HighPoint Resources Corp
Q1 2017 Earnings Call Transcript

Published: 3 May 2017

[Operator:]

Good day, ladies and gentlemen, and welcome to the Bill Barrett Corporation first quarter 2017 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 conference call is being recorded. I would now like to turn the conference over to Larry Busnardo, Senior Director, Investor Relations. Sir, you may begin.

[Larry Busnardo:]

Good morning, and thank you for joining us today for the Bill Barrett Corporation first quarter 2017 earnings conference call. Joining me today are Scot Woodall, Chief Executive Officer, and Bill Crawford, Senior Vice President, Treasury and Finance. Before we begin the call, I encourage you to read the disclosure statements provided within the forward looking statements of our earnings release, which has been posted to the home page of our website at billbarrettcorp.com. You can also find and review these disclosures as they are referenced in our other filings with the SEC or in our 10-Q, which we filed yesterday afternoon. In addition, we will be referencing non-GAAP financial measures during our call. You can find a reconciliation to GAAP financial statements at the end of our press release. And with that, I'll turn the call over to Scot.

[R. Scot Woodall:]

Thank you, Larry. And thank you for joining us today to discuss our first quarter 2017 financial and operational results. I'll spend some time reviewing our operational results and outlook before turning out call over to Bill Crawford to review the financial results. We executed on our operational plan and our first quarter results demonstrate that we were off to a good start to 2017 and on track to meet our operational objectives. The quarter was highlighted by production being at the high end of our guidance range, lease operating expenses and G&A that were significantly below the first quarter of 2016, improved oil price realizations that were driven by tighter DJ Basin oil differentials, as we exhibited continued capital discipline, as capital expenditures were below our guidance range. In Utah, we have renegotiated our oil marketing contract that will lower our oil differentials to below $2 a barrel beginning on May 1. Consistent with our strategy of maintaining balance sheet flexibility, we recently pushed our nearest term maturity with the issuance of senior notes due in 2025. The proceeds plus cash on hand will be used to redeem our current notes due in 2019 and extends the timing of our nearest maturity to 2022. The reduction in debt and related extension positions us better financially for the future. Bill will discuss these matters in more detail in his prepared remarks. Overall, it was an excellent quarter of execution by our operations organization and our entire organization, and provides a solid foundation for the year. During the quarter, we opportunistically added to our DJ Basin acreage position as we were issued a 2900-acre federal lease under the Riverside Reservoir for a very minimal purchase price. We are pleased with the acreage addition, as it is located in the central and southern portion of our acreage and is contiguous to our existing acreage. We're in the process of forming a drilling unit under this acreage to facilitate development. This acreage will add up to 50 extended reach lateral drilling locations to our inventory that is prospective for the Niobrara B and Niobrara C formations. Since the beginning of the year, we have added nearly 17,000 net acres in the Northeast Wattenberg through similar type transactions. As I have outlined in the past, our strategy is to opportunistically expand our core acreage position, and we will continue to pursue other opportunities as well. Now, turning to operations. We are off to a good start to the year and on track to execute our 70-well to 75-well program in the DJ Basin. As previously announced, we plan to add a second drilling rig in the DJ Basin during the second quarter that will further accelerate drilling activity. DJ Basin production averaged 14,200 barrels of oil equivalent per day in the first quarter, which was 22% higher on a year-over-year basis. We expect to deliver a company-wide increase of 7% in our 2017 volumes and are positioned for growth of 30% to 50% in 2018, with even higher oil volume growth, as we deploy increased capital to ramp up drilling activity during 2017. Our capital program is fully funded by our cash on hand, and we expect to end this year with a cash position and nothing drawn on our bank revolver. Although the first quarter was quiet from an operational news standpoint, we were very active from an operational perspective, utilizing one rig during the quarter to spud five extended reach laterals and nine mid-length laterals. In addition, completion operations were finalized on 13 wells that were placed on initial flowback during the quarter. This includes four extended reach lateral wells located in section 4-62-20 and nine extended reach lateral wells located in section 5-62-27. We also plan to initiate flowback on additional 14 wells during the second quarter. This will contribute to what is expected to be an increasing production profile through the second half of 2017, and translates into a significant increase in volumes in 2018, as outlined by our guidance. We maintain complete flexibility with respect to our drilling program, as we did not have any drilling leasehold or marketing commitments, allowing us to adjust our capital program very quickly, if necessary, to adapt to changing market conditions. The improvements in our completion design continue to evolve and are now substantiated with production history and actual results. With two years of production history, we've observed a 36% improvement in cumulative production for wells utilizing 1,200 pounds of sand per lateral foot when compared to wells utilizing 1,000 pounds of sand per lateral foot. Additionally, a comparison of wells with spacing of 120 feet per frac stage, compared to 170 feet spacing per frac stage, indicates a 10-plus percent improvement based on the first year of cumulative production. Our 2017 completions will build on these results as our base design for the year will include 1,500 pounds of sand per lateral foot and frac stage spacing between 100 feet and 140 feet. We are pleased with the early results of our enhanced completion program, including the higher proppant concentrations and tighter frac spacing, and we anticipate that well performance and recoveries will improve as we implement these changes more broadly. So a great job by our operations team in achieving these results. Our 2017 program provides an attractive investment opportunity on our base assumptions and expected to generate rates of return of greater than 45% at the well at current strip pricing. As we continue to optimize our enhanced completion design and focus on our efficiencies, we expect to see improvements in both well performance and our cost structure. Lastly, we are in the process of finishing up a nine-well recompletion program in the Uinta Oil Program that will begin producing in the second quarter. In summary, we are positioned to deliver on our operational objectives and we retain a meaningful cash position with ample liquidity that puts us in a good financial position to execute our development program. I will now turn the call over to Bill for further comments on the financials.

[William M. Crawford:]

Thank you, Scot. As Scot mentioned, we're off to a great start to 2017, with the first quarter providing a solid foundation for the year, as we posted solid results that generally exceeded guidance and sell-side consensus estimates. The outperformance was largely driven by production coming in at the high end of our guidance range, continuing improvement in our cost structure, and higher price realizations, all leading to top tier Basin operating margins. I'll now spend a few moments going over some of the highlights for the first quarter. We generated discretionary cash flow of $23 million and EBITDAX of $36 million, all above consensus estimates. Quarterly production volumes of 1.43 MMBoe were at the high end of our guidance range and, consistent with our internal forecast, volumes had a slightly higher natural gas weighting than previous quarters at 58% oil, 22% natural gas, and 20% liquids. This was primarily the result of not having any new XRLs completed in the latter half of 2016. We expect second quarter 2017 oil weightings to be slightly higher and average 60% to 65% for the full year as we bring on the new wells Scot mentioned. We captured a higher oil price for our barrels in the DJ, which averaged $2.78 per barrel off WTI. This was a 50% year-over-year improvement. We maintain a strategic advantage relative to our DJ Basin peers based on our ability to capitalize on not having any firm oil transportation commitments. We expect to see these tighter oil differentials for the foreseeable future and are locking these tighter differentials with our physical purchasers with no take-or-pay commitments. We're also benefiting from higher NGL prices, especially ethane and propane, and expect that we will see slightly higher NGL price realizations as a percent of WTI. In Utah, we recently took advantage of improved market dynamics due to lower supply of wax crude for the Salt Lake City refineries, and renegotiated our UOP marketing contract. Beginning May 1, we have secured differentials under $2 per barrel. This compares to an average of $7.75 per barrel off WTI for our East Bluebell asset during 2016. This tighter differential will make our nine-well East Bluebell recompletion program even more economic. LOE averaged $4.09 per Boe and was in line with expectations. It was a 37% year-over-year improvement. DJ Basin LOE averaged $3.47 per Boe or a 28% reduction compared to $4.80 this time last year. Our operations team continues to do a great job in reducing field level costs. Now on to the balance sheet. Consistent with our strategy of executing on items within our control and maintaining balance sheet flexibility, last week we completed the issuance of $275 million of senior unsecured notes due 2025. The proceeds of this offering will be used along with some of the cash on hand to redeem the $315 million of existing notes that are due 2019. This will close by the end of May. Since the second quarter of last year, we have reduced long-term debt by 16% and lowered our annual interest burden by $6.5 million. We continue to maintain a very manageable debt profile, with our nearest maturity not until late-2022. We also enjoy a strong cash and liquidity position. We had $266 million of cash on hand at quarter end, which was subsequently reduced by the $26 million in early April, with our normally scheduled interest payments. We are currently in the process of undergoing our semiannual borrowing base review, and expect that our current borrowing base of $300 million will remain unchanged. We expect to finalize this in the coming weeks. As a reminder, we are currently undrawn on our credit facility and do not expect to use it this year for ongoing operations. We continue to be an active hedger and are looking for opportunities in the market to add further support for our capital program and protect future cash flow. For 2017, approximately two-thirds of our oil production is swapped at $58.50 WTI. And we have approximately 3,100 barrels of oil per day swapped in 2018 at $54.50 per barrel, all of this weighted to the first half of the year. You can find a full summary of our updated hedge position in the press release or 10-Q. Now, an update to our guidance outlook. We expect second quarter production to be approximately 1.45 MMBoe to 1.55 MMBoe, which is an uptick from our first quarter production, as the wells we placed on flowback during the first quarter continue to ramp up. We're also reiterating full-year guidance of 6 MMBoe to 6.5 MMBoe, and we expect to achieve a very competitive growth rate of 30% to 50% in 2018 as we execute on this year's program. CapEx for the second quarter are expected to be $65 million to $75 million. And our range of total CapEx for the year remains unchanged, $255 million to $285 million. The remainder of our cost guidance remains unchanged and can be found in our press release. With that, I think we are ready for questions.

[Operator:]

Thank you. Our first question comes from Welles Fitzpatrick with Johnson Rice. Your line is open.

[Welles W. Fitzpatrick:]

Hey, good morning, and a great quarter and great acreage out there under the reservoir.

[R. Scot Woodall:]

Hi. Thanks, Welles.

[Welles W. Fitzpatrick:]

Should we think about the 36% improvement from the higher loadings and the 10% improvement from the stage spacing as cumulative? And I'm sorry if you mentioned this, but are those uplifts relative to the 600,000 curve?

[R. Scot Woodall:]

The way we do these things, Welles, is we take, like, a drilling spacing unit and we take a couple of the wells and we try something different on them, like the increased sand volumes or the tighter stage spacing. So it's relative to the other wells in the drilling spacing unit is where that calculation comes from. And that is cumulative over the two-year production history that we have of those two – well, the increased sand volume is on a two-year comparison; the stage spacing is just a one year cum. So you hope that that would continue to hold true as you go through months 13 through 24. And then you would hope that there's an additional increase as we move the sand loading from the 1,250 pounds to the 1,500 pounds that you also get an uptick in production and cums as well.

[Welles W. Fitzpatrick:]

Okay, perfect. And on the 1,500-pound design and 100-foot to 140-foot stage spacing, I believe the $4.75 million accounted for the loadings, but maybe not for the tighter stage spacing. Any thoughts onto where that might move? I know you're punching below that right now.

[R. Scot Woodall:]

Yeah. I think the $4.75 million kind of takes into account both, as well as some service cost inflation. And so, kind of, keep in mind that we budgeted that $4.75 million for the entire year in 2017, and first quarter we probably spent $4.25 million. And so, that's the reason for the underspend. So I don't know if we're heavy on our capital or not. We're just going to see how the rest of the year goes and where those tweaks in the completion design go as well.

[Welles W. Fitzpatrick:]

Okay, perfect. And then just one last one for me. Just eyeballing the reservoir, it looks like that 2900 acres is about all of it. One, is that right and two, are there any more onerous permitting requirements given where those wells will be located?

[R. Scot Woodall:]

Don't really think it's going to be a big permitting thing. Their federal minerals so you have to do a little bit of NEPA work, environmental assessment type work. But the team I think believes that probably second quarter of 2018 or so, that those wells will be popping into the drilling schedule.

[Welles W. Fitzpatrick:]

That's perfect. Thank you so much.

[Operator:]

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

[Brian Corales:]

Good morning, guys. I have a couple questions. One, maybe a follow-on to Welles' question. I see that it looks like 1500 pounds per foot and tighter spacing is kind of the new norm. Are you all going to test even tighter spacing and more sand going forward or are you happy with this plan you have?

[R. Scot Woodall:]

You know, we could, Brian. We obviously are kind of watching what others are doing as well, but I know a current pad that's being completed right now is going to go to 100-foot stage spacing. So that'll be testing one of the lower ends. And I think we'll have to look at some results of the 1500 pounds and see if we need to go larger or not. There's some operators that are doing some more. I think we can look at those results. So I think we'll evolve throughout the year a little bit.

[Brian Corales:]

Okay. And then I see you're recompleting completing some wells in the Uinta. Is this more exploratory or have you all done this in the past and maybe you give an idea of what a current well's producing and what it could become. I'm just trying to figure out I guess what are you targeting here?

[R. Scot Woodall:]

Sure, Brian. So it's in the Green River sections. So if you remember, that's a 1800, 2000-foot section of Green River. And so this is just adding uphole additional Green River pay. So very low risk and it's just very well mapped out. So it's just kind of a normal course of business. And with the differentials being lowered, it makes it economical and attractive and just a good base production optimization, operational thing to go do.

[Brian Corales:]

Oh, okay. So this is more uphole. And so I'm assuming you're going to see how these nine do and you may add some to that going forward.

[R. Scot Woodall:]

Sure. The team has an inventory of these types of opportunities. When you're completing that whole 2000-foot section, sometimes you didn't go all way to the very top of the section in some of the older completions and so it's just adding a few more layers. So we're just adding – it's basically setting a plug, perforating, doing some stimulation work. Pretty routine.

[Brian Corales:]

Got you. All right. Thanks, guys.

[Operator:]

Thank you. Our next question comes from Jason Wangler with Wunderlich Securities. Your line is open.

[Jason A. Wangler:]

Hey, good morning, guys. Was just curious as far as you look at the completion schedule. Are you able to get those on a calendar or do you have a dedicated frac crew as you start to ramp up how much you guys are going to be completing the rest of the year? Just how you see it from an availability standpoint.

[R. Scot Woodall:]

You know, I don't think we have a dedicated frac fleet yet just with the activity the first half of the year. We may get to that point the second half of the year with the two-rig program. But, yes, everything's on a schedule and we feel definitely that we'll be able to meet the timelines that we're laying out here and execute according to the plan, our internal plan and the guidance that we're delivering. So it's all scheduled and should be executed timely.

[Jason A. Wangler:]

Okay. And maybe just similar, but on the drilling side. I mean, you continue to drive down the drilling days, I guess, just under a week now. I mean, that puts you in a really good spot as far as getting your 70-well to 75-well program done this year. I mean, is there kind of a time that you're looking at that second rig or does that even kind of move around given the fact that you keep increasing it, that you could kind of almost push that further back given how well you're doing with the one rig now?

[R. Scot Woodall:]

Yeah. It kind of moves around a little bit. I think as we continue to drill faster, the need to add that second rig early in second quarter kind of slid to say maybe we'll do it in the second half of the second quarter. And so, that's kind of why you saw maybe a 30-day delay. But clearly, there's a rig availability. And so, that's not an issue. And obviously we have the permits and all the necessary documentation to get started. So you'll see us here in the next 30 days to 45 days probably start.

[Jason A. Wangler:]

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

[Operator:]

Thank you. Our next question is from Gabe Daoud with JPMorgan. Your line is open.

[Gabriel J. Daoud:]

Hey. Good morning, guys. Maybe just following up on the previous question on the second rig, just trying to think about how you synthesize that based on oil prices. If we stay around here, low-50s, high-40s, or if you take another lag of load, does that impact at all how you think about running the two rigs?

[R. Scot Woodall:]

Sure. I think we always look at changes in the commodity price. And with our entire acreage position basically being HBP-ed and without any marketing commitments or other type of obligations, we can change and make decisions based on commodity prices, the ability to hedge. So all of those things factor in. But if you look at those economics tables, if you look at something in the low-50s, we're generating a 45 plus percent rate of return, probably feel pretty comfortable going forward. Obviously, we would look at things differently if things go back – if oil prices long-term go back into something in the 40s.

[Gabriel J. Daoud:]

Thanks, Scot. That's helpful. And then, just one quick follow-up on the Uinta, renegotiating the marketing contract. Does that impact at all how you guys think about the asset within the portfolio? I guess, what I'm just asking is, now that realizations are improving, do you try to put it on the block again I guess?

[R. Scot Woodall:]

I think it definitely makes it more profitable. It improves the cash flow. And so, you're probably right, you would think it would enhance the value if we chose to monetize it at some point. And I still think that we probably will look to monetize it at some point, but no immediate plans today to do that.

[Gabriel J. Daoud:]

Okay, great. Thanks, Scot.

[Operator:]

Thank you. Our next question is from Derrick Whitfield with Stifel. Your line is open.

[Derrick Whitfield:]

Good morning, and congrats on the solid quarter and update guys. Regarding the tighter spacing and higher proppant density that you referenced earlier in the call, how do you guys think that's going to change the shape of the production profile? Will it take longer to reach peak with that optimal completion?

[R. Scot Woodall:]

Shouldn't take longer to reach peak. What you hope is that the peak is actually higher and perhaps the decline is shallower. And we've seen that on those couple of dataset points that I referred to earlier, where we had the two years of production history. And so, that would be kind of the expectation.

[Derrick Whitfield:]

Fantastic. And then just building on the question that Welles asked earlier, is it fair to assume that average field EUR should be 10% or higher than the 835,000 Boe that you mentioned in your Howard Weil presentation?

[R. Scot Woodall:]

I'm not following the 835,000, I guess.

[Derrick Whitfield:]

I'm just looking at the average EUR that you guys have mentioned in your presentations. The one that I'm looking at for XRL references third generation at 835,000 barrels equivalent. And my comment was, given the changes that you guys have made really since walking that design up, would it be safe to assume that the EURs would be, at minimum, to 10% higher than that or has that already all been baked into the 835,000 Boe number?

[R. Scot Woodall:]

Yeah. And I'm still not following the 839,000 (sic) [835,000] number. I think in the Howard Weil presentation, we have some illustrated economics of a 500 curve, a 600 curve, and a 700 curve that's in there. And, yes, the expectation is that we would build from those field averages as we continue to improve on our completion techniques.

[Derrick Whitfield:]

Okay. Very good. And then just last question if I could. If you could share with us the house view on Anadarko's vertical well announcement from last week and expected impacts to you.

[R. Scot Woodall:]

You know, obviously, that was an unfortunate tragedy, and obviously our company is an active member of that community and our thoughts and prayers go out to that family and that entire community on this incident. In terms of impact to our company, it's really pretty small considering the rural nature of our properties. If you look, our properties sit to the northeast side of the field. We're in a very rural area. Just to give you some comparisons, as this incident was unfolding last week, there were some – we went out and tested all the wells that we had that were less than 250 feet from an occupied structure and there's only four of those. We also went out and looked at the wells that we had within 500 feet and there's 11 wells. And so we really don't fit in a municipality or in a rural environment, and obviously we want to be compliant with all of our testing and the COGCC put out some new guidelines last night that obviously we will execute on, but the overall impact to our base operations should be pretty small.

[Derrick Whitfield:]

Got it. That's exactly what I expected, Scot. Thanks for a good update.

[Operator:]

Thank you. Our next question comes from David Beard with Coker Palmer (sic) [Coker & Palmer]. Your line is open.

[David Earl Beard:]

Good morning, gentlemen. Couple of bigger picture questions on the balance sheet and on sand. First on sand loadings. Just wanted to try to get a little more color on the impact of increased cost of sand for your wells.

[R. Scot Woodall:]

You know the way that we're kind of looking at it is the change from say maybe 1,000 pounds to 1500 pounds is probably $0.25 million. And then probably the incremental cost associated with going from 170 feet to 100 feet may be like another $0.25 million. So it could be that you're adding about $0.50 million, roughly, in well cost associated with those two enhanced completion techniques that we're executing on.

[David Earl Beard:]

Okay. That's helpful. And then just bigger picture question relative to oil and outspend and cash and your revolver. I know you mentioned you wouldn't expect to use the revolver. But is there a level of just cash on the balance sheet you wouldn't want to drop below before you would match spending with cash flow?

[William M. Crawford:]

I think we look – excuse me, David. It's Bill Crawford. Yeah, I think we look at it at the opportunities we have in front of us. And with the economics that Scot talked about, 45% plus rate of return, we feel it's helpful to put the cash on hand to deploy it to the levels that we can. And, obviously, don't want to draw on the revolver more than probably about 25% to 50% of usage. So, as we look at our outlook, we put all that into play.

[David Earl Beard:]

Good, that's helpful. Thank you, guys. Appreciate the time.

[Operator:]

Thank you. I'm showing no further questions at this time. I would like to turn the call back over to Larry Busnardo for closing remarks.

[Larry Busnardo:]

Great. Again, thanks, everyone, for joining us today. Feel free to contact us if you have any additional questions and we look forward to seeing you at future investor events. Thank you.

[Operator:]

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the program and you may now disconnect. Everyone, have a great day.