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American Eagle Energy Corporation (NYSEMKT:AMZG)

Q2 2014 Earnings Conference Call

August 4, 2014, 08:00 AM ET

Executives

Marty Beskow - Vice President of Capital Markets and Strategy

Brad Colby - President and Chief Executive Officer

Tom Lantz - Chief Operating Officer

Analysts

Welles Fitzpatrick - Johnson Rice

Irene Haas - Wunderlich Securities

Jeff Grampp - Northland Capital Markets

Ryan Oatman - SunTrust

Joel Musante - Euro Pacific Capital

Gail Nicholson - KLR Group

Ipsit Mohanty - GMP Securities

Operator

Greetings and welcome to American Eagle Energy Corporation's Second Quarter 2014 Financial and Operational Results Conference Call. At this time, all the participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. (Operator Instructions) As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Marty Beskow, Vice President of Capital Markets and Strategy. Thank you. You may begin.

Marty Beskow

Good morning. This is Marty Beskow, Vice President of Capital Markets and Strategy. Welcome to the American Eagle Energy second quarter 2014 earnings conference call. This morning we issued a press release announcing our financial and operational results for the quarter ended June 30, 2014. Our Form 10-Q was filed this morning. On the call with me today is Brad Colby, President and CEO; and Tom Lantz, our Chief Operating Officer.

Please be advised that some of our remarks including answers to your questions may include comments that could be considered forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings release and during this call. Those risks included among others matters that have been described in our earnings release as well as in our filings with the Securities and Exchange Commission, including the Annual Report on Form 10-K and our quarterly reports on Form-10Q. We disclaim any obligation to update these forward-looking statements.

During this conference call, we'll also be making references to certain non-GAAP financial measures including adjusted EBITDA, adjusted cash flow and adjusted income. Reconciliations of these amounts to GAAP financial measures can be found in our earnings release.

I'll now turn the call over to Brad.

Brad Colby

Thanks, Marty. Good morning. We'll begin this morning with some general comments and then we'll open the call up for questions. During the second quarter of 2014, we brought eight gross, four net operated wells on to production, six Three Forks wells and two Middle Bakken wells across our acreage that included infill wells in Eastern and Central Spyglass and a step-out well in Western Spyglass. Some of the best wells that we brought on to production during the quarter were in the Central and Western portion of our Spyglass acreage.

The Ella well, our Three Forks completion and farm-out well financed with our JV partner, produced at an average of 343 BOEs per day during the first 30 days of production. It's located 2 miles Southwest of the Bryce, another strong Three Forks well, and 4 miles Southeast of the Haugen well. The good initial oil rates from the Ella confirm a significant expansion of the productive Three Forks reservoir to the South and West of the current producing area. The Murielle well, also a Three Forks infill well located in the Central portion of Spyglass, producer an average of 389 BOEs per day during its first 20 days of production. It's in the same drill site spacing unit as the Stanley well, also completed in the Three Forks formation, which produced approximately 77,000 barrels of oil equivalent for its first year of operation.

The strong production performance we've seen on wells in the Central portion of Spyglass gives us confidence in our well development schedule that focuses on drilling wells with higher working interest in this area. We've recently completed drilling four wells on a single pad. The four wells were drilled in 62 days including rig moves. The last well on the pad drilled in 9.5 days from spud-to-TD, a new record for us. We anticipate starting completion on the four-well pad in August. We have an average 88% working interest on these wells and we believe that the four-well pad should add significant production and showcase our potential to realize significant cost savings relating to continual pad drilling and completion efforts.

During the second quarter of 2014, we produced an average of 2,006 BOEs per day, which generated $16.5 million of oil and gas sales and $9.6 million of EBITDA. We are currently producing approximately 2,200 to 2,300 BOEs per day. And as we complete more wells including the four-well pad, bringing those wells on to production, we expect production, cash flow and proved reserves to continue to grow significantly over the remainder of the year. We continue to remain confident that we'll exit 2014 with production that in excess of 3,000 BOEs per day. In fact, we believe that our daily production can surpass 3,000 barrels a day by the end of the third quarter. So the average for the quarter will be less than that due to the timing of when the four-well pad comes on to production. We're comfortable with the consistent consensus estimates for 2014 third quarter production volumes.

And with that, I'll turn the call back over to Marty, who will review the financial plans.

Marty Beskow

Thanks, Brad. We ended second quarter 2014 with approximately $22 million in cash, $108 million drawn on our Morgan Stanley credit facility and 30.4 million shares of common stock outstanding. We announced this morning that we plan to issue $175 million worth of notes. Proceeds received from the issuance of these notes will be used to fully repay the Morgan Stanley credit facility, fund well development and working capital. We have also carved out $60 million from resulting credit facility as part of this financing strategy. We believe we'll soon have access to approximately $235 million of capital at an anticipated blended rate that is below our current cost to capital and which provides us with a greater flexibility to grow our business.

Continued drilling efforts are allowing us to drill more wells with the same number of rates. We estimate that we'll drill approximately 28 gross, 18 net operated wells during 2014, spending approximately $113 million on development cost, with a budget of $2 million for participation in non-operated wells in Northwest Divide County. Our total well development budget for 2014 is approximately $115 million.

At our current pace of development and assuming we continue to utilize two rigs going forward, we anticipate drilling approximately 30 gross, 20 net operated wells during 2015 at a total cost of approximately $120 million.

At this time, I'd like to open the call for questions. I'll turn the discussion over to Jessie, our moderator.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question is coming from the line of Welles Fitzpatrick with Johnson Rice.

Welles Fitzpatrick - Johnson Rice

A couple of questions. One, on the EURs, can you talk a little bit about the Braelynne spacing unit, that 800 acres, and whether or not those were included in the EURs, and also any effect that the inclement weather might have had on that number?

Tom Lantz

All those wells were included in the reserve evaluation. And so obviously the Braelynne, the core performance out of that well, and (inaudible) dampen the results on there. As far as the question about the weather, I think you did see that effect. When you looked at some of the monthly numbers during the first half of the year, you saw that the numbers kind of got dragged down and they had to acknowledge that in their evaluation. I think realistically at the same time, they acknowledged that there is a possibility that as the year goes on, looking forward the reserves could come back up and stuff. But at that point in time, it did influence the tight curve derivation. And that's what as much as anything contributed to that reduction and sort of the tight curve numbers from around 450,000 BOE down to about 400,000 BOE.

Welles Fitzpatrick - Johnson Rice

Okay. So then the long lateral Three Forks and the core wells, are those still kind of hitting at or above that previous number?

Tom Lantz

Yes, they are. The core and net have had some history to them. The reserves on those didn't change very much at all.

Welles Fitzpatrick - Johnson Rice

And then obviously an offsetting operator has gotten pretty excited about more intense frac access and they're putting away something like 2.7 million pounds. If I remember correctly, you guys were testing something, I think, even up to 3 million of pounds of propane. Can you update us on the timing of that?

Tom Lantz

As far as the bigger fracs, the SM guys and stuff, they're kind of offsetting to the East. They are moving their frac sizes from about 2 million pounds. Again, these are all sort of, say, 9,500 to 10,000 foot laterals and stuff. So from about 2 million pounds up to like, say, 2.6 million pounds or 2.7 million pounds, which works out to be about 260 pounds per foot. Our jobs have historically been around about 240 pounds per foot. And so we're kind of in sort of that same ballpark as where they're going to now. We have tested one, as you mentioned. That was about 3 million pounds, and we're just getting that cleaned up and put on to production right now. So we don't have any meaningful results to give you at this point in time on that, but would expect to get some results out of that.

And going forward, I think we'll continue to do that and we'll tweak both the sizes and then the other thing that we'll end up doing is we're going to be continuing to work a little bit on how we pump the drums right now is sort of a combination of slickwater and cross-linked gels. We're going to pump some that are going to be an increasing amount of slickwater jobs. And in fact, we're pumping in right now that's going to be a complete slickwater frac job and stuff. That's called the Eli well. That's one we're pumping at present there.

The other sort of tweak, if you will, is going to a higher percentage of smaller sized province, which is the other aspect, I think, that people have paid as much attention to some of the things at SMs were doing and some of the other operators are doing also, but they're going to slightly smaller-sized province and some of their devices.

Welles Fitzpatrick - Johnson Rice

I think that they have gone to the commission, looking to do five wells per space in unit base, putting one along the lease line. Is that something you guys have looked into and might pursue?

Brad Colby

Yeah, we're watching what they're going to do. And we're certainly paying close attention. We'll watch a couple of those get drilled and see how they do. But we do think that is a likely possibility to further increase the density. And in those well, Tom rightly noted that in those wells where there a few of those wells will be a non-op and we certainly would elect to participate in those wells with them.

Operator: Our next question is coming from the line of Steve Berman with Canaccord Genuity.

Steve Berman - Canaccord Genuity

Pad drilling, can you talk about potential savings there per well, and maybe even before that talk a little bit about well cost on the second quarter wells and hopefully what kind of savings again you hope to see from pad drilling? And also, going forward how you see the balance between wells drilled on pads and wells drilled to hold acreage?

Tom Lantz

Well, as far as the pad drilling, the impact on cost, we had mentioned that in the remarks here earlier. About the drilling time on those, if you look at what the actual cost just to drill and case the four wells, it looked like they averaged about $2.6 million, which is about roughly $250,000 per well that we saved just in that base of it. Then you would layer on to that some additional pad or location cost, which would amount to about another $100,000 a well.

Going forward as far the completion goes, we would expect to see sort of similar type savings just because of the savings in rigging up one-time with fracs and the clean-up equipment, everything that goes with it. So we're thinking it's probably sort of a 10% to 15% savings that kind of grew from that sort of drilling.

Steve Berman - Canaccord Genuity

The mix just going forward between wells drilled on pads and wells drilled to hold acreage maybe using Marty's 30 wells in 2015 as an example?

Tom Lantz

The mix going forward on that's probably going to be about two-third, one-third type setup, two-thirds being on pads. And it may not be like a full four-well pad, but they're maybe sort of two and three-well pads. So some of those will be sort of a mixture of drilling into some new spacing units and then also some infill drilling. So that'll be a little bit of mix and match in there. But it's probably about two-thirds on pad drilling and about a third would spread and throughout the rest of the area developing some new spacing units.

Steve Berman - Canaccord Genuity

Brad, there's been a lot of M&A activity up there. You had Crescent Point and CanEra, SM and Baytex, Magnum Hunter formally put their Divide County stuff up for sale. Just your general thoughts on that and how you see that maybe changing how you operate with these others. You mentioned briefly you might do some more with SM. But just your overall thoughts on what's going on up there.

Brad Colby

We've talked a lot in the past about Divide County maybe wasn't on the beat and pass as much as some of the deeper parts of the basin. I think that's changed pretty clearly based on what we've seen Crescent Point and SM recently do. I'd tell you that we looked at the Baytex acquisition award. We bid aggressively. We would have loved to have been the buyer of that. Our bid frankly had some contingencies and I think that kept us from being successful. Part of the announcements that we talked about are that you've seen in terms of the offering that we just announced this morning is to try to strengthen the balance sheet and create more liquidity, so that we can take advantage of some of those other opportunities that are out there.

We like Divide. We continue to like where we are, a bunch I'll go back and just kind of speak to the cost issue. We started to talk about in the last couple of quarters. We'll continue to do that. Tom said it's $2.6 million really on the pad to drill in case all in completion numbers for all those wells another $3 million. So you're back to that $5.6 million number. In the Ryder Scott report, it's still $6.4 million. All the competitors are talking about $6.4 million or $6.5 million. And we think the real driver for us is to continue to push drilling and completion cost down and be able to do that on a consistent basis. And the returns in Divide County not to oversimplify, but those returns we think stack up as well as any other part of the basin if we can deliver on those numbers.

So long way around, we like to see the M&A activity up there. We think there's more opportunities and we'd love to participate in some of those if we can figure out a way to do that.

Steve Berman - Canaccord Genuity

Is Crescent Point still participating as a non-operator?

Brad Colby

There was a hiatus, Steve, where they didn't for a while. That changed about three months ago, and they are now electing to participate consistently on our operated wells.

Operator

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

Irene Haas - Wunderlich Securities

A little bit about the wells for 2015, there are 30 gross wells. I didn't catch how many net wells. But generally, can you tell me what the split will be between Central Western and Eastern? And then secondarily, when are you going to be drilling the next step-out well in the West of the Spyglass area? And also with the timing of the debt deal, do you think you will get this all racked up?

Marty Beskow

Just to answer your question quickly, the 30 gross wells is roughly 20 net wells. So that'd be an estimated cost of about $120 million per year for our operated wells.

Brad Colby

Irene, as far as the next step-out well, we're drilling a well right now that's offsetting the Ella well to the East. Actually it's spacing entered into some of these. It's called the [Skiremo]. But in the next well that we've drilled after that is going to be a Northwest offset. So it'll be about halfway in between the Bryce well and the Haugen well. And so that'll move that test out that direction. So that's the next point and it'll be probably spud in about sort of two to three weeks, somewhere in that timeframe.

Irene Haas - Wunderlich Securities

What's the name?

Brad Colby

It's called the Donald.

Irene Haas - Wunderlich Securities

Next year's well growth, what's the split between Central East and Western?

Tom Lantz

We don't have those things kind of well defined.

Brad Colby

It's probably 60%, I'd say, Central.

Tom Lantz

That's probably a reasonable one. 60% Central, 20% and 20% East and West.

Brad Colby

I might say 60% Central, maybe even 30% West and 10% on the Eastern block.

Operator

Our next question comes from the line of Jeff Grampp with Northland Capital Markets.

Jeff Grampp - Northland Capital Markets

Just wanted to get your thoughts on what the enhanced liquidity position you guys seem to be getting here, just kind of thoughts on maybe any potential drilling acceleration with maybe adding a third rig, if only intermittently, and then just any thoughts on if you guys may look to ramp back up your leasing program?

Brad Colby

Irene, I think, said what's the timing of the debt deal wrapping up the bond deal. Marty?

Marty Beskow

Just kind of figured it'd probably be in a couple of weeks.

Brad Colby

Jeff, we'll go through probably the end of the year run and one of the things we'll pay a lot more attention to as well, I think, most of the operators out there is the winter drilling in particular winter completion. And a short answer to your question is we'll look at accelerated drilling after we get past probably the first quarter of 2015 and just see how we're doing and see how our wells are performing, see how the markets are performing.

Jeff Grampp - Northland Capital Markets

I know you guys have talked off and on about some different kind of infrastructure projects to drive down LOE a bit. I know there're obviously some kind of one-off issues in second quarter. But just kind of hoping to get timing update on different projects you guys may be looking at to drive down LOE going forward.

Brad Colby

There's I guess a couple of aspects. So one is certainly the water disposal costs that are associated with it. We have been increasing the amount of produced water that's going through pipelines, hence cutting down on the amount of trucking that's going on. We've been doing that sort of on an ongoing basis over the last couple of months especially and have increased sort of our throughput by pipeline, we're probably up to where we're running 40% of our produced water through that. Going forward, that's going to be another kind of big effort to get some of that since some of the wells in our Central portion of the development tied into that.

Going into 2015, we would anticipate probably around the middle of the year that we'll be developing another disposal facility in that portion of the field, if you will. Again, that's something that I think we may have talked about previously. That's a couple of million dollar type infrastructure investment.

On the other side of the equation with the gas, our JV partner on that continuing to build that out. They estimate that they're going to have the full gas line that's going to be tied into the Hess Tioga plant operational in the fourth quarter of this year and so increase our gas sales and what not. They're also building out the infrastructure, the gas gathering portion of it, start tying in our wells. The Bryce, Ella wells, those wells to be better out into the Western portion of it. And they expect to get those tied in here before the winter comes. So we'll be continuing to build on that aspect of it also.

Tom Lantz

Jeff, we've also talked to a couple of groups about oil pipelines. We don't have anything definitive, but that is something that sooner rather than later we'd like to bring an oil pipeline into the area. The other thing we're talking about and we'll look pretty seriously about is adding additional tankage on each location as we go back into the winter again. We think that can help us keep production on more steadily and be less impacted. Hopefully they decreased the impact of road closures as we go into the 2014/2015 winter.

Jeff Grampp - Northland Capital Markets

Just hoping to get an update on the La Plata State and Shelly wells, have you guys had a chance to get back in those and any addition color on the status of those two wells?

Brad Colby

On the Shelly well, what we've done is we had went out there and pulled the pump on that. We mentioned I think previously that we had some plugging type effects in the production, fell off on those things on the Shelly well. I don't want to get too technical. What we found is the pump was full of gunk and whatnot. Actually that's being analyzed right now to try to make sure we get a good handle on what really is in there and stuff.

Basically we've got out rig brand and new pump, and it's been producing over the last week with some pretty decent rates over about the last week total fluids and whatnot. The oil has been up around 200 barrels a day and whatnot. So we'll see how that goes. That was kind of our first step we wanted to analyze that stuff that we found in the pump. And then we'll make a plan going forward if we're going to go back and do any kind of further remedial work on the well bore itself. And so we finished that work on the Shelly and basically have just moved over to the La Plata. There's the same work over there. And I don't have anything really to report on the La Plata well yet.

Operator

Our next question is coming from the line of Ryan Oatman with SunTrust.

Ryan Oatman - SunTrust

Just wanted to get a couple of points of clarity on the road closures that impacted 2Q, are those behind the company and should we expect production from some of those wells affected to be bouncing back in the near term?

Brad Colby

I think the weather has finally cooperated out there and stuff. Things have come and gotten into a normal pattern now. So yes, the road closures are behind us and whatnot, and the wells have been back, producing pretty steadily for the last few weeks to a month or so. So I think that's sort of the good news aspect of it. And I wouldn't anticipate that we'll see any kind of real impact here for a while now.

Tom Lantz

And I think the numbers that we counted up, I think it was like 14 or 15 days for the second quarter that really where they were partial or full road closures in Divide County. I think you probably know this, but every day is more like a day-and-a-half or even two days in terms of production impacts. It was a tough quarter for us and I think for some others as well just because of that. And we're hopeful that that is in the rearview mirror and looking forward to seeing our wells restabilize and get back on the curves. And certainly for the month of July, that's a true statement.

Ryan Oatman - SunTrust

Great. And we've mentioned kind of the M&A going along around your position there. Can you speak to any data sharing that you guys have with the new or the current operators in that area and kind of how that's informing your decision-making for drilling these wells moving forward?

Tom Lantz

Just for clarity, if the question is in terms of completion, design, if that's the question you're really asking right?

Ryan Oatman - SunTrust

Right. I'm just asking if there's any sort of data sharing with your neighbors and kind of how that's improves drilling completion for you guys moving forward.

Tom Lantz

The data sharing is really good. We're participants as a non-operator with our peer group out there. And so you see it that way. But most of the operators in the area are good too, just about talking. Richard Pershall, our Operations Manager, has a good relationship with the SM guys and with the Baytex guys. We talked a lot to the Baytex engineers here recently just about what they're doing. And we talk pretty consistently with SM. We've talked some with Crescent Point. It's not like it used to be 25 years ago when no one would share any data. I think there is really a pretty open honest level of communication, so that we're all working towards designing the best jobs.

Brad Colby

It's less of any kind of a formal data sharing. Arrangement is that it's just an informal sort of between peers, if you will, that kind of sharing and understanding what's going on and what's going to change as people are looking at it.

Ryan Oatman - SunTrust

And can you speak to the service providers that you guys use up there and any changes that we should expect moving forward on that front?

Brad Colby

As far as on the drilling side of things, two main banks, the drilling side of banks, where we use neighbors. We don't have any pressure on that side with the rigs that we're using. I think that that's kind of reflects the increased drilling efficiencies that you're seeing in the basin itself where you're getting more wells per rig drilled. So I think that that's kind of fairly stable environment. The other sort of main thrust is on the stimulation of frac crews. And for the most part, we've been using Halliburton. And we've also used a couple of other operators up there. There could be some upward pressure on the pricing side of things and a little bit on the availability. I think it's a little bit up in the air, just because I think they're going to be, they meaning the service companies, are trying to figure out how they're going to service not just the Williston area, but everything else that's going on too. And so there may be some jockeying around of the crews and that's where the thing that could impact us a little, but that's still up in the air at this point in time.

Ryan Oatman - SunTrust

Did I hear you correctly that the 3,000 barrel a day guidance if things go right that that could be hit by the end of the third quarter as opposed to the end of the fourth quarter?

Tom Lantz

Yeah, that's a possibility, even just kind of inter-quarter. It'll be based quite heavily on when that four-well pad, when all four of those wells are coming on to production. So kind of the timing of that.

Operator

The next question is coming from the line of Joel Musante with Euro Pacific Capital.

Joel Musante - Euro Pacific Capital

I just had a question on the Middle Bakken wells and the reserve report. Were there any adjustments for the Middle Bakken reserves or EURs?

Brad Colby

Joel, on the Middle Bakken, it was sort of a mixed bag. We mentioned earlier the Braelynne well and a couple of the other ones or short-lateral wells, those were adjusted downwards by roughly about 10% or so. The other longer-laterals and more so influenced by the results of the Taylor well and a couple of those basically remained fairly stable. They didn't really change the reserve forecast on a lot of those for either the tight curve of the individual wells and stuff. So we had a couple of wells where there were some pretty good long-lateral Bakken reserves. And then we had those other ones that were poor. So that's why I say it's kind of a mixed bag there.

Joel Musante - Euro Pacific Capital

And if I understood it right, when you were answering wells question, most of the reserve changes were because of the issues with our road closures that affected production rates and then the rest of reserves were based off of the lower production rate?

Brad Colby

It's basically honoring the lower rates over sort of the first six months of the year. We saw some decline there. And we're updating some of that and then more importantly averaging a lot of that into the overall tight curve impact. On the one hand, they acknowledged that it was affected by operational. On the other hand, they were somewhat obligated to acknowledge those reductions and stuff and factored into their calculations.

Joel Musante - Euro Pacific Capital

Just looking forward into 2015, what's the mix between Three Forks wells and Middle Bakken wells going forward?

Brad Colby

It will probably be sort of 75% to 80% on the Three Forks and then we'll continue to do work on the Middle Bakken section and stuff. And we'll just be more selective with the Middle Bakken for the near term anyway.

Operator

Our next question is coming from the line of Gail Nicholson with KLR Group.

Gail Nicholson - KLR Group

Looking at the Eli well you guys mentioned, that being an all slickwater well, can you talk about any cost difference on the completion during a pure slickwater versus the standard combo completion now?

Tom Lantz

The cost difference on that one, it'll probably be about roughly 25% higher on the completion, just on the frac job itself. And a lot of that, as much as anything, is just the nature of slickwater, the higher horsepower requirements and whatnot. But the other part is we're using (inaudible) services and stuff, oilfield services on that. And so their cost structure is a little bit higher and stuff. But I would think that's probably a reasonable estimate. So that would be $150,000 higher cost structure for that slickwater.

Gail Nicholson - KLR Group

And then what percent of your gas is currently being flared?

Tom Lantz

Right now, probably about 20% is being flared right now.

Operator

Our next question is coming from the line of Ipsit Mohanty with GMP Securities.

Ipsit Mohanty - GMP Securities

A quick question on your TL-positive, very confident on your exit rates and kind of meeting it probably in the third quarter. But if you could talk about what else gives you confidence behind the exit rate apart from the high working interest?

Brad Colby

The average for July or the last couple of weeks is about almost 2,300 BOEs a day. We've had a couple of days that were closer to 2,450 BOEs a day. If that's in the pad is about 3.5 net wells out of those four wells and if you just sort of grind through the math, if those wells performed over the near term like the Ella or the Taylor well or the Bryce well, which we anticipate they'll do, then you could add 700 to 900 net BOEs per day to the company just from that pad. And then we've got the Eli that should come on. And so that's how we get to those numbers.

Ipsit Mohanty - GMP Securities

Was the high working interest continuing to 15 as well?

Marty Beskow

Yeah, generally on our Central acreage and kind of that area that we're developing right now, we do tend to have a little bit higher working interest.

Brad Colby

We talked about it in the first quarter. It was the closing of the final tranche two of the acquisition and then also that land deal that we did where we did $6 million or $7 million worth of acreage with (inaudible) that we brought from them that really solidified our working interest in that Central portion of the Spyglass project.

Marty Beskow

End of March, it was about $11.3 million on additional acreage that really got us some higher working interest in the area that we're developing right now.

Ipsit Mohanty - GMP Securities

Throughout the quarters, we've seen variance in well results in the 20 days of production of size. Just wondering geologically what's the different between Murielle and Richard? In other words, how well do you know your acreage by now as you look into the rest of the year and stare into '15?

Brad Colby

In terms of our geologic understanding and expected well results from the East to the Western edge, I think certainly on the Eastern side, we have the geology pretty well understood. There's enough well control. We've been drilling there for 2.5 years. So I think we're on pretty solid footing. The Central portion, which we call the Murielle, Stanley, Eli, Taylor spacing unit into the Bryce then on to the Ella, we've recently completed a well called the James out in that area, certainly getting a much better handle there. And that's pretty well understood. And then we talked at the end of the first quarter of course a lot about the Haugen well on the Western edge. We're still working our way over to that in terms of understanding that. The Murielle is in the Central portion. We really expected that well to come on good. That's a Three Forks offset to the Stanley well. The Stanley has been a solid performance.

Tom Lantz

On the Richard well, I think we reported sort of the early production on that one, if I remember about, about 190 barrels of oil a day or something like that. And what it has done here recently is continued to sort of increase sort of slight inclined in production and has been kind of moving up to producing a little bit more into our barrels a day here in the recent week or so. So it's continued to clean up and produce a little bit better. It's got a high fluid level and stuff. So I see some fairly flat production out of that well for a bit and whatnot. It's not terribly surprising.

We've seen a similar type behavior in that spacing unit particularly with the Myrtle well and stuff. The Myrtle is a Bakken well and this is a Three Forks well, but it is similar type character where it kind of increased over the course of a couple of months and then stabilized. We've seen this kind of character before. As Brad mentioned on the Murielle, the early time performance is very similar to the Stanley and to the Bryce wells that are out in that same area. I think we're seeing kind of a consistency in that particular there around the Ella, Bryce and Stanley and James as far as the early production goes and looks very encouraging at this point in time.

Operator

Ladies and gentlemen, we have reached the end of our question-and-answer session. I would now like to turn the floor back over to Mr. Beskow for any additional concluding comments.

Marty Beskow

I'd like to thank everybody for joining us on the call and thank you for your interest in American Eagle Energy.

Operator

Thank you. Ladies and gentlemen, this does conclude today's teleconference. We thank you for your participation and you may disconnect your lines at this time.

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Source: American Eagle Energy's (AMZG) CEO Brad Colby on Q2 2014 Results - Earnings Call Transcript

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