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Executives

Paul M. Johnston - Senior Vice President, General Counsel and Corporate Secretary

Gary C. Evans - Chairman and Chief Executive Officer

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

Analysts

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

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Kim M. Pacanovsky - MLV & Co LLC, Research Division

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

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

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Magnum Hunter Resources (MHR) F4Q 2012 Earnings Call June 14, 2013 10:00 AM ET

Operator

Good morning. My name is Vernel, and I will be your conference operator today. At this time, I would like to welcome everyone to the Magnum Hunter Resources Earnings Call. [Operator Instructions] Mr. Johnston, you may begin your conference.

Paul M. Johnston

Thank you. Good morning. Today is Friday, June 14, 2013. This is Paul Johnston, General Counsel of Magnum Hunter Resources Corporation, and I would like to welcome everyone to today's conference call.

I will be the moderator for the call. The principal purpose of today's call is to discuss our fourth quarter and full year 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 will include forward-looking statements within the meaning of the federal securities laws, specifically, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

Our presentation will include statements regarding our projections, estimates, expectations, beliefs, assumptions, intentions and the future strategies. Such forward-looking statements will relate to, among other things, our revenues and production, upstream and midstream operations and reserves. These statements are qualified by important factors that could cause the company's actual results to differ materially from those reflected by the forward-looking statements, including those factors set forth in the Risk Factors section of the company's annual report on Form 10-K for the fiscal year ended December 31, 2012, which we filed this morning with the SEC. Our annual report includes a glossary of certain industry terms that may be used in today's call. The full forward-looking statements disclaimer is included in the company's press release dated June 14, 2013, which we issued this morning. The press release is posted on our website. This forward-looking statements disclaimer is in effect for the duration of the call.

The press release also contains and our presentation may include statements regarding certain non-GAAP financial measures. As part of the press release, we provided reconciliations of these non-GAAP financial measures to their most comparable financial measures calculated in accordance with GAAP. We refer you to our statements in the press release regarding these non-GAAP financial measures.

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

Gary C. Evans

Thank you, Paul. That was very exciting. I know you were up all night like a lot of us, so you need to get some sleep. All right. Good morning, and thank you, all of you, for dialing in. Magnum Hunter filed its Form 10-K for the 12 months ended December 31, 2012, very early this morning. That's why Paul sounds so tired.

This filing was accomplished after we fired our prior accounting firm, PwC, or PricewaterhouseCoopers, on April 10. And we subsequently hired BDO on April 16 to complete our audit for the fiscal year ended December 31, 2012. We stated when we hired BDO that we felt like we could get our audit completed within 60 days, utilizing the services of a brand-new accounting firm, and that goal was successfully accomplished this morning. It is quite unusual for a company to fire its accounting firm. Our Board of Directors and senior management team stand firm that we had very valid reasons for doing so back in April. And I think the proof is in the pudding, so to speak, this morning in that we hired a completely new accounting firm, the fifth largest in the country who didn't know us from Adam and they accomplished the goal in less than 60 days with an unqualified audit opinion. Need I say more?

Our next order of business regarding our financial reporting is a filing of our first quarter Form 10-Q as of March 31, 2013. We're working on completing this filing now; anticipate completing this document within 30 days. Our Form 10-Q for the second quarter dated June 30, 2013, will immediately follow and should be on time, which that deadline is on or before August 10, 2013. So we're not going to talk a lot about numbers post-December 31. I do want to spend some time today giving you some highlights of the numbers reported this morning. So let me give you those numbers, and I think it's safe to say there were no surprises. The only surprises were good ones, and so let's run down them quickly.

Revenues for the December 31, 12 months increased 101% from $41.6 million for the fourth quarter to $83.7 million for the fourth quarter, so quarter-to-quarter, for the fourth quarter of last year, increased 101%. Production increased 60% from 9,100 barrels a day in the fourth quarter of 2011 to 14.6 -- 14,600 barrels a day in the fourth quarter of '12. I think it's also important to note that the liquids mix increased 37% -- from 37% of production, which was in the fourth quarter of '11, to almost 60%. It was 57% in the fourth quarter of '12. The reason that liquids mix increased so dramatically was our focus last year in the Eagle Ford and in the Bakken, where we really drilled mostly oil wells. And we de-emphasized the Marcellus because we had $1.90 gas at one point last year, and our Mobley plant didn't get up and running until mid to late December of 2011 -- or 2012.

So let's talk about operating margins. They continued to increase the due to, again, more liquids production, which you have a higher net value. And we also were successful in reducing our lease operating expenses in the field on a Boe basis. Adjusted EBITDA for the fourth quarter was $54.7 million. Net income was actually $0.05 positive per share. That's after netting out our nonrecurring, noncash expenses of $94.3 million. The fourth quarter 2000 (sic) [2013] net loss after these expenses was $0.54 a share.

And let's talk a little bit about those nonrecurring expenses. A lot of those related to leases that we felt like we weren't going to drill. As you know, we've been on a very acquisitive nature in the last couple years, predominantly up in the Williston Basin and Appalachia. And we had leases that we felt like we're on the fringe that we did not need to drill, that we need to concentrate on the areas where we want to drill. And I really want to emphasize the inventory Magnum Hunter has today. If you go to Page 63 in the 10-K today, we give specific detail of our total acreage position. This company today has over 1 million acres of mineral leases, of which 725,000 is net acres. A company of our size holding 725,000 net acres is absolutely phenomenal. And a lot of that acreage is in what we deem to be core areas of both the Bakken and the Appalachia, both Marcellus and Utica. So it's okay to write off some acreage, which we did of areas that we don't plan to drill.

Let's now jump to the 12-month period. We just talked about the 3-month period. Revenues for the 12 months of the last year increased 139% from $114 million for the 12 months ended 2011 to $271 million. So we reported total revenues of $271 million, a 139% increase. Production also increased 139%, up to 13,152 barrels a day in 2012. That's up from 5,500 barrels a day in 2011.

Operating margins. We were able to decrease our LOE per Boe produced from $13.10 in 2011 to $10.67 in 2012. We were also able to report improved recurring cash G&A per Boe, which was $7.43 per Boe in 2012. Our adjusted EBITDA was $169 million for the physical (sic) [fiscal] year 2012. But remember, our adjusted EBITDA just for the fourth quarter was $55 million. So you can see, if you extrapolate that out, that would be well over $200 million for 2013, assuming our continued growth. Net income. Recurring net loss of $0.11 per share after netting out the nonrecurring and noncash expenses of $150.8 million. The actual 2012 net loss was $1.07 per share versus $0.80 for 2011.

Liquidity has been a big question with respect to the company. We believe we resolved a huge piece of that by selling our Eagle Ford division, which we accomplished in April to Penn Virginia. That significantly increased our overall liquidity. It was a $401 million transaction, of which $360 million was cash, $40 million was stock, which we still own today in Penn Virginia, it's about 10 million shares. Our current borrowing base today is $265 million. Our current liquidity as of May 1, 2013, which is what we reported today, is $380 million. So with the current liquidity of $380 million plus, we've announced that we are working on noncore property sales. These are assets that reside in the various parts of the country. They're basically almost all conventional assets that came with acquisitions. And we have about $100 million to $150 million of those assets that are being worked as we speak to hopefully divest this year. Some may go into early next year, but I think a lion's share will happen in 2013.

I'm going to give you a quick snapshot of what we have done, thus far, this year in drilling wells. I'm not to give you any results yet because we haven't reported obviously the first quarter Q, but I want to give you a flavor of how active we've been drilling wells this year. Total wells gross drilled, this is through today, for 2013 is 47 wells, of which 17 is net to Magnum Hunter. Those wells lie 13 gross in Appalachia, 7.5 net. In the Williston Basin, we've drilled 33 gross, that's 8.7 net. And down in South Texas in the Pearsall we drilled 1 gross well, 0.31 net. So that gives you your 47 and 17 total net wells for the year. I would anticipate that number to basically double by the time the end of the year is reached.

As far as current throughput in our midstream division, which has also announced a possible divestiture, we've actually hired a bank and are working that system. That's our gas gathering system up in West Virginia and Ohio. We are basically hitting peak rates on that system almost every day now. It's up to 110 million cubic feet of gas per day and about 50% to 60% of that is the third-party. The Triad Hunter or Magnum Hunter gas will continue to be increasing in that system as the year progresses as we're tying in additional Marcellus and hopefully, some Utica wells.

One of the things that I know a lot of people will keep asking about is how we're doing in the Utica over in the Southeastern Ohio. As you know, we have a large acreage position in 3 counties: Monroe, Noble and Washington counties. And we're very excited about the prospects for this area. We have drilled our first Utica well, it's called the Farley. It's a 4-well pad in northern Washington County, right along the Noble County border, in fact, I think the well TD in Noble County. The well looks very promising. We are actually setting casing today on the well, and we'll be frac-ing the well hopefully in the next 2 to 4 weeks. We will likely let the well rest for some period of time, and then we're looking for ways to tie it in.

The Eureka Hunter gas system, which is being laid in Ohio, is first going over into the -- another pad, a 16-well pad called the Stalder (sic) [Stadler] Pad, and then will come over to the Ormet, which where we have 3 Marcellus wells that we own. So it's going to be a while before Eureka's system can get over to the Farley, so we may look for another solution there so we can put this well in production. I will tell you we're very excited about what we see. And we obviously don't have a test in the well. We did have some drilling brakes and just some fractures that we did anticipate, which make the area quite exciting. So we'll have more to report on that well in the next 60 days.

We are continuing to increase our acreage position in Ohio, I will tell you that. We are working on a number of different projects. And as you see, looking forward what's going on with the company, I think you'll see a tremendous amount of focus on key areas. I know that's happening for us, especially up in Williston Basin, where we're honed in on the areas where we're getting much better well results, and costs have been declining in all of the areas because of competition. Obviously, gas prices have improved dramatically. We've gone from $1.90 to $4.30. I think we're around $3.80 to $3.90 today, in that environment. We're generating a tremendous rate of return up in the Marcellus because of our processing capabilities through the Mobley plant. And so we're excited about where we're going this year. We're sticking with our guidance that we gave of 23,000 to 25,000 barrels a day as an exit rate for the year. We continue to monitor that and feel really comfortable that we will accomplish that.

And so if you look at Magnum Hunter from this point going forward now that we've got part of our blackout behind us on this audit, is really a business of continuing to improve our liquidity, continuing to reduce our overall leverage and continuing to increase our production and in areas where our net margins are improving significantly. We've done a lot of hedging this year. We've put that in our press release this morning to protect our cash flows, and so I think you'll continue to see some significant improvements in our reporting. Remember, the sale of the Eagle Ford occurred in the second quarter. So we will be reporting a significant capital gain on that sale with our financial results when we report our June 30 numbers.

So with that, I would like to turn the call over to Ron Ormand, our Executive Vice President and Chief Financial Officer, because one of the things that we still have to address out some of our deficiencies in internal controls. And we addressed some of that -- a lot of that quite frankly in the 10-K today. And I want our investing public to get a flavor of the changes we've made and things we're doing to be sure that we can timely report and give you proper reporting in the future as we've done in the past. So, Ron?

Ronald D. Ormand

Yes. Thanks, Gary. The material weaknesses on internal controls, we originally reported in our 8-K back in April when we dismissed PwC. They are disclosed in the Item 9A in our current 10-K and substantially the same as we disclosed before. There's no additional weaknesses that are disclosed. The weaknesses are in 4 key areas: internal control, environment, financial reporting, leasehold property costs and complex accounting issues. Obviously, we take these matters extremely seriously and have been working very diligently, even through this reporting process, to begin addressing those and begin addressing those in mid-2012.

One of the key things we've done is significantly expand, upgrade our accounting personnel. Obviously, we hired a new Chief Accounting Officer, Fred Smith. We've hired a new Head of Tax, which we had, had done outside the firm previously. We've hired a new Head of Financial Reporting and beefed up that area with additional staff. We've hired a new Controller, 2 Regional Controllers and an Assistant Controller. And we have a new Head of Internal Control, which was also outsourced previously. We're also using a Big 4 accounting firm, assisting us in the areas of tax and internal controls. We have a remediation plan that is in place. The primary aspects of that, obviously, are new and more qualified people. New processes that will create efficiencies and more timely reporting for the company and a new integrated accounting system. And this will be occurring throughout 2013 and into early 2014. So we are committed to remediating all of these material weaknesses. We believe that is achievable.

And obviously, the next thing on the agenda is for us to complete our 10-Q for the first quarter, as Gary mentioned, within the next 30 days, followed by our second quarter 10-Q, which we expect to be on time. Most importantly, the financial -- the 10-K we filed today has a clean audit opinion. There were no misstatements, restatements of past financials, and we believe fairly depicts our financial results and financial position as of December 31, 2012.

So with that, I'll turn it back over to Gary.

Gary C. Evans

Yes. Before I turn the call over to our listeners for questions, I should also mention that we are doing a June 30 reserve report. Debbie Funderburg, who runs the engineering department is here with me as we sit here today. And Cawley Gillespie does that report. That should take in account the sale of the Eagle Ford and plus the reserve additions that we've been able to accomplish, both up in the middle Bakken and the Sanish, as well as the Marcellus. I doubt if any Utica reserves get booked because we won't have the well completed, I don't think, by June 30. But that will be in the report the year end. So we should report those reserve numbers sometime in the third or fourth week of July. So that will be something forthcoming.

So before -- one last thing I'd like to say before we kind of take calls. I really want to thank all of our personnel. This has been a trying time for me and our management team and all our employees. There was a lot of scrutiny on us. There was a lot of questions about our credibility and our accountability. And hopefully, we resolved a lot of that today. I also want to thank Ron and our entire accounting department. They've been working tirelessly for months now, trying to get through this process. So we basically have been rubbed, scrubbed about every way you can. And I think it says -- it's testimony to the entire team that there was really nothing found. We have a clean opinion, and there was no restatements. So and I think we've all learned what we've got to do to fix these things, so this never happens again. I've been following 10-Ks since 1990. 10-Qs, I've have never been through quite like this, but hopefully, we've got this behind us. So it's been a good lesson.

So with that, I'd like to turn the call over to -- I imagine we have a few analysts online that want to ask some questions. So operator, if you would take our first question?

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is from the line of Neal Dingmann.

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

Gary, you kind of ran through as far as -- give me an idea on the time as far as what you think on the tie-in, if you have any ideas, number one, on the Farley. And then just remind me again after that now, I know you've got your own rig coming, just kind of the -- as you sort of see the rig schedule down in the Utica for the rest of the year.

Gary C. Evans

I know that our guys in the Eureka Hunter division, our midstream division, are working with the fellows that run our Appalachia division on the best way to get a line and the quickest way from the Farley somewhere. So we're likely going to try to put a temporary line in to a major trunk line and maybe do some dehydration or a small cryo unit ourself there that well. As you know, we did do some flaring on that well from the natural fractures. And the gas looked really rich. So we know we've got liquids there. So we're going to have to do some form of separation. So all that's kind of being looked at now. Our alternative would be to wait until Eureka gets there, and that's not going to be until '14. So we're trying to come up with an earlier solution, which is more of a temporary solution to get us to another line, so we can start producing that well. With respect to other developments in the Utica, the next pad drilling is the Stalder (sic) [Stadler], and we are using our own rig, which is -- we've been testing, I think it's moving here in about 1 week to 10 days. And we're going to drill some Marcellus and Utica wells at that location. That particular location is a 50-50 joint venture with us and a company called Eclipse, who's very active in the area as well. And then we are working on a location to drill a Utica well in West Virginia, that's likely going to be in Tyler County, West Virginia, which will be the first Utica test, I think, in the state. And then we are looking at either the Crooked Tree, which is another pad, and there's a Woodchopper Pad. Both are near the Farley. So I think the jury is still out about which one we're going to go to. So the goal is to have at least 3, maybe 4 Utica wells in Ohio and 1 in West Virginia by the end of the year down.

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

Got it. And then just maybe 2 others. On the -- you talked a little bit about how much is flowing through the pipeline. What -- again, what do you think kind of an EPSA rate this year? Do you already have a fair amount of takeaway already lined up? Or what are you thinking on the pipeline Eureka on?

Gary C. Evans

Well, I think the pipeline based on our midstream projections should be approaching 200 million a day by the end of the year. So it's going to double its throughput between now and the end of the year. And that's a combination of our wells, Stone's wells, JV's wells, which is a private company, and others that are tying in. So we feel pretty good about that just based on our own projections of our own wells. So as you know, we have 200 million a day of capacity at Mobley. So that'll be full, but there's additional train up at Mobley that we can access at spot. So we feel fine about being able to produce everything. Should mention, we had a number of hiccups in the first and second quarter as it relates to the Eureka system because the liquids component of our wells in the Marcellus has been so heavy that we didn't anticipate. We designed the Eureka system to pig that line once a month and we're actually pigging once a day. The pigging is -- what the term refers to is moving a slug through the pipe to move the liquids that get caught in the low areas. So it's a good news, bad news. Good news is liquids are much higher than any of us anticipated. Bad news is that it caused some hiccups. We've got those resolved. They have been resolved now for about 30 days. And it's running quite smoothly. So we saw a lot of erratic production in the first 4 or 5 months of the year, and that is now leveled out now. And as we add more higher-volume wells, actually should help a little bit on the liquids side of the equation. So these are all good things. As you know, there's been some of our competitors have reported much higher EURs in the same area that we are. I know our third-party engineers are looking at that. And so we're -- while everybody's excited about the Utica, you should not look away at the Marcellus because the Marcellus in this area is quite good.

Gary C. Evans

And then let me ask that -- sorry, it's the last question. And I know over net acreage, you have kind of East, kind of West Virginia and PA and all that comes together, what's your thought as far as, I've heard recently about just in the Belmont, not far from you, some huge dry gas wells, so your thoughts as far as going after either liquids Marcellus or dry gas? How are you going to -- are you going to go after both? Are you going to -- if you hit a big dry gas well, are you going to after just some gas as well? Or how are you going to flow that?

Gary C. Evans

Yes. I mean, if you do the economics on a 20 million a day dry gas well versus a liquid-rich well that's doing, let's say, 5 million to 8 million a day and 1,000 barrels, they're pretty comparable. So with gas prices back closer to $4, we have no problem at all looking at dry gas. Obviously, it's easier to handle because you don't have to deal with all the liquids. But we're seeing definitely some opportunities to drill some very high rate dry gas wells in the Utica, which would be over in Southeastern Ohio and Western West Virginia. And there's a window there, we don't know how far east it goes, and that's why we're going to test the well over in Tyler.

Operator

Our next question is from the line of David Deckelbaum with KeyBanc Capital.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

You talked about the potential to sell midstream that you retained the banker for Eureka Hunter system. And previously, I think you had talked about lessons learned from past iterations of Magnum Hunter where you didn't want to give up the upside of the midstream and you were extremely bullish on the outlook for Eureka Hunter. How do you reconcile that with what you see today as to what you think you could get in terms of potential proceeds? And do you think that process would be something that closes before year end?

Gary C. Evans

Those are good questions. You're right on point with the point that you made about, this is a bittersweet decision because as much as I'm excited about the Marcellus and Utica in this area, I'm just as excited about the pipeline future. And I can tell you that there's been a lot of discussions with our private equity partner about that. They're not the most favorable in wanting to sell this now. So the question is why are we looking at that? If you look at the multiples being paid for midstream assets and there's some recent data points that are pretty compelling, you're looking at 20x to 25x EBITDA on '14 numbers. And so one of the reasons we've decided to wait a little bit to actually hit the market with our package, which is going to be more like August, September, is so that we have those '14 numbers in that. We've had several banks do a kind of complete analysis of the system, and the valuations are coming out between -- one was in the $800 million, one was in the $900 million. And those are obviously guesses at this point. So the more activity we have in the Utica, which is rather new, the higher the value the system is going to have. So there's certain parties that are active in this part of the world that almost have to buy the system because of competition. So we're in a unique situation, where we think we could get a real premium for an asset that would take several years to get that value had we -- if we just continued to fund it. And so with the enthusiasm we have on our acreage position in both the Marcellus and Utica and the fact that the Eureka system is really built out to the lion's share of the areas where we're going to drill, having a third party own it today isn't that big a deal. It would've been a huge deal a year ago. It becomes less a big deal every month that goes by. So it is really a bittersweet decision, but our company needs the liquidity. We think that having that kind of cash on our balance sheet and further reducing our debt is an important factor. And if you look at the company's total net asset value, you're an analyst, tell me what the market is valuing Eureka Hunter on our stock today. It's -- I don't -- it's minimal. It's like when we sold 1/4 of it to ArcLight for $100 million, the stock barely moved. So it does move when you got cash and you're paying off debt. So I think a reason that many mid -- E&P companies divest midstream assets is for that very reason. There's a huge delta between the value given an E&P company versus the value given a midstream and an MLP. And so that's really what it boils down to. I hope that answered your question.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

I guess I should go back to updating my nav spreadsheet. If you could provide some context, I guess, then on -- you talked about expanding a bit further into the Utica. Is it sort of the more Eastern area where you see potential sweet spots for very high rate gas, or would it be more bolt-ons around sort of the core area where you think you're chasing more of the liquids portion there?

Gary C. Evans

I would say if you see us do transactions, they're going to be in the counties where we already are. I doubt that we would venture out of those counties. We feel like we've got enough data points. We've got enough cross-section work, we've got enough well control, and we know what's going on there. The jury's still out about how far south this play goes. I think our Farley well and our recent PDC well, called the Garvin, are probably the 2 further southern data points. I'll tell you because of our results from the Farley well, thus far, we're encouraged about the area. And so our leasing efforts are really in those 3 counties predominantly. And I will tell you they're aggressive. We're out leasing aggressively.

Operator

Our next question is from the line of Kim Pacanovsky, MLV & Co.

Kim M. Pacanovsky - MLV & Co LLC, Research Division

Okay, let me just ask, first of all, a question about the impairment and abandonments. I'm realizing obviously that they're noncash, but is everything dumped into this K, or do you expect anything else to come into the midyear?

Gary C. Evans

Well, let me -- I'm going to address a little bit of it. I'm going to turn it over to Ron and make sure I get it right. One of the things that we did is we looked at our potential impairments for '13. And so this is really a forward-looking impairment charge, not a past-looking impairment charge. Is that right, Ron?

Ronald D. Ormand

Yes, it was a combination of, you have expirations. And then also, understand that if you look back historically, we acquired NuLoch in '11. At the end of '11, we really didn't have much data on which to go on. Throughout the year, we've developed data through 2012 on where we want to be drilling and where we want to focus our efforts. So as a result of that, what you didn't do is take a forward look and say, "Okay, here's where our drilling plans are, here's where our lease expirations are." And if you know that you're not going to be focusing in certain areas, then you go ahead and impair those today. So there's a combination of the 2. And we can get with you afterwards, Kim, and we have the numbers to break that out. But that's really -- when you have such a large block that we have there, 180,000 acres, it takes time to refine where you want to go. And we're continuing to do that, as Gary said. And we're focusing in the higher return areas. So as a result, under accounting guidelines, what you do is impair some of those areas that you're not going to be focusing on, that we have no plans to drill on in the near term.

Kim M. Pacanovsky - MLV & Co LLC, Research Division

Okay. So the big slug of abandonment and impairments was taken, and we'll just expect some fine-tuning through the year, is that it in a nutshell?

Ronald D. Ormand

Well, I'd say that yes, I'd say that is correct. I mean you're going to have expirations as you go through the year. At times when we're trying to extend things, we're not able to extend them, for example, we could change our plans. So I wouldn't say -- I think the answer is yes to your question. But if drilling results change, we find new area, that could change as well.

Gary C. Evans

I think it's also important to note, Kim, that if a lease expires and we enter into a new lease on that same acreage, let's say the acreage originally came with an acquisition and we placed $2,000 an acre on it. And we leased the acreage again, say, for a 5-year new lease and we paid $600 an acre or $1,000 an acre, something less than what it was, we have to impair the $2,000 fully when we take a new lease. Even though it's the same lease, we have to impair that lease for what the original charge was if we take a new lease.

Kim M. Pacanovsky - MLV & Co LLC, Research Division

Okay, great. I didn't know that.

Gary C. Evans

Yes, we didn't know it either.

Ronald D. Ormand

But the vast majority relates to the Williston area, Kim, because it is 180,000 acres. And that's what you see there.

Kim M. Pacanovsky - MLV & Co LLC, Research Division

Great, okay. And then secondly, I know when Cawley Gillespie took over Williston basin, they were a little bit more conservative on the EURs. Do you anticipate that maybe by the -- maybe not in the June numbers, but by the end of the year, you'd have enough performance data to maybe get some of that back?

Gary C. Evans

Debbie's sitting here with a puzzled look on her face. I would say we believe that the Cawley numbers are probably proper. Okay?

Kim M. Pacanovsky - MLV & Co LLC, Research Division

Okay. And then last question, I noticed on your presentation that for your Marcellus IRRs, you're using an NGL price of $47.70, which is 53% of your $90 crude price there. If you plugged in actual NGL prices today, what would that IRR look like?

Gary C. Evans

Well, I'll tell you, when you're looking at one little sheet of the IR presentation.

Kim M. Pacanovsky - MLV & Co LLC, Research Division

In your presentation, yes.

Gary C. Evans

We update that from -- with actual numbers. So you're getting actual data.

Ronald D. Ormand

Yes, we'll be updating that...

Gary C. Evans

But we update it -- don't you update it all the time?

Ronald D. Ormand

Yes, once we do the next review.

Gary C. Evans

Yes. You're right, NGL's have dropped some. But you've got to remember, we negotiated a unusual agreement in our processing with MarkWest because we sold them the plant. So we have a little bit different spreads than most would have, and that's one reason you're seeing a little better numbers.

Operator

Our next question is from the line of Leo Mariani with RBC Capital Markets.

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

Just question on your Tableland results. Just looking through your 10-K, it looks like you guys provided some more results here. If I'm correct, and I'm seeing your last 4 wells around 220-barrel a day, 24-hour IP, it sounds like kind of a degradation from previous results. Just wanted to get some color what's kind of happening there in Tableland?

Gary C. Evans

We are deemphasizing Tableland. I think -- I don't even know -- we may be drilling one well this year there. But our concentration is really Northwest Divide County where we're seeing EURs on 2-mile lateral wells, 500,000 to 750,000 barrels. So we drilled a lot in Tableland last year. I think we had decent results. We had good results in some wells, not so good results in others. And we're kind of watching to see how the decline happens this year. But I will tell you that our focus is not on Tableland. And Tableland, while it's not part of the divestiture group of the 100 million, 150 million, may become a divestiture candidate.

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

All right, that's helpful. And I guess, just jumping over to your midstream here. Just trying to get a sense of what you guys are thinking you could end up with on -- for throughput on the system in 2014?

Gary C. Evans

As far as throughput in the system?

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

Yes.

Gary C. Evans

I think you could see -- the system is designed to handle 350 million a day. And if we take 100 million and double it to 200 million by the end of the year, what could you do in '14? I think you could get to 300 million. It doesn't take many 20 million a day wells in the Utica to get that.

Gary C. Evans

Yes, I'd say it's a very -- I think it's a conservative number.

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

So is that 300 million an average for 2014 or more of an exit rate for 2014?

Gary C. Evans

No, it's so hard to say. I would say a 250 million by midyear and a 300 million by the end of the year. I think that's conservative.

Ronald D. Ormand

Yes. It depends on when the wells come on, when you get your pipe hooked up, so it's a little difficult to project. But I think the 300 million number is a conservative number by the end of the year.

Gary C. Evans

But where that begins to change, when you even go higher is you start backhauling. And we said that we'd set another cryo plant in Ohio. See right now, we're taking our Ohio gas under the river into West Virginia at Mobley. So it starts changing as you start playing laterals and backhaul and doing all other kinds of things. I know those guys have got other ideas up their sleeve.

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

All right. Yes, I was just trying to get a sense of that because obviously, you guys are talking about some big numbers on your midstream in terms of the sales. I'm just trying to get some of the background for how you guys are getting to those numbers. Also, related to that in your midstream divestiture, is that also going to include your treating business, and just trying to get a sense of, kind of what you think the treating business is sort of doing these days in terms of EBITDA?

Gary C. Evans

I would say its annual EBITDA is around $5 million to $6 million.

Ronald D. Ormand

If each sold separately.

Gary C. Evans

Maybe. It's -- we've been approached other buyers. But the treating business is doing a lot better than it was last year. We've made some management changes, and we've picked up a lot of new business. It's gone more from a business that was generating one-off sales to one of long-term leases of equipment. So the business is much more stabilized and much more conducive for MLP.

Ronald D. Ormand

And it's growing, it's back to a growth mode.

Gary C. Evans

Yes, we're basically wiped out our inventory. We're having to build new inventory right now.

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

Okay. But so I guess when you guys talk about kind of bankers valuing midstream, 800, 900, that includes the treating business, correct?

Gary C. Evans

Yes, but I'd only put $50 million to $75 million on that value.

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

Okay, got you. All right. And I guess just in terms of your CapEx, trying to get a sense of what your fourth quarter kind of non-acquisition CapEx was just, you guys have a lot of numbers floating around, but I guess you guys didn't specifically break out a lot of fourth quarter data when you released today, so just trying to get a sense of where that number came out?

Ronald D. Ormand

That's going to come out about $150 million on the upstream.

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

Okay. And then I guess there's a midstream component on top of that as well?

Ronald D. Ormand

$27 million, but we don't fund that.

Gary C. Evans

That's funded within that division.

Ronald D. Ormand

Yes.

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

Okay. And I guess just a question on LOE, just looking at your numbers during 2012, looks like it's kind of been creeping up on sort of a sequential quarterly basis, I know you guys are looking to get a lot of Marcellus wells on this year. How should we expect kind of LOE to trend during 2013 and kind of where are you guys at kind of right now on a sort of a per barrel basis there?

Gary C. Evans

Well, we haven't given any current numbers out. But I can tell you, remember, we just sold 50 wells that are the highest-lifting cost wells in our portfolio, or I should say, on the oil side being the Eagle Ford. So the reason those are higher-lifting cost wells, you've got rod and pumps, you've got submersible pumps. You've got all kinds of equipment out there that drives your LOE up. The flowing gas well, obviously, has much lower LOEs. So the fact that those were sold in April, you're definitely going to see a drop in LOE in the second quarter.

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

Okay, that's helpful. All right. I guess you guys talked about this non-recurring kind of transaction other expense of $7.4 million. Is that just kind of M&A costs, can you give us some color on that number?

Ronald D. Ormand

Yes, there's some M&A cost. We can get you the breakdown on that, Leo. But the M&A cost, obviously, we had some sunk costs with PwC that unfortunately got us nowhere. And...

Gary C. Evans

Maybe we'll get back one day.

Ronald D. Ormand

Yes. So those would be the 2 primary components of the legal and accounting costs incurred with that exercise.

Operator

Our next question is from the line of Irene Haas with Wunderlich Securities.

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

My question has 2 parts. Firstly is you mentioned at the Farley well that you hit fracture, so you did have some gas flare, that's what you said. And so I was just kind of wondering, did you encountered the right thickness in that well and the right kind of rock type? And so does it mean that you essentially have a discovery? Then question number two has to do with Gary's thesis on the 0 net debt scenario, so can you elaborate a little on that particular business plan?

Gary C. Evans

Okay. So yes, we had some gas kicks on the Farley, and they were pretty significant, which is quite unusual in a shale play. But we're hearing that a little bit of that's happened up in this area. So yes, we had a big flare until we were able to put enough drilling mud in the well to kill it. So usually, you don't -- in a shale formation, you don't have that kind of situation occur after you frac the well. So it did catch us by surprise, and it got our attention. I think poor Jim Denny slept out there for a couple days. So what we've seen -- but remember, we drilled the well first vertically and did some cores and did some logging. And then of course, we didn't quite get to the toe. We hit this pretty big frac or this fault, I should say, whatever it was. We hit it about 300 feet from the end of the well. So we, I think, TD-ed the well 6,700 foot, we didn't finish the last 300 feet. So you really don't know, Irene, until we frac the well. But all of the indications is we've got something that's pretty exciting. And we'll know more once we frac it and let it rest a little bit. But we may end up doing some seismic in this area or even some micro seismic to help us better determine what some of these faults are. But there is some complex geology here. This is not typical stuff, and we're actually bringing in the Drilling Engineer that ran our drilling operations for South Texas. He's going to be put in charge up here because of his -- we're treating these wells like offshore Gulf of Mexico. So we're putting -- we're doubling everything, BH, blowout preventers, ram, I mean where everything -- double everything on the well future because we're in a hostile drilling environment, best way to define it. So hopefully, that answers your question. The second question on net debt 0 or close to 0, all you've got to do is add up our debt, subtract our current liquidity, it made once [ph] $380 million, $150 million of noncore sales plus we got $50 million of Penn Virginia stock, there's $200 million. You add up the Penn Virginia -- I mean the Eureka Hunter sale, say, it's $750 million, $800 million, whatever the number is, maybe it's $1 billion, I don't know. But we have 60% of it. And you add all that up, you get to pretty close to net 0 debt number. So that's where that comes from.

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

Still on track, still thinking it's going to happen close to sort of year-end 2013?

Gary C. Evans

Yes, I would say that we're on track, working our asset sales for at least $100 million, hopefully $150 million by year end. And then we hopefully will liquidate our Penn Virginia stock this year. And then we -- I would say on the Eureka sale, we have a very good chance of having a deal, we believe, by the end of the year. It may or may not close until early next year, but something that we could announce hopefully.

Operator

Our next question is from the line of Hsulin Peng with Robert Baird.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

So my first question is regarding 2012 CapEx. I think the total was about $489 million -- with $428 million from the upstream. It's a little bit higher than what you initially guided to, so I'm just wondering if you can elaborate more on it as to where the additional CapEx went towards to?

Ronald D. Ormand

Well, it's slightly higher than what we got into, I think, $400 million that we got into…

Gary C. Evans

I think it's around $410 million.

Ronald D. Ormand

Yes, $400 million, $410 million so...

Gary C. Evans

I would say Eagle Ford. We were trying...

Ronald D. Ormand

We were trying to put -- yes, that's exactly what I was going to say. The Eagle Ford, we added a little bit of CapEx at the end because obviously, we're selling and we were trying to get more production online there that helps our sale.

Gary C. Evans

So remember, we spent a fair amount of CapEx in the Eagle Ford from January 1 until April. But because we had a January 1 effective date, we got all that money back. So that was another -- how much was that mark, do you remember, $30 million or so?

Ronald D. Ormand

$30 million, $40 million.

Gary C. Evans

$30 million, $40 million.

Ronald D. Ormand

Yes, at least there are about $30 million or $40 million came back. So that money was -- when you add CapEx -- it's also accrued CapEx, right? So some of those wells hadn't been completed until first quarter. So you're accruing it by completing the first quarter. And then as that production comes on and you get that CapEx back when you sell it.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay, got it. And the second question is regarding the -- I mean I know you mentioned that you are focusing -- in Williston, you're focusing in Northwest Divide area, and you're also [indiscernible] that some acreage expired. So I was just wondering, I guess right now, you have about 180,000 acres in the basin. What do you think your acreage would be after that, the French acreage expire, and where exactly are those French acreage?

Gary C. Evans

Well, again, when we did the write-offs at year end, we anticipated what would expire in '13 that we wouldn't drill. So that's already been taken into account. We won't know until we get towards the end of the year what we may or may not drill in '14, so that question can't be answered yet. But as far as quarterly numbers, March 31, June 30, regarding write-offs of unproved properties, they should be fairly minimal.

Ronald D. Ormand

And also, remember, we can still farm out or sell some of those properties even though we're not drilling them. Okay? So even though we take the impairment and we're not planning to drill it, we can recoup some of those costs. And that's our plan, actually.

Gary C. Evans

Yes, I would say that this part of Divide County is getting a lot more attention from our competitors. Companies that have moved quickly into the area and are nibbling at our heels are Continental, Oasis and St. Mary's. So those 3 firms are in and around us and trying to do deals with us.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. All right, that sounds good. I can -- we can check again later on. And I guess, maybe one more question here. You had mentioned that your first quarter production estimate was around 15,000 to 16,000 boe per day. Is that still a good number? And where is your current production?

Ronald D. Ormand

Yes, we don't have any guidance on first quarter production right now.

Gary C. Evans

Yes, we -- as I mentioned earlier in the call, we had some sporadic production in the first and even into the second quarter related to Eureka because of this picking situation. So we did -- even though we sold the Eagle Ford properties in April, we still get to report the production on those properties in the first quarter. So that will still be in our numbers. But we're just now getting back to the 16,000 to 17,000-barrel a day range, and it's ramping up pretty quickly. But that's really not occurring until I would say, May, June. So I wouldn't have real high expectations for the first quarter, for sure.

Ronald D. Ormand

We have to be careful about all we can say legally, to be honest.

Gary C. Evans

We haven't released these numbers yet so it's hard for us to day.

Ronald D. Ormand

We don't file [indiscernible] so we're really not in a position to do that.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. So when do you think you can file the first quarter Q?

Ronald D. Ormand

We'll -- as we said, within 30 days, we expect to beat that.

Operator

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

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Gary, looking at 2013 production, I know you don't want to get into the specifics. But the year-end exit rate of -- that you had mentioned, what do you expect the oil/liquids mix to be roughly this year post-Eagle Ford sale?

Gary C. Evans

I still think we're in the 50-50 range. The reason we say that is the liquids component is so high in our gas stream in the Marcellus, which is 25%, 27% liquids. Of course, everything we're drilling in North Dakota is oil. So even though we got this up to as high as 57% and we got rid of the Eagle Ford, we've almost, to the point of recouping the Eagle Ford production, and it's coming out of both Williston and liquids-rich Marcellus. So we feel comfortable stating we're still around the 50-50 liquids to gas mix at year end.

Ronald D. Ormand

Maybe even a little better than that, 50% or above.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. The Utica well, I know you've added a few things there. What are you expecting that cost for that horizontal to be?

Gary C. Evans

It's going to be higher than a typical well, mainly because of 2 things: We had to -- we hit 2 faults that we had to re-drill about 2,000 foot of lateral of the horizontal section because we wanted to have as much of that well -- well, we wanted all the well to be in zone. So once we knew those faults were there, we could steer the wells -- steer the bit to stay in zone. So that was a negative. And then we had the issues with hitting this gas kick, and that was an extra 5 or 6 days. So it's going to be higher than what I think a typical well's going to be. And again, we did a test of this well, too. Remember, we drilled the vertical sections, as I mentioned, before the horizontal. So this was -- I would call this, in many regards, an R&D well for us. We've learned a lot by drilling it. And we know what we can't do. And of course, the next well will be our own rig instead of a third-party rig. So I'm not comfortable telling you how much yet. I think less than 10 million, but it's probably going to be close to that number.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. And Gary, what's the production roughly associated with the noncore assets for sale?

Gary C. Evans

It's pretty minimal, less than 1,000 barrels a day.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. And then just lastly, going forward, what should we expect G&A to look like, including the additional costs for the beefed-up accounting staff and anything else associated with...

Ronald D. Ormand

Yes, I mean the accounting costs are just, in itself, aren't as high as you think, maybe a couple million a year. So it's not that...

Gary C. Evans

The percentage of our boe equivalent is going to still go down, but as an overall number, it's obviously gone up. We've obviously also spent a lot more money with third-party accounting firms and consultants. We will be going forward to get through this hump. And of course, we're going to try to recoup some of that later. But so I feel like we lost some people with the Eagle Ford sale. So that's going to offset some of the additions in the accounting.

Ronald D. Ormand

Right. And also, one thing you should understand is it'll probably go up initially. And we're putting in a new accounting system. And as we get efficiencies and improvements there, it'll probably come back down. So that's the idea of doing that, not only creating better information flow, but also efficiencies in the system.

Gary C. Evans

So again, overall, the number is going up this year. I don't think there's any doubt about that, but on a boe basis, I think it will still, by the end of the year, be less than what it was in '13 -- '12.

Okay. Operator, I think we've been on this call for a little over an hour. So I want to thank everybody that dialed in and listened to us today. And this is a good day for us to get this behind us. And we're looking forward to our actions and results for the remaining of the year. Please feel free to call Investor Relations department. If you have any specific questions, we can probably more openly talk about things now than we have been able to do now we got this K out. So with that, I hope you have a nice Friday and good weekend, and we'll talk to you soon. Thank you, operator.

Operator

Ladies and gentlemen, thank you for your participation in today's conference call. You may now disconnect.

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