HighPoint Resources Corp
Q2 2017 Earnings Call Transcript

Published: 5 Aug 2017

[Operator:]

Good day, ladies and gentlemen, and welcome to the Q2 2017 Bill Barrett Corp. 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 [Operator Instructions]. I will now like to turn the call over to Larry Busnardo, Vice President, Investor Relations. Please go ahead.

[Larry Busnardo:]

Good morning and thank you for joining us today for the Bill Barrett Corp. second quarter 2017 earnings conference call. Joining me on the call today are Scot Woodall, Chief Executive Officer and Bill Crawford, Senior Vice President, Treasury and Finance. Before we begin, I need to remind everyone 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 was filed yesterday afternoon. In addition, we will be referencing non-GAAP financial measures during our call. A reconciliation to GAAP financial statements can be found at the end of our press release. With that, I'll turn the call over to Scot for prepared comments.

[Scot Woodall:]

Good morning and thank you for joining us today to discuss our second quarter 2017 financial and operational results. I will start with an overview of the second quarter before turning the call over to Bill Crawford to review our financial results. Crude markets were volatile during the quarter as oil prices traded to a high at $53.40 per barrel in early April before falling to $42.53 per barrel in late June. Despite this, our operational team did an excellent job of executing in a challenging environment, and we delivered a very good quarter that met or exceeded expectations. Our quarterly results were largely driven by a production that was at the upper end of our guidance range, higher oil price realizations and lower per barrel operating costs. Capital expenditures were below the low end of our guidance range as we managed cost inflation. As highlighted in our earnings release, we are reiterating our full year 2017 guidance. Crude markets have begun to show signs of stabilizing. As demonstrated by our actions in 2016, we'll be prudent with respect to capital allocation as we navigate the current commodity price environment. I would reiterate that we do not have any drilling, leasehold or marketing commitments, and we maintain complete flexibility with respect to capital spending. This provides the ability to adjust our capital program very quickly to adapt to changing market conditions. Our 2017 capital program is also fully funded by cash on hand and we expect to end this year with a cash position and nothing drawn on our bank revolver. Now turning to operations. Our DJ Basin development program is located in a rural part of Weld County and near very few occupied structures. Drilling activity continues to progress at an active pace, and we are on track to complete our planned activity for the year. We operate one drilling rig for much of the first half of the year and a second rig was added in the DJ in June. This was consistent with our 2017 capital plans that we have previously communicated to the investment community. Operational activity in the quarter consisted of spudding eight XRL wells and one MRL well, while completion operations were finalized on four XRL wells and 10 MRL wells. In addition, we expect to initiate flow back on five XRL wells during the third quarter and 14 XRL wells in the fourth quarter. This will be a large component to our production profile for the first half of 2018. This level of activity provides a line of sight and confidence with respect to our 2017 operational objectives. Our operational team continues to do an excellent job of building on efficiencies, as XRL drilling days to rig release have averaged 6.5 days during 2017 with our best well drilled in 5.1 days. We also seek additional opportunities to mitigate expected service cost inflation. As outlined in our previous discussions, we have made improvements in our completion design that have been substantiated by up to 2 years of production history. This includes adjusting our fluid design to allow for higher profit concentrations to be placed in the well bore. Our base design has evolved to incorporate approximately 1,500 pounds of sand per lateral foot and tighter frac staging between 100 and 140 feet. Early results from the first DSU with enhanced proppant have been encouraging. I'm referring to the Section 27 wells in the central portion of our acreage position that were completed with approximately 1,500 pounds of sand per lateral foot, but had wider stage spacing of approximately 170 feet between frac stages. The wells are placed on flowback in March, and production continues to trend upward. The initial DSU that incorporated enhanced proppant as well as tighter frac stage spacing is located in the northern area of our acreage position. The wells were placed on initial flowback in June, and we are also seeing positive early results. As a reminder, we utilized a controlled flowback method, which limits initial production rates and pushes out peak production. We are still several months away from reaching peak production. Our confidence in the benefits of utilizing enhanced completions in lower GOR area is also being validated by the improvement in results that we are seeing from other nearby operators. As you can see, we are clearly encouraged by our recent result, and we will provide further data points as they become available. I would highlight that our XRL program provides an attractive investment opportunity on our base assumptions, with an expected rate of approximately 40% rate of return at the wellhead assuming current strip pricing. Now turning to Utah, we finished recompleting 9 wells in the Utah Oil Program during the quarter. We are seeing very good results, and we'll continue to monitor the production history before determining if additional activity is warranted in the area. In summary, we are positioned to deliver on our operational objectives in a safe and responsible manner. We retain a meaningful cash position that provides ample liquidity to fund our development program without increasing long-term debt, and we maintain the flexibility to adjust our capital plans if warranted. I will now turn the call over to Bill Crawford for a financial review.

[Bill Crawford:]

Thank you, Scot. Although we have had volatile crude pricing, we posted very good results for the second quarter, meeting or exceeding the various components of our guidance. Production was above the midpoint of our guidance range with total oil volumes at or above expectations. Our operations team continues to show an ability to improve efficiencies as evidenced by an improvement in LOE, and we saw the benefit of our marketing efforts as crude oil price realizations improved for the quarter. All of this led to delivering top-tier basin operating margins, and we generated EBITDAX of $37 million and discretionary cash flow of $22 million. Financially, we maintained flexibility with no near-term maturities and the necessary liquidity to execute on our capital plans. I will now spend a few moments going over to some of the highlights for the second quarter. Quarterly production of 1.53 MMBoe was at the high end of our guidance range. Consistent with our guidance, the oil weighting was approximately 60%, which we expect to continue to trend slightly higher as additional DSUs are placed on production in future quarters. We continue to benefit from not having any firm oil transportation commitments. For the quarter, our DJ Basin oil differential averaged $2.16 per barrel of WTI as we were able to take advantage of positive market dynamics. And this marks a 55% year-over-year improvement. Going forward, we expect differentials to average around that $3 to $4 barrel range we have previously said. As discussed on our last earnings call, we are also seeing improved oil market dynamics due to lower supply of wax crude for the Salt Lake City refineries. This allowed us to renegotiate our UOP marketing contracts to secure differentials of under $2 per barrel that became effective on May 1 and will continue for at least two years. Lease operating expenses averaged $3.61 per Boe and was in line with expectations and a 32% year-over-year improvement. DJ Basin LOE averaged $3.06 per Boe or an 18% reduction compared to the comparable 2016. We continue to work on efficiencies and with higher volumes, expect LOE per Boe to decrease through the remainder the year. All other costs were in line with guidance and expectations. Now an update to our third quarter outlook. We expect production to be approximately 1.55 to 1.65 MMBoe, which is up from the second quarter as the wells we have placed on initial flow back continued to contribute. We are reiterating our full year guidance of 6 to 6.5 MMBoe. CapEx for the quarter is expected to total $65 million to $75 million with that second rig added. Our range of capital expenditures for the year remains unchanged at $255 million to $285 million, but we are trending to the lower end as we manage the cost inflation. The remainder of our guidance is unchanged, it can be found in our press release. Now onto the balance sheet a little bit. Our strategy has always been to maintain balance sheet flexibility. And during the quarter, we took advantage of relatively favorable market conditions to complete a $275 million offering of senior notes due in 2025. We used the proceeds, along with a portion of cash on hand to redeem the $315 million, 3-1-5 million, of existing notes that were due in 2019, thus reducing our long-term debt position by $40 million. This leaves our debt profile very manageable with the nearest maturity not being until late 2022. As a reminder, we ended the quarter with $156 million of cash on hand and are undrawn on our credit facility, which we do not expect to draw upon this year to fund the ongoing operations. On the hedging front, we continued to seek opportunities to layer in additional support for our capital program given the crude price uncertainty that persists. For the second half of 2017, approximately two-thirds of our oil production is swapped at $58.77 WTI. We’ll also have $57.40 barrels of oil per day swapped in 2018 weighted towards the first half of the year and have even begun starting hedging 2019 at $50 per barrel or higher. You can find a full summary of our updated hedge position in the press release or in the 10-Q that was filed yesterday. With that, we are now turning it over for questions.

[Operator:]

[Operator Instructions] Our first question is from Brian Corales with Howard Weil. Your line is now open.

[Brian Corales:]

Good morning, guys. Just a question, I think, Bill, you talked about the CapEx being at the low end. Is that due to less activity? Or is that a function of like kind of less service inflation than you estimated? What's the driver there?

[Bill Crawford:]

Yes, Brian, I would say that the activity levels are the same. So we're on track to drill the same number of wells and put on the same number of wells as in our initial guidance. We probably -- when we set the initial guidance, it set our per-well capital kind of at the high end, thinking cost inflation. And then also I didn't know how much more money we were going to spend on the enhanced completions and moving the sand from 1,000 to 1,500 and moving the stage pacing from 170 feet down to 120 to 100 feet. So there was some room in our numbers to kind of implement some of those changes as well as a projection on service cost inflation. And so far, through the first half of the year, we've spent less. And so I think we've done a good job of managing those costs.

[Brian Corales:]

Okay. And then the recompletions that you went to see the -- bear some fruit with the oil production increasing there, do you have a lot of more opportunities in these recompletions? Or do you all -- what kind of the thought going forward from that program?

[Bill Crawford:]

Clearly, we like the results, and I would say that our partners are ecstatic about the results. And so there has been some discussions about, do we follow-up and do some other activity in Utah, whether that's drilling wells or more recompletions or just what. Obviously, that basin looks a lot more attractive with the new differentials, and so it kind of has everybody a little excited about these results. So I think it's something that we'll discuss over the next few weeks because, obviously, they look good. And there's clearly showing through to the financials.

[Brian Corales:]

Okay got it. Thank you.

[Operator:]

Our next question is from Welles Fitzpatrick with Johnson Rice. Your line is now open.

[Welles Fitzpatrick:]

Hey. Good morning.

[Bill Crawford:]

Good morning, Welles.

[Welles Fitzpatrick:]

In regards to the Uinta, I mean, those recompletions, the lower depths, are those combining to make it something that might be more attractive for you all to keep in-house? Or how has that changed your thoughts about potentially divesting that asset?

[Scot Woodall:]

I don't think it changes it too much, Welles. I mean we still think that the primary focus of the company is the DJ Basin, and we like the results that we're getting there and think that's the best use of our capital. But obviously, when you get positive results and the last wells, we drilled there, exceed our expectations, the recompletions exceed our expectations, the differentials are great. So we like the basin. But probably at some point, it's still going to be in the best interest of the company to probably exit Utah and put the capital into the DJ.

[Welles Fitzpatrick:]

Okay, that make sense. And then on the $4.5 million well cost, can you give us an idea of what maybe the 6-62-10 and 11 came in at? I mean, obviously, those are on the kind of leading edge of the stage spacing and proppant intensity. Were those a little bit higher than $4.5 million or were those closer to the $4.75 million?

[Scot Woodall:]

They were still at the 4.5 million, so those were actually -- that's our projected well costs on those.

[Operator:]

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

[Daniel Norman:]

Hi. This is Daniel Norman stepping in for Dave. Can you guys talk a little bit about the 30% to 50% growth target for 2018 that you originally laid out and maybe the flexibility of that if crude were to trade around $45 for the next few quarters?

[Scot Woodall:]

Obviously, I've kind of said in the openings comments there, Daniel. With no commitments on lease explorations or service costs or marketing commitments, we're free to make capital deployment decisions as what we think is best for the company, not for some external reason. So I think as oil sits in the $45 plus range, I would think we continue with our two rig program and that would deliver that growth profile that we originally outlined at the beginning of the year. So I think as we look at things today with crude sitting around $50, I would think those plans are still pretty intact.

[Daniel Norman:]

And then maybe just as a follow-up. Do you have maybe a target level of liquidity that you want to maintain that you would kind of not go below?

[Bill Crawford:]

Yes. I think we've always said that you never want to probably be more than about 50% drawn on your credit facility, and we'd always seek permanent capital for anything more than 25% to 50% drawn. So obviously, we'll balance all of that when we put together our 2018 plan.

[Operator:]

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

[Derrick Whitfield:]

Good morning and great update guys. Building on the previous caller's questions, do you guys have a view on maintenance capital required to hold production flat at 2018?

[Scot Woodall:]

I probably haven't really looked at that too hard yet but we used to kind of always quote something in that 20 or 25 XRL wells. And so if you thought maybe it's 25, and you did at times the $4.5 million and you 80% it, whatever that math comes up to be, you're probably in the ballpark.

[Derrick Whitfield:]

Got it, very helpful. And then moving over to the 5-62-27 and 6-62-10 DSUs, any further color you can offer on well performance with the 1,500 pounds per foot design relative to 1,250 design? I mean, I guess, I would ask, are you guys seeing higher oil volumes at this point of flowback operations?

[Scot Woodall:]

We are, but I would say that with a little bit of caution. If you remember, we do this controlled flowback, and so we kind of over the first six months are restricting both the fluid rate and the gas rate and maintaining a lower GOR. And so, if you go back to like the plots in the investor presentation where we speak of 1,000 pounds of sand versus 1,200 pounds of sand over a 170-foot stage spacing versus a 140-foot stage spacing, you really start to see that separation after month six. And so, in kind of months six through nine is where you really start to see that separation, and that's kind of why we put those plots in there. After you have more than a year of data, you feel a whole lot more confident in talking about the result. But the two pads, in particular, the two drilling spacings, in particular, that you're talking about, in these early time data, it looks strong. But like I said, it's just a -- I don't want to get out in front of myself here too much because I really think we've got to go through our normal process of the controlled flowback and kind of get out there a few months before we start quoting a lot of rates or a lot of projected future increases.

[Derrick Whitfield:]

Got it, that make sense. And with the higher intensity completions, would you expect a longer build to peak in terms of reaching the peak IP rate?

[Scot Woodall:]

I don't necessarily think so, but that's also coupled with the flow rate that you do in the early times. So we have been on some of the larger completions, flowing the wells back at a little bit higher hourly fluid rate. And so I think that, that peak time to plus or minus 5 months or so probably is still intact.

[Derrick Whitfield:]

Got it. Last question for me, if I could. Could you talk to some of the self-help measures you're taking to offset inflationary pressures?

[Scot Woodall:]

I think it's really just kind of comes down to more on the efficiency side. So I quoted some numbers on drilling times. Those guys continue to improve quarter-over-quarter. And then it also, I think, translates over into the completion operations as you become efficient in the number of stages that you do per day and the limited downtime. If you remember back in the old days, we used to keep track of like rotating hours on a rig versus downtime hours. Well, obviously, now it's almost more important on the completion side of the business and you're trying to minimize downtime hours there. And I think our team has just done an excellent job in the way they do things there. Then obviously, just on the surface facilities and things, you're always looking at streamlined ways of connecting up your wells and equipment and how you're managing your contract labor. And so it's just kind of a little bit of everything, but obviously we've been very pleased with the results and it's translating into lower capital spends projected 2 quarters in a row now.

[Derrick Whitfield:]

That’s all from me. Thanks for taking my call.

[Operator:]

Our next question is from David Beard with Coker & Palmer. Your line is now open.

[David Beard:]

Hey good morning, gentlemen. Nice quarter.

[Scot Woodall:]

Thanks David.

[David Beard:]

Just with the large amount of XRLs coming on in the fourth quarter, can you give any guidance, maybe I missed this, just relative to exit rate or what that can kind of do to production? Just any help there would be appreciated.

[Scot Woodall:]

Not really. I think most of it, as you can tell, that impact is going to be more first quarter, second quarter. So there's modest increases, and I think we're predicting Q3 over Q2 of this year and probably a modest increase Q4 over Q3. And then you'll really start to see the impact in more Q1 and Q2.

[David Beard:]

And my other question would be just relative to working capital. I know it's been bouncing around a little bit first quarter, second quarter. It's kind of a use of cash this quarter. Should we expect that to even out? Or were there something going on in the quarter just relative to a lot of working capital used this quarter?

[Bill Crawford:]

No, I don't think there was much this quarter that we used cash. I mean, we've always had -- with the timing of the interest payments, working capital is always Q1 and Q3 a little different, but now that the interest payments will be staggered, I think you'll still see that a little bit more consistent.

[David Beard:]

Okay, great, thank you. Appreciate the time.

[Operator:]

Our next question is from Jeff Robertson with Barclays. Your line is now open.

[Jeff Robertson:]

Thank you. Just Scot or Bill, a question on oil differentials. You've averaged below the $3 to $4. You all have talked about towards the DJ Basin for the first six months this year. Can you talk about what your expectations are out through 2018 for DJ differentials?

[Bill Crawford:]

Yes, we guided to $3 to $4. Part of it is we do have some non-off barrels that can change, and we don't have control over that. That blends some of it down. As people are not able to make their firm commitments on the pipelines, we are able to step in and we're able to typically get $2 to $2.50. We're starting to see that tighten a little bit. And we do try to go out and secure capacity through 2018. So I think we'll be at the low end of that through the remainder of the year, and we'll just have to see the pace of other's development and how they see and fit into their firm commitments. Our advantage, where we sit in our rural nature, A, we have the better gravity. So we're typically 38 to 40, which the people can use to blend. Further, we can get to Pony Express very easily. We can get to Saddlehorn, Grand Mesa and/or White Cliff along with the local refinery. So we're able to keep all that competitive tension. So try to keep it obviously as low as we can.

[Jeff Robertson:]

Second question, Scot. You all did a couple of acquisitions in the first quarter in the DJ Basin. With oil, if oil sits around current levels, do you think that will create any significant or any additional acquisition opportunities for Barrett to consolidate it around your position?

[Scot Woodall:]

I think we'll just kind of keep looking. There's a few little packages that are being marketed now. I mean, I think there's always a few operators that are opportunistically looking to try to sell. So I think our land team will just kind of keep looking for those types of opportunities kind of like we did in the first quarter.

[Jeff Robertson:]

Just a follow-up. Do you have any goal as to replacing the drilling location to your process through in any given year with adding acreage, either through leasing or through acquisitions?

[Scot Woodall:]

I mean, I don't think it's necessarily a stated goal but I think it's clearly a good objective to have. And provided I think that you're adding inventory that we think is on the same par or better than our existing inventory, it makes sense probably in any commodity price environment.

[Operator:]

And I am showing no further questions at this time. I would now like to turn the call back to Larry Busnardo for any further remarks.

[Larry Busnardo:]

Thank you again for joining us today. And please feel free to contact me if you have any additional questions regarding the quarter. We look forward to seeing you at future investor events, including the Oil & Gas Conference here in Denver where we will be presenting on Monday, August 14 at 10

[Operator:]

Ladies and gentlemen, thank you for your participation in today's conference. You may all disconnect. Everyone, have a good day.