Magnum Hunter Resources Corporation (MHR) Investor Day Conference November 4, 2013 2:00 PM ET
Gary C. Evans
Well, thank you, all of you, for showing up today for our first Investor Day. We've had, obviously, a number of analyst days. We've never had opened up a forum to institutional investors, as well as analysts at the same time. We think the time is appropriate in light of our activities in the company. And so we've got a whole team here today. To my left is Jim Denny, he runs our Appalachia Division, has been for the last 4 years since we got involved up in Appalachia with the Triad acquisition; Glenn Dawson runs our Williston Basin Division out of Denver, and he'll give you an update today as well; many of you had not met Joe Daches, he's our new Chief Financial Officer, came on board almost 4 months now and done a great job, he will update you on what we're doing on the County front; and Kip Ferguson, he used to run our Eagle Ford Division, he's looking for a job right now, so -- no, Kip's been helping me on a lot of special projects. One of the things that -- Kip did a great job of -- was convincing our third party engineering consultants at Colin Gillespie to give us the kind of reserves we felt like we were deserving. And so he has been helping other 2 divisions, especially working with Debbie Funderburg. Debbie's our VP Reservoir Engineer, get our year-end reserve numbers up. We felt like -- we've always felt like we had -- we are way underbooked on PUDs, and so we've been working hard this year trying to update that.
So I'm going to -- you're going to hear just very little from me today. You want to hear from all these gentlemen. And then we really want to open up this presentation to an open forum. So if you have questions along the way, this is not formal at all. Be sure to raise your hand or ask a question and I know Jim and Glenn both have brought maps, so we'll have -- we got this table up here, we can show you some specific maps and get you more educated as to what we're doing.
I got preach to this morning about this forward-looking statements because this is being webcast, so you may ask me some questions I can't answer. Remember, we have our earnings call this Friday. So I can't really talk about our financial results yet because they haven't been disclosed. But we're going to talk to you about well results as best we can. The big question everybody has is how the Farley is the doing, we'll talk a little bit about that today without giving you too much specifics. We'll give you a more specific information on Friday.
So would that be okay there, Paul? I don't have to read all of these, though? Okay, thanks. I'll start it. I failed to mention Kirk Trosclair, he runs our Drilling Division, Alpha Hunter; and then Paul Johnston, who I was just talking to, is our Senior VP, General Counsel; Chris Benton, who many of you talk to, runs our Investor Relations; Cham [ph] King works with him as well.
Okay. Most of you guys know our business. We started up about 4 years ago. We took over some little petro resources. We started buying acreage in what he felt like were key plays, bought companies and assembled 1 million acres. And now, we've been whittling it down, trying to focus on the plays that we feel like will give us the highest rates of return, give our shareholders the best value for our bucks spent.
And so in 4 years, we created a company with about $1.3 billion market cap, enterprise value of about $2.35 billion. Current production, still around 15,000, 16,000 barrels a day, headed to our target of 23,000, 25,000. Proved reserves, just under 60 million barrels, 3P 120 million barrels, and contingent reserves 730 million barrels.
Various win, this is all that's left of South Texas after the sale of the Eagle Ford division to Penn Virginia that occurred in April. I was telling some guys at lunch, I thought it was real smart. I made an extra $1.20 on the stock and stock's at $9-something today. So don't look at me to be a stock dealer, right? But no, we were the big overhang. We took a big equity position in the Penn Virginia sale to help them the transaction done. It was a win-win for everybody.
This last 7,000 acres, we've got under LOI, the sale to some Australians at a very nice price, and we'll talk about that a little bit more today. So that will just leave Williston Basin in Appalachia. We've got obviously, some properties in Kentucky that were also on the block, coming up next year. And then Glenn has just cut a deal. We signed the LOI to sell all Canada, and that's the process of going to definitive agreement. So we're really scaling this thing back to Williston Basin, which is Divide County mostly, a little bit Burke County and then the Marcellus Utica, that's really where we want to be.
So this is the chart I showed you, the acreage we've accumulated, 1 million gross, 740,000 acres net in where those properties lie. We continue to build our acreage position in the Utica, as well as the Marcellus over in Southwestern, West Virginia and Southeastern Ohio, and we'll continue to do that throughout the year and we're going to discuss that in greater length today as well.
So with that, I felt we'd maybe kind of start out just talk a little bit about reserves, and Kip and Debbie will give their presentation.
Hershal C. Ferguson
So I'll let Debbie start for us today, and then I'll beat in.
Good afternoon. My name is Debbie Funderburg, I'm the VP of Reservoir Engineering. I've been with the company for a little bit over 3 years and I do the corporate reserves. I do work with all the technical teams from me to the division: Calgary, Denver and in Jim's group at the Myriad [ph] office.
This first graph shows proved reserves flow over the last couple years, from 2008 to 2013, of 128%. We grew from 3 million to over 73 million barrels of oil equivalent. And that does include the Eagle Ford Shale division at that time. Our annual proved reserve growth per share is about 68%.
Okay, Colin Gillespie does our third party -- they're our third party reserve company. They do a report at year-end and also mid-year. And then we do internal reports at first quarter and third quarter. At midyear, our SEC proved reserves were about 58 million barrels of oil equivalent, were about 63% proved developed and 37% proved undeveloped. As Gary said, we've got a vast majority of acreage. We have a huge drilling inventory. So we're all working hard to increase the PUD value. An example is Colin Gillespie took a trip Jim's office in Myriad and we had a big meeting. He's got huge area where he's drilling, and Colin was only letting us book PUDs immediately offsetting [ph] the PDP. But he's got an 18th month drilling program, we have the capital, we have drilling permits. The pads are built. So Colin's going to allow us to book the PUDs in a huge block. So we'll see improvement there.
Our gas is about 50%, as oil and liquids and currently, the largest region is Appalachia, followed by Williston Hunter. Currently, we have about 4,300 wells and about -- that's gross in 3,000 net. We operate about 80% of our proved developed producing in 65% of our reserves. At midyear, we added about 139 PUDs, but a lot of the PUDs that were economic in Williston center at year-end became uneconomic at midyear. So what happened was the SEC pricing dropped $3.11 and our OpEx started going up. OpEx at Williston Hunter increased 60%. We had a lot of bad weather, flooding, roadwork, they checked the sands and we're growing so fast and lavayers [ph] were not electrified so they were having a generator which is super expensive, diesel, mechanics. But now, they the sands and Glenn's been meeting with them a lot. They have an initiative to lower their LOE. And so Baytex is in the process of electrifying everything.
So we met with Colin, Kip and I want to Austin last Friday. We met with him on the Williston Hunter. Since we have evidence that we have electrified, they're going to allow us to use a little operating loss, take away all the rental equipment, the generators, the diesel.
So we believe that a lot of PUDs were uneconomic and it may -- it will become economic. And Glenn is also going to show you that his CapEx to drill the wheels is decreasing as well.
At midyear last year, we had 2 reserve companies. We used HAM and Colin Gillespie. The Colin Gillespie has a lot of experience in the Bakken, so we decided to go 100% to using Colin. They do over 50 company reserve reports in the Bakken. They're experienced, they're accurate, they do a lot of studies, so we're now 100% with them.
The major difference is HAM is Canadian-based. They use type curves for everything. So for example, the Middle Bakken 1 mile, they were using 175,000 barrels of oil for each well. The Colin looks at each well, looks at the data, honors the data and theirs ranges from 150 to 350 in Boe. On a 2-mile, Colin -- excuse me, HAM was using 330 MBOE for each type curve and with Colin honoring the data, theirs ranges from 212 -- there's a well that's over 800,000 barrels of oil equivalent.
What we're seeing in the bi-county is there are areas that are performing really well and some aren't. We may have a well that's producing -- has an EUR of over 800,000 barrels of oil equivalent, sitting next to a well that's 400,000. So our initiative is to look at every well and find out what the differences are.
So we're looking at the frac job, the size of the frac jobs. Are we staying in zone, are we out of zone? I mean, what's making the difference? So we have curves on every single well, and we've been going through them and we've been working with Colin on that. So we think we'll see an improvement in our PUDs looking at the Williston Hunter as well.
We engage with Colin to do a 3P report at midyear as well. They looked at the Marcellus, the Middle Bakken and the Three Forks Sanish. We were not able to book anything on the Utica because we didn't have the cash. So the total problem possible reserves were 62 MBoe. And contingent resources where we put everything else to Utica, we've booked a lot there. And anything that was exploratory further out that may have been uneconomic at the time we did, the problem possible report we put in to contingent resources. So right now our unrisked 3P reserves and contingent resources is about 850 million barrels of oil equivalent, which is tremendous.
I want to mention one thing. Right now, we're at midyear, 58 million barrels of oil equivalent. But with the all the wells that Jim is going to be bringing on and all the wells that couldn't be brought on in Glenn's area, and the PUDs becoming economic, I believe that we can be between 65 and 70 MMBoe at year-end. Okay. Do you want to speak?
Hershal C. Ferguson
So I think our major -- the goal for the company and our reserve group right now is to make sure that we have communication between each division and the reserve analysts to make sure that nothing's being left behind. A lot of times, we had these guys, they're going so fast, they forget the story behind a lot of these plays. And so one of the things that we deal with is obviously we're bringing on [indiscernible] on the wells at the end of the year.
And Debbie and I worked really hard to bring all the data together. We collect data from all divisions, try to relate that into the third-party engineers. And we're just trying not to miss anything. We're trying to get the PUDs booked correctly, trying to get our new wells or PDP wells booked as best, as accurately as we can. And this was something that we did in the Eagle Ford that was quite helpful. And I hope you can see this, but we're using cube days plus[ph].
What we found is there seem to be a really accurate correlation and see the predictive -- I mean, it's a very predictable, very repeatable results. We pretty much knew what our EURs were going to be on these wells within the first 30, 60 days. And we're going to run it through a lot of stops in all the different divisions and really spend a lot of time on these wells all depend -- we've actually have data now collected on every single well. We're trying to approach this more as a corporate overview of our wells, but not just of our areas but of the individual wells themselves. And we're trying to relate this to some of the things that we did in Eagle Ford and make sure that all of the possible reserves are being accounted for. Not that we're trying to get more reserves than what we deserved, but really make sure they're accurate. And so we spent a lot of time really identifying every single well, how they're fraced, how they were drilled, and really looking back at these numbers.
So one of the things I think that has added value here is that -- the idea would be the goals for this group today always have been, is really to maximize shareholder value for the CapEx that we're spending, as simple as that. Look at the areas, how are they improving? What area is being explored correctly and optimized? And then we try to roll it into a full-blown development and try to help each division and the management at the corporation try and say where are we going to spend our capital budget every year? We want to look for the highest rate of return for those assets. And so we spend a lot of time trying to really understand each area and working with the divisions closely and said, look, we have some new emerging areas in the Bakken. We really like the Ambrose area with their -- the wells are outperforming a lot of the previous reserve reports. So I think that, that focus and where we're going with Utica and obviously, we have a lot of new results in Utica, which we'll talk about. But what is that going to look like in the next 6 months? How are we going to extend money where we don't apply capital? And I think that's something that we like -- we're trying to add support and really help the divisions and help the corporation understand where it is to maximize that value for the shareholders. So it's really important for us right now and I think that it's a whole new initiative that we're really taking next steps and really driving down details for each of these wells.
I think that's about it. Debbie, do you want to add anything?
[indiscernible] ask questions later, we could certainly -- we were -- we'd like to really get into all these areas, and I believe, we play in time [ph] we're looking at maps and talk about different results we're seeing. And we're happy to sit down, roll up our sleeves and meet with you guys on all these areas, too.
Gary C. Evans
Okay, non-core divestitures has been a big issue for us this year. So as you know, we started out with the Eagle Ford division, got a little gain on the PVA stock that I mentioned, then we sold some Burke County leases to Oasis, which were deemed non-core, and then this little gold mine was something we inherited from NGAS when we bought them a few years back, some other odds and ends, mostly South Texas. So in process, we have the Pearsall, which is that remaining 7,000 acres down in Atascosa County, some Waterfloods in North Dakota and West Virginia, $75 million, and then the Canadian assets of $85 million. So there's right at $200 million of additional sales that are pending that will occur towards the end of the year. Some may roll it to January but this is all coming down the road.
So for 1 year of sales, $636 million, $637 million of assets. Now, we -- if you've read some of our 10-Ks and 10-Qs, you could see that we've been in litigation over the last couple of years with a company that gathers the gas for us in Kentucky. And this was something that we initiated actually, 2 court cases and 1 arbitration case against this company for what we felt like were inappropriate actions. So we recently entered into a complete settlement agreement of all that litigation, very much to our favor. I can't talk about it in details because we're still doing the definitive agreements. But it's anticipated to close somewhere around the middle of November, is that right, Paul? And then once that occurs, we plan on putting all of our Kentucky properties up for sale. So Jim and his team actually have met with all of the management over there today. Because it's the first day that we've actually stated this. So we anticipate that to be $80 million to $100 million type sale and that's earmarked for the first part of 2014.
So we are already haven't even told Jim this, negotiated with a bank to lead that effort. So again, further streamlining into only Williston Basin and Eagle Ford and we're very focused on that's where we need to be and I am sorry, what did I say? Eagle Ford. Gosh, you're sitting at the end of the table and just kind of I'm sorry. I know you want to go back, don't you? So the Williston Basin and Appalachia, remaining Appalachia being Marcellus and Utica. So that is on the game plays for early next year. That litigation is what has held us back from selling those assets because the things that were agreed to in that significantly increased the value of those assets. So this is just to give you -- I don't want to go through every one of these, but give you a little more in-depth background of the non-core assets, what they are, where they lay, what exists within them. So we're continuing down this process. As we obviously, sell these assets, our number of employees goes down and we become a much leaner, meaner company. All right, we're going to turn it over to Glenn and he will -- just hit that right button moving forward.
R. Glenn Dawson
Okay. Well, the landscape up in the Williston Basin is changing very dramatically and this schematic page will give you sort of an overview of where we have our remaining land position with the divesture of the Burke County, not on this map, which is basically the Oasis operation.
So we've shrunk it down to about 175,000 acres by the time we rationalize the Canadian assets and the Eagle Waterfloods. So we're down to about 100,000 net acres in Divide County, which is going to be our -- was basically our focus area. As you know, we're working on targeting 2 plays in here, where primary, we're a Three Forks Sanish player initially, but we've now worked into Middle Bakken and Three Forks player. I'll talk quite a bit today about the Middle Bakken plays we're developing, how we got there and what we see going forward and the results we've been able to establish today.
We had as many as 7 rigs running earlier this year. We're down to actually 3 this week. We operate currently at double, which we're going to upgrade to a triple next week. We'll be able to drill 1.25 and 2-mile wells with that rig. Samson has a rig running, same areas of the rig running as of this week. Baytex is looking to probably start drilling again in December.
Our current production range is about 5,500 to 6,000 Boe a day and that's a bit lumpy because you only got pads and you bring on a pad and then structure goes way up and then they'd get shut in and your equipment and they come back on. So with pad drilling, you do have that kind of a profile. Our course, current exit target rate is 7,000 barrels a day equivalent, that would include current asset base. So if we shrink that with the Canadian sale and the Eagle sale, we're probably going to be in the 5,000 to 5,500-barrel a day range on exit.
This slide basically deals with our activity in the Ambrose area where we're focusing all of our capital this year. We basically pumped all of our money into this area, about 90% of it with Baytex and Sampson. And we're sticking to our higher rate of return projects in the Three Forks and the Middle Bakken. And we've been able to achieve much higher initial floor rates and more importantly, even higher IP 30 day rates from both formations. We're continuing to grow our anticipated and expected EURs, and our type curves are basically dealing with 2 types of wells out here, 350, up to a 550 occasionally if we get some wells that are better. But those would not be the norm on the current completion techniques.
If you look at how we have managed our project inventory to the 2 projects, I'm going to go through how we get the 2P and the 3P calculations. But we have over 500 gross locations just in the Ambrose area, all on held by on a production basis. So that is significant. We don't have any land expiry issues in the core block.
Most of the drilling that's ongoing now is on eco pads, no less than 2, as many as 6 wells per pad, which obviously are driving down our costs. I'll talk more about cost later in the presentation. Our current economic average runs about $6.4 million a well. We're spudding a well next week to a 2-mile lateral with 28 stages. They got an ASP on it for $5.9 million. And that really where we need to take this play to reduce costs, increase the rate of return. It's all about costs. The infrastructure is getting into really good shape. We've got one out coming on, we've finally got some gas moving through the system now, about 10 million gross. We've got -- probably going to sign a contract for some at midstream. In the next 2 weeks, we shall transport all of our crude out of this area, Samson's putting in a water disposal system. So all the heavy lifting is basically been done in the ancillary services, which all go to your bottom line. In the electrification front, about half of Samson's wells are electrified, half of Baytex wells electrified, and we expect 80% of Baytex wells to be electrified by year-end and then of course, that will dramatically reduce our loss and improve our profitability.
As I mentioned, we're dealing with 2 plays in here. The Three Forks Sanish is the initial play we've got involved in and this is the way it looks currently from our third party evaluator and the way we see it technically. So there's been a lot of development and we're using a 60% water cut-off to define this area. It's been developing in Canada, up to the North. Got Crescent point running in here, 5 or 6 rigs running in Husky, we've got same areas just to the west of it. So a pretty proven, mature area, with 1 well per section, or 1 well per 12 80, if you will, holding the base land tenure. Some of the more recent results, we got Bonneville, the Thomte, the Burt Rolson [ph]. We're getting some pretty good wells out it here this area, and you can see the IPs are commensurate with much better initial profiles.
A lot of oil is currently being produced from this area. If you look at the Ambrose white area right in here, you've got about 16,000 barrels a day coming out of the Ambrose area currently. Down on the Nessing [ph] where Continental is operating, you've got about 7,000 or 8,000 barrels a day of current production. So it's material production, so that's why all of these other services had moved in to help us affect the bottom line.
We're going to talk more about the Middle Bakken pay as we move into the presentation, not just give you some size and scalability on the project. We spent 3 years studying this to try and get to this point. There were plays developing over to the East in Canada at Taylorton and along the Nessing and then more recently, the Husky pool up in Canada, which is producing about 2,500 barrels a day.
So we studied all the vertical wells, we studied all the course and it's an optional bar system. We have looked at the 300 or 400 penetrations to determine what made this thing tick based on our well results, earlier well results and other competitors' well results. What we were able to ascertain is that there's a massive stratigraphic component to this play, which are these darker, gray areas. So essentially, trap the oil as it runs up dip out of the basin, into Canada.
So you got a calcification on the Middle Bakken sand or you've got a complete absence of the sand. And it's very predictable in these areas. And down dip of these traps, you'll find much lower water cuts than in the areas up dip from them. So it's created A pretty massive stratigraphic traffic, if you will, in an unconventional play. Also near the Canadian border, if you look at the core control, you'll notice that there is a significant change in permeability.
In Canada, it's somewhat of a conventional player. It's up to 15 millidarcies of permeability in Younger [ph] and Taylorton fields. In our area here, we're approaching 1 to 3 millidarcies right along the Canadian border, where it's down in the lower part of the basin, 20 miles south, it's 21 millidarcies. So I'll get a little bit more into that aspect of it but we're quite excited about the play. We've got about 23 wells into it currently.
Some of our recent in the second quarter production, selected production from a mix in Middle Bakken and Three Forks lowest curves are -- we're typically getting IPs in the 800 to 1,000 barrel a day range, and we're consistently getting 500, 600, 700, 800 IP 30. And that number of frac stages are indicated by the red line. And we've actually gone down a little bit over the last 6 months, kind of a trend we're seeing which would help reduce cost but the results have been the same.
Looking at some of our recent Three Forks well results. This is realtime data. On a Three Forks versus the type -- 2 type curves we're using. We're doing a pretty good job lately of performing to or at above the type curve. And we've established 2 type curves because the geology locally does show, really, 2 types of wells. This sensitivity slide was built just recently and then it takes into account sort of an overall look at our total well costs. Some of our costs, as Continental, are in the $7 million, $7.2 million range. Some of the them, as Baytex -- excuse me, with Samson, that -- we had been in the $6 million range. So we use $6.4 million, on average. And I up the differential based on current -- based on all considerations. I mean, the trends have been somewhat negative in the last 2 or 3 months, wherein, in the summer time we were kind of at $1 or $2. I've chosen to run it at minus $8 just to be on the more conservative side. We have $95, $97 curves. You can see the range from our lower type curve, to our higher type curve, where the sensitivities fall for the project.
Cost here, of course, the most important way we can impact the rate of return here other than doing newer and better completion techniques. But for a 1 and 1.25 mile lateral, we're currently looking at about $4 million AFE. And basically, the shrinkage in here on the capital cost, like the 2-mile wells, is mostly in dirt work, mud systems, better efficiencies at the bit, grinding on service companies to give us overall lower completion costs. And I think we're seeing a pretty good trend in that direction. Quarter-on-quarter, Samson's drilling costs over the last 3 years had decreased from $8.7 million to $6.7 million for 2-mile wells. And I know they're working on wells in the $6.5 million range consistently.
Our secret weapon is a $6 million well. That's our AFE for the next well we're going to drill. And that's going to spud in a week. And how we're getting there is a combination of things that I just mentioned but primarily, we're don't use oil-based mud. We use a water-based system. We reduced the dirt work significantly -- because we don't have to build the tips [ph] nor do we have to squeeze it. We use a smaller fingerprint on surface and we used a compact rig to reduce the overall move cost.
We're also going to a dissolvable ball system, which reduces your drill out costs to close to 0, unless they plug up, so you have the well flowing back and into production 30 to 40 days sooner. You also have no service rig moving in to drill those out to get the well flowing. So there's a significant savings in that area.
We've also redesigned our casing cost. We felt that the previous usage of P90 was just way too much. So we've saved about $250,000 well just on casing costs. So all in all, our goal here is to execute at $6 million and try and emulate what Crescent Petroleum is doing in Saskatchewan right across the border. I know they are drilling wells at $5.5 million, 2-mile laterals, with 30 stages. So that's kind of our goal. And that will materially change our rate of return on this project as we move forward, combined with lower LOF costs.
Talk a little bit more about the Middle Bakken discoveries. As I mentioned earlier, we drilled about -- we got 22 wells on production. We have about 30 well -- 33 wells on production by year-end. Most of the wells have been drilled just down-dip from the stratigraphic drop and these are some of the recent results we've got that we can talk about. Our best wells have been the Strom 2H. It's a 3-well pad, came on at 1,350 barrels a day IP. In the first 60 days, it made 70,000 barrels of oil, close to $7 million of revenue, and afloat. So we're just putting that on pump -- it's on, this week, on a jet pump and we'll see what it does when it gets at the end of this week.
2 other wells in that pad, the Strom 1H, was immediately put on pump. It's been on for a couple of weeks at about 600 barrels a day, 35% water cut. The other well in the pad, the Coronet, IP-ed at about 800 barrels a day, flowed for about a month. And it's now on a jet pump. So pretty good results there. We've had other good results at the Tom key [ph], the border farms and down in the Alamo. Most of the wells we drilled are on pad. So you can see, we've stretched the play out about 10 miles, north to south, and about 6 miles, east to west.
So 200 locations gross inside this P90 line. That's about 40 to 50 net based on our current working interest. So it's quite material, even if you were to lose 300 EUR type curve, that's about 10 million to 12 million barrels of crude, net to Williston Hunter.
Over in Central Divide, we're teeing-off this old [indiscernible] Middle Bakken field that Continental has been developing. We've mapped another stratigraphic trapping here. We're teeing-off the Rindel well, which is a 20% water cut. An old well we've been looking at for 3 or 4 years. It had 1 frac in it. That well's going to make 150,000 barrels of oil, when frac-ed in a 20% cut. So we're saying something's going to be going on here. Looked at the 3D. There's a pretty large salt collapse just east of the well. We think it's created a structure in an area of higher fracturing within the Middle Bakken. So we followed it up with a 2-mile well at 47% with Continental. The well came in quite strongly at 600 barrels a day, with a 45% cut, and it's now on pump. So it looks like a pretty good step-out to the Rindel.
We moved the rating here last week. We're drilling the Isaac, it's 100% 1-mile well. And you should have results on that well probably in about 30 days. We operated, with our rig, 2 wells up in this area called the Tundra, brought in on-budget, completed at Three Forks and the Middle Bakken and those results also look very good and will be on production next week. The flowbacks were in the 600 to 800 barrel a day range for the Three Forks and Middle Bakken on the Tundra lease.
So what this map is designed to show is that we've got running room in both plays, we see the Middle Bakken down, and helping down in this area, but there's probably 15 or 20 well penetrations, not 1 Middle Bakken well drilled down in this area. So we feel safe. We're seeing that in this area, the play exists, and we feel very comfortable now with these results that this area is also going to mature for us. This is just a blowup of the same map.
Debbie and Kip alluded to some of the work we've been doing with our third-party evaluator. So we've gone out and generated 2 and 3P maps internally and with a third party to sort of look at our reserve base and see what we feel fits in the 2P category and the 3P category. So for the Sanish Three Forks, you can clearly see the third party evaluators think that the bulk of our acreage in the Ambrose block is basically proven in some category. And the red areas represent an area that is contingent, that requires additional drilling to support an upward categorization of those reserves. And of course, over in Central Divide, we've got work to do on the Sanish, so we see it in a lower water cut trend coming off the Wetzel [ph].
And you could see that a commensurate number of locations grows in that associated with the areas that are booked, either 3P or contingent, for the Three Forks. Similarly, we did the same type of evaluation for the Middle Bakken. Gray is obviously the areas where the stratigraphic tract exists. Green would represent the 3P, the red would represent the areas that we have contingent resources. So again, the third-party evaluator sees in the Ambrose block, they feel comfortable that all of this area, based on well control -- when I say well control, we've got hundreds of vertical and new, modern age Three Forks wells underneath this Bakken field, which means you get a penetration, which means you get -- identification of the sand as being coarse and permeable and a gas log. So it gives you a high degree of confidence, that which you have in the Middle Bakken in here, is significant and, of course, reduces the risk as you move forward. So I have no issues with drilling anywhere inside that green area, which basically substantiates at a minimum 200 locations in the Middle Bakken, in the Ambrose sweet spot.
One of the areas that has been problematic for us this year has been the ONEOK gas system. This was negotiated over 2 years ago. They started constructing it last year, it was supposed to be on stream in March this year. They had some issues with their compressor when they started up and they basically had to redo the entire compressor station, all of the geotechnical that was core at [indiscernible] pads, cut all the imminent lines. To make a long story short, all of these red lines are now active and we have 2 operators. We have Samson up in this area here, and Baytex down in this area here. So you can see in green are the wells that are currently tied in and on-production, conserving Bakken and Three Forks gas currently, which is 50% in the Samson operated. It is projected that we will have 75% of the wells producing and on stream by year end in the Samson-operated area. We're currently producing initially 6 million gross, probably about 2.5, 2.75 million a day net of gas in the Samson-operated area.
In the Baytex-operated area, we feel the number's 4 million to 5 million gross. And we have a much smaller working interest in that there, so it's probably about 0.5 million or 750,000 cubic feet net in that area.
The significance of this is that it's a cash flow stream to be able to book the reserves and liquids associated with the timing of the gas. And the interesting thing that's developed is we're finding the gas stream to be much richer than we originally thought. We're thinking in the 1,400, 1,450 BTU range. Recent gas analysis that we've been able to obtain have shown gas as high as 1,700 BTU, and on an average, the September month through the plant was over 1,500.
So what that means is significantly richer stream. And we're doing our best to get updated gas analysis across the block. And we're trying to match those at the plant statement to see what kind of condensate and NGL values we're getting, which are currently economically run at about 140 barrels a million, which will likely move up as we get this quantitative work done to verify the gas contents in the NGLs and condensate contents.
So I think that's an exciting part of our project. We're going to get revenue out of this. We get 79% of the gas stream, 79% of the liquid stream. As you know, North Dakota has been on a tear to get gas wells tied in. So we're happy to say we're going to be fully compliant by 2014 with that restriction. We'll be keeping all of our production moving as we go forward.
So I talked about the oil lines that we're going to be working with Summit on, and Samson and Baytex on 2014. That should be -- we're looking at that contract next week. It's probably going to affect our bottom line about $2.50 to $3 a barrel across-the-board. Some of the lax units in higher-density pads that we tied in directly together is, we will truck the oil to 2 or 3 terminals that will be built in Ambrose block.
Gary C. Evans
I would like to just make maybe a couple of comments on the Williston Basin. We got our startup there with the acquisition of NuLoch. Just -- that Glenn was running, and then, we subsequently -- made the acquisition of the properties from Baytex.
And so if you kind of look at the last 2, 2.5, 3 years of what we've done up there, we built a large position. We focused on where we think we need to be. When we were in Divide County 3 years ago, everybody said, "You guys are crazy. And you are at the heart of the play," and guess who's moved in? We have Continental as our partner now. We have -- St. Mary is in the play. We have Oasis in the play, who we just sold the acreage to. So everybody has moved into the area. The Three Forks play and the Middle Bakken play has continued to the delineate itself. We've been drilling Middle Bakken wells, as Glenn indicated, in Divide County. And so now we know where we want to be. The Ambrose Field is a huge area where we're getting the best rates of return, and we're getting our gas sold. And we're selling off the table in the field, we are selling off Canada, really focusing.
If we can get these costs down, the $6 million on 350,000 to 600,000 barrel EUR wells, we can make a lot of money here. So we've been working with our partners. We continue to have meetings with our partners. I think you'll see some more consolidation in the area we're in. We'll probably lead in that effort and really home in on making this a really great play. And I don't think there's anybody that can drill wells cheaper in the basin and get the kind of recoveries we're finding. So we're pretty excited about where we see Williston Basin going.
So with that, I'll turn it over to Jim Denny to talk about Appalachia.
James W. Denny
[indiscernible] so I got to move. So I've got to speak up. And Gary gave me this height [ph] in here. How's that? Higher? Okay. And the clicker.
First of all, I'll dispel a couple rumors. My wife did not beat me up over the weekend, and Gary hasn't jerked my head off completely. Yet he tried, he didn't quite get it all over the Farley well and the mechanical issues we've had. It is actually attacked by a dermatologist. So that's what happened to my phase-in this particular area so that are part of face, and this particular area really swelled up.
Looking in through reserves for Appalachia, as Debbie mentioned, around 38 million Boe equivalent. And I think, to make the point that Gary was making earlier, if you do the math real quick in my head, that's about 66% of PDP of your total proved. And when you're in a resource play, that's a really big number.
So that's attributable, to my mind, to 3 factors. One is we're hitting good rates. Usually, in an unconventional play, you get a lot of reserves, and it takes you a long time to get them out of the ground. So we're getting them out of the ground in an efficient manner. Two, we've had a lot of upward revisions, so we're not seeing the declines that we once saw and we were predicting to see. And then, three, we're just very much under-booked in the other reserve categories other than PDP.
So those are the points, I think, that Gary was alluding to. We had added acreage of recently, another 10,000 acres, and that's always a balancing act between acres that you decided not to drill and we faded off for either cash or a different position. But most significantly, we're adding acreage in our Utica proposition in Ohio.
Our well count continues to go up, and we're very happy at the -- completing a number of wells tying in here. And I'll -- on the subsequent slide, I'll talk more about that. And then we currently have 2 rigs running, but we're moving a rig, and I'll show you that on a subsequent slide as well.
Same rates that we were showing for the Williston. I think Stone probably hates me when they see this slide, but that's a function of a couple of things. The most important one is our corporate philosophy. They bring their wells on just at an arbitrary 2 million to 3 million cubic feet a day, and then they remain flat essentially for a much, much longer period of time. So they work in the pressure rate curve to be a flatter, predictable rate. That has been a bit of a problem for us in -- is with our reserve estimation. And then you can see the difference between the wells and, of course, the difference between internal rates of return because these wells are literally 1,000. The ones in Wetzel County are literally 1,000 feet from the Stone wells. So you see in us a totally different rate time profile on the higher-rate wells, though all of them we've got a lot of pressure analysis to try and normalize that. And all of the wells are excellent wells. And at some point, their wells will cross in the future. So we end up within about 1 Bcf of one another is in-gate.
I think you're all familiar with the uplift from NGL and processing, which fluctuates dramatically and has diminished. The $1.25 was in February and the $0.75 was in June, and it stayed between those since then. So still very worthwhile endeavor, but something to look at in -- cautiously over a long period of time as to whether -- what you do with processing, especially if we get into ethane rejection, which is a wholly different discussion.
Again, our internal rate of return curve, you can see it's quite strong. Even at current commodity prices, I think we're down in here right now. This is our typical -- our amortized Marcellus well.
Okay, let's talk a little bit from this slide because how are we going to get from where we are and add the wells. I've been saying as many as 14 Marcellus wells net to us by year-end.
We have currently 3 wells frac-ed and ready to go here. Eureka's in the latter stages of laying this line. We're still predicting a December kickoff of those 3 wells. We are drilling -- we have drilled the Marcellus well here on the Stalder Pad horizontal and cased it. We are drilling a Utica pilot. We will plug that pilot back, drill the horizontal, and we will have one or both of those wells. If we can only do one by year-end because of the drilling issues we've encountered, then it'll be the Utica well because we need that data point more importantly than the Marcellus, and we feel like we know we got there.
We're participating with Eclipse on the Herrick well. We're waiting on the big rig now. We've drilled the top hole. We just finished -- well, we haven't finished. We're done about 3/4 of the way. We've done about 60 stages of 84 on a 4-well Collins Pad. So we should finished that in the next 7 to 10 days. And the frac spread will go directly to our WVDNR pad, which is our 100% wells next to the Stone wells, where we have completed -- or we have drilled and cased 3 wells. And so those wells, assuming we can keep water in the area, which the floods have been rather pretty regular, about one a week, so that's helped us to keep water in all of our frac jobs. And we do have 2 ponds completely full, and we have a source to buy water here in Wetzel County. So we feel confident that we'll have those 3 on.
So if we add them up, we've got 3, 4, 7, 10 that we control, 2 that are 50% is here on the Stalder Pad, 1 Marcellus and 1 Utica, all of which we hope to have tied in and producing by the end of the year. We will move the rig from the Stalder in order to get the test to the Winland-Stewart Pad here, and then I'll go back -- based upon the results and drill a combination of Utica and Marcellus wells. And I'll show you that on a subsequent slide as well.
Any questions about what we're -- this current activity and how we think we're going to -- we feel comfortable with meeting our year-end goals, even though we're quite a distance from there? The typical deal of pad drilling -- I mean, we'd all love for it to be the typical solitudes of PUD development. But when you drill 4 -- 3, 4, 6 wells on a pad, you'd really have a big step jump, so it's always a big -- So quarters don't mean -- when you look at quarter-over-quarter, the way you guys like to analyze, the way we like to analyze our business, it just doesn't always work very well when you're in the pad drilling. And since we don't have lease issues here in West Virginia, primarily all of our acreage or a large portion of our acreage is held by production, we go to this cheaper route and do pad drilling.
Talk about the Utica. I'm sure you guys have done a lot of analysis on this as we have. A lot of misnomers about the Utica. One, we're not drilling the Utica. We're drilling the formation called the Point Pleasant. We call it the Utica Shale play. The formation that we're drilling is not really a shale, it's a laminated carbonate. So it does have reservoir-character rock in it, which is different than a shale. The Utica Shale is -- typically runs 60% to 70% clay, and it's some of the bad clays under the illites and smectites. So it's not a very good reservoir.
So the size or the thickness of the Utica is not what's driving the well performance, and I'll mention now, those of you that can stay or don't have time constraints, I've got about a 30-, 40-minute presentation that I'll actually walk you through a North-South cross section and an East-West cross-section and then -- and maybe one down through the gas window and show you why we're so excited in some of the decisions that we've made with regard to the acreage that we have put together. So this is just kind of a primer for you to take away.
The Point Pleasant is very consistent over a very long period of aerial extent, maybe 120 or 150 miles North-South and 60 to 80 miles East-West, so it's a huge play. A lot of the ingredients that you love to see. It's got a lot of the right -- oh, here -- if you compare it to other plays, it's got a lot of the right ingredients that we're finding, even though we -- in Magnum Hunter, we have a collectively small sample, as we begin to compare notes with the industry as we each have staked out our position and become more comfortable with sharing data, we find that we're -- most of the parameters, we're on the higher end of this or maybe even better parameters especially as you move from West to East in the Utica play.
This is a description of a large position -- a large batch of acreage that we have under contract. It'll be between 30,000 and 40,000 acres. It looks like it's going to shake out. And it's designed because of the title issues in Appalachia to be staged over time. So we're already closed on 2 tranches, and we're looking to close on a -- it's design, ideally, we would close on about $15 million tranches over the next 12 to 16 months. And the way it works is we have 10 months, with clock running about 30 days now, to identify the title issues. They clear the title issues, and then they have 1 year to clear them. So this thing is going to be staged over a great period of time, which helps us handle it financially. So that's a plus, plus.
And you can see our costs here. Entry cost is fairly modest compared to the numbers that have been tossed around, especially lately with regard to acreage change in hands.
This slide is left in here. Colored takeaway of the porosity, of the inherent porosity in this rock. It's not connected to us, but you tell it, if I can frac this and create a stimulated reservoir volume that ties all these little 4 spaces together, then I can make so much better well than which you could make with a vertical well because you can tie in these things together over at least a mile lateral.
Again, I'm busting through these pretty close because I'm hoping that we'd get a pretty good audience here to talk in detail and certainly your questions in much more greater detail.
This has been our Farley well. It's going great, ended up taking a 300-barrel kick, had huge annular pressures. We're able to get the wells stabilized, get the well killed. However, we started losing circulation in that process, stressed the hole severely, never had complete circulation again, just got -- we're able to get the well quiet, got casing out to the tow. In the process of the cement job, we lost complete circulation and, therefore, had a poor primary cement job. We've done 2 remedial jobs, both of which have been somewhat successful. We've been able to get away 10 frac stages that we've -- and they went by recipes. So either you aren't able to do them because of communication behind pipe or you're able to get a successful frac away. That's 10 of 26 planned stages, which we've treated about 1/3 of the lateral.
So a couple things that we're looking to take away here. Our pressure, because we have the logs, we know what the water saturations look like, we know what this is, shale log, which I'll show you, and how it relates to the wells in the area. So what we didn't have, even though we had a pretty good indication from the well kick, was some actual measured data with charts, and et cetera. So we are now flowing the well back. As I said, we're in the early stages, and that the well is cleaning up. I've been asked not to mention rates specifically. I can't tell you that we're pleased with what we see compared to the number of stages they were able to complete versus the total number of plan. We are moving the rig that we've just finished in West Virginia, the Wetzel County, the WVDNR, 100% wells next to Stone. That rig has been moving to the Farley Pad as we speak. We're putting parts of it at its home base, which is only 4 miles away, and part of it on our production pad, which we're not utilizing at this point in time. We're just testing through a temporary facility. Yes, sir?
R. Glenn Dawson
Well, when you have those kind of pressures and rates in the process of a kill, we were holding 3,800 pounds on the casing side in order to control the gas, so we just totally stress the hole the minute it's kind of conventional. If we didn't -- haven't had oil base, in my opinion, we'd just stuck the pipe and we'd lost the hole at that point in time. So I think we were successful in not doing that, obviously, but little did I know that if I had known that my completion was going to be quite so compromised, we may have just drilled another well then.
So my bet is 170 [ph]. If they're [indiscernible].
R. Glenn Dawson
We get financed about 10.5 million, and I think on the dailies, we heard about 12 now. And we were under going into this -- when we were within 100 foot of our lateral. And on -- but that was with the pilot. And for a core rig, over about 180 feet. So you back all that out. And when we do the pilot, we're going to put keep a variant [ph] fees above 10. But we're looking at 9s, and then 8s once we get this down and go back to full pad drilling. And what we've seen in the Eagle Ford and seen -- and, Glenn, is now beginning to enjoy in the Williston, when you go to pad drilling, you can save about 600,000 to 750,000 right off the bat, just mob, demob costs and get them by that pad, et cetera?
[indiscernible] again[indiscernible] as it relates [indiscernible]?
James W. Denny
[indiscernible] with the same rig of that. So we're working -- we've been working. We're training the crews for this rig. We've totally retrained all of the Alpha rig, which is drilling our Stalder Utica right now as well.
James W. Denny
We changed a lot of people out. We've changed. I mean, this was a classic mistake. This was a classic management mismanagement mistake, which is why some of these scars are there.
James W. Denny
This keek was taking place over -- almost an hour. It was noticed by rig personnel who alerted other rig personnels without it making it all the way to the -- our personnel. So this was not a single catastrophic event. This was happening over a long period of time. On the Gulf Coast, this would have been a total atrocity. This is against everything you learn about well control.
[indiscernible] this is a big [indiscernible] you've talked about [indiscernible] and whether the results [indiscernible] suffice it to say [indiscernible]. What's your thoughts about [indiscernible]? Are you encouraged more [indiscernible] thoughts on [indiscernible]?
James W. Denny
I'm encouraged because -- Paul, can I talk about pressure gradient?
Paul M. Johnston
James W. Denny
Okay. We're finding that as the pressure gradients that I would have estimated at -- during the accrual processes is slightly lower than what I would estimate now. So that's -- that part's very encouraging. And I think that's what I'm looking the most from this from as I'm seeing -- we were estimating about 0.65. Now if you'd take the data that I have so far, it'd be over 7 -- or 0.7. So I'm still going to say it's going to be 0.68, 0.7, 0.71, somewhere along there. But If you go through the arithmetic, we'll fill a column of water. In other words, we were full of water. We had pressure on the surface, and we didn't flow gas for several hours. So if I assume that's all water, it's high. It's up there. So that these estimates' the most encouraging other than all the bigger takeaways from this well. So rigs are not discouraging, but they're not going to be -- they're not going to adequately describe what we're going to recover from this well though -- from this horizon in this area.
James W. Denny
I've talked about that Farley we've drilled, the middle because. We have 2 more permitted. And obviously, we have to set up now for 10 wells. I think 8 of which -- all the title issues are settled. So if we decide to develop here when we have takeaway, which is improving to a -- on a temporary basis fairly quickly, but we're also working on longer-term solution with Eureka, and maybe Don will talk some about that in his presentation. This is the Stalder Pad, 18 wells planned. We've drilled 1 Utica, which are the red ones, and about 1,000-foot spacing and the green, we brought -- excuse me, we drilled 1 Marcellus. So we -- at 750, we have 10 Marcellus wells, and I guess, it's 8 Utica wells here laid out on these 2 units. So I mean -- and if we're talking about the rates that we've been seeing in here, those of you that stay, I'll show you -- I'll share with you some of the rates from the area. I mean, it's not uncommon to see, in our opinion, 22-plus million a day flowing with north of 7,500 to 8,200 pounds. So we're talking about Gulf Coast economics. Think of it, 16 wells, that won't be all -- it won't all be that. But if I have 8 Uticas at 20 million and then I have 10 Marcellus, even at 2 million, this is a company changer. I mean -- and that's just 1 pad. And we're -- all of us looking at that. So marketing and commodity prices are going to drive this play in the long run. This is our new Alpha rig. We -- honestly, we've had a few keeks. But for the most part, we've been very pleased. I'm sorry, yes, sir?
I'm sorry. I'm just curious in the Marcellus and Utica wells, [indiscernible].
James W. Denny
Good question. As far [indiscernible] it is up 2,500 feet on the Stalder. We're thinking it's going to be about 3,200 to 3,500 feet, and we'll know more about that when we finish our vertical well. But it's thickening as you go east. Yes?
James W. Denny
And this will better -- it looks pretty small in here, but you can read them. This just shows a lot of the initial rates that have been announced, and I think the more important takeaway here is if you look at where we've gone back to pads, we've actually gone and confirmation wells have actually gone up, not down. And they've gone up dramatically. So there is a bit of a learning curve, and we're getting better at it, as you might expect in early in the game. Don? We had -- I mean, you have another shot at me, but any questions I can answer? Okay. Thank you.
Donald L. Kirkendall
Good afternoon, everyone. Can you hear me okay? I'm Don Kirkendall, and I am in the midstream group. And midstream by definition means everybody is always mad at us. We are not building pipe fast enough, or we've built too much capacity. We haven't built enough capacity, or we're behind schedule, or we built pipe in the wrong place. So I've been married for a long time, so I'm used to that, never being exactly right at any time. We've been a very busy group. I'll talk about what we do on a large scale. We're right in the heart of the wet Marcellus in West Virginia. Triad was the first company to drill horizontal wells in Tyler County. That's where we're the first midstream piece of pipe to service that area. We have about 90 miles of 20-inch pipes, mostly in West Virginia. We pushed into Ohio. We'll show you that. Maximum allowable operating pressure is about 1,135 pound. Ohio, we're going to go slightly higher than that. We have about 350 million a day of design capacity. We'll add some mainstream -- mainline compression at Carbide to help us move gas this winter as the company's bring on more gas, as well as Jim. Typically, our contracts are 10-, 15-year contracts. We have a combination of reservation and commodity-based contracts. Typically, we'll charge $0.15 reservation, $0.15, $0.20 commodity charge in West Virginia, slightly higher in Ohio. And we've got acreage dedication and a lot of pipeline expansion to cover here. We're building pipelines very, very quickly, as not quickly enough for Triad or other producers. I think we hold our own, though, against anybody else in the region. We have a very good working relationship with our construction company. Apex out of Nitro, West Virginia is building our pipeline exclusively. Their new plants are coming into the area, the Blue Racer suburban plant, MarkWest Seneca. In Natrium is -- they just had a fire at 1 of their 200-day plants. They'll be back up here shortly. They're very close to us. I'll show you where they are. And of course, we take most of our gas right now to the MarkWest Mobley plant in West Virginia. We're somewhat of an oddity inside Magnum Hunter. We are 40% owned by a private equity group, which is ArcLight out of Boston, and 60% owned by Magnum Hunter. So far this year, we've added about 25 miles of pipe. We've had a number of delays, due primarily to weather this year. It's been too wet to build pipe, but not enough water in the creeks to get water for frac-ing well. So it's kind of been a perfect storm for us. These are some shots. Most of you guys have seen this before. On the far-right side, our River Bore coming up into Ohio. We've pushed that from West Virginia. Then McCormick and Gary there in the middle, taking a look at pipeline routing in West Virginia, Ohio and 3 pipes relayed together at Carbide for condensate wet gas and dry gas. So just illustration that where it need be, we can put more than 1 piece of pipe and the same right away.
Gathering volumes, not as robust as I want. Our buddies at MarkWest had a problem with an NGL line in August, I guess it was, took us down for a couple of months. We're back up now. We're doing, right now, between 110 million and 135 million a day.
Gary C. Evans
Donald L. Kirkendall
Was it July?
Gary C. Evans
Donald L. Kirkendall
Gary C. Evans
Donald L. Kirkendall
Was it July 12? August 12?
Gary C. Evans
Donald L. Kirkendall
I have been -- anyway, we were down for about 2 months. Under contract right now, we have about 163 million a day, Magnum Hunter is 75 million, third-parties is 88 million. Now this was going to change dramatically. We've got contracts in place. End of the year, we should be about 275 million a day under contract. I have those numbers. They will be about 275 million under contract by year end. We should be flowing year end depending on how fast we can get piped in and put the IP rates on wells. We'll be -- and we'll go through the map. I'll show you where this is coming on. Year end, I'm looking at somewhere between 185 million and 200 million cubic feet a day, considerable jump from 110 million to 125 million a day from where we are. But this is where these lines are coming from. An area right in here called Big Moses, one of our third-party producer, JD, is bringing on an interconnection, and he anticipates 25 million a day by year end. He predicts that to ramp to 60 million a day by mid-next year. So we're adding compression there, so 25 million before year end. As Jim mentioned, the Triad wells coming on Collins. What do you think, Jim, 10 million, 15 million a day?
James W. Denny
Donald L. Kirkendall
Okay. The Stalder Pad, which is, of course, back over here in Ohio. That will be a combination of dry gas and possibly wet Marcellus. And what do you think for the IP of the Stalder? Take a wild estimate.
James W. Denny
[indiscernible] when I think about it.
Donald L. Kirkendall
15, 25 million? Okay. He used to...
James W. Denny
Higher, 30 million. [indiscernible].
Donald L. Kirkendall
All right. Eclipse, which is right at here at the end of it, of what we call the tip in collateral here, the chip into wells going down. They tested that well at 22.5 million a day. It tested at 22.5 million a day because that's as large as the equipment would go. Right about here, on our prolific lateral, we're tying in Chesapeake. They have a 1-well program right now. They want to evaluate it. They plan on pulling that, about 4 million or 5 million a day. So I've got between 60 million and 80 million a day to add before year end. Now going into January and December as well, we've got the Stalder Pad that we'll be pad drilling. Jim was talking about an 18-well situation. We're looking at somewhere between 150 million and 200 million cubic feet a day, combination of wet gas, dry gas. Triad has got drilling going on right here. They're planning on a dry Utica test and point to sell because this is primarily a wet line. This is where you set it up. Now Jim is set out to ruin my life with a bunch of wet -- a bunch of dry gas here. So I've got to move this some place because you don't want to take wet gas and take it over to a processing plant and need to process this out.
James W. Denny
Donald L. Kirkendall
Yes, dry gas, sorry. The dry gas that we anticipate here will initially flow back this way toward Mobley and into Dominion down here and up here. So in order to keep up with these guys, I've got to flow dry gas into wet systems. And then as we build out, we're going to come up north. I'll show you another slide. We're building a line called the Crescent up into REX and Texas Eastern. So I'm going to have systems running parallel, dry and wet, some running south and then some running north and up into TETCO and REX to dry. So we've got an awful lot of building to do. The expansion that we're looking at next year in Ohio, we have producers behind us that have made commitments or they are asking -- in the process of asking REX. We're between 650 million and 1.4 bcf a day of firm transport. So that means I've got obligations to be able to deliver that much gas. So in conjunction with that, I've got to build right up in here. I've got to build a compressor station to take this dry gas and the gas coming off the Natrium plant, going up into REX and Texas Eastern and Clarington. That compressor station will be somewhere between 30,000 and 50,000 horsepower, depending on what our throughput is. You're looking at compressors that are going to run about $4 million a piece. I'll need somewhere between 6 and 10 of these things, so just a considerable investment just in compression alone. The well results that Jim was talking about, Tippens, Stalder and the announcements that you're seeing, we fully expect that the Triad acreage that was recently added back in here will be equally as prolific. So ahead of me here on the next couple of years, we're going to be adding 20-inch system back down to the South and West.
When you look at the companies who we're talking to, we've already named Eclipse. Eclipse has been public with their announcement that they're coming to us. There are other companies that are backed by private equity groups that we're in negotiations with. We have signed letters of intent, working on contracts as we speak. But all these guys are planning on the same huge wells coming in. The Crescent system that you see right here, this is all along Eclipse acreage. And on the east side over here, a wet system going up through the Ormet area, where Triad's got wet Marcellus gas. You see this void right in here. There's a big player right here that we haven't really talked about, and that's Statoil. Statoil could easily produce 1 bcf a day of dry gas, where we'll have -- we're starting with a 20-inch system through the Crescent. We may do a 24-inch system if volumes warrant. We'll have another 20-inch system coming up through Ormet. That's under construction and almost done now. But all that gas will come north. Extremely wet gas that will kind of come through Natrium, dried, and we'll take it all up to Clarington. So it's easy to see when we start adding it, dry Utica back here, a dry system, parallel dry back here, dry up through here. It's easy to see how we can get through 1 bcf a day of throughput.
Donald L. Kirkendall
To get through a B? Depends on drilling, depends on how fast we can get pipes in the ground. By the end of '15, we should be in that B per day neighborhood. By early '15, we're probably 600 million a day.
[indiscernible] different parts of the [indiscernible] where we [indiscernible].
Donald L. Kirkendall
I can only talk about it only at a high level. Some of our producers are on a commodity-only situation. Those that are on a commodity-only are on a higher rate per MMBtu -- I'm sorry, they're on volumetric, mcf. And they range from $0.35 up to $0.55. There are some that are ranging in Ohio from $0.20 demand charge with a $0.20 commodity charge. We're charging slightly more in Ohio. The cost of construction is higher in Ohio than it was in West Virginia, where we got started. Construction costs are going up because of the competition to get good construction companies. And also, the landowners are charging a proverbial arm and a leg for right-of-way. When we started doing this in Ohio -- West Virginia, we were paying $5 a foot for right-of-way, and those from Western Texas and Louisiana, we thought, well, that's obscene. Well, in Ohio, we're paying as much as $50 a foot for right-of-way. So that's changed our economics considerably. When we started the project, our AFP was 1.25 million. Our first pipeline in the ground for about 1.3 million. In Ohio, we're -- our AFPs were running 1.6 million, 1.7 million, depending on where we are. And I could see that easily getting through 1.8 million, especially as we get into the Northern region, right up in here. The landowners know how valuable what little bit of buildable right-of-way is worth, and they extract every bit of pain out of us. Let's see, we've talked about Tippens, Stalder Pad. Jim, Stalder Pad and the pad drilling that is being contemplated here. Jim is only looking at 18 wells here. I say only because that's just for 1 region. You have to remember that all of these area could be drilled very much the same way. So when he's taking a rig off and then going back and drilling a bunch of wells and bringing them on, I'm bringing on as much gas from one pad more than what we have throughput on the system right now. So while it's, I guess, a great thing to have all this gas coming at you, it's another thing to have to live with it and actually move it. I mean, it's -- Jim's right, the price is going to be a big driver here, and the volumes from this area are just going to be massive. Guys, feel free to stop me. Obviously, I just -- somebody pulls my string, and I start talking.
[indiscernible] are you're already into [indiscernible] vis-à-vis, the ones you talked about 35, 45 [indiscernible] that are up, down, same kind of toward a trajectory but the price you are getting [indiscernible] is going to takeaway [indiscernible].
Donald L. Kirkendall
Our prices have come down just a little bit due to Blue Racers being in the mix here in Ohio. Blue Racer, it's a combination of came into Dominion East Ohio and Williams. Jack Layfield did a pretty good job of getting into West Virginia early. He didn't do such a great job of getting pipe in the ground. They've had some issues. That being said, the same producers know them in Ohio that knew him in West Virginia. And because his reputation has preceded a little bit, they are almost desperate to do any kind of gathering deal. So they have driven us to have to match what they're doing, and they're the ones that are driving commodity only with an acreage dedication. Now what I suspect will happen, as we start to fill up this pipe, I don't -- I won't have to be quite so flexible on my pricing structure. I think it will go up. And when we're talking about volumes, one thing that we do for the company and Triad especially, my group and as well that the marketing for Triad's volumes, so we're kind of the eyes and ears for the marketplace. And Gary and Jim firmly subscribed now to the idea of buying firm transport on REX to move gas out of Clarington. There's so much gas that is pent up this area. If you don't have firm, you're just going to be a price taker. And we saw on Tennessee last year, I think somewhere in Zone 6, now they were taking prices in the $0.50, $0.60 for swing gas prices. Well, we're pushing to get firm takeaway, pushing Triad's gases far down out of the basin as possible, talking to the big marketing companies, NextEra, Tenaska, BP, talking to the LBCs about setting up the firm takeaway arrangements. I think it's the only way you're going to stay ahead in this game. Another piece of business that we have to finish up next year is our Ritchie lateral, Triad's got 25,000 acres fairly contiguous down here. We have built out to about right here. We have another 12, 13 acres to build. All permits are in place. So that will be a fairly easy build. This dotted line right through here happens to be through the Wayne National forest. So in addition to the core of engineers where we have to please on every creek crossing, we also have to now make Smokey the Bear happy that we're not going to hurt his little forest.
A little bit about weather. I just talked about and this basis slide is old. This is back in August. But we're looking at basis here for TETCO M3 and Dominion South Point versus some of the mid-continent pricing. These are all relative to Henry Hub. A couple of months ago, TETCO was minus 20, Mishkan [ph] was plus 20, so a $0.40 differential. 2 years ago, when we started looking at this area, Dominion South Point was plus 20, plus 25. This area is rapidly becoming the supplier area, and all we have to do is just turn around the entire pipeline structure in the United States. So we've got a number of option -- obstacles ahead of us. Cut of the flow is just on a very simplistic map, dry Utica coming north, wet Marcellus north and south, wet Marcellus out through the MarkWest plant, wet gas out through Natrium, wet Utica up through Blue Racer and MarkWest Seneca. We're talking to Blue Racer about picking up the first Farley well. They tell us it'll take them 8 or 10 weeks to get that well hooked up. They have to push under the interstate to get it done. We will build a line coming up to Blue Racer and Seneca, and we're planning on a 20-inch system here. Assuming that the farming works out as planned, we should start on that as soon as we get our right-of-way taken through this area. This particular area, there is a coal company ahead of us, and they're not real anxious to work with us on a pipeline standpoint. So we're having to reroute a little bit.
You can see most of the gas is going north and east. I really wish we had good takeaway back down to about southwest so I could pull gas back this way, since that's where the drilling for Triad especially seems to be concentrating, where Texas Eastern is back over here. It's a 24-inch system. It's not a great system to get into. And the ethane is going to be a certain consideration with the wet gas. So we have to knock the ethane out before TETCO goes in and take it.
Again, just how we're accessing various markets, Mid-Continent, Northeast, going back to the Northeast, backhauling into TICO. Again, you can see a big void that I have over here that I'd like to fill, if we had interstate pipeline capacity.
The other thing that I do in my spare time, we have an amine treating unit. It's called TransTex Hunter. We build anywhere from 10 to 250 GPM amine units for renewal of hydrogen sulfide and CO2. We have some small refrigeration plants for small processing of heavies. We're expanding our Hallettsville shop right now. We've got about 35 units out. We have, I guess, 4 units under construction right now. And the little business is really doing pretty well. We're bringing our net revenue up. We just signed a lease the other day. We're in negotiations right now with an offshore player in the Gulf of Mexico. They won a 400 GPM unit, and that will be about $4 million to build that. That will go out on a 3- or 4-year lease.
And for those of you who are just dying to know what an amine treating looks like, that's what they look like. They're BSTs and BROs, big shiny things and big round objects.
I'm sure you guys got other questions about midstream. I know Gary does, and we're going to have pipe ready down.
[indiscernible]. Thanks, guys.
Okay. On the Alpha Hunter drilling side, we'll go through and show you our updated inventory here within Alpha. In 2010, when we took over Triad, obviously Alpha was inside the portfolio and had 3 Schramm T130 rigs, basically all shallow well. And then we started to use some of these T130s to run -- as a top hole rig, but quickly noticed that these rigs were not going to be large enough for the Marcellus and/or the Utica at that point.
So when we started to transition the 3 T130s into Schramm 200s, with that hook load capacity, we felt we could do the Marcellus, and we knew we could do the Marcellus at that point. And we're not quite sure at that point about the Utica.
So I'll show you the inventory. And I'll start a little backwards from what the slide has. The slide has the Four (5) Schramm TXD 200s, which are all under contract at this point. The 4, 5, 6 and 8, and that's just -- by the way, we took delivery of the rigs. Obviously, we took rigs 7, in between 6 and 8. So 4, 5, 6 and 8 are with the EQT. They're under contract through the remainder of 2013, and we just -- we have been awarded the contract for 2014 as well, the complete year, somewhere upwards of 300 wells or so that we're planning to drill the top holes for EQT in 2014.
Rig 9, which is our newest addition to the fleet, we took delivery in May -- I mean, in September, and we have started to drill with Eclipse, and then we're trying to work the contract out. It's through May of 2014, but there are some spotty scheduling issues in between in there. So we're trying to work that out with Triad to how to use this rig to go back and forth between Eclipse and Triad on top holes.
Rig 7, which you've seen a picture from Jim earlier. I will show you a couple more here in a little bit. Spud the first well on the Stalder Pad on July 1, 2013. It's got a 2-year contract with Triad, with a 1-year option, and I can't tell Jim, the swelling on the face, it does go down because I took quite a bit of beating over the first well, which was expected. We knew we were going to have some growing pains, and then we'll talk a little bit about those in a second.
Well, let's talk about them now. Why not? The first well, obviously, it had the bug bites. The main thing with the problems on the first well were control module issues. It was nothing really that the rig couldn't handle or anything like that, it was more -- I mean, this thing truly is a robotic rig. And getting the operators and the drillers, even though they had gone to schools and just to learn and understand the rig of -- there's no more field drilling out there, where you're out on the rig floor and you can actually feel what the rig is doing because you're sitting in a control room, basically like you're playing Nintendo. And that learning curve took a little while. And then the main thing was between Schramm on the rig modules themselves between the communication systems, between the pumps, the rig floor to the actual control module. And we've worked through those issues. We haven't seen any of those issues arise again. We had some smaller issues, again, on that -- it was like the well from hell. We also had a brand-new mud pump system. One of the engine skids had a complete failure. We had never seen anything like that on any of the other rigs that we had brought to the field, and we have that under warranty and is being repaired at this time as well.
So the second hole, obviously on the Stalder, has gone much, much better. We've had some small downtime issues with the top drive, a couple of things like that. But as where -- and our trip times continue to increase on the rig as well, as the drillers and the operators get more comfortable operating low-pipe handling systems.
The one thing that did help us on that, we knew we were buying a new technology rig. So we structured the contract as such to hold back a little over $1 million from the actual purchase price. And that helped us in the long run because we were able to use that as a negotiating tool with Schramm to offset some of our cost that in turn have to apply back to Triad for that first well.
So you can see here, from 2010, when we drilled somewhere around 50, 51 wells or so in 2010 and through 2013, so far, we're at 109, 110 wells. Right now, you see our annual average revenue growth of 222%. Basically, you can work through the math on that. The average day rate of all the rigs working at 320 days, about $84,000 a day. And then we typically use a conservative effort of like 320 or so for average run days. The other day rates are for downtime and things like that. So looking at about $26 million in revenue or so for 2013.
And you can see the year-by-year, the number of drills -- wells drilled based -- obviously, increasing some because of the increase in rigs, but also just increasing client base and expanding our contracts, as well. You see a total of 293 wells drilled so far since its inception when we took over in 2010.
And that's actually a picture of the new 500 on the Stalder Pad for the first well. And if you have any questions on the rig itself, I'll be happy to answer, or any of the rigs.
We have been in discussions somewhat with several of the other operators, now that we've gotten our run time back in place on the second well. Initially, nobody wanted to talk to us about it. But we have had operators come out in the last 2 weeks, even operators such as Chevron, EQT's been out, Eclipse has been out, several of the operators coming to look at the rig itself. Because of the main idea of driving the cost down, a typical triple rig that can drill these wells would normally take upwards of 90 to 100 loads to bring the complete rig package in. And on this particular package right here, we got the entire rig and all the auxilliary equipment in on 54 loads. So it's a huge cost savings to the operator on initial mob and de-mob and then also skidding times to bring -- tear the rig down and rig back up and move from -- on the pad drillings.
Gary C. Evans
Just to kind of refresh everybody's memory. We're not in the drilling rig business. When we bought Triad in February 2010, we inherited 3 drilling rigs. They were kind of old, junkie Schramm rigs. We've gotten rid of those 3 rigs, and all these rigs you see on this table that Kirk has provided are brand-new rigs. And Appalachia is a little different more than the other parts of the country because of its terrain and because of all the wells that we have in this area. We felt like keeping this division going made sense. And it's definitely turned into, not only an income producer for the company but a savings for the upstream company and provides tremendous flexibility. It is an asset, though, that is earmarked for sale at some point in time. So it's not unlike a lot of E&P companies who build up an early rig divisions that would -- will sell them. And that is something that -- it's not an immediate plan but it's something down the road. So -- but we feel like, with the business we've got-- Triad is a very small piece of the business. Most of our business is EQT, I guess, as all the rigs leased out.
Okay. So Kip, whenever you find that new job, stay in this spot. Joe?
Joseph C. Daches
Thanks, Gary. So this is the moment you've all been waiting for, right? The accounting update.
So as Gary had mentioned a little bit earlier, I've been here just a little over -- about 100 days, and the focus has been on reporting. We've -- I'm pretty confident we have eliminated the issues associated with our IM9 or 10-K, and we are marching forward.
And I did that by focusing on compliance, governance and controls this quarter and people in the organization. And the compliance piece, quite frankly, is pretty easy for me. We zeroed in with a series of work streams that focused on the MWs listed. And for those of you who don't know what an MW is it's material weakness. Those MWs looks good for the year end, quite frankly. And I like the way the group has progressed. We've hired some very specific key technical accounting positions and key SEC reporting and operational accounting people to really beef up the accounting department. And that the good news is, is we filed the June Q on time and the better news is we're going to file the September Q a little bit early. And we're going to just keep on trekking down that path. It's exactly what I think everybody in this room should expect, and that's exactly what we're going to deliver. We're going to deliver financial statements that have integrity, do not have issues and there will not be any future problems.
Next slide, and sticking with the theme here that we're releasing earnings on Friday, and I'm going to be very brief. I want to discuss here from the financial statements perspective is in 2013, we discussed the 3 big areas of capital spending, credit ratios and our hedging program. And our 2013 CapEx budget is about $300 million. And I think we're on track for that, as we reported previously, and we'll continue on that path. The credit ratio side is pretty obvious. We have $265 million approximately of availability in our borrowing base. We've raised quite a bit of capital last year, and we're going to continue doing what we need to do to ensure the capital programs of the company, in accordance with our operating cash flows from the business itself.
The hedging program, which is -- we'll talk about here more in the next page -- capitalization page. So this is pretty straightforward. You can see year-over-year progression. The big takeaway on this for me, when I look at this, is noticing the drop in the revolver, which is specific to the Eagle Ford transaction that happened in April 2013. You see it going from $325 million in March down to 0 in June.
This is an adjusted EBITDAX reconciliation. And again, this information is going to be updated with our press earnings release on Friday. But there's a nice progression year-over-year from $5 million to $4 million to $50 million to $168 million.
And this is our hedging program. So I think this is -- we're pretty happy about our hedging program. 2014 hedges look strong. We target about 50% of our production, and we have about just less than 5,000 of crude oil hedged in 2014 and about 20 million of natural gas. So back to you, Gary.
Gary C. Evans
Okay. We're going to quick summary and we'll take a little break. And then Jim is going to lay out a bunch of maps and show you a lot of his geological work as it relates to the Utica, which I know many of you are interested in hearing.
So in summary -- we -- can you hit the clicker? We've put together here -- these are the new wells that are coming online between now and 12/31. And I think a lot of the Street is concerned about our ability to jump from 15,000, 16,000 barrels a day to 25,000 barrels a day. So this is only North Dakota, and we've shown you here every single well. And Glenn, everything is on target here?
R. Glenn Dawson
[indiscernible] that every single pad is [indiscernible]. So it's a good time for it.
Gary C. Evans
So here is a net add of 2,000 barrels a day, and we're producing over 5,000 today. And this is everything over in Jim's division, in West Virginia and Ohio, and we're adding another 10,000 barrels a day. So, so far, we're on target of all this, pending no weather issues. As Jim mentioned, the frac-ing going on schedule, and we're now tying these wells in. So just in Appalachia and the Bakken well, we're adding additional 12,000 barrels a day, which gets us easily to the 25,000 number.
So we've also put together the net asset value if any company changes over time. And as more transactions occur up in the Marcellus and Utica and even the Bakken, you get to change these. We think we've been pretty conservative here. But it does reflect what we believe breakup value of the company is today. So changed dramatically as we started developing the Utica over the next 12 months. So still trading under our low-case basis, where the shares are today, around 7 40.
So I think we've emphasized our ability to focus on where we think the value of Magnum Hunter lies. We are moving forward on all fronts on these areas. As you know, earlier in the year, we talked about possibly selling Eureka Hunter pipeline. I went back to the board about 60 days ago and told them I thought that was a bad decision at this point in time, mainly because the Utica was growing so fast and just like the pipeline was so essential to Jim, as you were drilling Marcellus wells, the same thing exists across the river in the Utica. So -- and then you've heard Don talk about the kind of growth we're seeing, not only from our own production but third-party production being added on, and it just made no sense whatsoever. So that's why we kicked into high gear to sell all the other noncore assets in Canada, now Kentucky. So we've accomplished that void that we thought we would gain in liquidity from selling the Eureka Hunter Pipeline by selling other noncore assets, so keeping that in the portfolio at this time.
So with that, let's take a quick break and -- say, 10 minutes. It's in 10 until 3. We'll have Jim lay out all his maps and answer your specific questions about our acreage position in Washington, Monroe and Noble counties and why we're excited about where we lie in developing that acreage, okay?
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