Resolute Energy (REN) CEO Nicholas Sutton on Q2 2014 Results - Earnings Call Transcript

Aug.13.14 | About: Resolute Energy (REN)

Resolute Energy Corporation (NYSE:REN)

Q4 2014 Earnings Conference Call

August 12, 2014 04:30 pm ET

Executives

Nick Sutton – Chief Executive Officer

Ted Gazulis – Executive Vice President & Chief Financial Officer

Michael Stefanoudakis – Senior Vice President & General Counsel

Analysts

Ron Mills – Johnson Rice & Company

Jason Wangler – Wunderlich Securities

John Freeman – Raymond James

Ryan Oatman – SunTrust Robinson Humphrey

Jeff Robertson – Barclays

Richard Tullis – Capital One

Jeff Grampp – Northland Capital Markets

Noel Parks – Ladenburg Thalmann & Co.

Andrew Smith – Global Hunter Securities

[William Tiji – Bedo Capital]

Operator

Good afternoon and welcome to the Resolute Energy Corporation’s Q2 2014 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, sir.

Michael 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,” “believe,” “predict,” “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 could cause actual results, levels of activity, performance or achievements to differ materially from results expressed or implied from 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 appear in our Form 10(k) and is updated periodically in the Form 10(q)s and other public filings. At this time I’d like to turn the call over to Nick Sutton, our Chairman and CEO.

Nick Sutton

Thank you, Michael. Good afternoon and welcome to Resolute’s Q2 Earnings Conference Call. You’ve had an opportunity to read our press release that went out late yesterday afternoon so I will limit my comments to the most significant aspects of our business. Ted will give you an overview of our financial performance and then we will open the call for Q&A.

Keeping this discussion at the 30,000 ft. level, at the outset let me say that in my opinion a focus on the period-to-period comparative metrics runs the risk of missing the point of our quarter. Recall that we sold our North Dakota properties so our production and our revenues started in the deficit position relative to prior periods. If we look at production from current operations, for the six months ended June 30 production was almost 9% higher than the same period last year.

We also experienced some unanticipated delays in bringing wells on production in the Permian Basin but we are building significant momentum with our horizontal drilling programs in both the Permian and Powder River Basins.

In the Delaware Basin in Reeves County, Texas, we have four wells in various stages of drilling, completion or flow back. The Harrison State well was completed on June 27 with a 21-stage frac. Because of high pressures we have been bringing this well online in a very conservative manner, walking the choke size up in small increments such that even now, some 43 days after initiating flow back, we are on a 24/64 [cinch] choke and seeing flowing casing pressure of more than 2800 lbs. Even under this conservative operating scenario we have seen a 24-hour peak IP rate of 1312 Boe per day based on a calculation of three stream production. We think this well is showing the potential to be a great well.

Just as last week we finished completing our first 7500 ft. lateral in the Delaware Basin. The Renegade 0302BH was a 31-stage frac that put away 9 million lbs. of sand. Plugs were drilled out; flow backs started on Sunday and I was just informed that on this third day of flow back the Renegade has started to cut oil at a current rate of 5 barrels per hour. I think that’s a pretty darn good start.

Our second 7500 ft. lateral, the Steamworks 0301BH, currently is drilling ahead in the lateral portion of the well bore. We expect to complete that well later this month along with the James021 401H. In other words, barring some unforeseen event by late this month or early next month all four of these wells could be in production.

With this in perspective, if just the Harrison well had come online in the middle of May rather than at the end of June the extra 45 days of production from that well would have made an impressive bump in our quarterly average daily production tally. It didn’t work out that way but the production wasn’t lost, only deferred. Our optimism for this program is buoyed by the performance of our first Reeves County well, the Meeker C21 1501H that continues to perform well above type curve and has produced about 139,000 Boe during its first 161 days of production.

We think that this activity and these wells will set the company up for a strong exit from Q3. I’ll point out that these are high interest working wells, averaging about 84%, so you can do the math.

Looking to the future, after the Steamworks well is drilled our Delaware Basin rig will mobilize to the new location and continue to focus on drilling 7500 ft. laterals. In addition we anticipate restarting drilling operations in the Midland Basin in early 2015. We are very encouraged by the impressive results reported by operators near our Big Springs project area in Howard County. We are assessing our Howard County acreage for its potential for horizontal development.

We believe that our current Permian Basin leasehold offers substantial visible growth potential as by our estimation we have over 200 surface horizontal locations, virtually all with stacked formation potential.

Moving now to Wyoming, our primary focus is the Powder River Basin where we have drilled three horizontal wells targeting the Turner sandstone and the Highlight Field. Our first Turner well, the Castle321TH has produced a cumulative 123,000 Boe. It is still producing approximately 300 Boe per day at an essentially flat rate since we put it on pump about four months ago. It is worth a reminder that the Castle well tested at a peak 24-hour rate of over 1100 Boe per day with 90% of the volume being oil.

During Q2 we drilled two more horizontal wells, the Castle1341TH and the Grand714TH. Both are scheduled to be fracked this month. These two wells are located in the south end of the field and their productivity will provide additional information for planning of a potential continuous drilling program in 2015. These wells will join with our four Delaware Basin wells in contributing to Q3 production and an exit rate that should be meaningfully above our Q2 rate.

While drilling the Grand and the Castle we collected core and other science data and based on these data we think that Highlight Field may be productive from the paraffin and the Sussex as well. We have 45,000 acres in Highlight. We have identified approximately 48 unrisked horizontal Turner drilling locations and another 30 potential horizontal paraffin locations in our acreage block, providing a multi-year drilling inventory. We are securing drilling permits that could lead to an ongoing program in Highlight Field starting in 2015.

In the Big Horn Basin in Wyoming we have farmed out some of our acreage to a public operator to drill an exploratory horizontal well targeting the Phosphoria formation. The Phosphoria is a long-established oil-producing interval originally established using vertical wells. For [analytes] this will be the first horizontal test of the Phosphoria and we are looking forward to getting results later this year. If the test proves successful we will retain a working interest in subsequent drilling and we will hold an overriding royalty interest in the acreage.

The takeaway from all of this activity as you have probably gathered is that the backlog of horizontal wells waiting on completion has increased. With each well drilled we have spooled up the production flywheel providing latent production growth momentum that we expect will be benefiting us as early as this current quarter.

Turning our attention to Aneth Field I’m pleased to report that production is stable and above plan. This large, legacy asset continues to provide substantial and reliable cash flow with relatively little capital investment. Recent activities at Aneth include the build out of infrastructure and making improvements to operations, both of which help maintain production of over 6200 Boe per day net to Resolute, essentially flat with last year and the previous sequential quarter.

Our field operations team and the technical team in Denver have worked together exceptionally well to apply engineering and operational best practices that have paid off in achieving production levels consistently above plan. With the application of capital this team and our deep inventory of economic projects at Aneth Field point to a very promising future there.

That is a good segue into our third topic, a brief discussion on the status of the financing transaction that we mentioned on last quarter’s call. We have advanced our effort and it is fair to say that we are in detailed discussions with several very qualified financial partners. These potential partners are names that you would recognize, firms that have quality reputations, are financially strong and known in the oil patch. We can say with confidence that we have alternatives from which to choose and it is just a case of making the best choice.

Of course any transaction is subject to prevailing market conditions but we are optimistic about getting a deal done that will provide the company with the capital needed to accelerate our horizontal drilling programs and execute a step change to a higher growth profile.

In summary we are pleased with our progress during Q2. We are on track with our base capital plan. Our assessment of our asset quality continues to improve with time as we and the industry move up the learning curve and we have made meaningful progress towards a financial transaction that will allow us to accelerate our horizontal drilling programs.

With that I would like to turn it over to Ted Gazulis, our Chief Financial Officer.

Ted Gazulis

Thank you, Nick. A detailed analysis of our financial performance along with financial statements is included in our earnings release and also in our 10(q) that was filed yesterday. In addition we’ve posted a financial supplement on our website www.resoluteenergy.com. As a result my comments will focus on the big picture.

Simply looking at the reported numbers Q2 2014 production of 1120 mBoe was down about 6% from the same quarter last year. Nick has pointed out that comparing production from the prior year periods is a bit misleading since we sold the majority of our North Dakota properties 13 months ago and the remainder in March of this year. Pro forma for the North Dakota properties sale production for the quarter ended June 30, 2014, actually increased 1% compared to the prior-year period.

Through the six months ended June 30, 2014, reported production was up 1% to 2254 mBoe from 2240 mBoe during the comparable prior-year period. Pro forma for the North Dakota sale though production increased 9% from the same period last year. Sequential production was essentially flat from Q1 2014 to Q2. As noted previously, we anticipate increased production in subsequent quarters from our new wells in the Permian and Powder River Basins.

For the six-month period ended June 30, 2014, revenue increased 7% over last year to $179.3 million. Leased operating expense including production and ad valorem taxes was up 9% from the comparative six-month period, and G&A expense was up 8%, both largely a result of increased operations and staffing to manage our growing Permian Basin activities. Sequentially LOE including production and ad valorem taxes was flat on a quarter-to-quarter basis, and cash G&A increased by about $345,000 or 6%.

Adjusted EBITDA, a non-GAAP measure, was up 7% to $76.8 million or $34.09 of Boe in the first six months of 2014 as compared to $71.8 million or $32.05 of Boe last year, primarily due to increased commodity pricing. In Q2 adjusted EBITDA was $35.7 million or $31.88 of Boe, 13% lower than the $41.3 million or $34.61 of Boe in the same quarter last year, largely due to higher operating costs.

Reviewing our capital program we invested approximately $47.3 million in Q2, bringing our six-month total to $83.3 million, net of $4.8 million in divestitures. The majority of our capital budget was allocated to horizontal drilling programs in the Permian and Powder River Basins and to CO2 purchases and ongoing infrastructure investments in Aneth Field. We remain on track with our base capital plan. At the point that we complete a financing transaction such as Nick described earlier we expect to increase our capital budget and accelerate our oil drilling activity in the Permian and Powder River Basins.

Turning to liquidity, at June 30, 2014, we had a total of $335 million drawn on our revolving credit facility which has a borrowing base of $425 million.

In summary, the Resolute team has worked hard to build and maintain operational strength and with our horizontal drilling activities we’ve set the stage for what we think should be meaningful increases in production. In light of that we do not believe that our current share price accurately reflects the value embedded in our asset base and as such we think that the current environment presents a real buying opportunity in Resolute shares.

Thank you for your interest in Resolute. With that I’ll turn the call back to Nick.

Nick Sutton

Thank you, Ted. We’d like to open the lines for a question-and-answer session. Operator, would you do that for us please?

Question-and-Answer Session

Operator

We will now begin the question-and-answer session. (Operator instructions.) The first question comes from Ron Mills with Johnson Rice.

Ron Mills – Johnson Rice & Company

Hey, a quick question on the Harrison State well. It’s produced for 43 days; you did it on a 24/64 choke. I think at least according to the Railroad Commission the Meeker was at 40/64 of a choke so can you talk a little bit about that restricted choke or pressure management program and when you think those curves look like they might intersect? Just trying to get a sense of it seems like EURs in the flat or decline will be higher. When will they intersect to get comparative type economics on those wells?

Nick Sutton

Good question, Ron. Let me first point out that the two wells although geographically near each other in the big picture of things have different pressures. And while the pressures are certainly appropriate let’s call it, in the Harrison well the pressure is higher than in the Meeker. So in effect we’d be comparing apples to oranges if we tried to do a direct comparison between those two wells.

The more conservative approach that we’re taking with the Harrison is really driven by the higher pressures, and it’s not so much a flow back for us because it’s generally applicable. It’s just we believe again this very high-pressure regime, we have to watch that we don’t draw the pressure down too fast and create too big a sink across the sand base in effect and it starts (inaudible). So you’re absolutely right. We’re on a restricted choke and we’re seeing very high pressures even this far in the flow back.

At this stage the difference between what we produced from the Meeker and what we have produced thus far from Harrison is only about 12,000 Boe after these 42 days so it just shows you that the Meeker is a very, very good well, very much stronger than our type curve, but this Harrison has we think just stellar potential. So as I say they’re not directly comparable and we’re doing this regime, this pressure control flow as we have looked at other basins and as we have examined certain data points in our area that are confidential and proprietary.

Ron Mills – Johnson Rice & Company

Okay. And is the plan to flow these back on more of a restricted choke going forward in all of your wells or is it going to be pressure dependent like you said on the Harrison State?

Nick Sutton

Right now our approach is that it will probably be pressure-dependent, although each well provides us a new data point for learning and we are monitoring this very, very actively. We think it’s the right thing to be doing on the Harrison. If we see these pressures again which I think are likely on some of our upcoming wells we will follow the same pressure maintenance program unless and until we determine that it’s not necessary and we can go ahead and flow the wells more aggressively.

Ron Mills – Johnson Rice & Company

Okay, and then stepping up to the PRB, the second and third wells it sounds like are about three miles away from your first well. If you look at your position there and the 45 remaining locations in the Turner, what do you think about the level of de-risking from the first three wells once we get these next two well results?

Nick Sutton

Well, I think that assuming that the results of these two wells come back positive, which I certainly expect based on our geologic mapping – and I’d remind everyone that we’ve got wells and logs all through the Highlight Field so we’re very familiar with the geology in that area. So we expect these to be good wells. But in terms of directly de-risking I’d estimate maybe 8000 acres and 25 locations, we would have a much stronger confidence after these wells are completed and we get some production back from them.

Ron Mills – Johnson Rice & Company

Okay, and then one last one as it relates to Permian – it sounds like you have another 7500 ft. lateral lined up after the Steamworks and by looking at the press release you talk about permits in hand, maybe even to get started back up in the PRB here in Q4. Am I reading too much into that or does that point to a pretty short fuse in terms of getting something announced on Aneth? Because I know to move up from the base CAPEX program, you were talking about not doing that until you had some proceeds in the door from Aneth.

Nick Sutton

We do have at least two more wells scheduled in the Delaware Basin. I would point out that the working interest in those wells is not quite as high as in the wells we have drilled to date. The next well on our schedule is called The Great Divide and we have a 50% working interest; and the one following that will be The Harpoon which will be a 64% working interest. So our plan is to keep right on going. We expect that the production that we expect to get from these wells – the Harrison, the Renegade in particular, what we’re already seeing there – will add to our cash flow and our liquidity. And we’ve got pretty good liquidity right now.

I don’t think that we will move into the Powder River Basin late in 2014. I’m looking at that as more a 2015 program. But we are accumulating permits and we are absolutely ready to go.

You sort of bring up the related subject of timing and I can assure you that the Resolute Operations Teams in Aneth, in Permian and in Powder Creek are all working very, very aggressively to in effect drive [a value play], to stretch that rubber band so that when we get our financing it’s going to be prepared to rip loose and fly into action. We are going to (inaudible) assets through the end of the year, there’s no doubt about that, but in terms of being able to accelerate we’re laying the groundwork for that because we have every anticipation that we will get the financial transaction accomplished.

While the Operating Team is doing all that it can do, all those first [valves], I can tell you that the management and financial functions of this company are very focused on the transaction that we have outlined. And I think we have made excellent progress with some terrific potential counterparties. So this is not something that we anticipate is going to drag on for some extended period of time.

Ron Mills – Johnson Rice & Company

I’ll let someone else jump in and get back in line. Thank you, Nick.

Nick Sutton

Thank you.

Operator

The next question comes from Jason Wangler with Wunderlich Securities.

Jason Wangler – Wunderlich Securities

Hey, good afternoon, guys. Nick, you kind of hit on it there a little bit – I mean is there any color as far as dealing with multiple parties? I assume it just kind of takes the process a little bit longer, but it seemed like at least previous comments getting into the fall or even later to the end of this year was the hope to really start ramping back up. Is that still kind of on the table or do you have an idea of the timeline of when you’d be able to start really getting the operations going a little bit quicker?

Nick Sutton

In terms of a date certain, no. We still have to get the transaction finalized, and you know, the old joke about [the check is in the mail]. But we are working with some potential counterparties but as I mentioned before they have very strong financial [experience], very sophisticated. They are people that we have known for a very long period of time, have good working relationships with and these people know how to move. So we anticipate that we’re on schedule. I’d like to see us get back up by the end of Q3. And will that happen absolutely? I don’t know, I’m just telling you what I would like to see happen.

But we are in a position to carry our water on the field and the people that we are working with as I mentioned before are very sophisticated transaction-knowledgeable and they want this thing to move quickly as well. So I don’t think I’m stretching by saying (inaudible). That would certainly allow us to move right on through the end of the year and we would look to accelerate our programs accordingly.

Jason Wangler – Wunderlich Securities

And that’s helpful. And just to be clear, is that have it announced and as you said the check cleared by the end of Q3 if you’re able to go on that timeline?

Nick Sutton

I don’t know, I think that’s kind of cutting hairs. It’ll be what it’ll be, yeah.

Jason Wangler – Wunderlich Securities

I mean give or take. You’re thinking as far as the completion of the transaction at that time versus an announcement I guess is what I’m asking.

Nick Sutton

Yes, yes.

Jason Wangler – Wunderlich Securities

Okay.

Nick Sutton

It might be a week either side…

Jason Wangler – Wunderlich Securities

Oh yeah, I’m not going to hold you to September 30th, just more announcement versus financing.

Nick Sutton

Okay, I just wanted to make sure. [laughs]

Jason Wangler – Wunderlich Securities

No, I appreciate it.

Ted Gazulis

Jason, this is Ted. I think the other thing that I want to convey is our goal here is to get this transaction done, to get it done with the appropriate party, to get it done timely. But we’re all focused on making sure that the timing of the transaction works so that we can continue drilling where we’re drilling and be set up to actually accelerate sooner rather than later. So Q3, end of Q3 is a very reasonable and realistic deadline and we’re all working to meet that.

Jason Wangler – Wunderlich Securities

Perfect, I’ll turn it back. Thanks, guys.

Operator

Next question comes from John Freeman from Raymond James.

John Freeman – Raymond James

Good afternoon, guys.

Nick Sutton

Hi, John.

John Freeman – Raymond James

It seems like what bumps in the road we’ve hit on production has generally been, at least from my perspective, a little bit out of your control where it’s something’s supposed to be fracked and completed on a certain timeframe, then it gets pushed back. And I’m just curious, and this is a much longer-term I guess thought process, but what kind of a level of activity do you think you would need in both the Permian and up in the Powder River Basin in terms of activity to justify having like a dedicated frac crew in each of those areas where you maybe avoid some of these issues?

Nick Sutton

I don’t know what the exact level of activity would be. I think it’s kind of a moving target. Certainly in the Powder River Basin we’re seeing less pressure than we are in the Permian. But I would point out that we have developed good relationships with vendors, and for example you talk about one of the bumps in the road – with our Renegade well we contracted with Helmerich & Payne as opposed to the company that drilled the first couple of wells. H&P brought a rig out that had been cold stacked. They knew it was going to take a little bit of time to work the kinks out of that, and part of the contract was they were going to eat the cost of that time and that effort to get that rig moving well.

I can tell you that the Steamworks well is drilling extremely well and so that’s kind of one of the bumps that we have. But in that process we worked very carefully with Helmerich & Payne. They’ve been extremely professional in our opinion as to how they approached working with us and when the problem developed on the rig they solved that problem. That’s the kind of partnership we’re looking for.

And on the frac side we have over time moved our business to a couple of the larger vendors, and in talking with some of the senior officials at the one in particular I’m thinking of they’ve committed that they are with us on this. They treat us as a company that’s on the move, its activity level is going to be increasing and that they will do anything that they can to help us achieve that goal. Of course they’re looking forward to some business out of that, too.

And so as we look at the frac service and supply companies we’ve got good relationships, and we think that there’s good communication back and forth. It’s not necessarily that we can have a dedicated crew, and at some point you’re absolutely right – that would be great to have. But we’re in a position now where we can schedule and coordinate with these vendors in a way that we get dates certain, and then that’s subject to be moved around a little bit – if the frac in front of us takes a little bit longer for example our date might slide.

But we’ve got slots on the calendar. We’ve got the two wells in the Powder are going to be fracked within a week, commencement within a week and we’ve got a couple fracs lined up in the Permian for later this month. So we might have to work this situation a little bit more than a company that can handle a dedicated frac crew. We’re not quite there but I have to tell you we’re getting strong cooperation from some of the best names in the business because they see this company as being a company on the move.

John Freeman – Raymond James

Okay. And then my last question has to do with some of the longer-term well performance in some of the wells we’ve got a good bit of history on now. So the first Turner well that you have it’s now cum’d 123,000 barrels over roughly the eight months. Last quarter we obviously didn’t have that much production history to go on at that point; you all had kind of given an estimated EUR on that of like 519,000? Could you kind of update on where you think that’s tracking now? It’s obviously been much flatter than what you would have expected.

Nick Sutton

It is but we had an opportunity as we were going in to do a little well work to put that well on pump. So it went down and then the pump rate that it’s at right now was designed to allow it to pump at that certain rate – 300 barrels a day is what we’re pumping now and it’s been absolutely flat for the last four months. So it hasn’t been your typical decline curve.

We have adjusted our EUR very slightly simply because the gas/oil ratio has changed a little bit but it’s still hanging in there as pretty close to what we initially said; and as I say, it hasn’t been a drop-off in oil production, it’s just the EUR has changed a little bit and that affects our longer-term projections.

John Freeman – Raymond James

And then just the same question on the Meeker well relative to the 500 to 750 EUR range you all have given in the past?

Nick Sutton

I don’t know that we’ve updated that since what we have said in the past. I mean we’re looking at that production carefully. I can tell you the well is producing significantly above type curve and producing in every way that we would like. Now we have put it on gas lift. It was one of those things where again, we had an opportunity to go in when we were working on the well and take that opportunity to put it on lift, and so that changes the production characteristics somewhat in that process. But a good, strong well and when we update our EURs we’ll let you know.

John Freeman – Raymond James

Thanks, guys, I appreciate it.

Nick Sutton

Thank you, John.

Operator

Next question comes from Ryan Oatman from SunTrust.

Ryan Oatman – SunTrust Robinson Humphrey

Hi, good afternoon. A couple of quick housekeeping ones from me here: can you just remind us how many wells you anticipate completing in each play this year under the base plan assuming no acceleration?

Nick Sutton

Assuming no acceleration we will complete the wells in the Powder River Basin starting in about a week and we will complete two more wells in the Delaware Basin toward the end of the month. And we will be drilling at least two more wells after we finish with the Steamworks – that [remaining] well as I mentioned before and move on to Great Divide. And (inaudible) we would anticipate completing those wells this year.

Ryan Oatman – SunTrust Robinson Humphrey

Gotcha, very good. And what are the current well costs for a 7500 ft. lateral versus a 5000 ft. lateral in the Delaware Basin? And how do you feel like the rates of return kind of compare in between those two?

Nick Sutton

Right now we are [AFE-ing] our 7000 ft., 7500 ft. laterals at about $11 million and the 5000 ft. laterals at about $9 million. And we believe that the rates of return on the 7500 ft. laterals will exceed that of the 5000 ft. laterals but we certainly are going to need a little bit more production history, a little bit more real data in order to support that estimation with a lot more confidence.

Ryan Oatman – SunTrust Robinson Humphrey

Okay. That makes sense. And I mean with all these wells, I mean five net wells or so set to come on in the next month or so, what should we be looking for in terms of production growth for Q3 and Q4?

Nick Sutton

Well, I wish I could answer that for you because if I were that prescient I’d be looking in a crystal ball or something like that. It’s just very difficult to say. I mean I’m looking at the fact that the Harrison well in just its third day of flow back is cutting five barrels an hour. Where could that well go? Who knows? It just has great potential. We know that the Harrison well is producing very, very well. I don’t know, I’m withholding judgment on the Castle and the Grand in the Powder River Basin but we’ll have that information very shortly.

So you kind of caught us, let’s say, I don’t know – at the drag strip? Our foot’s on the accelerator but we’re at 10 MPH rather than 150 MPH right now. I think give us a quarter of a mile down the road and we’re going to have a lot better feeling for how this dragster’s going to run.

Ryan Oatman – SunTrust Robinson Humphrey

Right, for sure. I’m looking at the same thing – I mean the first Delaware Basin well did almost 1000 barrels a day for 100 days and you’re extending the laterals here. I mean is it unreasonable to think about for Q4 rate 13,500 or 14,000 barrels a day?

Nick Sutton

14,000 barrels a day from the five wells?

Ryan Oatman – SunTrust Robinson Humphrey

No, I mean for Q4 given the up-flow from these wells?

Nick Sutton

Oh, for Q4? I don’t know. What I would suggest is, and I’m not trying to be coy, I’m just trying to say that on a public conference call I don’t think it’s appropriate for me to provide numbers given that the data would be mere estimates if not just outright guesses. But what I do because I ask myself those same questions, I kind of say “Well suppose the wells come in at X and decline or hold steady or whatever. What would that do for production?”

And in that way I can kind of bracket where I think it would be but that’s not a scientific estimate and it’s not something that I would disclose publicly. But it’s certainly something that especially with your experience in this business you would be capable of doing in order to ballpark it.

Ryan Oatman – SunTrust Robinson Humphrey

Sure, sure. I appreciate it. And in looking into 2015 in terms of the potential acceleration there, can you just kind of discuss kind of what informs your decision to accelerate more on say the Midland Basin side versus the Delaware Basin side?

Nick Sutton

I would not suggest that we are going to accelerate more in the Midland Basin than on the Delaware Basin. I think it would be more that we would be in a better position to be doing not “or” but “and.” And certainly what that means from a finite standpoint will depend on our scheduling and projections out into 2015 and 2016, but as I say I would not approach it as Delaware “or” Midland but rather Delaware “and” Midland.

Ryan Oatman – SunTrust Robinson Humphrey

That’s helpful. Thank you; I’ll hop back in the queue.

Nick Sutton

Thank you, Ryan.

Operator

Next question comes from Jeff Robertson from Barclays.

Jeff Robertson – Barclays

Thanks, Nick. Can you talk about plans in both the Permian and the Powder to test the zones other than the Turner and the Wolfcamp B?

Nick Sutton

Yes, not with a great deal of specificity. But I mentioned that as we were drilling the Castle and Grand wells we took cores, got some sidewall cores and did some pretty sophisticated logging such that those items of data certainly point to the prospectivity of the paraffin and the Sussex. And somewhere in that program as we ramp up a continuous program in the Powder River Basin we would look to test the paraffin and/or the Sussex as part of that program in 2015.

Certainly as we look at our development in the Delaware Basin and in the Midland Basin as well we will be testing other formations without a doubt. I mean we like what we’re seeing in the Wolfcamp B and you know, when you’ve got a horse that’s running well you want to run with it. But nonetheless we are actively monitoring what some of our neighboring operators are doing and in some cases we’re [non-participants] in those wells so we get good data. And it’s not lost on us that there’s very good production to be found in other parts of the Wolfcamp section in the Permian basin.

And so we will start to de-risk some of the other formations but frankly at the present time we’re riding the horse that’s running real well and we’re letting some of our colleagues in the field help us by de-risking acreage that is right near where we have our acreage positions.

Jeff Robertson – Barclays

Is it fair to think that those zones could be a part of the 2015 capital program then?

Nick Sutton

Yes.

Jeff Robertson – Barclays

And just on capital, is there a number or an activity level that you would like to get to in the Permian and the Powder that would allow you to make your operations more efficient and maybe cut some costs just because you’ve got a higher level of activity in a more efficient operator?

Nick Sutton

I think that’s absolutely correct, Jeff. On the Powder our current thinking is – and all of this is subject to change based on results and you know, external considerations – but it is that we would have one rig working continuously in the Powder. We’ve got one rig in the Permian right now. We would look to move that to two rigs and maybe six months later go to three rigs, and six months after that go to four rigs. Beyond that we’ll just have to see, but our approach is that it would be imprudent to try to go from one to four.

We want to do this in a very systematic way and certainly you can think that production slide will in fact work in your favor and so that’ll impact your [J curve] and negative cash flow before you can start going into positive in terms of your capital expenditure versus your cash flow. But by taking a more prudent approach it lessens the negative on the J curve and allows us to build internal capabilities at a [responsible] level. Right now we’re really very ready to go with the company [rates] and we will be building additional capacity and capability as we go forward.

We have been very pleased with our ability to hire impressive people in Midland and we all know that that is a market where the personnel are skilled, talented, experienced personnel. It’s a difficult market but we’ve been very happy with our ability to hire good people and we will anticipate that that will be a continuing focus for us as we go forward.

Jeff Robertson – Barclays

Lastly, Nick, just on that point – organizationally where are you all scaled in the Permian now? Is it two rigs or could you run three or could you run four just based on the organization that you currently have there?

Nick Sutton

I think that three or four would be pushing it. I would say two right now without much trouble and we will be backfilling in a way that we will be able to stand up a third rig at the time that we have scheduled. As you know from a personnel standpoint, from a staffing standpoint, from a whole organizational standpoint growth tends to go in step functions and sometimes you’re understaffed and sometimes you’re a little overstaffed. Right now we can take on some more work because we are anticipating the continuous drilling programs that we’ve talked about.

Jeff Robertson – Barclays

Thank you.

Nick Sutton

Thanks, Jeff.

Operator

Next question comes from Richard Tullis from Capital One.

Richard Tullis – Capital One

Thanks, good afternoon everyone.

Nick Sutton

Hi, Richard.

Richard Tullis – Capital One

Nick, with so much activity I guess to occur over the next month or so how are you looking at the next update? Would you look to do an intra-quarter update on the well results once you have them all in?

Nick Sutton

I would like to. It wasn’t been our practice but in anticipation of the activities that we’ve got over the next month, in some cases it’s two to three weeks, and by the time we actually get some wells flowing back and talking about the wells that would be later in August in the Permian [it’ll take] time to get some flow back so we have some real concrete data to share with you. If that turns out to be the end of August, beginning of September we’ll put our heads tighter and determine whether it’s appropriate just to give an operating update even though that’s not been our practice.

But you’re right, Richard, we’ve got a lot of things that are in the queue; a lot of hard work and good work that took place in Q2 that did not show up in just the hard numbers. But we’re anticipating that, I used the sort of metaphor of the rubber band: when that’s released we’re going to see a lot of good results we anticipate, and so a long answer to your short question. Yes, I would like to see us do an interim update.

Richard Tullis – Capital One

Okay. And I know you talked about the 7500 ft. lateral wells in the Permian. Is that Steamworks well a 7500 ft. lateral?

Nick Sutton

Yes it is, Richard.

Richard Tullis – Capital One

Okay. And then I guess the other, I believe you said two more wells after the ones that are currently in process. Would those be 7500 ft. laterals as well?

Nick Sutton

Yes, they are.

Richard Tullis – Capital One

Okay, I think that’s it from me. I believe everything else was already touched on. Thank you.

Nick Sutton

Thank you.

Operator

Next question comes from Jeff Grampp from Northland Capital Markets.

Jeff Grampp – Northland Capital Markets

Hey, guys, thanks for taking my question. Just kind of a strategic, high-level question for you, Nick: assuming something gets done at Aneth and you guys get the influx of liquidity I was wondering how you guys balance looking at acreage acquisitions versus development spending. It seems like there’s some decent opportunities to bolt stuff on at Reeves, but at the same time knowing you guys are anxious to get back to drilling at Midland and Highlight. So kind of how do you guys look at balancing accelerating development versus adding to the inventory?

Nick Sutton

That’s a good question. I pointed out that we’ve got 200 surface locations and let’s just pick, I don’t know, three or four laterals that, call it three to be conservative – that’s 600 wells at let’s say what, $8 million, $10 million a well? I mean that can keep a program going for a very long time. At the same time we recognize that we want to make sure that we’re backfilling our inventory and that when we see a good opportunity to acquire additional acreage that is in proximity to what we already have so that we get some operating efficiencies we will take a hard look at that.

There’s no doubt that just part of the business is always looking out in front of you, out the windshield and making sure that the opportunity set doesn’t shrink but continues to grow. However, just to reiterate, we’ve got a lot of room in front of us to drill some really good wells, and I would say our real focus is going to be on drilling and completing wells, increasing our production, increasing our cash flow; and that in turn enhances our ability to continue to accelerate drilling but also to make appropriate strategic acquisitions on the side.

The primary focus is going to be on drilling but we will pay attention to acquisitions, particularly to things that are right there in our neighborhood that are additive from an inventory as well as sort of an efficiency standpoint, operational efficiencies.

Jeff Grampp – Northland Capital Markets

Okay, that’s great color. And then just kind of on the HBP status in Reeves, can you remind us how that’s looking – if that’s still an impediment for you guys and maybe when we could see you transition to doing some more pad drilling?

Nick Sutton

We’re looking at pad drilling, and once we get into a continuous drilling program we would look to do pad drilling in Reeves County. Our acreage position is not absolutely all HBP but it is all HBP-able in a reasonable amount of time with a reasonable amount of activity. So that will not be driving our scheduling to a significant extent as we look at Reeves County.

Jeff Grampp – Northland Capital Markets

Okay, got it. And then shifting over to Aneth and I know it may be tough to handicap, but in terms of the oil contract I know you guys are looking to renew that starting in ’15. But maybe at least directionally do you have any indication relative to the 950 differential that you guys are at right now where that may turn out?

Nick Sutton

I would say that we’ve had a lot of discussions with Western and we’ve got a good relationship with them. And we have outlined where we think this is going to go, and I would say it’s not going to be significantly different than the 950. It’s likely to be up a little bit because the next iteration will be for at least a two-year period and so it will have built into it a little bit of an escalation.

Jeff Grampp – Northland Capital Markets

Okay, great. And then the last one from me, just kind of a housekeeping one, do you guys have a commodity breakout on the Harrison State well or maybe at least kind of what the oil mix was on that 24-hour IP rate?

Nick Sutton

58% oil.

Jeff Grampp – Northland Capital Markets

Okay, perfect, that’s it from me. Thanks, guys.

Nick Sutton

Sure, thank you, Jeff.

Operator

Next question comes from Noel Parks from Ladenburg Thalmann.

Noel Parks – Ladenburg Thalmann & Co.

Just a couple things: on the income statement I just wanted to ask, it looks to me that unless stock compensation runs higher than sort of the recent last couple quarters’ run rate it looks like you’re on track to be below the guidance that you gave for cash G&A. Am I reading that right?

Ted Gazulis

You know, I don’t think that we’re going to change anything with regard to how we look at guidance, I think rather than to kind of make… I think using Nick’s comment earlier rather than making up or estimating numbers that will flow out I think we’ll see what we see. I think the guidance number will probably remain the same.

Noel Parks – Ladenburg Thalmann & Co.

Okay, fine. And then just kind of along the same lines what’s your thinking on differentials for the second half of the year, rest of the year?

Nick Sutton

I mean there’s no doubt that differentials have widened in the Permian Basin and some of that is driven by refinery outages and those sorts of things. So to project what it’s going to be in upcoming months and quarters is very difficult. What we are seeing is directionally differentials have widened and there’s reason to believe that they are going to stay a little widened in the near term here. And as I say out longer than near term will take care of itself.

Noel Parks – Ladenburg Thalmann & Co.

Okay, and again sort of along that same line I haven’t had a chance to get into the (q) and see if there are any difference with hedging but your thoughts looking forward into next year on hedging?

Ted Gazulis

Noel, you know that we believe that hedging is appropriate as you’ve watched us over the course of the last years as a public company. We continue to believe that hedging is like every other form of insurance – we’ll add hedges in ’15, we’ll probably start thinking about ’16 as we get towards the end of the year. You know we work the hedge book pretty actively. Our philosophy hasn’t changed. The execution will change depending on market conditions, and to be honest I think one of the things that we all have to bear in mind is that when the financing transaction occurs that’ll give us another look at how we hedge as well.

So we’ll continue the way we’ve always been active in our hedge book. We won’t get out too far but we’ll definitely, we do want to hedge, we do need price insurance.

Noel Parks – Ladenburg Thalmann & Co.

Okay, fair enough. I guess and again of course the Aneth ownership may well change with a financing transaction, I mean your interest there. Any thoughts of your interest in hedging for your Permian production as opposed to what you’re sort of done with Aneth?

Ted Gazulis

We tend to look at our hedge book as covering the entire company. We don’t really think very much about which, well that’s not quite true but we don’t think a lot about which barrel comes from which well and which area. We have a stream of production; we look at our PDP curve, we look at what we think is out in front of us and like to hedge those barrels almost independently of where they come from.

Noel Parks – Ladenburg Thalmann & Co.

Okay, great. And just one more. I might have missed what you said on this but as far as the Big Horn Basin, can you just talk a little bit about sort of your range of expectations there from your partner’s drilling and also kind of refresh my memory on where things stand with lease terms out there?

Nick Sutton

Our acreage position is getting a little bit long in the tooth which is one of the reasons why this transaction that was proposed to us, one of many reasons it was attractive. It’s a very good operator. It’s done its homework. It has its view of the potential of this particular play in the horizontal phosphoria. We thought that was a good play as well, it’s just we were putting our money in the Permian and the Powder rather than in the Big Horn.

And so it’s a good transaction from our standpoint in that the operator is going to drill a test well and if it’s successful and we wish them all the luck in the world, we will have some ongoing opportunity there as well as an override. As to what the range of outcomes is going to be, it could go all the way from being dry to being a very good well that sets up a really good program. It will all depend on this first well, or depend heavily on the first well.

Noel Parks – Ladenburg Thalmann & Co.

Okay.

Nick Sutton

It is as we pointed out, as I believe I did in my comments, it’s to our knowledge the first horizontal phosphoria test and so it is somewhat exploratory in that regard.

Noel Parks – Ladenburg Thalmann & Co.

Gotcha. And actually talking about sort of breaking new ground in drilling, to what degree is your Reeves County acreage more, well I don’t know what portion of it you expect to be as highly pressured as what you’ve seen in your recent drilling. Are there any particular challenges in the drilling for your higher-pressure locations that you haven’t seen in earlier ones?

Nick Sutton

There’s a gradation of pressures and so it’s not as if, let’s say if one crosses a fault that’s a binding fault of some sort you go from one pressure to a dramatically different pressure. There’s a gradation. And certainly drilling in the higher-pressure areas presents some challenges but good drilling engineers are able to meet those challenges generally speaking. And certainly it also presents a challenge from a completion standpoint as we’ll be looking at pretty high pressures to break down that formation.

But I would point out again that the Renegade well which it completed at pretty high pressures, we managed to get away with 9 million lbs. of sand so it went smoothly and the service company that did that job along with our team, they have a lot of experience as well. So that team worked very well and certainly overcame any pressure issues in the process.

Noel Parks – Ladenburg Thalmann & Co.

Great, that’s all for me, thanks.

Nick Sutton

Thanks, Noel.

Operator

Next question comes from Andrew Smith with Global Hunter Securities.

Andrew Smith – Global Hunter Securities

Hi, can you elaborate on what drove the higher LOE in the Permian Basin and any initiatives you’re taking to lower that?

Nick Sutton

Yes. Just without going into a lot of detailed explanation you’ll recall that one of the areas in which we’re active, we refer to it as Gardendale. And Gardendale does have some development. I mean it’s not dense development but it’s certainly not like Reeves County where you have to really hunt to find anything living. And we have committed to being very good neighbors in that Gardendale area and we’ve undertaken equipment upgrades and things of that nature that are more or less one-off expenditures that will help with just any kind of [acre relations] and things like that that might take place in that area. That’s been a driver of some of the LOE increase and that’s kind of a one-off.

In addition in the Gardendale area our commercial saltwater disposal well went down and that forced us into trucking a fair amount of water. Now that situation is expected to be resolved sometime this month so that again is a one-off that we had to deal with. And then other and more generally we’ve got very strong cost control initiatives and the team in the Permian is very much aware of this. And costs are coming down and we expect them to continue to come down. So it’s a combination of when will activity [goes to] a one-off and we do expect that our LOEs will come down.

Now the Aneth I have to say has been spot on. They’re right on the plans and so that has not been a contributor to the LOE issue. It’s been in the Permian and it’s more specifically focused and the team in the Permian is very, very much on top of this. So it will get fixed.

Andrew Smith – Global Hunter Securities

Alright, thank you.

Operator

Next question comes from [William Tiji at Bedo Capital].

[William Tiji – Bedo Capital]

Yeah, hi. Hi Nick, hi Ted.

Nick Sutton

Hi, Bill.

[William Tiji – Bedo Capital]

My question – you mentioned Helmerich earlier in the call and I presume you’re using their Flex Four rigs I guess. They are really earmarking a high percentage of their new builds for the Permian Basin. Can you give us an idea of what their rig rate costs have been there and the trend, and then maybe also touch on a percentage trends and other service costs?

Nick Sutton

We are using a Flex Three rig and it’s running about $25,000 a day. There’s no doubt that there is pressure generally but I think the rigs being mobile they have a way of taking care of themselves. But I’ll give you an example of one of the areas where we’ve seen pressure and that’s with frac sand. We could [use] 9 million lbs. on one job – that’s a lot of sand. That’s a lot of railcars and that’s a lot of trucks. And so that does pressure it.

It does adjust the cost; it’s also getting the sand and that’s why we’re working with some of the big service companies, it’s helpful. But even they have at times trouble getting adequate sand, particularly if you’re looking for one mesh versus another mesh if you’ve written 30/50 as opposed to 20/40 or what have you. So we are seeing some pressures not just in upward pricing but in some cases getting ahold of frac sand, but again, working with both the better and more established service companies that is a manageable thing.

Other areas where these guys are seeing pressure is just getting a hold of truck drivers and people like that that are vital to the logistical efforts behind drilling and completing wells. And so that’s not our problem directly but it affects the people who are providing goods and services to us. It’s a tight area; it’s a vibrant area. There’s so much going on down there it’s just exciting to see.

[William Tiji – Bedo Capital]

Okay, thank you.

Nick Sutton

Thanks, Bill.

[William Tiji – Bedo Capital]

You bet.

Operator

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

Nick Sutton

The only closing remarks that I would have are one, thank you very much for joining in on this call with us. The second thing I’d point out, which I think I pointed out adequately before is we got a lot of work done this quarter. It didn’t quite show up in the numbers as reported but we got a lot of work done and it’s been good work, and I think that we’ve got the springboard of heading toward higher production, higher revenues, higher cash flow.

As Ted pointed out we think that the quality of our assets and the quality of the work that we’ve done is not presently recognized in our stock price and I think at some point, my personal opinion is at some point in the not too far distant future there are going to be people saying “How did I miss that?”

We look forward to continuing to talk with you, and if anybody has any follow-on questions you know where to reach us. We stand by, we’re here to help. Again, thank you very much.

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