HighPoint Resources Corp
Q1 2015 Earnings Call Transcript

Published: 8 May 2015

[Operator:]

Good day, ladies and gentlemen, and welcome to the Bill Barrett Corporation First Quarter 2015 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. As a reminder, this call is being recorded. I'd like to introduce your host for today's conference, Jennifer Martin, Vice President of Investor Relations. Ma'am, you may begin.

[Jennifer C. Martin:]

Good morning, everyone. Thank you for joining us. We are very pleased with our first quarter results and here to discuss these results today are Chief Executive Officer, Scot Woodall; and Chief Financial Officer, Bob Howard. And briefly, before we get started, I need to remind everyone to read the disclosure statements provided in the earnings release posted to the homepage of our website. We will discuss forward-looking statements such as guidance and well performance, for which there are cautionary statements provided. During our discussion, we make reference to non-GAAP measures, such as discretionary cash flow and adjusted net income. Reconciliations to the appropriate GAAP measures may also be found in the earnings release. A report on Form 10-Q was filed this morning and is also available on our website. So, with that, I will turn it over to Scot Woodall to get started. Scot?

[R. Scot Woodall:]

Thank you, Jennifer. Good morning and thank all of you for joining us. I have a few key messages that I want to deliver this morning. First off, the first quarter production beat is a direct result of the extended reach lateral program in the Northeast Wattenberg portion of the field. Secondly, really since initiating this extended reach lateral drilling program less than one year ago, we have refined our techniques in terms of completions and drilling, these most recent wells that you see reflected in the report are some of the new completion techniques, and they are significantly outperforming our previously completed wells. I also want to point out that our Northeast Wattenberg extended reach lateral development program will yield stronger returns than standard linked lateral wells. We estimate that on our acreage position, more than 80% of our acreage will be developed in the future on extended reach lateral development. We remain very well-positioned financially, in terms of our balance sheet, liquidity, debt metrics and hedge positions. So, let's update each of these points in a little bit more detail in the next following comments. The last few months of production data from our extended lateral program continues to validate our performance assumptions about the play. These results support our confidence in the play. We have drilled and completed 35 extended reach lateral wells to date, with 25 wells on sales. As discussed over the past several months, we have tested a number of drilling and completion techniques in these wells. We have done a great deal of work in a very short period of time. The results of these tests are indicating a preferred combination of mechanics that include completing the wells with plug-and-perf rather than sliding-sleeve using approximately 1,000 pounds of sand per foot, completing 55 stages versus 40 stages and controlling both the water and gas flowbacks. It is still early, but we believe that the preferred mechanics are positively impacting the overall well performance. Early production rates indicate as much as a 40% improvement over previous techniques. Today, we also announced the results from four new wells that reached 30-day IP rates since the last time we reported. These four wells averaged 608 barrels of oil equivalent per day per well over the peak 30 days. All four of these wells were completed with plug-and-perf and 55 stages. To date, the average 30-day rate for the 20 wells is 581 barrels of oil equivalent per day per well. To date, we have released 60-day rates for 16 wells. Of these wells, the wells with plug-and-perf completions have averaged a 60-day rate of 557 barrels of oil equivalent per day versus wells with sliding sleeves completions that have averaged 457 barrels of oil equivalent per day over the 60 days. While many of you know I'm not a big supporter of releasing 30-day and 60-day rates. However, we are providing those for you today. More importantly, the niche is – than the 30-day or 60-day rate is the shape of the production curve and the corresponding pressures that will ultimately drive recovery. Impacting our overall cost structure of these DJ wells continues to be a focus of the company. Our current drilling and completion costs for these wells is $6.25 million per well, representing roughly a 25% reduction from Q4 activity of 2014. We expect and continue to drive operating efficiencies and identifying opportunities for overall cost structure reduction. We expect the returns on the extra well development program to be in the range of 25% to 50% depending upon ultimate recoveries at current cost. Next, to emphasize our competitive advantage, our Northeast Wattenberg acreage position is largely undrilled. Future well placements are not severely impacted by old vertical wells or 640 linked horizontal wells. Therefore, our acreage position is highly conducive to extended reach lateral development. We estimate that at least 80% of our acreage will be developed with XRL drilling, offering the highest returns in our portfolio. Also during the quarter, we completed eight standard linked lateral wells that were drilled in 2014. These wells are located in the southern portion of the Northeast Wattenberg acreage position and are currently on sale. We expect these wells to be at a peak rates later in the second quarter. The remainder of our 2015 activity will be focused on the DJ Basin. Nearly all of our remaining activity will be on drilling completed extended reach lateral wells. I'll now turn the call over to Bob to discuss in more detail our financial position and our updated guidance.

[Robert William Howard:]

Thank you, Scot. We're very pleased with our first quarter results. Solid production performance, including production growth in the DJ Basin that was up 82% year-over-year and up 28% sequentially, generated cash flow that well exceeded consensus numbers for the quarter. Our strong first quarter performance supports increasing 2015 guidance. First quarter production beat was attributable to improved well performance. We are increasing production guidance for the year by 7% to 5.9 million barrels of oil equivalent to 6.3 million barrels of oil equivalent, attributable to improved well performance and increased working interest in a few wells. We expect second quarter production will be 1.5 million barrels of oil equivalent, with quarterly production roughly flat until the fourth quarter when we expect an uptick due to the timing of wells coming online. Our capital expenditures are anticipated to be at the higher-end of our $240 million to $280 million guidance range to reflect an additional 10 net wells to be drilled in 2015 compared to our original plans. This increase is the result of an increased working interest in several DJ wells, as well as participation in some non-operated wells in the Chalk Bluffs area that continue to understand our position in that area. We are also planning for the cost of drilling three net wells in the Blacktail Ridge for our portion of an eight-well drilling obligation under the EDA. These Blacktail Ridge wells will be completed at a later date. Our lease operating expense guidance for 2015 is increasing to $48 million to $52 million to correspond with the higher expected production. Typically, LOE is seasonally higher in the first quarter. The unit cost in the second quarter is expected to be at or similar or slightly lower level. We are taking several actions to reduce future LOE, with most of the impact we realized starting in the third quarter, which would appreciably reduce LOE per unit. For the full year, the midpoint of our updated guidance indicates an LOE rate of $8.20 per barrel of oil equivalent compared to our original guidance of $8.42 per barrel of oil equivalent, which reflects the benefit of increased production. We have one cost commitment related to discontinued drilling operations. We're actively negotiating a settlement for this commitment, but if we are not able to reduce or deploy this obligation, we could incur an additional $2 million of unused commitment expansion in 2015, which is being reflected in our updated guidance. Other notes in regards to modeling our operations, the first quarter production tax expense was reduced for an annual true-ups of certain property tax bills. On a going forward basis, we expect our production tax rate to be approximately 8% of pre-hedge revenue. Annual G&A guidance is unchanged, but it was more heavily weighted to the first quarter due to beginning of the year cost and one-time costs associated with employee severance that increased first quarter expense disproportionately to the remaining quarters. Lastly, based on second quarter production guidance of approximately 1.5 million barrels of oil equivalent, we should be roughly 95% hedged for both oil and natural gas as the WTI oil price of $90.39 per barrel and the Rockies natural gas price of $4.13 per MMBtu in the second quarter with no NGL hedges. With the recent upturn in oil prices, we recently lay in a few small hedge positions for 2016 and early 2017 locking in WTI oil prices in the $63 per barrel to $66 per barrel range which are included in the updated hedge table in the press release. One item of clarification for the quarter is an update in the pre-hedge price realizations for NGLs and natural gas. The preliminary revenue estimates that were announced in April were based on classifying deductions related to our percent of proceed contracts for processing NGLs as deductions from the NGL revenue stream. Beginning with the first quarter of 2015, we are now allocating those revenue deductions separately to our natural gas and NGL revenue streams. Therefore, the first quarter NGL, natural gas average sales prices will be a better indicator of our expected realizations going forward. Turning to the balance sheet, we remain well-positioned. A $375 million borrowing base under our bank credit facility was recently reaffirmed. We extended the maturity date of the credit facility to April 2020 with no significant changes to the covenants and terms. We have zero drawn on the facility. We received $43 million in the first quarter for the refund related to the Roan Plateau settlement, and we ended the quarter with cash and short-term investments of $149 million. We will not need to increase debt during the year with ample cash and short-term investments to fund the amount that capital expenditures will exceed discretionary cash flow. We ended the first quarter with a net debt to trailing 12-month EBITDAX at 2.4 times. Effectively adjusting for the 2014 asset sales, net debt to annualized first quarter EBITDAX was 2.8 times. And we have commodity price hedges and placed for over 90% of remaining 2015 oil and gas production. Our 2016 hedge position is approximately one-half of our 2015 hedges. To wrap up, we have a strong liquidity position, excellent hedges in place and reiterate our Northeast Wattenberg operations are going very well. Our first quarter presents a very solid foundation for the remainder of 2015. That concludes our prepared remarks. And, operator, would you please open up the call to questions?

[Operator:]

Thank you. And our first question comes from Chris Stevens from KeyBanc. Your line is open.

[Chris S. Stevens:]

Hi, guys. In the press release, you guys talked a little bit about the 30-day rates on four new wells and the DJ with different amounts of sand. Can you just quantify a little bit, any sort of performance difference you're seeing from those wells, the one with more relative to less sand?

[R. Scot Woodall:]

It's probably too early to make a difference that those four wells, two of them are completed with a 1,000 pound per lateral foot and two of them are completed with 1,300 pounds per lateral foot. I would say, to date, it's probably hard to see much differentiation in those performance. As we've said in the call, those four wells though with the plug-and-perf 55 stages are clearly outperforming those with sliding sleeves.

[Chris S. Stevens:]

Okay. And...

[R. Scot Woodall:]

I think maybe with more time, you might see some differentiation between 1,000 pounds per foot and 1,300 pounds per foot, but we're still early.

[Chris S. Stevens:]

Got it. Okay. And are there any plans to kind of keep pushing the limit on how much sand you can put in the wells and seeing what your incremental performance benefit is from maybe pushing out a little bit higher?

[R. Scot Woodall:]

I don't know if that's the main driver, but I think we obviously always looked – try to optimize and tweak various techniques and things. So, I'm sure we will do some tweaking as we go forward. But I think we've kind of taken the major steps going from where we were last summer to where we are at year-end and Q1.

[Chris S. Stevens:]

All right. Thanks a lot, guys. Great quarter.

[R. Scot Woodall:]

Thanks, Chris.

[Operator:]

Our next question comes from Jason Wangler from Wunderlich. Your line is open.

[Jason A. Wangler:]

Hey, good morning. You kind of maybe tapped a little bit on it there on the last couple of questions, but it sounded like at least in the prepared remarks that you're getting a little bit more refined, I guess, on your completion as far as how much sand you want to use plug-and-perf versus sliding sleeve. Can you maybe talk about, as we go throughout this year kind of the variability, you're going to do in completions or are you kind of maybe settling into pretty understood kind of going forward plan at least from a high-level?

[R. Scot Woodall:]

Yeah. From a high-level, yeah, Jason, I think we are talking about staying with the plug-and-perf and staying with those 55 stages and roughly about 1,000 pounds per foot of sand. I'm sure we're going to do a couple of minor tweaks, but I think overall, that's kind of what we settled in and that's kind of what the early performance data is suggesting to us is kind of the right range to be in.

[Jason A. Wangler:]

Okay. And then maybe just sticking to the DJ, you talked about, I think Bob said that flattish production for second quarter and obviously, the timing of the XRL showed pretty nice in the first quarter. As you look through, is there an idea in your head of what we're going to see as far as completions throughout the year? Is it back-end loaded or is it third quarter? Just kind of where you're seeing – what we're going to see from the well that you do bring online?

[R. Scot Woodall:]

It's probably – it's anything a little bit more left to do in Q2 and Q3 and probably not as much in Q4 and that's just really because we're running multiple rigs through February of this year. So, you still got a little bit of work being done kind of at the end of Q1, beginning of Q2, that will push that distribution of wells coming online probably more in Q2 and Q3 versus Q4.

[Jason A. Wangler:]

Okay. And it will just be as you have talked about before, I guess, just the cleanup and the time it takes to get you to the peak rate and that's why we'll see that ramp the production itself, actually ramp up at the completions are being done, call it, now and the next couple of months?

[R. Scot Woodall:]

Correct.

[Jason A. Wangler:]

Okay. Thank you. I'll turn it back.

[R. Scot Woodall:]

Thanks.

[Operator:]

Our next question comes from Dan McSpirit from BMO Capital Markets. Your line is open.

[Dan E. McSpirit:]

Thank you and good morning. Want to revisit that last question. If I heard you correctly, you stated that there will be more completions in the third quarter versus the fourth quarter. If that's correct, what does that mean for an exit rate this year?

[R. Scot Woodall:]

Quarter-over-quarter going out, I think we're still kind of thinking that it's roughly fairly flat in this 1.5 million barrels of oil equivalent to 1.6 million barrels of oil equivalent for each of the remaining quarters. So, I would think that we're relatively flat on an exit rate Q4 versus Q1.

[Dan E. McSpirit:]

Okay, great. And for me another question here. Are the locations of the XRL wells such that you believe the Northeast Wattenberg leasehold has been de-risked at this point?

[R. Scot Woodall:]

Yeah. I think a majority of it has been, Dan. We still haven't gone and tested the ultimate like southeast corner or the northeast corner and that's really more of a relationship of the infrastructure build-out. If you remember, everything is coming from the north to the south or from the west to the east in terms of roads, pipelines, all those types of things and so we're still methodically walking across that acreage is what we're doing.

[Dan E. McSpirit:]

Okay, great. And then lastly here, you stated that 80% of the remaining leasehold can be developed with these extended reach lateral wells. What does that mean in terms of location count? I am trying to get a handle on the inventory here.

[R. Scot Woodall:]

Yeah. It puts that extended reach lateral inventory count a little bit north of 2,000 wells.

[Dan E. McSpirit:]

Great. Thank you.

[Operator:]

Our next question comes from David Tameron from Wells Fargo. Your line is open.

[David R. Tameron:]

Good morning. Nice quarter on your end.

[R. Scot Woodall:]

Thank you.

[David R. Tameron:]

If I think about the XRLs and, Scot, just look at the type curves, I know you had a – I think this presentation from a prior conference; we had all these plotted. The EURs, what's your best guess on these? I think the most recent completion, where are these EURs tracking to?

[R. Scot Woodall:]

I'm probably not going to quite answer your question, David. But I would say that on those previously reported ranges of that presentation that you're quoting, I would probably say that those sliding sleeve early completions are at the lower end of that range. And I would probably say that the new well completions with the 55 stage and the plug-and-perf are at the higher end of those ranges.

[David R. Tameron:]

Okay.

[R. Scot Woodall:]

And so when you think about going back to that previous question, you think about 2,000 wells of inventory and you do more of them are going to be towards the 55 stages, plug-and-perfs, we kind of expect it to be more at the higher end of that range going forward. You have to remember, we're on a pretty still limited dataset. We only have 20 wells that we reported some results on and you probably have three or four well types in each of the five different buckets of completion things we've done. So you're still pretty early, but if – and I'm sure we will update the investor presentation over the ensuing next month or two. Some of the plots that we have that are now by completion types are pretty impressive, supporting the overall statements that I'm making.

[David R. Tameron:]

All right. That's helpful. And if I think about – not to jump years, but I am going to – if I start thinking about 2016, can you frame it up for us as far as how you think about cash flow CapEx? I know you have liquidity this year. How do you think about that in 2016? I don't know if that's for you or Bob, but how would you guys think about the balance sheet and what you'll be willing to spend?

[R. Scot Woodall:]

I think obviously it's early to really comment on that, David. I think we try to give our planning department at least a week or so off after the rigor they went through getting ready for 2015. But it is a balance of all the things that you're talking about. So, clearly, we're looking at impacting cash flow and EBITDAX by still looking at the balance sheet. It also depends on where commodity prices land, where our hedge position lands. So, there's just a lot of moving parts to that that I think we probably – and where service costs fall in line with commodity prices. So, there is just a lot of still moving things there to directly answer you. But I'm sure that all – I'm sure we will run a bunch of different scenarios and look at all options and opportunities.

[David R. Tameron:]

All right. I'll let somebody else jump in. Thanks.

[Operator:]

Our next question comes from Drew Venker from Morgan Stanley. Your line is open.

[Drew E. Venker:]

Hi, Scot. I just wanted to follow up on Dave's question. Just philosophically, can you give us a sense of how much you are comfortable out spending? And I mean the results look good, so whether that influences your decision to spend or allocate capital in 2016?

[R. Scot Woodall:]

Yeah. It's still going to be part of that balance. So, probably not ready to speak directly to 2016. Yet clearly, seeing the results gives us a lot more confidence. If you think about where we were 90 days ago in terms of all of these factors that we're rolling into, I think 90 days ago, we were having a lot of discussions on where commodity prices were going to go, we were having a lot of discussions on where we thought service costs were going to go, we had a lot of discussions about where our EUR and well performance was going to go. And I think we've got a much better vision, now 90 days later, than what we did going into the beginning of this year. And I am sure that picture will continue to clarify itself over the ensuing next few months as well.

[Drew E. Venker:]

So, Scot, I guess I wasn't trying to belabor this or anything but I think last year coming into 2015, you guys said you probably didn't want to spend more than 150% of cash flow. Is that the same thinking, just in any given year? Is there some kind of cash flow relationship that you guys think about internally?

[R. Scot Woodall:]

I would say – I don't know yet, I guess, would probably be the right answer to that. On a...

[Robert William Howard:]

Yeah. It's getting good returns on the capital we're investing and we'll end the year with a borrowing base undrawn while we'll have some cash on the balance sheet. And we will be looking at oil prices. As far as the – what we have spent, I think that would be one factor just as how much cash flow will help to generate that, but also the returns on what we would model out is the cash flow we would generate to them in the payout period. So, just to put one factor as a governor to our spending, I don't think that's fair at this point in time. But we're getting good returns and we'll end the year, this year, beginning of the year with still a fair amount of liquidity with the borrowing base that's expected to be undrawn. That will give us flexibility to make some decisions long-term, but as Scot said, we're well ahead of – your questions are well ahead of our planning stage here. So, give us a few more months and we'll be able to narrow that in. But we do like what we see and like the returns we're getting, and the cash flows are generating at these oil prices.

[Drew E. Venker:]

Thanks.

[Operator:]

Our next question comes from Brian Corales from Howard Weil. Your line is open.

[Brian M. Corales:]

Good morning, guys.

[Robert William Howard:]

Good morning, Brian.

[Brian M. Corales:]

Just more a question on the spacing. The well results look pretty good now. And I was wondering if you've tested the proper spacing? And I am assuming all these extended laterals were in the B zone. Have you all tested this and the Cs – the extended lateral in the C zone yet?

[R. Scot Woodall:]

Yes. There has been some C zone tests that have been incorporated in these numbers as well. So, so far, Brian, what we've been drilling is 80-acre spacing per horizon. So, where we have – like for example, where we have two horizons, we're drilling 80 acres per horizon. So, you can think about that as 40-acre spacing on the Niobrara or 80-acre per horizon. And some of those have been a little bit closer together in some instances, but primarily, it's been 80 per horizon.

[Brian M. Corales:]

Is that something that you may want to downspace or try a downspace test at some point?

[R. Scot Woodall:]

It could. Like I said, we have a couple examples that are probably that we've done that we're monitoring that, or probably more in that 65-acre type of spacing. And I'm sure that will probably factor into some of our decisions about if you try to go further or not. We're still probably in the stages of exploiting those different benches. I mean you brought up the C, which we have been exploiting it some. We think there is some potential of the A on horizons and we've done limited drilling of the Codell, only a few wells. So, there is probably going to be some focus on some of the other horizons coming later this year or next, I would think.

[Brian M. Corales:]

Okay. And then just that went into my next question but the – is there a limit, I mean a thickness whether it's in the Codell or the A? We started hearing from some other companies that may be your neighbors testing the Codell on thinner and thinner sections or potentially even the A. Is that perspective over your acreage? Can you maybe try to quantify that a little bit?

[R. Scot Woodall:]

Sure. If you think of the Northeast Wattenberg acreage position, if you drew a north-south line like in the middle of our acreage, that would probably roughly represent a seven-foot Codell line. And so I know some of our peers are testing seven-feet, eight-feet, nine-feet. So it may work across the – half of our acreage. We took some cores that I alluded to in the end of last year, Q1 of this year and three different wells across our acreage position, really looking to test some of these other horizons. So, they were cores that – core the Niobrara A, the B, the C, the Codell, and then we even took some Greenhorn core and one of those wells. And so we are trying to look at the mapping and look at the prospectivity of some of those other positions. I would say it looks like the northern acreage position. It does look like you can map A into the northern acreage position at least based on the core work that we've done today. And so, it does have some promise that looks to that as probably something that will get on our radar screen to test, like I said, may be end of this year, beginning of next year. So, I think a lot of that work is being done and we will probably have some more clarity once the geologists have time to digest all the results.

[Brian M. Corales:]

Thanks, guys. Helpful.

[R. Scot Woodall:]

Thanks.

[Operator:]

Our next question comes from David Beard from IBERIA. Your line is open.

[David E. Beard:]

Hi. Good morning, everybody. Nice quarter.

[R. Scot Woodall:]

Thank you.

[David E. Beard:]

My questions – two questions. First, could you just talk a little bit about what you feel is the timing relative to midstream expansions in Lucerne 2 and how that may impact you guys? And then second, philosophically relative to 2016 hedging, is it a question of price of the commodity or timing getting closer to the end of the year before you would be willing to hedge out more?

[Robert William Howard:]

Look, I'll address the – as far as the infrastructure in the DJ Basin and from what we hear and understand is that the Lucerne 2 processing plant should come on in the second quarter, along with some additional plant compression and we expect to get some benefits from that. So, I think it's fairly imminent and that we have had a little bit of impact from the midstream and our DJ operation, but nothing that's not expected within our guidance. So I think we're imminent there and that should be – any issue we have should be resolved quickly here. Regarding hedging, we make good economics at current oil prices. We don't probably like those prices based on a historical basis, but we have economics and rates of return that are competitive at the current capital costs. We have added a few hedges and you look at our updated hedge table and that reflects a few hedges we've added to $65 range and that's just putting in the next layer. And as we get closer to the end of the year, we'll continue to layer our long-term goal. It has been and will continue to be being 50% to 70% hedged for the next 12 months and we're in very good position for that today for the next 12 months to 18 months. As we get closer to the end of the year, I want to take some of the risks off the table and we'll be willing to hedge certainly at today's prices and if it's higher price, we'd also certainly hedge at those prices. So, kind of layering it in. We did take a small layer here with a – where the oil prices were over the last week or so and we'll continue to look at those markets and by the end of the year, we'll expect to add some more hedge layers in.

[David E. Beard:]

Okay, great. Thank you for your time.

[Operator:]

Our next question comes from Jeffrey Connolly from Clarkson Capital Markets. Your line is open.

[Jeffrey R. Connolly:]

Hi. Good morning. In the prepared remarks, you mentioned picking up some additional working interest. Are you guys seeing an opportunity to lease some of that acreage or are the operators intent on keeping it and just going non-consent for a couple of quarters?

[R. Scot Woodall:]

Yeah. The working interest that we're referring to is some non-consent working interest that basically just increased our working interest in existing wells that we had on our schedule to drill. To answer your overall question, by and large, I think most of the acreage is held by somebody. So your opportunities are more and swaps or trades or our approaches or things like that. I don't think there is really too much available acreage that sits out there today.

[Jeffrey R. Connolly:]

Okay, thanks. That's helpful. And then you guys also mentioned participating in a couple of wells as a non-op up in Chalk Bluffs, what zone are those targeting and then who is the operator?

[R. Scot Woodall:]

It's mostly Codell and the major players up in the Chalk Bluffs is really EOG and Anadarko. So, most of our participation has been with those guys.

[Jeffrey R. Connolly:]

Okay, great. Thanks, guys.

[Operator:]

Our next question comes from Dan McSpirit from BMO Capital Markets. Your line is open.

[Dan E. McSpirit:]

Thank you. A few more questions, if I may? What do you model as the first year decline rate on the extended reach lateral wells to get to the higher end of the 600 MBoe to 900 MBoe type curve?

[R. Scot Woodall:]

Dan, I probably wouldn't know that one off the top of my head. So, Jennifer may have to follow up with you on that one.

[Dan E. McSpirit:]

Okay. Great. And then earlier, you gave the answer of 2,000 locations when I asked about the inventory count on the remaining leasehold. Is that the Niobrara B only, Scot?

[R. Scot Woodall:]

No. That would include – just B and C is what that would include. So, 80-acre spacing on B and C is basically what that's saying...

[Dan E. McSpirit:]

Okay, great.

[R. Scot Woodall:]

...where we think geologically C is applicable.

[Dan E. McSpirit:]

Right. Got it. And then, do you view your completion technique, the new and improved completion technique different than other independents in the basin or is it now more consistent?

[R. Scot Woodall:]

I'm sure despite some nuances from operator to operator, but we're doing basically the plug-and-perf and you're doing like the zipper frac on a multi-well pad. Fluids, I'm sure are probably slightly different, but I wouldn't think they are largely different. And then like, say, we've been pretty big proponents of this flowback where we're controlling the water flowback rates and we're trying to control the GOR as well and thinking that's improving our well performance also.

[Dan E. McSpirit:]

Okay, great. And then, lastly here and apologies if you mentioned this in your prepared remarks, but the drilling complete costs on the plug-and-perf rather than the sliding sleeves or versus the sliding sleeves?

[R. Scot Woodall:]

Really, we model that about flat, if the number of stages are the same, if you're on a multi-well pad. The sliding sleeves are cheaper if you're on a single-well pad, but if you're on a multi-well pad, basically you have zero downtime as you're going back and forth between multiple wells. And so that cost ends up being kind of flat.

[Dan E. McSpirit:]

Okay, great. Thank you.

[Operator:]

And our next question comes from Mike Kelly from Global Hunter Securities. Your line is open.

[Michael Kelly:]

Hey, guys, good morning.

[R. Scot Woodall:]

Good morning, Mike.

[Michael Kelly:]

Really seems like an inflection point quarter in the Wattenberg here. And you've maybe answered a lot of questions operationally. As we look forward, though, maybe one of the other looming questions on you guys is 2016 and a lot of people, I think, were dancing around the point for next year on the balance sheet side of things. With hedges rolling off and activities slowing, it looks like leverage steps up quite a bit and – just wanted to hear your confidence that maybe you've got a lot more comfort there than maybe some of us have. And one of the things that potentially could be a real quick fix and cure is selling the 48,000 acres you don't have in the northeast portion of the Wattenberg in the overall basin. So just wanted to hear, Scot, the comfort on the balance sheet side here that you guys could maybe fix it quicker than some of us think. Thanks.

[Robert William Howard:]

Well, I think looking at the balance sheet, we do have the two senior notes. The first maturity is in 2019 and we just redid our credit facility for 2020. So our short-term maturity, we have a long time for any maturities with respect to the – looking at our overall debt position. We still have a liquidity in order to develop the properties and there is a tremendous resource there that has to be developed on a pace that's appropriate for the commodity prices and the rates of return. We're getting good rates of return. So is there a quick fix to the balance sheet? You have followed us in the past that we do look at properties that aren't getting capital and determine exactly what – how those properties fit in our portfolio. But I think we have the asset base and we'll have the ability to continue to generate cash flows from those asset base even at today's commodity prices that we'll be able to increase production, increase cash flow and increase our – and increase our cash flow that manage it. But we just have several options and in different areas and with the assets and the balance sheet in good shape that we don't have any pressure, I guess, I'm not – I think we're in good shape now. Is leverage higher than we want to be? Yes. Do we have the assets? I think with the 2,000 locations Scot referred to that can generate the cash flows to fix that as we get very efficient in our operations, I think that's the case and we'll continue to work toward it.

[Michael Kelly:]

Okay. So in terms of – yeah, the liquidity is there, but having a net debt to EBITDA that maybe approaches six times in 2016, is that something you are comfortable just managing through given that liquidity, or is it something you would like to take down through some other action?

[R. Scot Woodall:]

I don't think we have any kind of internal model that would ever get you to six times.

[Michael Kelly:]

Okay.

[Robert William Howard:]

And we watch that. We watch that very much as we plan out. So we aren't modeling a six times or we are not modeling that our debt is above the 2.5 goal that we've stated and we would like to – we expect to get to over time and it's harder to get there, of course, in $65 environment than a $90 environment. But I think our assets allow us to do so. Yeah, six times, that's a number that – probably need to see your model and see where that comes, because we don't have that level.

[Michael Kelly:]

Yeah. I'll work on that. Maybe one of the things that's a critical factor that is the – like your PDP decline rate or your exit decline rate from the end of 2015 and how we should think about that going forward.

[R. Scot Woodall:]

I think maybe you need to work with Jennifer on your model a little bit is probably what I would say.

[Michael Kelly:]

All right. Fair enough. Thanks.

[Operator:]

And our next question comes from Paul Grigel from Macquarie. Your line is open. Paul Grigel - Macquarie Capital (USA), Inc. Hi. Good morning. Just on the differentials, could you guys just talk on what your outlook is in the Wattenberg? It seems as if they're tightening up. And then just maybe also briefly touch on the Uinta program on if it's coming pretty dramatically. If crude were to rally here at the higher levels, would we expect that to come out and widen a little bit given on a percentage or is that still based on absolute dollar value?

[Robert William Howard:]

Well, within the DJ Basin, we do see some positives toward the basin differential, but for our internal purposes, we're going to – still like modeling in that $9 to $10 range and hope to be surprised to the upside, but we expect that that's somewhat fixed. I don't see that being tied to WTI prices. So, it's a fixed cost. In the Uinta, we did have about $15 in the first quarter and that reflected a combination of higher differentials early in the quarter one contract rolling off. We're planning for the remainder of the year about $12 to $14 and for the most part, that's fixed today in the Uinta. As you know, in the past there has been a percentage kind of tie to the percentage. So, I can't speak to what the purchasers will do if prices were to go up. But right now, we're kind of modeling at this current price environment about a $12 to $14 deduct overall including a little bit of trucking – includes a bit of trucking, about $12 to $14 and a $60 WTI price. Paul Grigel - Macquarie Capital (USA), Inc. Okay. That's helpful. And then turning to the unused commitment and increasing the charges there, is that a run rate that we should expect going forward for the life of those contracts? And then, could you maybe provide a little bit more color on the potential settlement that you guys touched on earlier in the call?

[Robert William Howard:]

Well, the commitments we have about our pipeline commitment of about $1.5 million a month and that does have some term into 2021 timeframe. We do have one service commitment of about $2 million, that's one-time only and we're looking to see how we can best deploy that or settle it or negotiate it. We're actively doing that. It's something with the drilling operations that have changed over the years. So that $2 million, which we increased our guidance by is one-time only for this year. We're hoping we're able to work to either reduce or eliminate that. As far as going forward, we do have the Ruby Pipelines, Ruby and associated contracts, again, as mentioned, about $1.5 million a month. That's not a lot of market for that today. So, we see that. It's probably an expense we should plan for. But as gas markets change and whatever, that's just what the relative value is for the gas between the west side of the Rockies where we can deliver the gas to the upper Pacific Northwest where it's delivered and we don't have a crystal ball that says that it will change. But there are some things that could happen to make that become more valuable with needing to get the gas from Rockies to the upper Pacific. Paul Grigel - Macquarie Capital (USA), Inc. Okay. That's helpful. Thank you.

[Operator:]

And we have a follow-up from Jason Wangler from Wunderlich. Your line is open.

[Jason A. Wangler:]

Hey, Scot. You mentioned some non-op guys going non-consent. Was just curious, obviously, not your problem or your issue, but curious if you'd had any understanding of necessarily why? If it was financial or other reasons given what you have seen on your results?

[R. Scot Woodall:]

No real feedback, Jason. I think it's more that everybody is trying to figure out how to manage their capital spend in this type of commodity price environment and so, obviously, I think maybe they're thinking about taking their capital to another basin or another area or maybe they've got lease commitments that they've got to spend their capital to fulfill lease obligations or things like that is what I'm assuming is what it is. Clearly, what this type of well performance will take all the non-op working interest that we can get. So, we're very pleased to accommodate them.

[Jason A. Wangler:]

No, I totally agree there. And obviously, the other thing I am just curious on is, obviously, a lot of talk on the call about the balance sheet and things, but you monetized the Powder River stuff as well. Are there any – even small blocks you are still looking at throwing out there just to continue to consolidate the portfolio or are you pretty much done with that couple year program that's obviously paid off?

[R. Scot Woodall:]

I mean I think any company that's going to thrive going forward always has to look at upgrading their portfolio. So, there's probably always room to do some sort of transactions to either buy things or to sell some things. And I think we have a team that looks at that pretty consistently. Clearly, all the changes that we've done in the last couple of years were the big hits. And so, I don't think there's any big hits left in the portfolio. And so, I think it just maybe normal course of business type of activities.

[Jason A. Wangler:]

Okay. I appreciate it. Thank you.

[Operator:]

And we have a question from Chris Stevens from KeyBanc. Your line is open.

[Chris S. Stevens:]

Hey, thanks for taking my follow-up. Just wanted to see – what are you guys seeing on the oil percentage in the DJ Basin over that 30-day to 60-day period? And I guess what are you guys expecting for like first year oil cut relative to what it is over the life of the well?

[R. Scot Woodall:]

It's in that mid to high 60%s oil cut is what we see.

[Chris S. Stevens:]

Okay. And does that change at all, 30-day versus what your EUR assumption is?

[R. Scot Woodall:]

It will change. I'm not sure where that inflection point is that. What I'm quoting you is like a first-year number. Through time, yes, I think it does change a little bit. And I think we modeled the change in there, but I probably can't speak directly to it.

[Chris S. Stevens:]

Okay. How much production was associated with the asset you sold, the PRB and other non-core sort of assets? And did that close in 1Q or 2Q?

[R. Scot Woodall:]

It closed in like early February and the production associated with that was – they're telling me it's around 16,000 barrels of Q1's production. So, pretty nominal.

[Chris S. Stevens:]

All right. Thanks a lot.

[Operator:]

Ladies and gentlemen, this concludes today's Q&A. And thank you for participating in today's conference. Everyone, have a great day.