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Resolute Energy Corporation (NYSE:REN)

Q4 2013 Results Conference Call

March 10, 2014 4:30 PM ET

Executives

Jim Piccone – President

Nick Sutton – Chairman and CEO

Ted Gazulis – CFO

Analysts

Jason Wangler – Wunderlich Securities, Inc

John Freeman – Raymond James & Associates

Ron Mills – Johnson Rice

Noel Parks – Ladenburg Thalmann & Company Inc.

Richard Tullis – Capital One Southcoast, Inc.

Ryan Oatman – SunTrust Robinson Humphrey

Jeff Grampp – Northland Capital Markets

Operator

Good afternoon, and welcome to the Resolute Energy Corporation year-end and fourth quarter 2013 conference call. (Operator Instructions) Please note this event is being recorded. I would now like to turn the conference over to Jim Piccone, President. Please go ahead.

Jim Piccone

Good afternoon, everyone. My name is Jim Piccone and I am the President and former General Counsel of Resolute. I'd like to read the forward-looking statement before turning the call over to Nick Sutton, our Chairman and CEO.

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.

You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this investor conference call. A listing of the material risk factors faced by Resolute appears in our Form 10-K and is updated periodically in the Form 10-Qs and other public filings. At this time, I'd like to turn the call over to Nick Sutton, our Chairman and CEO. Nick?

Nick Sutton

Thank you, Jim. Good afternoon, and welcome to Resolute's fourth-quarter and year-end 2013 earnings conference call. I will assume that you have had an opportunity to read our press release [across] [ph] earlier this morning. So I will focus my comments on the primary drivers of our performance during last quarter and last year. Ted Gazulis will give you an overview of our financial performance and guidance, and then I will put some color on our direction going forward to 2014 before opening the call for Q&A.

There are three major themes driving our value creation here at Resolute. The first is our complete transition to horizontal drilling. The second is our continuing focus on oil prone activities, and the third is our ability to allocate capital across an attractive portfolio of crude oil assets.

Combined, these three factors create a foundation for strong cash flow generation, multi-year visible growth potential, and exciting upside. First, let's talk about production during the fourth quarter. Production averaged 12,709 Boe per day, a 10% sequential improvement from third quarter. Production was 26% higher than the same quarter last year.

For the full year, production averaged 12,239 Boe per day, 31% higher than last year. Substantially all of the production growth came from the Permian Basin, offset by small declines at Aneth, and the loss of almost 300 Boe per day from the sale of our New Home assets in the Bakken. Increasing our asset base in the Permian Basin, and increasing production volumes from our horizontal drilling program there, drove fourth-quarter production volumes from the Permian to a level that was 26% higher on a sequential basis, and 2013 Permian production was nearly 600% higher than last year.

During the fourth quarter, we finished our vertical well program on our Gardendale acreage in the Permian Basin, and now all of our new operated wells are being drilled as horizontals. In the Midland Basin portion of the Permian, our first three horizontal wells were drilled to the Wolfcamp B interval on our Gardendale acreage. In December, we announced preliminary results from the first two of those horizontal wells in the Permian Basin and also from our first well in the Powder River Basin.

The third Permian Basin horizontal, the Munn-Clark 2617H, was drilled to a lateral length of 4,550 feet, completed with 15 frac stages, and it came on with an additional 24-hour IP rate of 600 Boe per day. At the time, we thought that was pretty good. But Munn-Clark went on to produce at a peak rate of 877 Boe per day, and then settled into a 30-day average daily rate of 465 Boe; 94% of its production is crude oil.

Our other Gardendale wells are performing in a similar manner which helped increase Permian production in 2013 to an average of 3,950 Boe per day, a nearly six-fold increase over the previous year. And we estimate that EUR at the Gardendale acreage in the range of 350,000 to 400,000 Boe per well. Internal rates of return in those wells are expected to range between 25% and 45%. You can see the Gardendale horizontal wells are attractive investments.

After finishing the three wells in Gardendale, we moved the rig to Reeves County in the Delaware side of the Permian Basin. There we have spud three horizontal wells. One is in production, one is waiting on completion, and one is nearing TD.

Our primary current objective on our Delaware Basin acreage is to horizontally tap the Wolfcamp A and the Wolfcamp B intervals. The first of the wells, the LH Meeker, continues to flow and had a 24-hour peak IP of 1,403 Boe per day, and an initial 30-day IP that averaged 1,074 Boe per day based on three-stream method of calculation. Productions from the Wolfcamp A interval is approximately 48% crude oil.

We currently expect IRRs in this area to range between 20% and 40%, so they compete for capital very well. We estimate that we have 80 horizontal surface drilling locations in Permian Basin. Each of these locations should support multiple laterals, so the resource capture and the value added should be substantial. Added to this horizontal potential are approximately 135 lower-risk recompletion opportunities.

In sum, our total Permian Basin leasehold provides visible oil growth potential for many years to come. Of course, we are always looking to expand our operations in this area.

Let's move onto to our emerging, and I think very exciting, horizontal activity in our Hilight Field in the Powder River Basin. Last December, we reported that our first horizontal well in the Turner/Frontier formation, the Castle 3-21TH tested at a peak 24-hour production rate of 1,134 Boe per day with 90% of the volume being crude oil.

Time has been the Castle well's friend, as the well continues to be a strong producer. It had a 60-day average production rate of 763 Boe per day, which was actually 84 Boe per day higher than the well's 30-day IP rate of 679 Boe per day. In its first 90 days of production, the Castle well has produced an average of 723 Boe per day, in other words, a relatively flat profile over that period. Over that same 90-day period, the well produced approximately 65,000 Boe.

Let me see, 65,000 barrels times $100 per barrel equals $6.5 million. Okay, there are taxes and royalties, but you get the picture. We have estimated that internal rates of return for our horizontal Turner wells will range between 14% and 16%. No doubt the Castle well is very early stage, but based on this early production, we currently estimate the well's EUR at approximately 0.5 million Boe. The IRR is well over 100%, so we may have to rethink our estimates as to expected IRR ranges from the Turner wells.

Clearly, these wells are very attractive investment opportunities, so they will be strong competitors for capital. With up to 48 potential horizontal Turner/Frontier drilling locations currently identified, the Powder River Basin offers complementary visible growth potential to our core Permian assets.

The great news is that all of our 47,400 net acres in Hilight Field are held by production. The well economics are not burdened by acreage acquisition costs, we operate 100% of our leasehold, and, like the Permian, the geology at Hilight offers multiple pay zones and opportunities for additional oil development.

The second major theme at Resolute is our oil focus. Our horizontal drilling program in the Permian Basin is driving oil production higher, and we expect that horizontal Turner wells will become another growth engine.

Importantly, the Aneth Field, our legacy oil-producing asset, continues to deliver strong cash flow generation. Briefly turning our attention to Aneth Field, severe winter weather negatively impacted production and operations in the fourth quarter at this giant oil field. In addition, during the first nine months of 2013, natural gas sales were curtailed due to a third-party pipeline issue that has since been resolved except for periodic mechanical blips.

Permitting delays also served as a damper on production. But despite all of these factors, gross sequential production increased 5%. Due to the sale of a portion of our interest in the field to Navajo Nation Oil and Gas Company our net production was flat compared to last year.

And while we're on the subject of Aneth Field, let's discuss year-end proved reserves that were negatively impacted by the SEC's five-year rule on proved undeveloped properties. In short, the SEC does not permit companies to keep PUDs on the books for longer than five years. Although many of the fifth-year projects at Aneth are strong, economically viable investments, they just do not compete well for capital as compared to our horizontal drilling program, which is where we have allocated most of our capital investment.

Given the ranges of returns noted earlier, it just simply makes sense to allocate more capital to the horizontal drilling program. But since our activity in the Permian Powder River Basin are just getting started, the reserve additions in horizontal Wolfcamp and the Turner/Frontier formations did not grow fast enough in 2013 to offset the reduction in fifth-year PUDs at Aneth. Consequently, we realized a one-time non-cash impairment of $188 million associated primarily with unbooking the fifth-year projects at Aneth.

Approximately 25 million Boe at Aneth that was classified originally as proved undeveloped was reclassified into the probable and possible categories. I want to emphasize this impairment has nothing to do with the asset quality of Aneth. The oil resource is still in the ground and waiting to be recovered. It is simply that our growth assets in the Permian and Powder River Basins have captured a significant share of our investment capital.

The reclassified reserves can be placed back on the books at such time as they have capital firmly committed to their timely development. At year-end 2013, the pre-tax PV10 value of our proved reserves was $1.1 billion, or about 12% lower than year-end 2012. And importantly, 80% of our 59.4 million Boe of proved reserves are crude oil. Another 8% are natural gas liquids.

As we drill more horizontal wells and add to our producing property base, we expect the horizontal program to drive increasing production and values. At this time, I'll turn the call over to Ted Gazulis to discuss our financial results.

Ted Gazulis

Thank you, Nick. Good afternoon. As you've all seen this morning, we published our earnings release and filed our annual report on Form 10-K, and those items incorporate detailed discussion and analysis of our results. So, as with Nick's approach, and as with our last call, I will focus on the big picture items and discuss some of the key drivers of our financial performance.

Looking at year-end financial results, as Nick mentioned, the key operational metrics of production, revenue and adjusted EBITDA, a non-GAAP measure reconciled to net income, were up strongly both year-over-year and sequentially. However, the required implementation of the SEC five-year rule negatively affected our earnings. As Nick noted, the rule requires that undeveloped reserves be developed within five years from when they are first added to the proved reserve base. The rule makes no value judgment about the attractiveness of any particular project, but if those reserves have not been developed they must be removed from the proved category.

That was the case with several high-value projects at Aneth. While they have solid economics, they don't compete well for capital when compared to our horizontal drilling opportunities. Since we cannot say that the Aneth projects will be completed within the required regulatory timeframe mandated by the SEC, the reserves associated with the deferred projects were removed. That required us to write down the proved asset pool, and as a result, we recognized a $188 million non-cash impairment charge to earnings.

I want to reiterate that this impairment says nothing about the asset quality of Aneth. The oil is there, our ongoing projects continue to perform, the already identified opportunities remain, we believe that there will be many as yet unidentified projects to undertake, and the long-lived oil reserves will be producing from Aneth for many, many years.

But the reserves associated with the effective project had been, at least for now, reclassified as probable instead of proved. They can be returned to the proved property base once we can say with some certainty when we plan to implement them.

Perhaps our most important job as a management team is to allocate capital optimally across our asset base and opportunity-rich portfolio. Right now the returns on our growth assets in the Permian and Powder River Basins make a compelling case for a higher capital allocation.

Turning to some financial metrics, let's talk first about lease operating expense. Although year-over-year LOE rose on an absolute basis by 29%, on a per-unit basis they actually dropped 1% to $23.12 per Boe. We see the same pattern sequentially, as LOE in the fourth quarter rose by 9% over the third quarter, but fell by 2% on a per-unit basis to $23.37 per Boe, as rising volumes outpaced the rise in absolute cost.

Absolute cost increases were pushed higher primarily as the result of having more wells to operate, and adding to our staff to handle our increased current and expected future operations. As we look at our cash flow, in the fourth quarter, we generated $50.6 million of adjusted EBITDA, again, a non-GAAP measure, which was sequentially 33% higher than the third quarter and 59% higher than the year-ago quarter.

On a per-unit basis, adjusted EBITDA was $43.27 per Boe in the fourth quarter, which was sequentially 21% higher than the third quarter, and 26% higher than the prior-year quarter. Full-year adjusted EBITDA for 2013 was $160.4 million, 48% higher than the previous year. On a per-unit basis, full-year adjusted EBITDA in 2013 was $35.89 of Boe, 13% higher than the prior year.

The key financial takeaway for 2013 is that we grew production faster than costs as we focused capital on higher growth lower-cost areas. That combination generated more cash on both an absolute and per-unit basis.

Turning to our capital program, we invested approximately $237 million during 2013 in our ongoing tertiary recovery and drilling projects in Aneth Field, and drilling and completion projects in the Permian Basin, the Powder River Basin, and to a lesser extent, in the Bakken trend in North Dakota.

I need to make a correction to one number that was in today's press release. We made the comment that the reported field level capital expenditure excluded $290 million of net acquisition, divestiture, and other corporate capital. That number did not, in fact, incorporate the divestiture proceeds. Giving effect to divestitures, aggregate non-field level capital was $168 million rather than $290 million.

Capital expenditures were financed by operating cash flow, borrowings under the Company's revolving credit facility, cash on hand, proceeds from the sale of interest in Aneth Field to Navajo Nation Oil and Gas Company, proceeds from the sale of the New Home properties in North Dakota, and the issuance of equity securities.

At December 31, 2013, we had $335 million drawn on our revolving credit facility which matures in March of 2018. At the end of February, we had approximately $80 million of liquidity available from cash on hand and borrowing capacity. We anticipate that this liquidity, combined with projected cash flow from operations, is sufficient to fund our 2014 base capital plan.

As Nick mentioned earlier, we are actively looking at financing options that would allow us to significantly accelerate our horizontal drilling. If, and as such financing options come to fruition, we will adjust our capital budget and communicate the results to all of you.

Speaking of our 2014 capital plan, let me talk about guidance for the year. In 2014, we expect to invest between $136 million and $153 million for base development activities, which includes our horizontal drilling programs, supporting infrastructure, and other items. We expect to fund that base capital plan with cash flow generated from operations and existing liquidity. We do not plan to fund the program by incurring incremental debt.

Of course, we will evaluate our spending on a regular basis, and may adjust our activity up or down based on commodity prices, cost trends, well results, and other factors that affect cash flow. And on any given day, our revolver draw might be more or less than it is today. We expect full-year 2014 production to be between 4.5 million Boe and 4.9 million Boe. The midpoint of our guidance represents a 5% increase from full-year 2013 production of 4.47 million Boe.

We project 2014 LOE to range between $98 million and $113 million, and given the production increase, this should result in a small reduction in per-unit LOE this year as compared to 2013. G&A expense this year is expected to range between $25 million and $30 million excluding non-cash stock-based compensation.

We do anticipate that G&A will rise primarily because of the increased staffing needed to support our growing operations in the Permian Basin and elsewhere, as well as the full-year effect of personnel additions that occurred during the course of last year. Finally, we expect DD&A for the full-year to fall between $29 and $31 of Boe.

Thank you all for your time and your interest in Resolute. We hope to see many of you during the coming months, and at this point, Nick, I will turn it back to you.

Nick Sutton

Thanks, Ted. As a concluding comment, I would just like to say that the Resolute team has done an excellent job of setting the foundation for future growth in production and reserves. This captured acreage with excellent hydrocarbon-bearing geology and has built the skills and capabilities to conduct a horizontal drilling program that offers very robust returns.

Our current guidance represents what we expect from what we refer to as our 2014 base operating and financial plan. We believe that this represents the low range of potential.

As both Ted and I have mentioned, capital allocation is one of our most important jobs. As we look at the results of our horizontal activity thus far, we find that we have a multi-year visible growth potential from highly value-added projects. Given this abundance of opportunities across our portfolio, we are looking at ways to increase investment over and above our base development plan in order to accelerate our drilling activity, principally the horizontal drilling.

We currently are in the process of re-evaluating all of our assets from the ground up to assess their suitability for achieving our long-term plans. These alternatives include, but are not limited to, divesting non-core assets, the proceeds of which would be used to strengthen our balance sheet and accelerate our horizontal drilling program. This process is ongoing and has the full support of our Board and our management team. I think the potential outcomes are very exciting.

And I realize we've covered a lot of ground today, and with that, I thank you all for listening, and I'll turn the call back to the operator for Q&A. Operator?

Question- and-Answer Session

Operator

Thank you. (Operator Instructions) Our first question comes from Jason Wangler at Wunderlich Securities.

Jason Wangler – Wunderlich Securities, Inc

Good afternoon, guys.

Nick Sutton

Hi, Jason.

Jason Wangler – Wunderlich Securities, Inc

Curious, and you kind of referred to it there at the end, as you look through all of your assets, the capital program that you have now, where do you see the majority of the growth coming from for that 5%? Where do you see the Aneth levels of production? And also, just in the Powder River, how active would you be there with that spend?

Nick Sutton

In the base plan, we are going to keep production at Aneth relatively flat. We are going to continue to inject CO2, and we will, of course, have certain other activities that we are going to undertake there. But the majority of the capital will go to the horizontal drilling program. And under this base plan, we are going to drill approximately four wells in the Permian, and also we will be expending capital to complete the well that is waiting on completion now and to finish out the completion on the Harrison well, which is the one that is nearing TD.

In the Powder River Basin, we currently plan to drill two wells there. In the Permian, some of the wells we have 100% working interest in and others we have an average of 65% interest. So if you're doing your models, the four wells in the Permian are going to be in the Reeves County side. We have about a 65% working interest in those.

Jason Wangler – Wunderlich Securities, Inc

Okay. That's helpful. And then, Ted, just curious as far as with reserves, obviously, just the SEC stuff, but is there any effect that you would see on the borrowing base, and when is your next re-determination?

Ted Gazulis

We are in the middle of our re-determination right now. I expect that that will get wrapped up and finalized this week. I anticipate that we will have an increase in our borrowing base.

Frankly, most senior secured lenders are interested in your proved undeveloped reserves, but they don't really ascribe much value. They’re really looking at what's available over the course of the next several years, largely out of the PDP base. So there doesn't appear to be much effect on our borrowing base with regard to the write-down.

Jason Wangler – Wunderlich Securities, Inc

That's helpful. I will turn it back. Thank you, guys.

Nick Sutton

Thank you.

Operator

Our next question comes from John Freeman, Raymond James.

John Freeman – Raymond James & Associates

Good afternoon, guys.

Nick Sutton

Hey, John.

John Freeman – Raymond James & Associates

Following up on the Aneth production outlook, so when we've looked at Aneth in the past, both at the Analyst Day and then kind of recent presentations, we've always shown that that big increase in the gross oil production over the next three years to where some time in, call it, the end of 2016 you kind of eclipse like that 14,000-barrel-a-day gross level.

Should we think about that trajectory different in the context, I guess, of the way the capital allocation is proceeding and the commentary about Aneth looking to be flat this year?

Nick Sutton

Good question. Certainly, you are targeting at exactly the right thing with respect to Aneth, and that is that as we have chosen to allocate capital elsewhere, some of that growth that we had projected for Aneth will not take place on the timeframe that we might have expected a year, or two years, three years ago. And I'd emphasize that those projects are still viable projects, good strong projects, it just, as we look at the overall competition for capital, they don't rise to the top.

So one of the beautiful things about Aneth that we've also talked about regularly over the years is that it has a very low decline curve. We can maintain production by continuing to put CO2 in the ground and picking off a couple of the very high value, most attractive projects in Aneth. So our expectation would be that we would hold Aneth flat, certainly that's the way the base 2014 plan sets out. That could change as the year progresses.

In 2015 and 2016, I would say that's probably going to continue because I don't see anything dramatic happening that would cause Aneth to be able to capture a greater share of available capital. So in your models hold Aneth more or less flat and look at the results of the horizontal programs to be driving growth in the years to come for at least for the foreseeable future as we are planning right now.

John Freeman – Raymond James & Associates

Okay. And I'm not trying to jump the gun here with this next question, but if that is the case, and Aneth is more of a, maybe a flattish sort of production profile as opposed to maybe the pretty decent increase you were going to have previously, does that make you re-evaluate Aneth overall?

I think in the past, and I'm not trying to put words in anybody's mouth, but I think in the past, we talked about production sort of ramping up into 2016, 2017 and then you think about that asset as maybe an MLP candidate, divestiture candidate, things like that. Does it change the way you think about that field now?

Nick Sutton

I think that we have to look at things sort of in aggregate, rather than in isolation. And the reason I say that is that the production profile at Aneth could change with a greater availability of capital. So I wouldn't want anyone to think that Aneth is perpetually growth challenged. It is not.

It is right now challenged in its ability to compete for capital with certain other projects. That said, Aneth is, like every other asset in our portfolio, is subject to evaluation and an assessment of how it should best fit into the overall picture on a going forward basis. And really everything's on the table, no ideas are off the table.

And you're absolutely right, John, we've talked about MLPs in the past, and that's certainly one of the options that is out there for evaluation. And I'm not pre-judging the outcome by any means, but that's part of the evaluation that we're going through right now.

John Freeman – Raymond James & Associates

That's helpful, guys, I will turn it over to somebody else. Thanks a lot.

Operator

The next question comes from Ron Mills at Johnson Rice.

Ron Mills – Johnson Rice

Good afternoon, Nick.

Nick Sutton

Hey, Ron.

Ron Mills – Johnson Rice

One, just a clarification question. Did you say just a second ago that the plan on that – if you're going to spend $70 million to $77 million in the Permian that that's going to have four wells in the Permian? And were all of those in Reeves County, or are you also going to start or move the rig back and also do some stuff in Midland, just trying to reconcile the CapEx with the number of wells.

Nick Sutton

Certainly, from a new drill standpoint, yes, we are looking at four wells in Reeves County. We also are looking at completing the Meeker – or the James well. We've got to finish drilling and complete the Harrison well, and right now we don't anticipate the rig going back to the Midland Basin in the near term.

I'd also add that in addition to completing the wells that are in process in Reeves County and the new drills in Reeves County we've got infrastructure over there. We are in an area that does not have extensive infrastructure, and so some of the capital will go to building out that infrastructure to make sure that we get the wells on production as quickly as we possibly can.

Ron Mills – Johnson Rice

Okay. Great. And then, as it relates to the Hilight area and the Castle well results in particular, is there something from either a geologic standpoint or maybe from your engineering department standpoint in terms of– I think it is an area you had suggested didn't have much water production– what caused that 30-day rate to be above the IP rate, and the 60- or 90-day rate, I guess, to be fairly flat with the 30-day rate? Is there something going on from a rock standpoint? Or is that the profile you would've expected?

Nick Sutton

I never expected inclining production profile. So I cannot really say that it is one that I would've expected. I happily welcome it. We, frankly, are evaluating this well carefully.

I think that additional drilling will help provide more data that we can rely on to assess what is really going on in this well. It is certainly a stronger well than other wells that have been drilled, I say in the area somewhat it loosely in that they range in how far away from the Castle well they are. But this is definitely a very, very strong well. And we don't know exactly whether we've tapped into a fracture swarm, whether it is just better rock.

We have mentioned in the past, I remember at our Analyst Day we did, we talked about what we called the [two-fer] [ph] area where there is some indication that we might be able to get a contribution from the Niobrara depending on where the fracs go. So at this stage, we just don't have a whole lot– we don't have a lot of data to evaluate. We are watching the well carefully, working on it carefully, and we welcome the results that we've gotten so far.

Ron Mills – Johnson Rice

And since that, I think, is kind of the south or southern southwestern portion of your Hilight area is where you think you have the Turner/Frontier. If we– based on the data that you have from well control, are there any appreciable differences in terms of what you see from a rock standpoint from this Castle well and the couple wells you are going to drill this year? And are those located in this same area?

Nick Sutton

The couple wells that we're going to drill this year on the base plan are in the same general area, and there's some talk, leave it at that, so far that it may actually be in an area where the rocks could be better. As we look across the overall Hilight acreage position, we've said that we currently believe there are approximately 48 locations. As we move to the east and the northeast we believe we will lose sand quality, some degradation of production, but right now our focus is in that same general area as the Castle well, being set up partly by surface considerations and lease considerations, our ability to get on surface and have permits in hand.

Ron Mills – Johnson Rice

Okay, and then one last one in the Permian, is most of the activity going to be down in Reeves County near where you currently are, or will you do some stuff up around Appaloosa and are those– are those similar from a commodity mix standpoint, or is one area more oily or how does that lay out?

Nick Sutton

We are going to balance between what we refer to as Mustang and Appaloosa. I think we will see some difference as to gas versus oil. The suggestions are that as we go to the east away from Mustang to Appaloosa we will find– it should get oilier.

Ron Mills – Johnson Rice

Okay. And, Nick, one for you. The write-down of the reserves, that shouldn't have any impact on a borrowing base or anything like that, correct?

Nick Sutton

No, as Ted kind of mentioned, the banks really focus on the proved developed producing reserve category in determining borrowing base. There's some sort of nod to the proved undeveloped, but it doesn't materially factor into the borrowing base re-determination, and all of the reserves that were taken off the books were in the proved undeveloped category.

Ron Mills – Johnson Rice

Were they also longer dated, Nick, and was there and associated PV with those reserves that were taken off the books, or was it just really not a very significant number?

Nick Sutton

There certainly was some present value associated with them, but if you look at the change in the PV10s that we reported, it is not a substantial difference. It is not comparable to the write-down of reserves and that is associated just with the timing associated with those projects as they were on the books as proved undeveloped reserves.

Ron Mills – Johnson Rice

Okay, great. Hey, thank you, Nick.

Nick Sutton

Thanks, Ron.

Operator

The next question comes from Noel Parks at Ladenburg Thalmann.

Noel Parks – Ladenburg Thalmann & Company Inc.

Good afternoon.

Nick Sutton

Hi, Noel.

Noel Parks – Ladenburg Thalmann & Company Inc.

A couple things. When I think about the Delaware Basin activity going forward versus Midland Basin, what's the learning curve look like in the Delaware Basin as far as what sort of improvement you might have in efficiencies and so forth? Is there still a lot of experimentation to do, or do you think the model you have for drilling and completion is roughly set at this point?

Nick Sutton

I would say that we are on a good program right now. But we will be evaluating each and every well individually and in the aggregate to see where we might make some improvements as we move forward. I think where we will see efficiencies will be when we move into– I don't know whether we want to use the buzz word manufacturing mode or whatever you want to call it– and you start to look at pad drilling and start to look at the possibility of walking rigs and some of those things that will bring the drilling cost down.

I think we will see some efficiencies on that. I think that based on the Meeker well we're pretty happy with the completion we put on that well. But our engineers and our technical team certainly will be evaluating that on a going-forward basis. Can you save money there without degrading performance commensurately?

So right now I would say that as to between the Reeves County and the Midland Basin wells we are deeper and so the AFEs will be more expensive. The sort of headline numbers on Boes are larger, but we certainly do have more gas over in the Delaware portion of the Permian, so those things all come into play. But I think we will find our learning curve continue. It is an ongoing effort and everybody is focused on absolutely the right things.

Noel Parks – Ladenburg Thalmann & Company Inc.

I was struck by, as you pointed out, how at the moment, roughly similar the returns look between the Midland Basin and Delaware Basin. So I guess I was thinking from a land standpoint, I know it is not easy getting acreage anywhere really out there, but in the risk/reward, is it fair to say that decent acreage in Reeves County, even with the differences, probably looks more attractive price-wise than what you could find in Midland Basin? Even with the greater risk perhaps of execution?

Nick Sutton

I would say that as opposed to comparing basin to basin, I would say that there are more macro factors that are– that come in and out of play periodically. And I know that in the Delaware Basin in our area, we are surrounded by a lot of very large companies that have large acreage positions. It is sort of a question as to how much of that they are going to be able to get to in the lease term. And one of the things that we did in 2013, you might recall, Noel, is we were successful in picking up additional acreage in Reeves County.

And part of that was just by good old-fashioned top leasing, as our people were working the data and the ground pretty carefully to find opportunities along those lines. I think that we are going to see acreage, we're going to be through periods where it is really tight, really expensive, and we are going to find times where it is going to be a little bit more available.

One of the things that we like about the Permian Basin is it is very large and there are a broad range of players out there that go all the way from local mom and pops to the majors. And given its size, and given the variety of different participants, there is kind of a food chain that is always out there, and it ebbs and flows, but it is always out there. So we think that the Permian will be a place that we will be able to block up our acreage, and our responsibility to our shareholders is to exercise capital discipline and not overpay when things are frothy and be ready and be prepared to jump when things are more moderately priced.

Noel Parks – Ladenburg Thalmann & Company Inc.

Great. Is there a particular date horizon where there's a lot of acreage expiring out there near you in Reeves County this year or next year?

Nick Sutton

I would not say that there's like a bright line in the sand. It sort of– it extends, it depends on who took what down when, which is why it is a big effort for our land team to work that because if it were a bright line, it would be pretty clear. Since it is not, it is a matter of working the data very, very meticulously.

Noel Parks – Ladenburg Thalmann & Company Inc.

Fine. And just one last one for Ted. Would stock compensation expense over the course of 2014, do you have an idea of the seasonality of how the amounts might fluctuate? I noted that last year second quarter, I think, was the highest number, dollar number of stock compensation, and is that going to be similar this year, do you think?

Ted Gazulis

Yes, I think it has to do with the timing of our granting of performance shares and other kinds of things that happens early in the year. You will see it again in the second quarter. It won't be a huge spike, I don't think, it is fair to say, but it will peak in the second quarter and be lower than that in third and fourth.

Noel Parks – Ladenburg Thalmann & Company Inc.

Thanks. That's all I had.

Nick Sutton

Thank you, Noel.

Operator

Our next question comes from Richard Tullis at Capital One.

Richard Tullis – Capital One Southcoast, Inc.

Good afternoon, everyone. Just a couple questions that haven't been touched on yet. Nick, what was the cost of that first Delaware Basin horizontal well?

Nick Sutton

Would you repeat that question? It kind of faded out there.

Richard Tullis – Capital One Southcoast, Inc.

What was the cost of that first Delaware Basin horizontal well?

Nick Sutton

Approximately $8.9 million.

Richard Tullis – Capital One Southcoast, Inc.

What's the outlook for average well for 2014 in Delaware?

Nick Sutton

We're AFE-ing them at roughly $9 million, a little bit over $9 million, $9.1 million, $9.2 million, allowing for contingencies and what not.

Richard Tullis – Capital One Southcoast, Inc.

How long will those laterals be?

Nick Sutton

How long will they take?

Richard Tullis – Capital One Southcoast, Inc.

How long will the laterals?

Nick Sutton

Anywhere from 4,500 to 7,500 feet.

Richard Tullis – Capital One Southcoast, Inc.

Okay.

Nick Sutton

We do have some land that might allow for a 10,000-foot laterals, but that's not really our focus right now.

Richard Tullis – Capital One Southcoast, Inc.

Okay. The production growth trend for 2014, how do you see it quarter-to-quarter? Will it be rather steady?

Nick Sutton

Yes. I would say that under the base plan it is a little bit front-loaded. Because I think the activity under the base plan will taper off as the year concludes.

Richard Tullis – Capital One Southcoast, Inc.

Okay. Going back to the other financing options, what do you classify in the non-core assets at this point? It would be the gas assets in Powder River Basin, the Bakken, would you be looking to potentially monetize the Midland Basin acreage?

Nick Sutton

Not really the Midland Basin acreage. You've touched on a couple of them. We've been approached periodically about the legacy Muddy production in the Powder River which is fine with us as long as we get the ability to continue to drill the Turner and other formations.

The Bakken is pretty much divested at this point. To give you another example of a field that we think has got potential, but it is just not going to rise in the food chain for capital, and that's the Denton Field in southeast New Mexico. It has got good stable production, roughly 1,000 barrels a day. And right now we are not allocating any meaningful capital to that. So there are a number of them like that we can continue to work on.

Richard Tullis – Capital One Southcoast, Inc.

Okay. And then if you were to increase your CapEx budget, what would be the first area to get additional funding?

Nick Sutton

I don't think I could at this point say that it would be Reeves County over Midland Basin, or either one of those over the Turner play in the Powder River Basin. We are in the process of blocking up leases in all areas, or not leases but permits, and so we'd be in a position to move on all of those. Frankly, at some point, depending on other considerations, we've got some really, really nice projects in Aneth that could at that point compete for capital when the capital is less constrained.

The one thing I would say while we are on this whole thing about the capital availability and doing something that allows us to accelerate our activities. I would caution that people shouldn't assume that high on our list of alternatives is a capital markets transaction. Just take that for what it is worth.

Richard Tullis – Capital One Southcoast, Inc.

Okay, and then just lastly for me, Nick, what are the 2014 well cost assumptions for the Turner wells?

Nick Sutton

Turner wells are about $7 million to $7.2 million.

Richard Tullis – Capital One Southcoast, Inc.

Okay. All right, that's all for me. Thanks a bunch.

Nick Sutton

Thanks, Richard.

Operator

You're next question comes from Ryan Oatman at SunTrust.

Nick Sutton

Hey, Ryan.

Ryan Oatman – SunTrust Robinson Humphrey

Hi, good afternoon. A couple of quick ones for me here. Still working through the capital spending in the Permian Basin. Are there any verticals on the Midland Basin side planned?

Nick Sutton

We have a couple where we are not the operator and we have referred to historically as our Big Springs area, and we've got about three of them where we are less than a 50% working interest owner that are currently on board for vertical. They have nice rates of return. The wells around there produced nicely, and as important from our standpoint is that the vertical wells there, while being acceptable from an economic standpoint, will also help us hold that acreage as we see horizontal activity moving in that direction.

Ryan Oatman – SunTrust Robinson Humphrey

Got it, but no operated vertical activity over there?

Nick Sutton

Not in our plans right now.

Ryan Oatman – SunTrust Robinson Humphrey

Okay. And then, looking at Aneth, how much was capital spending there this year? 2013, that is, I apologize.

Nick Sutton

Hold on one second. Got accounting people looking at papers to answer that for you. With more specificity than I could arm wave at.

Ted Gazulis

We spent about $62.5 million in Aneth last year.

Ryan Oatman – SunTrust Robinson Humphrey

Okay. That's helpful. I guess, my question here is, although Aneth production's bounced back pretty nicely from 3Q levels, can you speak to your confidence in production holding at or around current levels in 2014 given the capital spending is only going to be about $35 million or so this year?

Nick Sutton

We are pretty confident that we're going to be able to hold production flat 2013 to 2014.

Ted Gazulis

Ryan, let me also point out, of that $62.5 million about $20 million was CO2. The point is that next year, this year, I guess, we are in 2014, we will continue to spend the full measure of CO2 and still have some more dollars available to do some of the smaller projects and to keep up on infrastructure which allows us to feel very comfortable that production stays very flat.

Ryan Oatman – SunTrust Robinson Humphrey

Okay. I got you. And then, obviously, in Reeves County, in past presentations you guys have talked about 50 locations there. I think you refer to this a little bit in your prepared comments, but just wanted to hash out that thought, is that still the right number, or if you had Wolfcamp A, B, D, if you had all these zones work for you could you see it being higher than that 50 location? And I will leave it at that. Thanks.

Nick Sutton

On a net basis versus a gross basis, in Reeves County we currently count 63 locations.

Ryan Oatman – SunTrust Robinson Humphrey

Perfect.

Nick Sutton

Then you could have anywhere from two to five benches in there. We think two are pretty darn solid these days, and there is activity going on at least three of the other benches. So if you apply the number of locations to a low and high on the number of benches, that's a low of 126 laterals to a high of 315 laterals based on our current acreage holdings in Reeves County.

Ryan Oatman – SunTrust Robinson Humphrey

Perfect. Thank you.

Operator

Next question comes from Jeff Grampp at Northland Capital Markets.

Jeff Grampp – Northland Capital Markets

Hi, guys. Thanks for taking my question. Most of mine have been answered, but just had one quick one on the leasing front. I know you've allocated, it looks like some capital to leasing in 2014.

Just curious where you think that's going to be allocated to, or if that's just kind of a discretionary number, or if you think there's– I would imagine it would probably be allocated towards Delaware if you guys think there's an ample amount of opportunities there to use that budget up in 2014?

Nick Sutton

It is a discretionary budget, and it allows our land folks and the folks on the ground to act opportunistically. I would personally say that it is more likely that we will see some of that in the Delaware Basin, but we are also seeing opportunities in the Midland Basin, as well. Our position in the Hilight Field is, of course, lock solid, 47,000-plus acres all HBP. But we also see some opportunities to expand our position up there targeting the Turner and perhaps, the Shannon and the Sussex and others.

Jeff Grampp – Northland Capital Markets

Got it. Okay, appreciate it. That's all it got.

Operator

Our next question comes from Jack Jones at [Iroquois] [ph]

Unidentified Analyst

Which assets would you consider monetizing as you are looking for ways to fund your West Texas development program?

Nick Sutton

If you put it that way, all of them but West Texas. (laughter) I don't mean to be flip about it, but as I said, in my comments, really everything is on the table in that we are very, very commercial people. We are here to make money for our shareholders, and if we see the best opportunity to move on is in, hypothetically, the Midland Basin, that's not off the table.

It wouldn't be our top priority, but really everything is on the table, and what we are focused on is what we internally refer to as the flywheel effect associated with drilling some of these wells that have just extremely strong rates of return. Put me in front of 48 Turner wells with 144% IRRs and everything else becomes less valuable. I'm not pre-judging, I'm just saying everything is on the table.

Unidentified Analyst

Would the CO2 assets in particular feature higher or lower on the scale of assets that might be sold?

Nick Sutton

I would say that the CO2 assets lend themselves to different kinds of structures and those are being evaluated. We are in an interesting position where we have these incredibly great assets, but they have different characteristics.

And just to draw on the Permian Basin broadly, generically, versus Southeast Utah. One is a very large doing 1.5 billion barrel oilfield that we think has got substantial long-term upside. But it is long term.

That's the nature of a CO2 project. It is longer term, as opposed to the high growth assets in the Permian and the Powder. I think there's some ways that we can structure around so that those assets are held in ways that are more valuable to our shareholders in aggregate.

Unidentified Analyst

Thanks a lot.

Nick Sutton

Sure.

Operator

(Operator Instructions)

Our next question comes from Ron Mills at Johnson Rice.

Ron Mills – Johnson Rice

Hey, Nick, one follow-up. I think you started to answer this a second ago. In your press release, you talk about 460 wells in the Permian and in Powder River Basins, of which, I guess, 48 we can think of as being in the PRB. How do you get to that 400-plus in the Permian, and is that doing the work and breaking it down by Wolfcamp A and B and the Spraberry, et cetera?

Nick Sutton

Yes, that's exactly what we are doing. If we look at it from a gross basis rather than net, what we see is– I'm going to go through this fairly quickly– 79 operated gross locations in Reeves, 87 non-operated for 166 total. If you apply two to five benches you come up with 332 to 830. Doing that on a net basis, same kind of math, you come up with a low of 126 and a high of 315 laterals. That's on 63 locations, some of which are operated, some of which are not operated. Most of them being operated.

In Gardendale, I'm just going to continue with net, we are looking at about 22 locations, all of which are operated. We are seeing two to six benches over there. So applying that math, you come up with 44 to 132 laterals.

And in the Turner, we've talked about 48, one of them is down, and another one has got some questions, so let's just call it 46, 47 to go. That comes up with the 216 to 493 actual laterals. That's on a net basis. On a gross basis, that's exposure to 426 to over 1,000 laterals on a gross basis.

So whether you look at it net or gross, I think that, obviously, the exposure to the science and everything is on a gross basis. It has got good exposure there. On a net basis, 493 laterals. Will it turn out to be 400 or 600, or who knows, but that's just on our existing acreage position.

I think the key takeaway is that on our existing acreage position, and with the number of laterals that are substantially de-risked by ourselves and by others, we are looking at 200 laterals. Call it $7 million per lateral and you can see that's a pretty big capital program that can keep us busy. And if we look at the high end of the number of laterals and this is not just picking numbers.

Is the lower Spraberry substantially de-risked or is it not, so does it fall into the left side of the equation or right side? Those are individual questions. Data is being developed on a daily basis, and let's assume that we are limited to the things that we have already identified as being potential, that is almost 500 laterals. Pick a number again, $7 million a lateral, $3.5 billion of CapEx.

Do we have runway in front of us? We've got a lot of runway in front of us because we do operate much to most of what we've got on our plates, and certainly, I think it is a combination of excellent well results by ourselves and by our industry colleagues in our respective areas of operations coupled with the acreage position we have relative to the size of the Company. You can just– you don't need a four-function calculator to do the math on that, so it is pretty exciting.

Ron Mills – Johnson Rice

Great. No, I appreciate the clarification. Thanks.

Nick Sutton

Thank you, Ron. Well, operator, I think if there are no other calls we can bring this meeting to a close. It is been an hour now, so I appreciate everyone's time. Everybody is very busy, and we thank you for joining with us on this call. We are here always to answer any follow-up questions as you go forward.

We are here to help you when you need clarity for building your own models and developing your own outlook here. Again, thank you for your ongoing interest in our Company, and we are here to help you do your job, as well. So thanks again.

Operator

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

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