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Magnum Hunter Resources (NYSE:MHR)

Q2 2014 Earnings Call

August 08, 2014 10:00 am ET

Executives

Paul M. Johnston - Senior Vice President and General Counsel

Gary C. Evans - Chairman and Chief Executive Officer

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

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

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

Christopher T. Akers - Executive Vice President

Chris Benton - Vice President of Finance & Capital Markets

Debbie Funderburg -

Analysts

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

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

Dan McSpirit - BMO Capital Markets U.S.

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

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

Operator

Good morning. My name is Holly, and I'll be your conference operator today. At this time, we'd like to welcome everyone to the Magnum Hunter Resources Second Quarter 2014 Financial and Operating Results Conference Call. [Operator Instructions]

I'd now like to turn today's conference over to Mr. Paul Johnston, General Counsel. Please go ahead, sir.

Paul M. Johnston

Thank you, Holly. Good morning, everyone. Today is Friday, August 8, 2014. This is Paul Johnston, General Counsel of Magnum Hunter Resources Corporation. And I would like to welcome everyone to today's conference call. The principle purpose of today's call is to discuss our second quarter 2014 financial and operating results, among other matters, of interest regarding our company. We announced these results in a press release, which we issued earlier this morning. The press release is posted on our website.

Before we begin our presentation, I would like to advise everyone that today's call will include forward-looking statements within the meaning of the federal securities laws, specifically Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Our presentation will include statements regarding our projections, estimates, expectations, beliefs, assumptions, intentions and future strategies. Such forward-looking statements relate to, among other things, our revenues, production, capital expenditures, liquidity, drilling activities, reserves, anticipated sales of non-core assets, and other upstream and midstream operational matters. These statements are qualified by important factors that could cause our results to materially differ from those reflected by the forward-looking statements, including factors set forth in the Risk Factors sections of our SEC filings, including our most recent Annual Report on Form 10-K and quarterly report on Form 10-Q. Our most recent Annual Report on Form 10-K also includes a glossary of certain industry terms that we may use in today's call. The full forward-looking statements disclaimer is included in our press release issued this morning. This disclaimer is in effect for the duration of the call.

Our press release also contains, and our presentation today, may include statements regarding certain non-GAAP financial measures. As part of our press release, we provided reconciliations of these non-GAAP financial measures to their most comparable financial measures calculated in accordance with GAAP. We refer you to our statements in the press release and in the Form 8-K we filed this morning with the SEC regarding the press release, relating to these non-GAAP financial measures. These statements include our reasons for providing the 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, and thank all of you for taking the time this morning to dial in and listen to our second quarter financial and operating results. Before I go into that, we did have our Annual Meeting of Stockholders yesterday and I'm pleased report that everything that the board had proposed at the Annual Meeting was voted and accepted. So we have that completed.

The highlights for this quarter include all the things you look for in an improved operations. We had significant growth in revenues from oil and gas, which included obviously, production. Our pipeline throughput from Eureka Hunter was much greater and continued to grow. We're able to grow our reserves over the 6 months from January 1 to 6/30, and at the same time we did all this, we also reduced our lease operating expenses in G&A on a BOE per day basis. And I anticipate that to even become greater as the year progresses.

So we have all the senior management on the call are here with us in Houston. We also announced yesterday that we're moving our corporate headquarters from Houston, Texas to Dallas, Texas in order that we can consolidate all of our people under one house, and we're pretty excited about that event occurring.

So I'm going to turn the first part of the call, which is our actual financial results, who's going to summarize those is Joe Daches, our Chief Financial Officer who -- he's in Grapevine today and will go over that. Joe?

Joseph C. Daches

Thank you, Gary, and good morning, everybody. Let me start off by just giving some brief highlights. For the quarter ended June 30, 2014, the company generated net loss attributable to common shares of approximately $80 million or $0.43 per basic and diluted common share outstanding. For the same -- for the 6 months, the company generated a net loss of $156.5 million or $0.88 per basic and diluted share. Adjusted net loss attributable to common shares for the 3 months ended June 30, 2014, was $0.09 and was $0.24 loss for the June 30 per basic and diluted common shares.

Oil and gas revenues for this were $78.2 million for the quarter, which was up 57.7% increase over the prior quarter and $148.4 million, an increase of 76.2% for the 6 months ended June 30. This increase is primarily attributable to increases in oil and gas production as a result of our expanded drilling efforts to the Marcellus, Utica shale plays, coupled with higher average realized commodity prices, specifically, as a result of production from the Collins, Ormet and WVDNR wells which began to flow into production in December of '13, April of '14 and May of 2014, respectively. Production in our Appalachian division alone increased 232% to 2,074 MBoe for the first 6 months compared to 625 MBoe for the same period in 2013.

Third-party revenue from our midstream and marketing operations increased by $34.4 million or 246.1% to $48.4 million for the quarter and by $50.1 million or 167.9% to $80 million for the 6 months ended June 2014. These increases are driven primarily by strong marketing revenues and increased throughput on the Eureka Hunter pipeline. Approximately 38% of our pipeline throughput is attributable to our own production.

Our production increased by 49.3% to 1,449 MBoe for Q2 compared to 970 MBoe for the prior-year quarter in 2013. Year-to-date production also increased by 70.7%, 2,781 MBoe or 15,363 BOE per day compared to 1,629 BOE or 9,000 BOE per day for the prior year, year-to-date. Finally, the Q2 mix of oil and liquids stood at [indiscernible] for the quarter and 44.8 year-to-date.

Thank you. Gary?

Gary C. Evans

Thank you, Joe. I'd like to now turn the call over to Glenn Dawson, who's going to give us an overview of the Williston Basin division. Glenn?

R. Glenn Dawson

Thank you, Gary. During the second quarter of 2014, the company participated in 13 gross, 2.4 net wells and the completion of 6 gross, 1.3 net wells in Divide County, North Dakota. We're switching our completion technique over to perf and plug. We're making significant progress with this technique and we're seeing significantly more fluid over the first 90 days up to 30%.

Our well cost currently range between $5.7 million and $6.3 million for a 2-mile lateral well completed within 3 stages and 50 tons per stage. Our current production out of the division is 4,200 barrels a day equivalent and it has been very stable over the last quarter, as we brought on additional volumes through the ONEOK gas system.

We're focused on reducing our LOEs further. We have a very, very low LOE compared to our peer group. But we plan to drive that down further over the course of the second half of 2014.

How are we going to do that? We have really ramped up our ancillary services over the last 12 months. We've recently engaged a third-party to gather and transport oil from certain of the company's non-operated properties in Divide County to the Colt hub in Epping, North Dakota. This will significantly eliminate trucking cost, to the tune of about $2 a barrel, minimize downtime and keep our oil moving during spring break up. Further, this will keep trucks off the road and just basically improve the overall efficiencies of our properties.

We expect 51 wells to be tied in directly to the line shortly, another 18 that are on built pipelines later in the year. The balance of the wells will be connected to truck terminals which are currently being constructed and reducing the trucking distance for those barrels, and they will then flow into the system. We expect this system to be fully operational by mid-September.

On the electrification front. We have electrified 113 gross wells and ultimately expect the bulk of our 227 wells in production to be electrified. This significantly increases run times and production on the well, it reduces LOE and the fuel gas dependency is reduced significantly, allowing that fuel to be sold into the ONEOK gas system, increasing production and revenue.

I will point out that the gas up in this area of the Bakken is very rich. The Btu content is, on average, about 1,500, as high as 1,700. So the barrels of liquids that we procure from the sale of gas is over 200 barrels per million. Our revenue and production has increased dramatically over the last 6 months to 600 barrels a day equivalent, net of royalty and $500,000 a month net to the company. I anticipate this to increase to about 1,000 barrels a day by year-end.

The ONEOK gas system is up, running at a 90% efficiency. We have 183 gross wells currently tied into the system. And we are also completing a major project this week, the tie-in of the pipeline from Saskatchewan into North Dakota. The Tableland system is being constructed by us. This should start flowing gas next week. And we will be initially capturing about 600 to 700 Mcf, not a large volume but we will be buying the gas and dedicating that to our ONEOK contract. The line has the capability of producing up to 6 million cubic feet a day and we control that system, which will further support our commitment to ONEOK and future revenues.

We've also recently completed, with our partner Samson, a water disposal gathering system, which gathers all the water from the bulk of our wells in North Dakota, further driving down our LOEs. And we anticipate another 5% to 10% reduction across-the-board by the end of 2014.

That's all I have.

Gary C. Evans

Thank you, Glenn. Before we turn the call over to Jim Denny, who's running our Appalachia division, I'd like to make a couple of comments about some of the things that we acquired up there in the Marcellus and Utica.

During the second quarter of 2014, we acquired specific new leasehold acreage covering approximately just under 20,000 acres, which net was about -- a little over 15,000 net acres. And these were in various areas, various counties, including Washington, Noble, Monroe. Those are the 3 counties over in Ohio where we are concentrating our efforts and also included a couple of counties over in West Virginia, which were Tyler, Ritchie and Wetzel County. So the total purchase of all this acreage was $66.2 million. That worked out to about $4,347 per average net leasehold acre and that includes acreage that we had previously committed under the MNW energy transaction back in August of 2013.

Subsequent to the end of the quarter, we spent another $22.7 million buying 1,700 net mineral acres over on -- under a lease called the Ormet, which is over in Monroe County, Ohio, where we're actually drilling some wells, also include a little acreage under the river over at Wetzel County. So Jim is going to talk about that here in a second. So we have spent, just here in the last 60 to 90 days, almost $90 million buying additional acreage in the heart of our play up in Appalachia. So, with that, Jim, why don't you tell them what we're doing in our operations?

James W. Denny

Good morning, everyone. Thank you, Gary. We go into quite a bit of detail on the operations but I thought I would highlight where our rigs are running and how things are going.

We currently have 3 rigs running, 2 of which are on Utica pads and 1 of which is on a Marcellus pad. One of them, the Utica pad is on our Ormet pad, where we're drilling a second of 4 laterals there. And what we've gone to is we drilled the air section, which take us to an intermediate casing and then we go from well to well, drilling the intermediate point. So we're on the second of 4 of the intermediate point on the Ormet pad. We're on the third of 3 on the Stalder Pad for intermediate casing, and we are on the second of 4 for the intermediate casing on our West Virginia Department of Natural Resources pad in Wetzel County. In addition to that, we'll be moving in. We just shut in an additional 3 wells. We're moving in a top hole rig on our Everest-Weese pad where we shut in 3 Marcellus in order to drill 2 more Marcellus. The goal is to move the rig from the WVDNR pad to the Everest-Weese pad and have those wells on by year-end as well. And I'll summarize that here in a minute about how we're looking for year-end.

In the next 30 days or less, we have a number of wells that will be coming on. As far as operated wells on our Stewart-Winland pad, we have frac-ed the Utica well there and we are zipper frac-ing the Marcellus wells and we're about midway in that operation with a little seasoning on the Utica. I expect all 4 of these wells to come on in early to mid-September.

And then to kind of summarize where we are with production. We're at about 11,000 barrels per day here in Appalachia with the wells that we just shut in. Have a total of 8 wells shut-in, representing about 5,000 BOE a day. All of those shut-in wells would be back on production as we bring on the new wells. The wells are shut-in to drill additional wells.

So given that and then what's happening on our Stewart-Winland pad, we're virtually surrounded with the 3 Marcellus wells, with the Collins and Spencer wells, which Joe had alluded to. Just came on production here in the late first and second quarter and impacted our production dramatically. So, being a little conservative, I'm expecting about 15 million a day of increased production there, about 600 barrels per day of condensate and about 1,100 barrels per day of NGLs. So, if you put those together, that's about 4,200 BOE a day net. Those are 100% wells to MHR.

And then the Utica well, while it is a step out, it'll be our most southeastern -- the industry's most southeastern test to date of the Utica. We have logs that are very encouraging. We have excellent gas shows, the frac saw went very well. So I'm expecting a very high rate dry gas well there. If it looks anything like our Stalder, we can expect around 20 million a day. So that's an additional 3,000 BOE a day equivalent. So that one pad alone can add 7,500 BOE a day.

So if you can see the arithmetic, the challenge for the rest of the year, I do have some flexibility and we are anticipating bad weather this year as opposed to learning from our -- the issues that we incurred last year, which was so brutal for not only our industry, but the entire U.S. So we planned -- if we have to stop drilling on one of these pads and drop a well, then in mid -- in late September or mid-October, then we will do so because we have the cushion to do that. So we intend to be in a frac operation primarily in the late third and fourth quarters to make our goals, which I feel very comfortable in being able to do that. And we've been working very closely since Utica is a primary driver here, of these wells, we've been working very closely with Halliburton who's been doing our Utica work to make sure we have the crews and efficiencies necessary to get that done.

And then -- so, in review, we've got about 16,000 BOE a day, bringing on an additional 7,500. And then we've got 9 Utica, 6.5 net that will be coming on or returning production, and then we have 7 Marcellus, 7 net either returning or new production. So I think we have an excellent chance of staying on course. Right now, we are on target, so I'm not planning on dropping anything. But we do have that flexibility.

And then finally, I'd like to highlight that we know we've kind of switch gears here since -- with the acreage acquisitions that Gary alluded to and the things that we have teed up here for the remainder of the year from a gatherer to -- we're reorganizing our land and ops department -- or realigning, I think, would be a better word, to move from a gatherer to a fill and execute type of mentality. And so we'll be building units to try and get ahead of a multiple rig schedule. We have about a year's work in our pocket, but we're trying to get ready for subsequent years as we intend to ramp up rigs and additional production.

So, Gary, those are the things I wanted to highlight. Now I'll just wait for questions at the end.

Gary C. Evans

Okay. Thank you, Jim. We'd like to now turn over the call to our Midstream division, Chris Akers is our Chief Operating Officer and he's been up in Ohio as well. And we've got a lot of activity going on there and we had a great quarter with Eureka. So Chris, why don't you give us an overview?

Christopher T. Akers

Okay. Thank you, Gary, and good morning, everyone. First thing I want to cover here is our current throughput right now is about 240 MMBtus per day, with our expected capacity or expected throughput at the end of the year of 350 MMBtus per day. Out of that, about 33% of that at capacity is from our sister company, Triad.

Right now, we have several pending contracts with producers to increase that throughput in end of '14 -- or end of '15. Right now, probably our main focus is on construction, trying to deliver on 4 new transmission interconnects with REX, Spectra Energy, Columbia Gas pipeline, Dominion Transmission. That will, along with a wet interconnect with Blue Racer's Natrium plant. With all that said, it will increase our throughput capacity from 0.3 Bcf a day to about 1.5 Bcf a day. That will give us some room for growth for any new capacity coming on to Triad or any other third-party producers. Some other key significant issue or significant item we're working on now is we're now in the process of acquiring several miles of pipeline right-of-way for inventory for future construction in 2015 and '16.

Those are all the key highlights for Eureka Hunter Midstream, Gary.

Gary C. Evans

Great. Thank you, Chris. Before I turn over the call to Chris Benton, who's our VP of Finance, he's going to talk a bit about some of the capital transactions, I want to mention our hedges because the hedges today have become a lot more meaningful with the drop in gas prices that we all experienced over the last 45 days. So, for 2014, we've got about 31 million cubic feet per day hedged with a weighted average swap price of $4.23 in Mcf. We also have another 15 million a day hedged with a weighted average ceiling price of $5.23 and a floor price of $4.27. So, collectively there, that's just under 50 million a day. In 2015, we've got about 20 million a day hedged average swap price of $4.18. So we've got some protection here with respect to the drop in commodity prices on natural gas. Chris wants to talk about liquidity.

Chris Benton

Thanks, Gary. The company continues to focus on maintaining manageable credit ratios and sufficient liquidity to provide us with the operational flexibility, while allowing us to execute on our capital plan in the Marcellus and Utica shale plays.

During the 6 months ended June 30, 2014, we raised, in total, $180 million of common equity to further bolster our liquidity position, which allowed us to execute on our drilling plan in Appalachia, and continue to acquire and build up our acreage position in Ohio and West Virginia.

As of June 30, 2014, the borrowing base under our senior credit facility was $272.5 million. We recently released our midyear 2014 reserve report and our 3P Reserves. Over the next several weeks, we will be working with our banks on the reserves and driving towards an increase to borrowing base as a result of the reserve additions from the organic growth from the drill bit.

As of July 31, 2014, the company had approximately -- had total liquidity of approximately $49.1 million, which was comprised of $42.1 million of cash and $7 million of borrowing base availability. To further enhance our liquidity position, we're actively pursuing additional non-core asset sales, which the company expects to close throughout the remainder of the year.

Through a combination of internally generated cash flows, borrowing base increases and additional liquidity sources, including, but not limited to noncore asset sales, we believe these will be -- will provide us with more than sufficient liquidity to fund our capital budget for the remainder of the year.

Gary C. Evans

Thanks, Chris, and to touch on some of those asset sales, maybe I'll give you a little more information regarding the significant divestments we've made so far in 2014.

So we completed non-core asset divestitures, resulting in net proceeds excess of $100 million. The company divested its remaining South Texas properties in Atascosa County to New Standard Energy for $24.5 million. We've got $15 million cash there, $9.5 million of stock in that company. We then monetized all of our properties in Alberta, Canada for CAD 9.5 million, which netted about USD 8.7 million. And we also divested all of our other properties in Canada over the Tableland Field in Saskatchewan and that netted CAD 75 million, USD 67.5 million.

We also sold a small property over in West Virginia called -- in the Vadis field for $0.5 million. So that's about $100 million of assets. I can tell you, based on what -- where we sit today, we probably have at least another $100 million that I feel pretty good about telling you will be divested this year. These are basically 3 different properties that we've -- are having ongoing discussions on. So, and it may be more than that but I feel good about relating that we probably at least another $100 million to report before the end of the year.

So with that, I think we've pretty much covered all bases. I want to do one last thing before we take questions. And I know there will be a number of callers wanting to add information about our Ambassador situation down in Australia. So I'm going to let our General Counsel read a little something so hopefully, that will kill any of those questions.

Paul M. Johnston

Sure. Thanks, Gary. Because of legal considerations, I will be brief. Regarding Ambassador, as we have a publicly reported previously, we have made an all-stock tender offer for Ambassador. At this time, our offer remains open and the exchange offer ratio we have offered remains the same. Our offer is currently scheduled to expire around August 22, approximately 2 weeks from today. And as we have reported, our offer is subject to a competing bid. Because we are involved in a competing bid situation for Ambassador, we are legally constrained regarding what we can say at this time. However, we do expect to be able to provide an update early next week.

Gary C. Evans

Thank you, Paul. And operator, I think with that, we're ready to take on some questions.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question will come from the line of Neal Dingmann with SunTrust.

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

Say, Gary, just turning to -- maybe for you or Jim, and obviously in the Utica and Marcellus area. A lot of wells, obviously, may come in on late this year. Just trying to get a sense -- you did have one Stalder well that came on I think it was reported at 30-plus. I'm just trying to get a sense of any potential estimates you all have for -- any reason to think those additional Stalder Pads would be any different or then moving down to the 4 Ormet or the 8 DNR or even the Stewart-Winland pads, just kind of trying to get a sense of expectations for those type of wells coming on.

Gary C. Evans

Jim, you're probably better suited to answer that.

James W. Denny

Yes, at this time, we've got shale logs that, from our NUTECH work, on all of those areas and wells and we feel very comfortable in the -- that they will look very similar to the Stalder. The Stewart-Winland is 200 feet deeper, which was one of the question marks we had going in as, does structure accelerate as we go to the East? And that has not occurred. So that takes away a lot of temperature and concerns with regard to substandard gas that we've seen great pressure and shows in the drilling process. The fracs went very well, mostly as planned. Many better than plan. And we really haven't seen the Utica yet, as far as penetrated other than pilot on the Ormet. So I can't to speak to shows or fracs there. And the new Stalder wells look every bit as strong as the original Stalder well. So I have no reason to think that they won't be anything less than high-rate gas. And that rate will be the mystery. But given the pressures we've seen, the rate will be high.

Gary C. Evans

Jim, you might mention that on the Stalder Pad, aren't your lateral lengths longer on these subsequent wells?

James W. Denny

They are longer on these wells than the original one. And the one real important point that I failed to mention on the Ormet is that, with our recent purchase of the minerals there, our net revenue interest will be in excess of 97%. So the impact of those wells is more than what we would usually find and given the rate that we expect, those will be important wells to the company.

Gary C. Evans

That's one area that a lot of people overlook is that we've been working to acquire those Ormet minerals for the better part of a year. And that was a very, very important purchase for us because we covered 1,700 acres, we already had 3 shallow Marcellus wells, of which we had just leases on. So then we picked up minerals under 3 existing wells that got us, as Jim said, 97% to 100% net-net lease. And then we had no Utica rights under those -- under that lease. So we have both the Marcellus and Utica. We've got 2 separate pads. We've got -- in the Marcellus wells are still producing today, while Jim's drilling the Utica wells because they're 2 separate pads. But 4 new Utica wells, similar to the Stalder with 100% working and 97% net mineral, that is huge impact to this company.

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

And maybe Gary, maybe a follow-up for you and perhaps even Chris. And I think you alluded to this a little bit earlier as far as having enough takeaway. When all these come on, is it fair to say that most of the midstream will already be tied in?

Gary C. Evans

Chris, you want to comment there? Why don't you mention both the Stewart-Winland and the Ormet?

Christopher T. Akers

Yes, okay. Stewart-Winland were expected by the end of this month to have our pipeline in place and ready to go for the well. And also, everything at Ormet, we should be about a month ahead of any drilling plan to be able to take that away. And as I mentioned earlier, our new interconnects has just given us fairly unlimited capacity to send that gas to market.

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

Okay. And then lastly, just on liquidity, Gary. You mentioned a number of deals. One, I guess, have you hired, in the process for the Bakken, any bankers yet specifically there? And then just thoughts on -- I know you mentioned about the potential size deals coming on just trying to get a sense of timing versus the current liquidity?

Gary C. Evans

We had actually had a board meeting here in Houston yesterday right after our annual shareholder meeting. And we have 3 significant liquidity events we're working on and none of which include capital market transactions. So we recognize the need for additional liquidity. We have things that the board has approved yesterday that we hopefully will announce in the near future once we get the definitive agreements. And so we've -- and these events are significant. So we believe that we've got all that handled for the remainder of the year and as you watch the news flow over the next 30 days, you'll see those events. So hopefully, that answers your question.

Operator

Your next question will come from the line of Leo Mariani with RBC.

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

Maybe you could expand a little bit more on the asset sales. You guys talked about $100 million worth of sales. Just trying to get a sense of what assets are being included there? Does that include the old NGAS properties down there in Kentucky?

Gary C. Evans

No, it doesn't. It's predominately related to Divide County, North Dakota. As you may be aware, Baytex, who was the operator of a group of our assets over in the Western side of Divide County, had an open data room and sold their assets to SM Energy. It was announced I think a week or 10 days ago. And we're having conversations with a number of different parties concerning us selling our non-operated working interest there. So that's an area. We have some other peripheral properties in North Dakota that do not include the Samson operated that we're having negotiations with third parties on. We also have in a -- we've negotiated a transaction to with a -- I wouldn't call it a clearinghouse but it's basically, some -- a group of West Virginia and Kentucky properties that are not part of the really, the NGAS gas properties that we are trying to market as well. So if you put all that together, it could be $150 million of assets. But I'm trying to be conservative and just say $100 million.

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

Okay. I guess, just with respect to some of the shut-ins here on the wells in Appalachia, I guess, I totally get why you guys would be shutting these in during frac-ing. Maybe just give us some more color on why you're shutting in a lot of wells just during the drilling process. Is this just kind of logistics on the surface or maybe explain that a little better?

Gary C. Evans

It's all got to do with safety. And, Jim, you want to touch on that?

James W. Denny

Yes, sir. The lay of the land in Appalachia can be very difficult. So you don't have the luxury of the room of spreading these wells out like you might do in a cornfield or something. So the rig is literally sitting on top of the wellheads in some cases. And what we've done is put double bridge plugs and weld a plate over the top of the tree. So there's no chance of us knocking a wellhead over which has been done and can be very dangerous. So we try not to be drilling next to a live well and so that's the reason for them being shut-in. It's for further development, purely and simple.

Gary C. Evans

Leo, we've also -- there's some other companies, I'm not going to name names, last time I did that, I got in trouble. There are some companies out there that had tried to drill wells with live wells on and had some horrible blowout. So it's pretty much -- I think, all the companies in our area have just recognized that the safety is too important. And so let's keep the wells shut-in while we're drilling on the pad. Now, obviously, that creates big lumpiness with respect to our production. But as our production base grows and it will grow significantly this year, that lumpiness will be much smaller in forthcoming years.

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

Okay, that's helpful. I guess just jumping to your gas prices, you had very strong realizations this quarter, significantly above NYMEX pricing. I know you guys do breakout NGLs as well in your production. Can you just give us some insight into what was striving strong gas prices here?

Gary C. Evans

Well, I think it's a combination of the fact that we do control our gathering and we can do some things maybe a little different up in our area. But a big part of it had to do with the Bakken. The gas pricing that we got up there was extraordinarily because of the high Btu level that Glenn mentioned, that 1,700 Btu. And the contract we had negotiated with ONEOK is very advantageous and that was a big shot. And remember, all that casing head gas, that's like free money because it's gas, it's been flared and as we continue to tie these wells in, that's just additional production with no cost.

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

You guys have estimate of roughly what your net gas production was in the Bakken and where that may be going, later this year you tie more wells in.

Gary C. Evans

Glenn.

R. Glenn Dawson

Yes, it's currently about 2 million cubic feet a day net and we're forecasting it will be closer to 3 million by year-end.

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

Okay. That's helpful. And I guess, could you guys just speak to the timing, I think you guys have made a payment to Penn Virginia recently to settle some litigation. Just trying get a sense of when that was made?

Gary C. Evans

A couple of weeks ago.

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

Okay. And can you just speak to kind of balancing liquidity versus leasehold. You guys have clearly been aggressive in securing a lot of leases here in the Utica and the Marcellus. And just kind of speak to that strategically and how you're thinking about balancing those 2?

Gary C. Evans

When we have additional liquidity, we'll continue leasing. Basically, we do have additional leases we've negotiated. You will see some additional lease purchases over the next 60 days. But you'll see also a liquidity event occur before that.

Operator

Your next question will come from the line of Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

Can you relate to us the reserves production and/or EBITDA associated with the Divide County assets expected to be divested by year-end?

Gary C. Evans

Reserves, can you do that, Debbie?

Debbie Funderburg

Yes. The reserves associated with that would be about 15 MMBoe.

Gary C. Evans

Production is about 900 net BOE per day.

Dan McSpirit - BMO Capital Markets U.S.

And then turning to the reserve report at June 30. What were the recovery assumptions on the 4 Utica Shale wells included in that report, maybe both the average and the range? And are those good recovery assumptions to use for modeling purposes?

Debbie Funderburg

We don't have a lot of production as you know. So Colin Gillespie was very conservative. They've assigned 10 Bcfe per well but we expect those to increase significantly once we start getting production data.

Gary C. Evans

Yes, remember the only well they really had tee off of was the Stalder. The Stalder only produced 42 days before we shut-in to start drilling the other Stalder wells that Jim's drilling now. So as we've experienced in the past with the Marcellus, I mean, our first Marcellus wells, we had maybe 4.5 Bs per well. Today, we're approaching 12 Bs per well. As time goes by, as performance improves, the reserves will go up. So that's why we've actually formed internally a reserve committee with executives on board, as well as 2 of our board members to really work these reserves hard because I've been preaching for the last couple of years, I think, we're way under booked with respect to our reserve potential. And the only thing that's going to really fix that is time. Now by the end of the year, we'll have over 10 Utica wells online so that will help dramatically with respect to the reserve bookings at year end.

Dan McSpirit - BMO Capital Markets U.S.

And as a follow-up, just turning to the balance sheet. You talked a lot about divestitures and maybe additional acquisitions before the year is out here. Where do you see leverage at year-end pro forma for the acquisitions and planned divestitures and does that estimate include preferred stock as debt?

Gary C. Evans

Well, if you were to take now until the end of the year, I think you'll see a drop in leverage based on liquidity events we're working on. The acquisitions of additional leases probably won't be more than another 50 million, and the divestitures and the other liquidity events that we're working on are much greater than that.

Joseph C. Daches

And Dan, if you think about fourth quarter production coming on and you look at a run-rate basis, you're looking to leverage it, I'd say 3.5x on an annualized basis. And as that production comes on, for a full quarter, in the first quarter, I think you're going to continue to delever from there on out.

Operator

Your next question comes from the line of Chad Mabry with MLV.

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

Probably alluding to a liquidity event but you had mentioned at the Analyst Day, potential sale of mineral interests. Just curious if you could provide -- maybe help us quantify the numbers around that and potential timing of that transaction?

Gary C. Evans

I don't think you'd see us do anything there this year. I think it'd be likely a next year event, if we did. And what Chad's referring to is we've done some internal studies of, obviously, watching other public companies who have recently gone to the IPO market with mineral interests. And so the fact that our net revenue interest on many of our properties are so high, in other words, they're 87.5% net minerals. We obviously bought the Ormet, we own 97% of minerals there. What we could possibly do if we wanted to carve out minerals and put them in an IPO and we've got about $100 million to $150 million of value there. And so it's something we're continuing to explore, but it's not something I would count on for 2014.

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

Okay, great. And then just looking at the release, I guess, the decision to officially sell the Divide County assets, would those be re-classed into discontinued operations going forward? Are you still going to be able to realize that production until a sale is announced?

Gary C. Evans

Joe, you want to comment on that? Joe Daches, are you there?

[Technical Difficulty]

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

I'll follow up offline.

Gary C. Evans

I just called Joe. He's the one that handles all that discontinued and I don't want to tell you something that's not right.

Operator

And your next question will come from the line of Richard Tullis with Capital One Securities.

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

Gary, going back to the Divide County potential asset sale, particularly the operated piece there. Would you be looking at, say, first half 2015 transaction if it happened?

Gary C. Evans

On the operated piece?

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

Yes.

Gary C. Evans

I can't really say. The part that we're really working on right now doesn't include that piece. But you never know. As you start talking to parties, they start asking, "Well, what if I did this? Or what if did that?" So it's on the table, but it's not something being actively marketed at present.

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

I see. And if you were to sell it, what sort of range of proceeds do you think you might be able to generate from the operated piece?

Gary C. Evans

I'll let Glenn comment on that.

R. Glenn Dawson

I think there's some confusion here. We have only a very small operated piece. The bulk of the production is operated by Samson. We have -- which is almost 3,000 barrels a day. Continental operates about 200 barrels a day. We operate about 350 to 400 barrels a day, Bakken Hunter. The remaining properties were operated by Baytex, which is the piece we're focused on selling and then we have a minor piece operated by Crescent Point and a minor piece operated by St. Mary. So what we're focused on selling is about 1,100 barrels a day, the asset that St. Mary's acquired from Baytex. That's our primary focus for this year.

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

Okay. And then as you go into next year, everything else in addition to the Baytex is potentially to be sold?

Gary C. Evans

Potentially.

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

Okay. Looking at the borrowing base, Gary, what sort of impact would the Baytex sale have on that? And then if you were to sell the rest of the Williston Divide County, what sort of impact could that have on the borrowing base?

Gary C. Evans

Typically, when we've sold assets in the past, the borrowing base reductions have been anywhere between 30% and the most, 50%. I would say on the Baytex assets it's probably more like 40% because it does include quite a bit of acreage that banks don't lend you money on. So I would say about a 40% -- so let's, for argument's sake, say we got $100 million, you'd talk about a $40 million reduction in borrowing base and a $60 million liquidity event.

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

Okay, okay. And then presumably, you would be getting increases along the way on additional drilling in Appalachia?

Gary C. Evans

Yes. Well, we're going through our borrowing base review now because of the midyear reserve report, which was up, but we won't probably get another borrowing base bump until our year end reserves and that should, again, be significant. Not only will reserves be up big time, but production will as well.

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

Okay. And for E&P CapEx, what's the expectation for the second half of 2014?

Gary C. Evans

Similar to the first half. I mean, we're on target [indiscernible] budget. You're going to see some of the extra money we spent in midstream, I think you'll see some of that recouped. So you should see less of that capital being spent in the second half of the year.

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

Okay. And then just the last question for me. How do you look at the Eureka potential monetization? Is that something you think you may see in the first half of next year? And what sort of potential options do you see for monetization of that asset?

Gary C. Evans

Well, we said all along that having control of that pipeline is very essential to our future. And now that our focus is even greater on Appalachia than it has been in the past, that continues to be the case. So an outright monetization with a third-party is probably not in the cards and monetization would have to occur most likely in our own MLP IPO. So we are having -- we discussed that yesterday at the board. We're having lots of discussions about that. I'm actually interviewing people as soon as this call is over. So we are on that front.

Operator

And your next question comes from line of Bedrum Buck [ph] with Wunderlich.

Unknown Analyst

Just a quick question on the production looking forward. When is the Stewart-Winland pad coming on? And the other question is just with all these pads being kind of lumpy and with the production coming in, how does the breakdown between 3Q and 4Q look like, could there be like a really big ramp-up in 4Q depending on how the pads come in?

Gary C. Evans

Okay. Well, I think Jim may have mentioned on the Stewart-Winland, he's expecting those wells to come on early to mid-September. And the pipeline will be there as Chris mentioned, by the end of August. So you should see in the third quarter, probably at best, 15 to 20 days of production off that pad. But when there's other wells that'll be coming on in the next 30 days, that Jim's mentioned as well. So with respect to the big boost in production, it's going to be the fourth quarter and a lot of it is going to be November, December. So it's a huge jump in the fourth quarter. So don't expect to see major increases in the third quarter. That's our last question, operator.

Operator

Yes, that is the last question. At this time, sir, please proceed with any closing remarks.

Gary C. Evans

Thank all of you for dialing and spend the time this morning, we've spent about 1.5 hours on this and we appreciate your interest in our company. We're excited about where we're going. We reiterated, again today, our exit rate of 32,500 barrels a day. We think built in lots cushion this year and we're prepared to meet that goal, a lot of us sitting around this table and in this company our bonuses are dependent upon it. So we're working hard. You all have a good day, and call us if you have any specific questions. Thank you.

Operator

Thank you for your participation on today's conference call. You may now disconnect.

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Source: Magnum Hunter Resources' (MHR) CEO Gary Evans on Q2 2014 Results - Earnings Call Transcript
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