’ve kind of been going back and forth on our EURs. They’ve actually been increasing every time we do an analysis, just because we have lot more information.

Hsulin Peng – Baird

Right.

Kip Ferguson

What we’re using right now is 450 Mboe.

Hsulin Peng – Baird

Okay.

Kip Ferguson

Some of the puds that we – some of the wells that we have are even approaching 550 from internal estimates. We have some wells, they’re clearly exceeding the Cawley Gillespie’s decline curve. So we’re quite excited about it. We have like four or five of them actually that are exceeding that 450 decline curve that we are projecting. But right now, I think, we’re just going to stay with the 450 on our projections and what we kind of estimate going forward. And if we get better results, we’ll probably announce them in December.

Hsulin Peng – Baird

Okay, great. And last question. Can you just tell us what you’re current production is and any update on the timing of the curtailment in Appalachia?

Kip Ferguson

Do you – would you like to talk about the company’s current production, or individual?

Hsulin Peng – Baird

Overall would be great.

Kip Ferguson

Okay. Gabe, you want to talk about that for Hsulin?

Gabe Scott

Yeah. It’s the same as we announced in the second quarter operations overview. And as far as production curtailment it’s still status quo.

Hsulin Peng – Baird

Okay.

Gary Evans

Yeah, the – well, the curtailment that we were experiencing up in Appalachia – I got an update on that this morning, Gabe, are basically gone. So we had some significant curtailments due to weather, over 2 million homes were knocked out in Ohio with a storm that came through there. And we were curtailed off and on for a number of weeks. But as of today, we’re pretty much running full speed ahead with our production.

I do think it’s important though, Kip, for you and Jim even for you to mention how many wells you got drilled and are waiting for completion, because we’ve got probably one of the biggest backlogs right now that are all coming online here over the next two to four weeks that will have substantial impact on our production. Kip?

Kip Ferguson

Yeah. Thanks, Gary. Yeah, so one of the things in the Eagle Ford, we’re starting to do a lot more pad drilling, which obviously gives you a pretty good surplus of wells needed to be fracked. I mean, currently we just finished a frac and we’re just pulling back a new well right now, and we have seven wells that are either fracking or waiting to be fracked as we speak, so, all within the next 60 days. So we have quite a new – bunch of new wells coming on, I think, in – between now and the end of the year we have an additional seven wells gross that will be drilled, maybe even 10 wells gross that will be drilled by then and hopefully fracked to come online. So we have a huge push of wells to be fracked.

Our service provider is Halliburton. And Halliburton has promised us all the frac crews that we need to get our wells all fracked by the end of the year. Even to the extent of getting us a dedicated crew for that area, Gonzales area. So we’re quite appreciative of Halliburton for doing that for us. So, we’re looking forward to a really nice third and fourth quarter. Jim?

Jim Denny

Yeah. Good morning. We have three 100% wells and four 50% wells that are drilled and cased and waiting for frac. We intend to frac those wells to time that to be come on production in mid-November or maybe even a little earlier based on the processing plant coming live at Mobley. So we will have five net wells coming on in the fourth quarter.

Hsulin Peng – Baird

Thank you very much.

Operator

Your next question is from the line of Richard Tullis with Capital One.

Richard Tullis – Capital One

Thank you. Question for Kip on the Eagle Ford. I don’t believe you mentioned it, Kip, what our current well costs running you for your longer laterals?

Kip Ferguson

Right now with the pad drilling we’re looking around $8.2 million, $8.4 million a well. And the only difference from us and other people I guess is we report all production facilities, the fracked wells, the fracked con, so really that’s kind of an all-inclusive cost, including electricity and pipeline and everything to be hooked up. So a little bit different way to report your well costs that we have included altogether.

Richard Tullis – Capital One

Okay. And are you still using the method where you shut the wells in initially after completion and then bring them on maybe a week later?

Kip Ferguson

We are. When we’re fracking wells in and amongst other wells we have to shut in all the wells around us. So we can try to get the best – we don’t want any leak off. We really want this to – we call it Shake and Bake is what we kind of coined the name. And Shake and Bake is just basically utilizing the hyper pressure that you have injected into the formation by the frac crew and kind of shutting that in even after frac from anywhere from five to 10 days.

Just trying to get a little extra stimulation and I think allow the rock to continue to frac. Obviously, we all know the Eagle Ford and the Marcellus, the Bakken and Sanish alike have a tremendous amount of oil in place and gas in place, it’s just a matter of really stimulating that rock better and getting that rock to continue to frac, we found a tremendous result from our efforts in doing that Shake and Bake.

Richard Tullis – Capital One

Okay. Well, thank you that’s all for me. The rest of my questions have been covered.

Kip Ferguson

Thank you, Richard.

Operator

Your next question is from the line of Steven Karpel with Credit Suisse.

Steven Karpel – Credit Suisse

Good morning. Can you talk about – Gary, in the past you’ve referred to taking over operatorship on some of the other acreage in the portfolio specifically probably the stuff up North. Can you comment a bit on where you are on that and where you think that goes?

Gary Evans

Well, we are an operator now in North Dakota. We operate about 300 wells predominately over in Burke County and that’s related to our Eagle acquisition we did earlier this year. We continue to have discussions with Samson about possibly operating an area right along the border of Canada and North Dakota. And those discussions are continuing. We’re just trying to arrive at values that we both agree to regarding that acreage. So we don’t operate obviously the acreage that’s’ with Baytex. It’s only about a 10% working interest and it’s probably deemed today to be non-core and it may be something we may divest in the future.

And then we do obviously have the 47.5% in the Baytex assets that Samson is the operator. So I will say this, Samson has made great strides in taking into account some of our completion techniques and they’ve done a good job in bringing down their cost. And so we’re feeling much better about the way they are handling their business. As you know, they have been bought out by KKR and they have a lot of other senior financial people overlooking their shoulders. So everybody is watching their Ts and crossing them and dotting their Is. So I feel like things have improved markedly there and it is still our goal to become an operator in the Williston Basin more on the Bakken, Three Forks side and I think that will happen this year.

Steven Karpel – Credit Suisse

And then secondly is some of the well performance I think since you’ve taken over has been better. Can you quantify a bit? I know it’s only been a short period but some of the well performance you’ve seen on the acreage, I suppose pre and post you taking operatorship?

Gary Evans

Glenn, can you comment on this? Glenn?

Ron Ormand

I think (inaudible).

Gary Evans

Okay. I can tell you that we just actually had a Board meeting yesterday where Glenn Dawson presented some of the drilling results that we’ve had post the Baytex closing. And you are correct, the results have been better. We’re having wells that are IP-ing 800 to 1000 barrel a day range and 30 day rate still in the 600 barrel a day range.

So I think that’s a combination of longer laterals, more frac stages, smaller frac stages in between from the standpoint of sand amount. And therefore we are not getting so much water. So we feel really, really good about the acreage we bought. I think the market felt like we paid too much. We think give us another six months to a year and we’ll prove what we’ve acquired there. So we’re actively exploiting some of the areas that we know best. We’ve been approached by some of the companies wanting to buy in our interest, which we chose not to do. So we know from the competition when we have leases coming up for expiry, we are renewing and we see the top leases from all the big names up there. So we know Divide County is getting a lot of attention from our competition.

Steven Karpel – Credit Suisse

And just lastly on that, since you’ve taken over the operatorship, can you talk about AFEs? And are you actually doing things pretty substantially different on the cost side to them?

Gary Evans

Well the things that we’re operating are primarily over in Burke County, which are Mississippian wells. And what we’ve been able to do there is substantially cut the lease operating expenses.

We have yet to drill a well there in the last couple of years. So I can’t give you an AFE. But I can tell you, we now have two rigs running in Saskatchewan, which is just across the border. People think Canada is a long ways away; you can throw a rock and hit our rigs across the border.

So we’re drilling actively over there. These are 100% owned wells. Again, 97.5% in that royalty interest, so economics are phenomenal. And we’re getting consistently 600, 700, 800 barrel a day wells and they’re holding up nicely. And the engineers at midyear gave us a nice bump on the EURs so that is where we’re drilling one-mile laterals, they’re not two-mile. They’re shorter laterals because we only have that royalty relief for the first 100,000 barrels of oil we produce.

So we believe that we’ve really kind of got the code figured out. We’ve been stepping out and drilling some wells on some really kind of a rank acreage and having some good success. So we continue to pick up crown acreage, continue to expand our position there. And I wouldn’t doubt to see in a couple of years we got 100 wells producing up there.

Steven Karpel – Credit Suisse

Thank you, guys.

Operator

Your next question comes from the line of (inaudible) with Jefferies & Company.

Unidentified Analyst

Good morning, gentlemen. Most of my questions have been answered. I just have a quick one about, I guess, what your next steps are in the Utica right now. Are you kind of planning on getting that first well done first or are you currently looking for a partner to do that with you? Kind of just – want to be...?

Gary Evans

Yeah. That’s a good question. We keep asking ourselves that same question. So, one day we think, well, this – we – as you know in the Utica, we’ve seen spotty results for the last year until the last 90 days. In the last 90 days we’ve seen some phenomenal results. And when we’re leasing in Noble County and Washington Counties and Monroe County, everybody was yawning and saying, you guys are way to South, you’re not in the play. Well, guess, what, all the new wells are right offsetting our acreage within either feet or miles. I mean it’s really close stuff. So we are getting – we received unsolicited offers for acreage that’s substantially greater than what we paid just in February of this year.

Remember we bought a big chunk of this acreage. It was a $20 million transaction, I think, we closed in February. So we could flip what we bought in February for probably 3 to 4 times what we paid. So we’re trying to determine, well, do we put a bunch more cash in the bank, do we do a JV, do we drill, so I can’t answer that question yet. We’re still kind of laying behind the log and trying to figure it out. But one thing we do know, as time has gone by our acreage value has gone up substantially.

Unidentified Analyst

Well, thanks for that. I was just wondering if you have any color on what people are doing differently that made the resource better.

Gary Evans

Jim, you got any comments on that?

Jim Denny

I think just they’ve been moving mostly from the oil window down into the condensate window keying off the Chesapeake Buell well, so I think it’s the contour of the window that they’re dealing with. And you get a little bit better rock as you move west to east. So I think it’s a combination of that. I think you’re watching the drilling fluids a little better and I think they’re using more frac spaces.

Unidentified Analyst

All right. Thank you so much for that color. That’s all I have.

Operator

There are no further questions at this time.

Gary Evans

Okay. Operator, I think we are done. We’ve been right at an hour, so, again, we thank all of you for dialing in. We feel like the company is staying on course. Growing its resource base and all the basins we’re in. We’ve gone from 3 to 5 unconditional resource plays. And we hope to have more news about our activities in these new plays as the year progresses. But more importantly, we are ploughing down the road that we’ve outlined and staying on budget and bringing on some very nice wells, so that will increase our reserves further and increase our revenues and EBITDA, cash flow and then we hope to become a positive income maker here before too long. So thank you for your time and thank you for your support and have a good day.

Operator

This concludes the Magnum Hunter Resources Second Quarter 2012 Financial and Operating Results Conference Call. Thank you for joining. You may now disconnect.

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