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Resolute Energy (NYSE:REN)

Q1 2013 Earnings Call

May 06, 2013 4:30 pm ET

Executives

Michael N. Stefanoudakis - Senior Vice President, General Counsel and Secretary

Nicholas J. Sutton - Chairman and Chief Executive Officer

Theodore Gazulis - Chief Financial Officer and Executive Vice President

Analysts

Jeffrey W. Robertson - Barclays Capital, Research Division

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Operator

Good afternoon, and welcome to the Resolute Energy First Quarter 2013 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Michael Stefanoudakis, General Counsel.

Michael N. Stefanoudakis

Good afternoon, everyone. My name is Michael Stefanoudakis. As the operator mentioned, I'm the Senior Vice President and General Counsel of Resolute. And before beginning the conference call, I'd like to read the forward-looking statement.

This investor conference call includes forward-looking statements within the meaning of the Safe Harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Words such as expect, estimate, project, budget, forecast, anticipate, intend, plan, may, will, could, should, poised, believes, predicts, potential, continue and similar expressions are intended to identify such forward-looking statements.

Forward-looking statements in this conference call include matters that involve known and unknown risks, uncertainties and other factors that may cause actual results, levels of activity, performance or achievements to differ materially from results expressed or implied by this investor conference call. Please refer to our SEC documents for a full listing of risk factors. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this call.

At this time, I'd like to turn the call over to Nick Sutton, our Chairman and CEO.

Nicholas J. Sutton

Thank you, Michael. Good afternoon, everyone. Thank you for being on the call with us today. This morning, we issued a comprehensive press release covering the first quarter of this year. As a result, I don't intend to get into a lot of detail on this call. Rather, I will simply cover some highlights and then turn the call over to Ted Gazulis for a financial review.

During the first quarter, average net production was 11,633 BOE per day. That's 39% higher than the same quarter last year. As you know, towards the end of the quarter, we acquired the remaining 68% working interest in and operatorship of our Gardendale project area in the Midland Basin. On a pro forma basis, that would add an additional 1,923 BOE per day of first quarter production, resulting in pro forma net production of 13,556 BOE per day, or 62% higher than the same quarter last year.

As might be expected, January and February were difficult months weather-wise. Nonetheless, our oil production was in line with our expectations. Gas production was somewhat below expectation, primarily because of the pipeline issue in the Aneth Field that was described in our release. I'd point out, however, that 92% of our revenues were oil-related. So the impact of the reduction in gas production was somewhat de minimis in the big picture, and at any rate, we expect that to be a temporary situation.

Aneth Field production continues to increase. A quick read of our net Aneth Field production numbers would show an immaterial 1% increase over the net production in the prior year quarter, but we must keep in mind the divestiture of a portion of our interests to Navajo Nation Oil and Gas Company in early January.

On a gross basis, Aneth Field oil production increased by about 8%, showing success in our ongoing CO2 flood project, our focus on compressor run times and various field activities undertaken to further enhance production.

As a result of our drilling program on our acquisitions in the Permian Basin, production from that area increased over 800% from the prior year period, and production from there amounted to 27% of our quarterly production on a BOE basis, reducing Aneth's contribution to 52%. Of course, the Permian percentage will increase when we can fully reflect the March Gardendale acquisition in our financials.

Production from our other areas, Hilight Field and the Powder River Basin, and Bakken production in North Dakota, accounted for only about 21% of our production, 13% and 8%, respectively. Bakken production was slightly below our expectation, as the fields on numerous wells go down primarily due to weather conditions. Alcon operates those properties, so we expect them to address the situation with vigor. On the other hand, our Wyoming properties performed above expectation.

So all in all, we were pleased with production, particularly in the most difficult time of year, operationally speaking. Let me again emphasize that our oil production, which dominates our revenue stream, was on target. We previously guided to a full year production increase of 50% over last year. We are reaffirming our 2013 full-year target of 13,000 to 15,000 BOE per day.

On the negative side, we were not immune from certain issues described by many, many other operators over recent weeks, notably the temporary but impactful widening in the Permian Basin differential and NGL prices that were weaker than the historic norm. Fortunately, the basis issue has corrected itself, but we do expect NGL prices to languish for a while.

Our increase in unit lease operating expense could raise an eyebrow, but I would like to explain. Virtually the entirety of the increased LOE was in Aneth Field. There, our field managers use their professional judgment to allocate crews and equipment to field activities. Some of these field activities are maintenance, and therefore expensed as an LOE, and some are capital in nature and therefore go against the capital budget.

On the capital side, the managers have a list of approved projects, but the timing of those projects can depend on permits, surface clearance, proximity to other activities and so forth. It just so happens that, this quarter, the dollars were relatively more weighted to expense work than to capital work.

From a cigar box cash accounting standpoint, it makes no difference. But from a GAAP standpoint, it does, as you see in this quarter's LOE numbers. January and February were higher expense months and March was substantially lower. We currently expect that, over the course of the year, these numbers will mean revert to our expectations.

I'll turn the discussion to the fun stuff, the growth projects area by area. In Aneth Field, we are now injecting over 100 million cubic feet of purchased and recycled CO2 per day, and we continue to see production increases as a result. All 4 phases of the Aneth unit CO2 flood are under injection, and March gross oil production from the unit was 5,000 barrels of oil per day, the highest it's been in over 15 years, since November of 1997.

We continue to advance our DC IIC recompletion project in the McElmo Creek Unit, seeing good results, with all of the recompletions to date contributing an aggregate of about 930 BOE per day of incremental production. In addition, we have a list of production enhancement projects scheduled for this year, targeting unswept resources. These horizontal or high-angle wells, in both Aneth and Ratherford units using existing well bores, will help us add incremental production and reserves at low cost and with marginal risk.

In the Permian Basin, our Gardendale project area, we plan to run a 2-rig continuous drilling program to drill 20 vertical Wolfberry wells and 3 horizontal Wolfcamp wells. Both rigs are currently on location and drilling. We expect the first of the horizontal wells to kick off in late June or early July. We estimate our current acreage position holds a multi-year drilling inventory, consisting of 70 gross horizontal drilling locations and more than 400 gross vertical drilling sites.

We also have over 80 rig completion opportunities that are not categorized as proved. We believe that a significant potential upside exists from the multi-pay, multi-play nature of the area, which is prospective for horizontal development in Wolfcamp, the Cline and other formations.

As for our Reeves County position, located in the Delaware Basin portion of the Permian, to underscore our enthusiasm for the potential there, I need only to point you to the press releases and statements from certain other operators in the immediate vicinity of our acreage.

We also are looking forward to potentially exciting results from 2 projects in the Powder River Basin. Recall that in our Hilight Field, we have 45,000 acres, all held by production, hundreds of wellbores providing geologic data and a seismic survey covering most of the field. Nearby, other operators have been successfully drilling horizontally into the Turner formation, with the best well by one of those operators being immediately adjacent to our acreage. Our geologic interpretation supports analogous results on our acreage, and we look to drill our first horizontal test in mid-summer. If successful, our current work suggests that we could have more than 40 locations prospective for the Turner formation.

In addition, as you know, we have been studying the Mowry formation in the area. Overall, our testing to date has been economically successful, but the results have not been uniform on a well-by-well basis. We believe that, through our seismic work, we may have identified a geologic reason contributing to the success of the better wells. We intend to test the concept with 3 well recompletion programs starting this quarter.

If the results lend credence to our interpretation, we could have approximately 30 locations for horizontal -- for a horizontal Mowry program.

To summarize, we have a diverse portfolio of oil-prone assets, giving us the ability to direct capital projects having very attractive returns. I can assure you we will be very busy.

Now let me turn the call over to Ted to discuss our financial results in more detail.

Theodore Gazulis

Thank you, Nick. As Nick discussed, we were pleased with our first quarter results. They're in line with our guidance released early in April, production is on track to achieve our total year 2013 guidance and costs are trending the right way.

Production is growing in Aneth through the response to our CO2 flood. We have rigs running in the Permian Basin, and we're now operating the Gardendale assets after closing that acquisition at the end of March. Production drives cash flow, of course, and total company production for the first quarter of 2013 was 1,047 MBOE compared to 762 MBOE for the first quarter of 2012, a 37% increase over the same quarter last year.

Oil production, representing 92% of our revenue, is actually a little ahead of plan. I'd also note that, because of the late March closing of the Gardendale acquisition, the full effect of that incremental production will not be seen until the second quarter.

Turning the quarter, revenue excluding realized derivative settlements rose $78.9 million, 24% higher than the year-ago period. A substantial production increase has more than offset a decline in comparative period prices. During the quarter, average realized revenue per BOE, excluding realized derivative settlements, was $75.36, down from $83.33 a BOE in the same quarter last year. That price was for the short term increase in basis differential on our Permian Basin properties, which has since reverted to more normal levels.

Rising production levels led to increases in the aggregate operating expenses, as did some weather-related operational issues in January and February. Those operational issues have been addressed. For the first quarter of 2013, our aggregate lease operating expense was $25.2 million compared with $17.2 million in the same quarter last year. On a unit of production basis, we experienced a slight increase, from $22.54 a BOE in the first quarter of 2012 to $24.08 in the first quarter of 2013.

Total first quarter production taxes of $10.2 million were consistent with the first quarter of 2012 on an aggregate basis, but decreased on a per unit basis from $13.41 a BOE in 2012 to $9.76 a BOE in 2013. The tax rate decreased to 13% of revenue this quarter from 16% in the same quarter of last year. The per unit and percentage decreases primarily stem from lower ad valorem tax estimates in Aneth Field and increased production and revenue in areas with lower tax rates.

Our general and administrative expense was $8.6 million for the first quarter of 2013 or $8.18 a BOE. That represented a 20% increase on a per unit basis from the prior year quarter. The increase was largely due to the fact that we added staff in the first quarter, as we anticipated the additional workload required to manage our new properties and operations.

Our LOE was also affected by increased professional services costs associated with transactions, offset by increased overhead billings and capitalized time.

In the first quarter of 2013, we have $30.5 million of aggregate adjusted EBITDA, a non-GAAP measure, which was an increase of 26% over the prior year quarter. Higher total company production more than offset lower commodity prices and higher costs. On a unit of production basis, we generated adjusted EBITDA of $29.14 a BOE, an 8% decrease from the prior year period, in which Resolute generated $24.2 million in aggregate adjusted EBITDA with $31.79 a BOE. The per unit decline is primarily due to lower realized commodity prices.

Turning now to our capital program. We invested $40.4 million during the first quarter, largely in ongoing tertiary recovery projects in Aneth Field and drilling and completion activities in Texas and North Dakota. This amount does not reflect the $257 million used to acquire the additional oil and gas assets in the Permian Basin. That purchase was financed with borrowings under the company's revolving credit facility and proceeds from the sales of Navajo Nation Oil and Gas Company of assets in Aneth Field. You may recall that Navajo Nation Oil and Gas Company exercised an option to produce -- to purchase 10% of the company's interest in certain Aneth Field properties, for a total cash consideration of $100 million. That purchase occurred in 2 equal transfers of 5%, with one part closing in July of 2012 and the other in January of 2013.

At March 31, 2013, we had outstanding $400 million of our 8.5% senior notes due 2020, and had $390 million drawn on our credit facility that has a borrowing base that was recently redetermined at $485 million, and the context of the redetermination and the life of the facility was extended to 2018.

We said before that we're willing to use our balance sheet to make compelling acquisitions, and we believe that our recent Permian Basin purchases are just that. We believe that we can carry our current debt level without undue financial stress. I would note, however, that we've announced our intention to monetize our Williston Basin properties and use the proceeds to reduce debt.

Finally, as we do with every earnings release, we've posted some supplemental financial data on our website, resoluteenergy.com. You can always find our most current investor presentation on the site as well.

With that, I thank you all for listening. I'll turn the call back to the operator for Q&A. Laura?

Question-and-Answer Session

Operator

[Operator Instructions] And our first question is from Jeff Robertson of Barclays.

Jeffrey W. Robertson - Barclays Capital, Research Division

Nick, can you talk in a little bit more color in the Mowry? How long do you think it will take to evaluate these 3 recompletions before you can determine whether or not your concept is working?

Nicholas J. Sutton

We're going to kick them off in basically, let's call them, mid-summer. And what we're going to do -- they're not going to be done just one right on top of the other. And so we're going to stretch them out a little bit so we can evaluate the results of each one. I would not expect to see anything truly material in that regard until at least the end of the year. So that we've had time not only to do the work but to evaluate what kind of results we're getting and tie them back into the geologic data and the seismic data.

Jeffrey W. Robertson - Barclays Capital, Research Division

Can you say if you're trying different completion methods or you're trying to complete in different or -- in areas of the Mowry that are geologically different?

Nicholas J. Sutton

We are targeting areas of the Mowry that, hopefully, are geologically the same, testing one concept, but spread out over a couple of different or a few different geographical locations on our acreage. So again, it's one geologic concept, 3 different tests in 3 different areas. And although, I would say that's the primary reason, of course, it's always natural to reevaluate frac success, completion attempts on an ongoing basis. But right now, it's not so much an attempt to try different fracs as much as it is to make sure that we get a spread over the acreage position, testing a common theme geologically.

Jeffrey W. Robertson - Barclays Capital, Research Division

Okay. And just a question on the LOEs at Aneth. Can you talk about what kind of production was added through that activity and whether or not that activity is more -- I think you said it just happened to fall more in the first quarter? But is that -- do you anticipate that LOEs out there will decrease over the course of the year?

Nicholas J. Sutton

I would say certainly as compared to January and February, we would expect them to decrease over the course of the year. We have an ongoing maintenance program, and we study the failure rate in wells and the root causes of failures. And sometimes we act reactively and sometimes we try to respond proactively. In January and February, of course, you get difficult weather conditions which affects wells. But you also get sort of a distribution of complexity on any activity that's done on a well. And sometimes, you can go out on a well and you can replace rods or tubing rather easily, and sometimes it gets more complicated. And I think we had a run, in January and February, of wells that were aggravated by just some difficult downhole locations. Over the course of the year, those tend to average out. And in addition, as I noted in my comments, the guys in the field are always evaluating how to put equipment and manpower to work in order to maximize production. And sometimes, that's fixing wells that are down, and sometimes, it's moving forward on capital projects. The fact of it is though, that the capital projects, while we've got a good list of them, there's -- we have to get permits, we have to clear the surface, we have to do a lot of things, and the scheduling depends on a lot of factors. And during Q1, the workover activity, let's put it, the allocation of manpower and equipment, was disproportionately allocated to LOE than we would normally see the case. And as I said, our expectation is that kind of mean reverts over the course of the year. So we look at January and February as an anomaly, March is right down right where it's supposed to be, and certainly considerably lower than January and February. And over the course of the year, particularly when we get into the more operating -- operationally benign months, we should see that LOE expense go down. So again, we don't see it as a systemic increase as much as it's, more or less, let's call it, a statistical anomaly, as we go through the year. If we had gotten those same number of wells that turned out to be a bit of a problem in the third quarter, you'd see it averaging out over the course of the year and it'd be less notable. But here in the first quarter, naturally, the thing is you can't do a year-to-date comparison and it just kind of stands out. But it is very explainable and it's, as I say, let me emphasize, we don't see it as any kind of systemic long-term increase in LOE.

Operator

And our next question is from Ron Mills of Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

You had a lot of acquisition activity over the course of the first part of this year. Can you just provide an update on how the integration of both the Selaro [ph] and RSP properties is moving along, now that you've had operations since early April, how the buildout of your team is, and what some of the -- what some of your early feedback or discoveries of information have been from the integration of those assets into Resolute?

Nicholas J. Sutton

Sure. First of all, let me emphasize that we've only been operating on the ground for approximately a month, a little over a month, and essentially in the case of the Gardendale in particular. But what we have found is what we would normally expect in an acquisition, and that is that in a transition of management, the attention level under us will be, I would say, more heightened. And I would say that our guys on the ground, we do have field operators on the ground and we do have, as you know, a very skilled and experienced staff in Midland to manage these properties. Those guys are already advancing ideas on how to improve production and identifying wells that, even if they're not down, they could be handled in a different way that we believe will enhance production. So again, really early stage. What we're seeing is what we would expect, and that is plenty of opportunity to apply a real focus on these properties and see some improvements or some growth in production on a well-by-well basis. So again, let me emphasize, I think it's what you would expect in this area. And we're happy to have our guys now in control and making decisions and really advancing the ideas and carrying forward with those ideas and putting them into effect.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And as it relates particularly to Gardendale, but even to Reeves County, in Gardendale, you'll drill 3 horizontal wells later this year. How much information you're able to apply from recent offset activity and also as it applies to Reeves County? I know you talked about potentially starting up in 2014. What are some of the key factors in terms of your decision point, in terms of moving forward with horizontal activity in Reeves?

Nicholas J. Sutton

Okay. First of all, as the Gardendale area, you correctly pointed out that there's a lot of activity around our properties. And the results that have been announced to date, which I know you and your colleagues track very carefully, are very, very encouraging in our estimation. And so we're looking forward to getting the first of these horizontal wells down in the Gardendale area. We are not going to go rig release on one side and immediately move over to the other. We're going to intersperse the 3 horizontal wells among some vertical wells, so that we can see what the results are from the first well before we move on to the second well and before we move on to the third well. So we're going at it, as you would expect, in a very rational and thoughtful way. But again, all of the activity around us is so darn encouraging, that we're excited about moving forward with Gardendale.

Now in terms of Reeves, frankly, we're excited about that area as well. We've pointed out another operator who has announced results on some wells that are immediately adjacent to our properties in Reeves County, or at least one set of our properties, our Mustang project area. And those results are very, very strong. The level of activity around us in Reeves is picking up by well-known operators, and again, we're seeing excellent results. We are in the process of trying to solidify and broaden our lease position. We have no lease pressures in Reeves County, so we see no reason to rush right into there while we're further building on our lease position and while a lot of our other operators are providing excellent data for us. So as we have said before, we would expect to get going in the Reeves County area in 2014 and continue with our focus on the Gardendale area this year.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay, good. And maybe, Ted, one for you. On the guidance, in April following the Permian acquisition, you put out new guidance. I know, January and February were challenging from a production standpoint, weather and whatnot. It sounds like though, you're reaffirming kind of your 2013 outlook. Is that a fair characterization? And can you quantify what some of that downtime, whether it's the pipeline and the weather that sounds like was spread across your basins, what impact that had on your first quarter production?

Theodore Gazulis

Sure. I mean, let's start with the guidance. Obviously, we put out guidance on April 5, and at that point, we had a pretty good sense of what had happened in January and February, and frankly, had a pretty good sense of what had happened, at least, qualitatively, and to a lesser extent, quantitatively through March. So the guidance that we issued on the 5th incorporated our thoughts and the reflections on what we had seen in the first quarter. So that being the case, we're very comfortable with what we said on the 5th and would have no reason to change it. I think the important point for -- and we issue annual guidance because that's the right horizon for us to look at. Nick mentioned the fact that the guys who are on the ground and run the fields have the discretion to use their professional judgment in how we utilize, for example, workover rigs. And if you do more workover activities and less capital-related activities in a given period, you'll see more LOE and less capital and vice versa. So as you look across the entire year, we think things are pretty comfortable. We think we will certainly reaffirm the guidance that we put out there. I'd also note that again, we don't -- we didn't see production looking dramatically different from what our plan was. Our oil production was flat to actually a little bit up from our plan. Our gas production was marginally affected. So it's hard -- I don't want to try to quantify barrel by barrel, area by area. But in aggregate, we feel like the quarter worked out very much, particularly with regard to production, very much where we thought it would, and as a result, we think the year looks like it's shaping up quite well.

Nicholas J. Sutton

I would only add the following, and that, as you mentioned, Ron, the gas. And just to quantify that a little bit more, the gas revenue that we lost, so to speak, because of the pipeline issue, amounts to about $250,000 per month. So on a $71 million gross revenue basis, you can see it really is immaterial. We'd like to have that $250,000 a month, there's no doubt about it. But in the big picture of what we're doing, gas just isn't where we are. As you know, we're an oil producer, and as Ted said, our oil production was right on target. In fact, it was slightly above target.

Operator

And the next question comes from Jason Wangler of Wunderlich Securities.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Just one over in Aneth with the 10-well pairs at McElmo and then the Ratherford enhancement projects. Have you really started those yet, or were you kind of waiting for the weather to get to obviously be a little bit better operationally before you'd start that, and kind of maybe walk through the plan throughout the year there?

Nicholas J. Sutton

Yes, we have started on the DC IIC, and that will continue throughout the year. And on the enhancement projects, we have started those. There's no doubt that we've -- more or less, we're waiting for better weather and some surface clearance and things of that nature to really get going with an aggressive program. But it's not as if we were just standing back and waiting. We are underway, and we will expect those plans to accelerate as we go through the year.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Okay. And maybe for Ted. If -- I noticed you talked about receiving bids on the Williston, and assuming something would go through, was that basically just those funds looking to go toward paying down the credit facility, just to kind of unlock that liquidity?

Theodore Gazulis

That would be absolutely the thing we would do.

Operator

And our next question is from Ryan Oatman of SunTrust.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

In the Permian, you saw some nice production adds from recompletion activity. Is there a chance to pick up some of this low-hanging fruit on newly acquired acreage as well?

Nicholas J. Sutton

As I mentioned, we have in our inventory something like 80 recompletions and certainly, we could go forward, and they're relatively inexpensive, compared to horizontal wells in particular. So you can see that we will do that over the course of the year. But I would not say that it is the highest activity on our list of priorities. You're right, it's low-hanging fruit. In some cases, it depends on differential pressure, some things of that nature, that come into play, so when is the proper time to go in and recomplete certain wells. It's been an ongoing point of focus, but as you put it, it's low-hanging fruit, it's out there. We'll always pay attention to it, but right now our primary focus in the Permian is to drill the 20 planned vertical wells and the 3 horizontal wells, and then other things as the case may be.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then, what are you planning for this first horizontal well in terms of well cost, completion design, frac stages and whatnot?

Nicholas J. Sutton

I'm going to turn that call over to Doug Dietrich [ph], who's a lot closer to this. Doug, I don't know if you've got Mike Griffis on the phone with you, but you can give us your latest thoughts on that regard.

Unknown Executive

Sure. No, Nick, I do not have Mike Griffis, who's our drilling manager, on the phone. But we anticipate currently that, that first horizontal well will be about $7 million, be about a 4,500-foot lateral, covering the north, south direction of the section, which would probably equate to about a 15- to 20-stage completion in that horizontal.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Okay, great. And then just one more, if I may. With the Bakken output, production did decline a bit quarter-over-quarter. Is there a chance for a rebound from that 1Q level once wells are brought back up? And where do you think that production could go to?

Nicholas J. Sutton

Before I jump into that, I'd point out that Doug Dietrich [ph] , who you just heard from, is our Permian business unit manager, heads our Midland office. And as to the question in the Bakken, I'm going to turn that over to Preston [ph], who is our Northern Rockies business unit manager. Preston [ph] ?

Unknown Executive

I definitely expect a rebound in the second quarter as wells come online from weather downtime, as well as post-completion workovers. I would guess the range would be between 1,100 and 1,200 BOE per day, with some upside potential there.

Operator

And next, we have a question from Noel Parks of Ladenburg Thalmann.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Actually, just following up on that last question about the Bakken, the expected production rebound. Is there going to be any effect from spring breakup out there? I was sort of under the impression that, that was really the -- that didn't have much of an impact on second quarter in the region, but that it was kind of kicking in right now. I'm sorry, didn't have much impact on the first quarter, but was kicking in right now.

Nicholas J. Sutton

Okay. Once again, I'm going to turn that over to Preston [ph] . And the reason I do that is Preston [ph] lives these projects on a day-to-day, minute-to-minute basis, and he has the clearest and best most updated information on questions like this. So Preston [ph] ?

Unknown Executive

You hit it right on the head there. We will also see spring breakup issues. Even on our operated production, we have, as late as 2 weeks ago, lakes on some of the pads. Right now, I believe we have at least 4 wells waiting on the pump unit to be set, and that's all about spring breakup and trying to get a good pad to set that unit on.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Okay. I -- so far, not looking anywhere near as bad as you saw a couple of years ago though with flooding and so forth?

Unknown Executive

Correct. Not as bad as 2 years ago but still a, I'll call it, typical North Dakota spring. Last year was much, much easier.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Great. I wanted to head back to Aneth for a minute. With the DC IIC, where does the inventory of recompletion opportunities stand for that right now?

Nicholas J. Sutton

Our total count is about 50 producers and 50 injectors, and we're approaching 20 of them, plus or minus, that are done to date. And that will be producer injector payers. And I'd remind you, Noel, that what we're doing in the DC IIC is really vertical conformance and reinitiating waterflood that had been prematurely terminated. A lot of this work is in preparation for eventual CO2 flooding of this zone. So that's -- not only do we get great economics associated with the work we're doing now, but again, it's opening up zones that have been shut in for some time or opening them up for the first time in some cases, where they're exposed to waterflood and eventually it will be to CO2 flood.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Got it. And turn to the Delaware Basin for a minute. A couple of minutes ago, you talked about what the costs are going to look like out there. Roughly, what sort of volume improvements compared to a vertical would you need to see from horizontals for the economics to work there and lead you down the path of doing mostly horizontals? Thinking is it sort of like you need to see 3x what you get out of a vertical to make it worthwhile?

Nicholas J. Sutton

Let's put it this way. We're seeing in the mid-300s to low-400s, I would say, MBOE per vertical well. And in some cases, somewhat less than that perhaps on a well-by-well basis. The results that have been announced by another operator with which you're familiar, right off our acreage, they've come out with a statement saying they've got 900,000 BOEs per well. So I'd just call it a 3x multiple when you run your economics on that, and they're very stout economics on those wells.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Right, right. And actually, where are the costs standing right now in the verticals out there, the well costs?

Nicholas J. Sutton

Roughly, let's call it 2.5, maybe a little bit more than that.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Right. And I'm just trying to get a sense as far as the cost environment out there. Is that doing a little bit better than when you guys first got out there, or is that still -- or is that affected by inflation?

Nicholas J. Sutton

I should turn the most accurate current view over to Doug Dietrich [ph] . I would say, and I don't mean to prerun Doug on this, but what we're seeing is a more readily available service and supply. But that has not yet translated into a significant decrease. I think that we are more in a -- running toward a deflationary environment rather than an inflationary environment. But Doug, I'd ask you to weigh in on that with your most current up-to-date view.

Unknown Executive

Yes, a couple of things there, Nick. We're seeing a lot of vertical rig availability here in the Permian Basin now, as a lot of operators are focusing on horizontals. So that has driven down the price of vertical drilling in the Permian, as well as frac costs. As early as the first part of 2012, we couldn't -- we'd have to wait maybe 2 months to 3 months just to get a frac date in some cases. Now we can usually find a frac date in 2 to 3 weeks. A lot of horsepower has come into the basin, which has driven those costs down as well. Out there in the Delaware Basin, we did spend quite a bit of time looking at the completion designs as we moved through the year. We were able to reduce the number of stages without really impacting the performance from those wells, which reduced the DC&E [ph] costs out there as well.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Great. And just one last thing. How's the labor cost component looking out there these days?

Unknown Executive

Yes, labor is still a tough market out here. It's a very busy area, as you guys know. We are having -- I feel like we've been pretty fortunate. We've got the staff in place now, we've got 26 full-time employees that call the Permian Basin home. As of about 18 months ago, we could just say that with 1 person who called Resolute home for the Permian. So we've done a lot of growing out here. We've increased the staff. But it is a challenging market to bring labor in, especially full-time employees, as well as the service industry.

Operator

[Operator Instructions] And our next question comes from Ron Mills of Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Nick, just a couple more details, or maybe it's for someone else. But on the Hilight Field and the planned activities, especially as you look at both the Turner and/or Mowry horizontals, when you drill that first well in the third quarter, what are you testing first? And I think in the prior press release, you talked about Turner/Niobrara or Muddy -- just can you provide a little bit more color as to what you saw on the verticals and why you're going horizontal?

Nicholas J. Sutton

Sure. First of all, we're going to be testing the Turner formation, and we do not have any vertical Turner wells. A lot of activity has been undertaken in and around our acreage or, let's call it, around it, not in our acreage, but certainly that includes immediately adjacent to our acreage. And so we've been monitoring those results very carefully. We also have been tying into as much geologic data as we can, with hundreds of wellbores through there. We do have a pretty good geologic picture. But I think the final thing that was brought to bear on the analysis was our seismic survey. And I think the most important thing to say is that the seismic doesn't point out that you will have a great Turner. What it certainly confirms is that there's no reason to believe that, geologically, there's something going on that will cause our results to be less than the results immediately offsetting our acreage. So again, it's not as if you have the old traditional deep gas, bright spot kind of analysis. But it's more a confirmation that there's nothing going on that's notable on our geologic database or our seismic interpretation to suggest that we should achieve anything less than the offsetting acreage. Now what we also find, when you mentioned the Niobrara, is the best Niobrara well, vertical Niobrara well in the basin, I believe, for really an extended area, is located on our acreage. And it's an older well, it's got good production history. And we track the Niobrara so that, we believe, that in the southwest portion of our acreage, we have an area where the Niobrara and the Turner both are present. And the question is whether you attack or approach those independently or whether there's a chance that you can really just drill into, say, the Turner and frac up in to the Niobrara, so that you get the combined effects of both formations. How that works out remains to be seen, but we do think that, geologically, we're in an advantageous position, where both of those formations are aligned and, as some of our guys call it, a twofer. So we'll just have to see how it goes and evaluate the results, but that's how the Niobrara comes into play.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And then on the Mowry, it sounds like if you do something there, that would be more of a 2014-type opportunity. And then you've been talking in the past about a more conventional play in the Minnelusa that has been successful in the area. What are your thoughts on the Minnelusa as well?

Nicholas J. Sutton

The Minnelusa is likely to slide over to 2014 just because of some lands considerations that all have to come together with permits and whatnot. And so we just think that's, more than likely, going to be a 2014 exercise. And 2013 on the Mowry, as we've said, we're targeting 3 Mowry recompletions to test this geologic concept. If after we evaluate the results of these wells, we think that there's reason to believe that it would support a horizontal program, we could start that arguably in 2014, certainly not in 2013. And as a practical matter, it would be one of these things where you ease your way in as you collect data, because we all know that once you start drilling horizontally, things get expensive very fast. So we're fortunate that we can test this concept by recompleting in existing wellbores. If the data look encouraging, then we will move into evaluating the economics and the prospectivity of a horizontal drilling program. And we will probably, again, go on a measured pace, where we test the concept horizontally before we roll it out with, let's say, a manufacturing mode. But the neat thing is, is that if it does work out, we have 30 or more locations where we -- that do, right now, look like they support a horizontal concept in the Mowry, if the testing heads us in that direction.

Operator

And this concludes our question-and-answer session. At this time, I would like to turn the conference back over to Nick Sutton for any closing remarks.

Nicholas J. Sutton

Thank you, Laura, and thank you, everyone, on the call. We know that this is a busy time of year for all of you, and we do appreciate your time and attention, both by signing on the call, by asking questions, and certainly by the ongoing relationship that we have with many of you on a day-to-day basis. So we appreciate your interest in our company and your support, and we'd encourage you to get back to us if you have any questions that occur to you after the call is completed. So again, thank you. Have a good evening.

Operator

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.

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