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Resolute Energy (NYSE:REN)

Q2 2013 Earnings Call

August 05, 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

James A. Tuell - Chief Accounting Officer and Vice President

Analysts

John Freeman - Raymond James & Associates, Inc., Research Division

Phillip Jungwirth - BMO Capital Markets U.S.

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

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

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

John C. Nelson - Citigroup Inc, Research Division

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

James Spicer - Wells Fargo Securities, LLC, Research Division

Operator

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

Michael N. Stefanoudakis

Good afternoon, everyone. My name is Michael Stefanoudakis, I'm the Senior Vice President and 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 on this call. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this call. A listing of the material risk factors faced by Resolute appears in our Form 10-K and is updated periodically in our form 10-Qs and our other public filings.

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

Nicholas J. Sutton

Thank you, Michael, and thanks to all of you who have joined us on the call today. I'm going to provide a brief overview of recent results and then our operations updates. Then after that, Ted Gazulis will review our financial results and we then will take your questions.

In my opinion, the high points of the quarter are increased production, lower lease operate expenses, drilling our first horizontal well in the Midland Basin, ongoing enhancement activities in greater Aneth Field and preparation for our first Turner horizontal well in the Powder River Basin.

Total company production in the second quarter reached a record 13,107 BOE per day, which was 39% higher than the same quarter last year. Contributing to the production increase was incremental production associated with our Permian Basin acquisitions and our drilling program in the Permian.

At the beginning of the quarter, we acquired operations of our Gardendale properties and we commenced the 2 well -- 2-rig drilling program, drilling 10 wells, of which 4 were completed by the end of the quarter. The other 6 wells were at various stages of completion or flowback. Our plan for the year is to drill a total of 20 vertical and 3 horizontal wells on our Midland Basin acreage.

Production from the Aneth Field for the second quarter was 6,247 BOE per day, an increase of 210 BOE per day from the year-ago quarter and a decrease of 401 BOE per day from the first quarter of this year. The sequential decline reflects the sale of certain properties to the Navajo Nation Oil and Gas Company and the continued shut-in of the gas line, as previously reported in our first quarter earnings announcement.

An integrity test performed on that line raised questions about the pipe, such that the operator decides to take a pipe off-line, at least for the time being. In the meantime, we are working on an alternative, but at this time we can offer no assurance as to when we might be able to sell gas from the Aneth Field. Production from our Wyoming and North Dakota properties was in line with our expectations after we get effect to our sale of the New Home Bakken properties that was announced previously.

As you know, last quarter's lease operating expense was anomalously high, primarily due to workover expense in Aneth Field. This quarter, we achieved a reduction in lease operating expense with second quarter LOE at $21.45 per BOE, which represents a sequential decline of 11% from the first quarter.

Gross margin was 71.3% in the second quarter, as compared to 68% in the first quarter of the year, despite revenue per BOE being 1% lower. From an operational standpoint, to me, our highlight is the fact that our first Midland Basin horizontal well, the Midkiff 1818H, reached total depth on July 31. The liner has been set and the rig released to move on to our second horizontal well, the Pearl Jam 2417H, which is expected to spud later this week.

The Midkiff 1818H is scheduled for completion to start on August 26. I don't mean to let the horizontal program overshadow our vertical well program in the Midland Basin, but we intend to drill 20 wells this year. The drilling has proceeded on schedule. And after a slight delay, the completion activity has ahead of steam. The 6 wells were in various stages of completion at year end, along with the new drill should contribute nicely to third and fourth quarter production.

As we mentioned in our press release, a significant saltwater disposal well and depth field was down for about a month for casing repairs, impacting production from that area during the quarter. Up with the situation in the category of stuff happens, and note that the well is back online after some excellent work by our field staff.

Also, in the category of routine good work, our team made improvements in downhole pump designs and artificial lift operations. But so far, a period of improved uptime on legacy wells. These efforts enhance production and reduce operating costs.

In the Delaware Basin, in Reeves County, Texas, we are very encouraged by horizontal drilling activity in close proximity to our leasehold. Ongoing horizontal drilling in the area is derisking our acreage position and we have built gas gathering, water disposal and electrical infrastructure on our Mustang block to handle anticipated increased volumes when we are again drilling in this area. In the meantime, we are flowing back a couple of vertical wells, one of which is being completed one stage at a time in order to give us an opportunity to evaluate the prospectivity of specific intervals for horizontal drilling.

We also are continuing to add to our acreage position in the area, although for competitive reasons, we are holding the details tight. At Aneth Field, production enhancement projects continue to be the focus, including the continued CO2 injection into the Aneth Unit CO2 expansion. Normal completion of 2 sidetrack wells in the Aneth Unit, and deepening levels in that DC IIC zone in McElmo Creek Unit.

The 2 lateral sidetracks in Aneth Unit increase the injection rate fourfold. This has the benefits of increasing fluid flow through the reservoir, increasing reservoir pressure, thus hopefully improving oil recoveries.

The McElmo Unit, year-to-date, we completed 4 producer well deepenings and one injector on our DC IIC project. 15 additional wells, a mix of producers and injectors, are planned for the remainder of 2013, along with facility modifications that handle increased fluids associated with the project.

Our overall inventory at McElmo Creek, DC IIC wells is about 140 opportunities, counting both producers and injectors. And at the end of the year, we should have about 74 wells left in the queue.

In Ratherford Unit, the well laterals project, where the existing well bore will be drilled out in a specific direction targeting under-processed parts of the reservoir, are scheduled for third and fourth quarter implementation. The first lateral was drilled in July. And as many as 3 others are planned for the fourth quarter, after the rig finished its scheduled drilling activity in the Aneth Unit.

Lease operating expenses have improved in the Aneth Field in the second quarter and for the first 6 months of 2013. As I mentioned, LOE was higher than expected during the first quarter because of relatively high number of workover projects, which are expensed for accounting purposes.

In the second quarter, overall LOE was back in line, and we expect LOE cost to remain closer to budget for the remainder of 2013. In our Hilight Field in the Powder River Basin, we have cleared permits to drill our first horizontal Turner formation test. We expect the well to spud later this month or in the very early September, with completion expected to occur in the fourth quarter.

In addition, during the quarter, we completed 2 Muddy refracs with one more on the current schedule. Finally, we previously announced that we completed the sale of our New Home assets in Williams County, North Dakota for $75 million. No doubt you've already updated your models for the sale, but we thought it appropriate to provide you our views of the impact on our production associated with the sale of New Home plus the ongoing shut-in of the Aneth gas field.

As announced in our press release, the 2 items together will reduce our overall average production for the year by about 675 BOE per day.

To summarize, we have a diversified portfolio of oil-prone assets, giving us the ability to direct capital projects having very attractive returns. Our second quarter achievements represent a strong down payment of effort and meeting our growth goals for 2013. It's an exciting time for Resolute, as we ramp up activity in the Permian Basin, begin to convert the significant resource we have captured into production and cash flow. With the sale of New Home, our portfolio is more focused with Permian Basin as our primary growth engine, Aneth Field as a generator of free cash flow, while still showing production growth. And our Wyoming asset showing exploration upside. Our portfolio is heavily weighted to oil it provides a diverse mix of complementary opportunities at different stages on the growth curve.

Now, with that, I'd like to thank you and turn the call over to Ted Gazulis to discuss our financial results in more detail.

Theodore Gazulis

Thank you, Nick. As Nick discussed, we're pleased with our second quarter results and we're very happy to have taken over operatorship in the Gardendale area of the Permian Basin beginning at the second quarter. We're excited about the opportunities that we see ahead of us. Our Permian Basin acquisitions at year-end 2012 and at the end of the first quarter of 2013 will drive the bulk of production growth for 2013. So we expect to continue to grow production through the drill bit. That growth will be achieved through the response from CO2 flood program in Aneth Field, as well as other activities there and the development of our Permian Basin assets. We're also particularly excited about the horizontal drilling potential in the Permian.

Moving to the drivers of our financial performance in the second quarter of 2013, total company production for the quarter was 1,193 MBoe, thousands of equivalent barrels of oil, compared to a 858 MBoe for the second quarter of 2012, achieving a 39% increase.

I'd Highlight the production increase from our Permian Basin properties, which increased almost tenfold to 402 MBoe from the prior-year quarter. Obviously, the acquisitions were the major factor so we have been and continue to be drilling actively in the Permian.

Similarly, year-to-date production grew dramatically, with first half 2013 total company production of 2,240 MBoe compared to have 1,620 MBoe for the first half of 2012, an increase of 38%. Revenue in the second quarter of 2013, net of realized derivative settlements, rose to $82.2 million, a 49% increase over the prior-year quarter, driven primarily by production increases.

During the quarter, the average realized revenue per BOE, excluding realized derivative settlements, was $72 -- $74.72 per BOE, down from $75.16 a BOE in the same quarter last year. For the first 6 months of this year, revenue, net of realized derivative settlement, was $154.2 million, an increase of 40%, with average realized revenue per BOE, excluding realized derivative settlement of $75.02 a BOE, down from $79.01 of BOE at the prior-year period.

Not surprisingly, with rising production came increases in total lease operating expenses, though as we anticipated our LOE per BOE declined. Aggregate lease operate expense from the second quarter of 2013 rose to $25.6 million from $19.6 million in the same quarter last year, but decrease from $22.81 a BOE to $21.45 a BOE in the same comparative time period.

Sequentially, total lease operating expenses increased by about 1% in aggregate, but declined 11% per BOE from the first quarter to the second quarter of 2013. For the first half of the year, the results show similar pattern, with total lease operating expenses rising from $36.7 million to $50.8 million. Total production taxes for the second quarter also increased with incremental production by $1.2 million to $10.9 million, $9.12 a BOE, as compared to $9.6 million or $11.24 a BOE for the same quarter last year.

However, and again, as I anticipated, we saw a meaningful reduction in the effective tax rate from 15% of revenue to 12% of revenue, reflecting the fact that we now have a higher proportion of our production coming from lower cost areas.

Sequentially, the tax rate dropped from 13% to 12%. And comparing the first half of 2012 to the first half of 2013, we saw a reduction in the effective production tax rate from about 16% to about 13%.

We incurred general and administrative expense, including share-based compensation of $9.1 million for the second quarter, or $7.65 a BOE, which was a 15% increase on a per-BOE basis from a prior-year quarter due to increased salaries and wages necessary to meet growth demands associated with our Permian Basin expansion and other activities.

Excluding share-based compensation, our cash G&A cost was $4.08 a BOE, a decrease of $0.09 a BOE or 2% from the prior-year quarter. Turning to adjusted EBITDA, a non-GAAP measure, in the second -- point 13 we generated adjusted EBITDA of $41.3 million, a 58% increase from the prior-year period, in which Resolute generated $26.1 million.

Now represent an increase of 14% to $34.61 a BOE from $30.41 a BOE in the comparative quarter.

In the first half of 2013, we generated adjusted EBITDA of $32.05 a BOE, an increase from $31.06 per BOE in the first half of 2012. This might be a good point for me to make a comment about our derivatives program. As you know, we believe in protecting the downside with various forms of hedges, swaps, colors, puts and combinations of those things. In 2013, we'll roll off the last of some relatively low dollar oil slabs that have been in place for some time. This information is, of course, reported in the 10-Q that we filed today. But I'd note that our oil swap position in 2013 consists of 5,000 barrels a day, swapped at about $80 a barrel. In 2014, our swap volumes dropped from 5,000 barrels a day to 2,000 barrels a day and the swap price increases to north of $89 a barrel. Everything else being equal as these roll off, we should see a positive effect on adjusted EBITDA.

With regard to our capital program, we invested $61.8 million during the second quarter of 2013. primarily at our ongoing tertiary recovery projects in Aneth Field, and drilling and completion activities in Texas, Wyoming and North Dakota. Through the first half of the year, our total capital expenditures were $103 million, excluding the $257 million we used to acquire the Permian Basin assets. That acquisition was financed with borrowings under the company's revolving credit facility and proceeds from the sale of certain Aneth Field assets to Navajo Nation Oil and Gas Company.

Finally, I'd like to talk about liquidity. During the second quarter, we completed an equity offering, selling 13.3 million common shares at $8 per share, and net proceeds of $101.8 million were used to partially repay bank debt incurred in the Permian Basin acquisitions. Once the equity offering was completed, a $40 million non-conforming tranche of our revolving credit facility was terminated under its own terms, setting the borrowing base at $445 million.

Shortly, after the end of the second quarter, we closed the sale of our New Home Properties in North Dakota and as a result of that sale, our borrowing base is reset to its current level of $415 million. At the end of the second quarter, we had $320 million drawn, $320 million drawn on our credit facility as compared to $390 million for the first quarter of 2013.

We are comfortable with our liquidity position. We believe our Permian Basin acquisitions, and particular the potential for horizontal drilling in the Midland and Delaware basins, enhances the visibility of our opportunities to grow the company organically and to leverage the strength of the cash flow from our long life foundation asset in Aneth Field. We look forward to continuing to report our progress to you in upcoming quarters. Thank you all for listening. Now I'll turn the call back to the operator for Q&A. Amy?

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from John Freeman at Raymond James.

John Freeman - Raymond James & Associates, Inc., Research Division

First thing I want to focus on. I know that you all mentioned that you were adding some more acreage in the Permian, but didn't really want to disclose that at this point. Just sort on that topic, I know previously you have talked about trying to be consolidate your acreage position, Reeves County was possibly doing some acreage swaps. I'm wondering if you could just say if you made any progress on that front?

Nicholas J. Sutton

We've had several conversations on that topic. I would say that nothing is imminent at this point.

John Freeman - Raymond James & Associates, Inc., Research Division

Okay. And then, on the Permian, you run the 2 or 3 workover rigs during the quarter just to sort of draw down the inventory of wells. Where does that stand currently? Where do you see that going through the rest of the year?

Nicholas J. Sutton

The inventory of wells, meaning that...

John Freeman - Raymond James & Associates, Inc., Research Division

Sorry, the number of workover rigs that you're running.

Nicholas J. Sutton

I would say that we brought our -- the list of wells needing attention down to a current steady-state. And we'll go forward with a couple of rigs so that we're constantly working on the wells and keeping them at maximum production.

John Freeman - Raymond James & Associates, Inc., Research Division

Okay. And then just a couple of housekeeping items for me. Ted, could you give me the specific split on production during the quarter and then also, the actual realized oil and gas price, not just the BOE equivalent numbers?

Theodore Gazulis

I believe we have put that out there. It's on the website. There are handful of slides that breaks all that information down, John, so.

Operator

The next question comes from Phillip Jungwirth of BMO Capital Markets.

Phillip Jungwirth - BMO Capital Markets U.S.

Well, the second Gardendale rig that's now drilling the horizontal. Will that drill horizontals for the rest of the year? And then looking into next year, do you think that you'll continue to run one vertical rig or could you go purely to a horizontal program?

Nicholas J. Sutton

The horizontal rig will keep busy on Gardendale through this year. And as to next year, we're going through that right now. I would say that at this point, in Gardendale, we will drill both vertical and horizontal wells with the increasing focus on horizontal.

Phillip Jungwirth - BMO Capital Markets U.S.

And can you tell us what the lateral length is of the 3 horizontals in the Midland?

Nicholas J. Sutton

Yes, about 4,500 feet.

Phillip Jungwirth - BMO Capital Markets U.S.

Okay. And then last, I think, Permian production pro forma for the first quarter, I think, was around 5,100 barrels a day. It's a little bit less in the quarter. Is that just due to natural declines and not getting the rigs out there until you close the acquisition, or is there anything out there?

Nicholas J. Sutton

I think there are couple of factors. One is certainly natural decline. Another is the loss production when the depth field saltwater disposal well went down, and that's now back online. And also, as we indicated, the completion of some of the wells that we have drilled were stacking up, we've broken that logjam and we're aggressively completing the wells at quarter end were in the queue. And so we're turning the work around much faster. As we speak about turning the workaround much faster at Gardendale, I would say that our rig efficiency has increased rather dramatically. And the last well, I think, was about 8 days spud to spud. So we're really -- we're moving through that project right now in a very efficient way. So I think all those factors contributed to the production for the second quarter.

Operator

Our next question comes from Richard Tullis at Capital One South Coast.

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

Ted, just going back to the LOE outlook for the rest of the year, just so I get a better understanding on it. Do you expect it to kind of go back to that level where you were, say, in the fourth quarter of last year, say, the low $23 lever or even below that?

Theodore Gazulis

I think the important point Nick made in his comment was that, and as we discussed on the first quarter call, the first quarter LOE was substantially higher than we had planned. It was a tough January and February. We -- Jeffrey Dillon and his team in Aneth have the flexibility to use their judgment in how best to use our workover rigs. And there was a lot of work to be done. I think that the -- we've sort of -- the comparatives that are better are the $22, $23 numbers rather than what we saw in the first quarter. So I think we'll normalize that level meaningfully below where we were in Q1.

Nicholas J. Sutton

I would also point out that the real key thing is we're well within our guidance, as to a lease, operating expense.

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

Okay. And then, Ted, are you able to give the current liquidity pro forma, the Bakken sale?

Theodore Gazulis

Well, we're at -- I think we'll probably have $100 million or so in revolver happily without really stretching too much.

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

Okay. The guidance, the updated guidance, how much of that reduction of, I guess, it was about 675 barrels a day. What's the split between the Bakken sale and the Aneth gas shut-ins?

Nicholas J. Sutton

Approximately 500 BOE per day from the Bakken and about 175 BOE per day related to the Aneth gas.

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

Okay. And then, just lastly, for me. What's the current plans for the remaining Bakken assets?

Nicholas J. Sutton

The remaining Bakken assets could be divided into 2 pieces. On the one piece, we're heading to our likely closure. And on the other piece, we're involved in the discussion with the company. And at this point, it's uncertain as to whether that particular company will close on, on a transaction. And we -- what I would say is we have continued to permit in that area we are prepared to move ahead with drilling plans. So as to the Paris acreage, its just -- it could go 1 or 2 ways, and on the other as part of the property, which is relatively minor, we expect that to close in short order.

Operator

Our next question comes from Ron Mills at Johnson Rice.

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

Nick, just one clarification question. When you talked about keeping one rig horizontal at Gardendale the remainder of the year, does that imply that you may end up drilling more than the 3 planned horizontals, given the timing of drilling those wells?

Nicholas J. Sutton

Good question. That's under review right now. Personally, I'd love to see it keep right on ongoing, but we also have a budget that we have to adhere to, and we're looking at various ways we might adjust it around. But we have that option in front of us, and that decision will be made in upcoming weeks.

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

Okay. And as you look to the Reeves County acreage and notwithstanding how much acreage you added, you highlight continuing to gather data from offset operators including those using your system, what are the steps you're taking now to prepare for starting to drill horizontally in 2014 in terms of permitting and getting things ready? Is it going to be in place where you can, I guess, I'm trying to get a sense as to when you may end up spudding your horizontal program down in Reeves?

Nicholas J. Sutton

Well, we're moving forward with permitting. Permits are not really a big issue there. And it's all going to depend on how we sort through our 2014 operating and financial plan and our allocation capital. It's a good area. I would expect us to move forward there. But we haven't made any final plans around as to the ultimate allocation of our capital for 2014.

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

Okay, great. And then shifting all the way up to the Powder River Basin. It sounds like here within the next month, you'll be spudding your first Turner well. I know couple weeks ago, there was a report of a private company with a well that came on at 3,000 plus BOEs per day. How is -- can you refresh our memory how that compares to the PetroHunt well offsetting you in what you're seeing in the area and what if anything it could mean for your acreage?

Nicholas J. Sutton

Well, I'd say that, that 3,000 or 3,300 barrel a day well is certainly a very robust loan. I would love to find a bunch of those on our acreage. The -- if we look at PetroHunt, the PetroHunt well, that was for an IP rate of 600, 700 BOE per day. But I point out, yes, that's a 30-day IP rate on the PetroHunt well. And I'm not sure whether that 3,300 BOE per day was 24-hour or 30-day.

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

Right. It sounds like 24 hours.

Nicholas J. Sutton

Yes, it does.

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

And then, I guess, lastly, for me. You touched on the pro forma liquidity, Ted. I think you said $100 million. Is that what you suggest is available pro forma for the Bakken sale under your revolver given the lowered borrowing base for the sale? I just want to make sure I get the right numbers.

Theodore Gazulis

Yes, I think that's in the ballpark. Yes, well, of course, it depends day-to-day, whether we've gotten our run check from our refinery, friends or not. But that's a ballpark number that we think is comfortable and realistic.

Operator

Our next question comes from Noel Parks from Ladenburg Thalmann.

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

Just a couple of things. In Aneth with DC IIC program you're looking at for the rest of the year, is that activity level pretty much set in stone at this point, or do you see any -- I don't know, either you're slowing that down a little bit to maybe use capital elsewhere or maybe getting a little more aggressive before the end of the year, sort of depending on sort of overall production levels?

Nicholas J. Sutton

Right now, we are focused on the DC IIC in accordance with our plan, as we've outlined. That's been a very good project for us economically. And as you know, it's a prelude to turning that into a CO2 flood. And so what we're effectively doing at this stage is reinitiating the waterflood, and we're getting good economics with that. But we think that the real bang for our buck is going to be when we're able to start CO2 flooding the DC IIC. And so given that, that is our objective for the DC IIC, we're not inclined to slow down. What were trying to do is increase reservoir pressure toward minimum visibility, and that encourages us to keep moving with the DC IIC program in a pretty aggressive way.

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

And in the Permian, I wonder if you just had me updated, thoughts or information about completions out there. At the Analyst Day, you've -- were giving some -- giving us some ideas what you expect increase to be like. And then just curious whether anything has changed since then.

Nicholas J. Sutton

On the horizontal well, we're looking at about 20 stages. And in all, we tend not to comment on what other people are doing out there because I'd hate to miss speak as to what Diamondback or somebody else is doing in the area. We encourage people to get the information directly from them. But as we look at the completions at our area, we're looking at about 20 stages.

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

If I -- were you thinking about maybe doing somewhat more intensive. I thought I remember the number being a little higher than that. Maybe 24 or something like that.

Nicholas J. Sutton

I don't believe so, no.

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

Okay. And...

Nicholas J. Sutton

Just a reminder, we're scheduled to start that completion on the 26th of August. So it's going to be just a couple weeks off.

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

Okay, great. I think the only other thing I had, just looking ahead for the model, capitalized interest was up for the quarter end. Just wondering if -- I think it was $4.7 million. Is that a pretty decent run rate going forward or might that shift around a bit?

Theodore Gazulis

Yes, I think that's probably a decent run rate. Obviously, as we work through how you capitalize interest as a function of where you're spending your money. And we're spending a lot of money on capital projects. So it's not -- I don't think it's realistic -- I don't think it's unrealistic to think that's a pretty good number.

Operator

The next question comes from John Nelson at Citigroup.

John C. Nelson - Citigroup Inc, Research Division

I was hoping to come back to the LOE question. I was wondering if maybe you guys could provide a little color on what LOE is looking at the Gardendale, given it seems that a lot of the production growth in the back half of the year will be coming from those properties?

Theodore Gazulis

I actually have -- LOE in Texas and in the whole Permian, in Gardendale, we think will be consistently lower than it has been in, for example, Aneth. I don't have -- I'm looking at Jim Tuell who has -- should have the numbers available. But I'm not -- I don't know that we have a good breakout right now that we'd like to...

Nicholas J. Sutton

We don't have that number specifically as to Gardendale. And we certainly can get the number for you. The numbers we have in front of us are more generic Permian, Powder, Aneth, et cetera. John, if you cycle back to us, we'll call HB and we can provide that information to you.

John C. Nelson - Citigroup Inc, Research Division

Fair enough. And then, just a clarification. I think the queue mentioned about $20 million in spending in the Bakken in the quarter. I just wanted to clear up if that was associated with New Home and you'll get that back as part of a purchase price adjustment or whether that was spending in one of the other 2 areas.

Theodore Gazulis

Go ahead, Jim.

James A. Tuell

Hi, this is Jim Tuell. Mostly, that is a cash flow number, so it reflects when we paid for our capital expenditures or when we made the payment, not necessarily -- it doesn't correlate to when the work was done. And so, yes, in conjunction with the sales during this quarter, some payments were made, but it doesn't reflect the actual accrual basis spending.

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

Does $75 million is all I should think about as coming in, in 3Q?

Theodore Gazulis

Correct.

Theodore Gazulis

Yes.

Operator

The next question comes from Ryan Oatman at SunTrust.

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

In the Midland Basin, can you provide any color on the first Wolfcamp B horizontal test, what you saw when you were drilling and how it drilled, et cetera?

Nicholas J. Sutton

I think the best thing we can say right now is that the entire well went extremely smoothly. We landed right where we wanted to land. As we were drilling, it was responding as we would have expected. And -- but for, I think, there was an MWD failure that we have to trip for, it really, really went smoothly and the reservoir responded as we would have expected. Can't really get into the details of things like shows and whatnot at this point.

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

Sure. No, it's all the color I was looking for. And you said about 20 stages on the completion, yes, lateral length, again, on that was about 4,500 feet, is that correct?

Nicholas J. Sutton

About 4,500 feet.

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

Okay. And then looking further out, any plans to test the OTB in Big Spring acreage horizontally? Or do you think you'll focus more on Gardendale, given the offset operator success?

Nicholas J. Sutton

Yes, for the time being, we're going to be focusing primarily on Gardendale. But certainly, Big Springs OTB provides some future opportunity for us.

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

Okay. And I would imagine the same thing, but ask anyway. Any plans in 2014 to test other zones? I know others have had a good success with the Wolfcamp A, for instance, lower Spraberry. Do you see those as potential targets to get after maybe even late in 2014?

Nicholas J. Sutton

It's certainly a possibility. We've been watching that activity as well, and it's very encouraging. But right now, we're really focused on B because there's more data there, there's more knowledge there. And as you know, our approach generally is to let the companies with the really deep, deep pocketbooks run some of their initial interference on other formations. So I think you're going to expect us to focus on the B and start working our way into some of the other formations over a period of time. And I can't tell you whether that's the end of 2014 or into 2015 or exactly when that is going to transpire.

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

Right. All that makes sense. And then shifting up to Powder River, can you discuss what you're seeing in these Mowry vertical recompletions and kind of how that program looks going forward in the Mowry specifically?

Nicholas J. Sutton

Yes, sure. We outlined the 3-well test program to recomplete in the Mowry based on a particular seismically defined geologic concept. And the 3 wells are over a broad area. We've got 45,000 acres, plus or minus, in the Hilight Field. So we've got a lot of area to work with there. The concept was really applying to the 3 wells. And I would tell you that the first 2 have not been overly impressive. And it's too early to really conclude what not overly impressive means particularly because we've got the third well that's going to be testing the concept in a different area with different subsurface conditions. So as I say, if we were left to make a decision based solely on the first 2 wells, based solely on the information that we have today, it's just not very exciting. But we've got some more work to do there and the guys are working real hard.

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

Okay, that is helpful there. And then, obviously, it looks like you guys are going after Turner there. Do you see other's perspective across the 45,000 acres in Hilight or only a portion? I was just curious for your thoughts there.

Nicholas J. Sutton

We're principally targeting the Southwest part of our acreage and looking at maybe 10,000 to 12,000 acres initially. Who knows what the results will open for us. We like the Southwest because certainly, that's where the closest activity to us is taking place. We also like it because what we see is a confluence of overlap -- Venn diagrams overlapping between Niobrara and Turner. And so we could get enhanced production to the extent that we're able to complete in both formations with a signal wellbore. So that's our initial target area. And if results cause us to be more optimistic, perhaps we can go out further than 10,000 to 12,000 acres. But that's really, the 10,000 to 12,000 is where our focus is right now.

Operator

[Operator Instructions] And our next question comes from James Spicer at Wells Fargo.

James Spicer - Wells Fargo Securities, LLC, Research Division

A balance sheet question for me. Can you tell us what your leverage was at quarter end relative to the covenant levels in your credit facility? And then, remind me what level of leverage you guys target over the longer term?

Theodore Gazulis

Sure. We have, in the context of our acquisitions, our covenant level is 4.5x for calendar '13. We were well under that at the quarter. We feel like with a low floor handle. We feel like, and of course, at the quarter, we had not received the payment for the New Home sales. So obviously, immediately after the quarter it dropped even further. I think the important point is that as we look forward over the long term, we've talked about the sustainable level of the sort of debt to EBITDA in the 2.5x to 3x range we will work to get there. But one of the things that we've said pretty consistently, and as we've demonstrated both at year end and at the end of the first quarter, we're willing to stretch that to take advantage of what we think are these terrific acquisition opportunities and then delever over time.

James Spicer - Wells Fargo Securities, LLC, Research Division

Okay, that's helpful. And one more. The $100 million of pro forma availability you have under the credit facility, is that about the right level you guys think of as a cushion that you'd like to have over the longer term?

Theodore Gazulis

Yes, I think that's an amount that -- that gives us position flexibility to take advantage of the smaller opportunities, but plenty of cushion to run the business effectively, spend the capital and operating dollars that we need to spend and not feel like we have any meaningful constraints on our ability to run the business.

Operator

This concludes our question and answer session. I would like to turn the conference back over to management for any closing remarks.

Nicholas J. Sutton

Thank you. One point of clarification, not that it's terribly important, but in the interest of accuracy. I referred to our Gardendale verticals as being down to 8 days spud to spud. What I really meant to say is 8 days spud to release. So just correct your notes accordingly.

With that, I'd like to thank all of you for participating in the call. Thank you for the interest in the company. And as always, feel free to circle back and call HB or anyone of us and we can provide whatever additional details that should be appropriated consistent with our responsibilities under Reg FD. So again, thank you very much. We wish all a good day.

Operator

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

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