HighPoint Resources Corp
Q2 2018 Earnings Call Transcript

Published: 9 Aug 2018

[Operator:]

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Second Quarter 2018 HighPoint Resources Earnings Conference Call. [Operator Instructions]. And as a reminder, this conference is being recorded. Now it's my pleasure to turn the call to Mr. Larry Busnardo, Vice President of Investor Relations. You may begin.

[Larry Busnardo:]

Good morning, and thank you for joining us this morning for the HighPoint Resources Second Quarter 2018 Earnings Conference Call. Joining me today are Scot Woodall, Chief Executive Officer; Paul Geiger, Chief Operating Officer; and Bill Crawford, Chief Financial Officer. Before we begin, I'd like to remind everyone to please review the disclosure statements provided within the forward-looking statements of our earnings release, which you can find on our website at hpres.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 after the close yesterday. In addition, we will be referencing non-GAAP financial measures during our call, and a reconciliation to GAAP financial measures can be found at the end of our press release. And with that, I'll turn the call over to Scot for prepared comments.

[Scot Woodall:]

Thanks, Larry. Good morning, and thank you for joining us today to discuss our second quarter financial and operating results. Before we begin, I would like to take a moment to welcome Paul Geiger to our HighPoint team as Chief Operating Officer. Paul has a proven track record of managing full-scale development programs and ensuring successful execution of capital programs. His strategic insights will be invaluable to HighPoint as we continue to deliver returns-focused growth. I'm excited to welcome Paul to our team and for you to meet him in the coming months. Also during the second quarter, we solidified our executive team with the promotion of Bill Crawford to Chief Financial Officer. Bill has been a key member of our management team, and we congratulate him on a well-deserved promotion. I will start with an overview of the second quarter and of our recent drilling and completion activity before turning the call over to Bill to review the financial highlights and discuss guidance. Our second quarter results demonstrated our continued operating excellence as we reported total equivalent production sales volumes within our guidance range, including oil volumes that were above the midpoint of guidance. We generated EBITDAX of $63.1 million for the second quarter, an increase of 35% over the first quarter of 2018 and a 72% increase over the second quarter of last year. We had a busy start to the year, highlighted by the completion of the Fifth Creek transaction and the addition of the Hereford Field. Integration has gone smoothly, exceeding my expectations. The back-office integration happened seamlessly. The operations team had equipment in the field and initiated drilling and completion operations within weeks of closing the transaction. I previously outlined our intention to add a second rig to the Hereford Field by midyear, and I'm pleased that we accomplished this goal in June, ahead of schedule. This will allow us to build on our strong operational momentum during the second half of the year. I'm proud of the efforts of our entire organization. With respect to midstream, we continue to feel the impacts of constraints in Northeast Wattenberg that resulted in curtailed natural gas and associated liquids production during the second quarter. These issues have persisted into the third quarter as well. As outlined in our press release, we have adjusted our guidance to account for these temporary issues as they relate to natural gas and NGL volumes, but we expect that full year oil volumes will be relatively unchanged from previous expectations. This is important as the majority of our revenues are derived from oil volumes. Our longer-term growth objectives remain intact, and we are reiterating our 2019 outlook. Bill will expand on these topics as well as the proactive steps we have taken to secure midstream diversification in his remarks. Now for an update on operations. We are currently operating 3 drilling rigs in the DJ Basin, two are active in the Hereford Field, and 1 is active in our Northeast Wattenberg acreage. We plan to maintain this level of development and drill approximately 120 to 125 gross extended reach lateral wells in 2018. Our Hereford drilling operations began in April on drilling a spacing unit 11-63-14. This included 10 extended reach lateral wells, of which 6 were Niobrara wells and 4 were Codell wells. Drilling operations were finished in July and based on the timing of completions is anticipated that these wells will be placed on initial flowback during the third quarter. I would now like to provide an update on the initial Hereford drill but uncompleted wells that we completed during the second quarter. Completion operations commenced in April on 3 pads with 3 wells each. As a reminder, these wells were not optimally drilled and spaced, consistent with our full field development plans. Our completion design consisted of approximately 1,500 pounds of sand per lateral foot and 82 stage completions. Controlled flowback was utilized. The first 3 wells were placed on flowback in May and continued to trend towards peak production with a high oil cut. Although it's still early, we are encouraged by the early production as these wells have been performing consistent with our expected type curve for the first 60 days of production. Under the current flowback time line, it is anticipated that peak production will be achieved after approximately 90 days. The remaining 6 DUCs were placed on production in June and July, respectively, and are in the initial flowback stages. Our focus on full drilling and spacing unit development is paying early dividends as we are realizing significant cost savings due to the synergies generated. Completion cost for the 9 DUCs were 29% below the legacy completion cost. In addition, drilling costs for the initial drilling and spacing unit were 17% below the legacy cost. We average approximately 8.5 days per well from spud to rig release, including a best-in-class well that was drilled in 6.9 days. This highlights the efficiencies generated to full-scale development of our drilling and spacing units in the Hereford Field. We expect this trend to lower and match historical averages achieved at Northeast Wattenberg, and we continue to expand our operations. We look forward to providing further updates on the Hereford assets soon. Turning to Northeast Wattenberg. We produced an average of 23,900 BOE per day in the second quarter of 2018, representing a 65% increase over the second quarter of 2017. We drilled 20 extended reach lateral wells and placed 21 extended reach lateral wells on initial flowback during the second quarter. Recent activity was highlighted by the DSU in 5-61-27, which includes 10 extended reach lateral wells and is located in the east central portion of the Northeast Wattenberg field. Initial flowback began in the second quarter, and early production data is performing consistent with expectations. Our operations team continues to do a good job in offsetting the impact of service cost inflation as wells drilled during the first half of 2018 averaged approximately $4.85 million. This is in line with our internal expectations. In addition, total drilling and completion cycle times averaged approximately 16.5 days for the first half of 2018, which is a 6% improvement over the 2017 average and was driven by a reduction in the number of fracs and drilling days. In summary, we have done an excellent job integrating our Hereford asset, executing on our drilling plan and managing through the short-term basin-like constraints associated with third-party natural gas processing facilities. We remain well-positioned for a long-term growth value creation through disciplined capital allocations and within a favorable asset targeting oil-weighted and rural areas of the DJ Basin. I will now turn the call over to Bill.

[William Crawford:]

Thank you, Scot, and good morning. Our second quarter was highlighted by oil volumes that exceeded the midpoint of guidance, strong realized oil prices and a lower per unit LOE, all of which led to strong EBITDAX and cash flow generation. I will now go over some of the financial highlights, provide some additional detail regarding our midstream position and discuss guidance for the remainder of 2018. We reported production sales volumes of 2.41 MMBoe, representing a 58% increase over the second quarter of 2017. Second quarter production came in at the lower end of guidance range due to lower gas and NGL production. This was a result of high line pressures, unplanned processing facility outages caused by unseasonably hot weather, along with delays and lower product recoveries associated with interim third-party processing facilities. Oil production of 1.51 million barrels was approximately 3% above the midpoint of guidance and did the consensus estimates. Lease operating expenses of $3.15 per BOE was a 13% decrease from the comparable 2017 period and a 4% improvement from the first quarter of 2018. We expect the LOE to continue to trend lower going forward. We continue to generate greater value from our barrels as our oil price differential to WTI averaged $2.76 per barrel as we have the ability to capture multiple markets with our desirable 38- to 42-degree crude. We expect that oil price differentials to the benchmark pricing will be less than $3 per barrel for the foreseeable future. Our high oil cut, low differentials and low operating cost allowed us to generate a strong margin of over $38 per BOE for the second quarter, which we expect is the highest among our DJ peers and was up over 40% from the comparable 2017 period. Touching on the balance sheet. We are in the process of amending and extending our credit agreement to incorporate the Hereford reserves and expect to upsize the facility from the current level. We expect to close in mid-September as the market is strong and we anticipate comparable or better terms in our current facility. When combined with our quarter end cash balance of $107 million, we enter the second half of the year with liquidity of $381 million. Our debt metrics continue to trend as expected with net debt-to-EBITDAX of 2.4x this quarter and are forecasted to be below 1.5x in 2019. We reiterate that we expect to be cash flow positive in mid-2019. The midstream challenges in Northeast Wattenberg experienced during the first half of the year resulted in minor production impact that led to lower natural gas and NGL volumes. We estimate that the midstream impact was approximately 0.2 MMBoe in the first half of the year, over and above what we had already factored into our H1 guidance. And we're expecting a slightly higher amount for the third quarter as third-party processing delays persisted into July and is baked into our Q3 and full year guidance. Natural gas processing capacity has improved as our allocated volumes to DCP have increased by approximately 25% with the Mewbourn 3 plant becoming operational last week. We have worked diligently to diversify our gas processing capacity and have signed agreements with several third-party midstream providers to alleviate high line pressures and to increase our available gas processing capacity by over 70% by the end of 2018. This provides us the flexibility to direct approximately 35% of expected fourth quarter Northeast Wattenberg volumes to processing facilities outside DCP's legacy system. All of this midstream optimality provides us the ability to maximize our oil production, which is, by far, the largest driver of revenues. I would note that Hereford natural gas volumes are processed by some at midstream, which is in the process of expanding its gas processing capacity to 60 MMcf per day by the end of 2018. I will now take a few moments to provide an update to our operational outlook. Incorporating the impact of midstream and weather-related issues, we anticipate that our natural gas and NGL production will be lower than previously forecast. Accordingly, we are revising our pro forma production guidance to 10.5 to 11 MMBoe, but our pro forma oil per volume guidance remains virtually unchanged and is expected to be in the range of 6.6 million to 6.9 million barrels or approximately 63% of total production volumes. We expect third quarter production to average 2.65 to 2.95 MMBoe, 63% of which will be crude. This represents a sequential increase of 16% at the midpoint as we benefit from the wells that were placed on flowback during the second quarter, including the Hereford DUCs, offset by the July midstream constraints. Capital expenditures for the third quarter are expected to total $140 million to $150 million as we continue to operate 3 rigs and 2 completion crews. Full year 2018 CapEx guidance is unchanged. As Scot mentioned, we are setting ourselves up for a strong 2019, and we are reiterating our outlook. On the hedging front, we continue our strategy of being 50% to 70% hedged on a rolling 12- to 18-month time frame and have taken advantage of the recent strength in crude prices to layer in support for our capital program to provide predictability and visibility into future cash flows. You can find a full summary of this hedge position in our press release or the 10-Q. To wrap up, despite the near-term midstream headwinds, the team has executed the drilling and completion program on plan, and we are poised for strong value creation. We are now ready to take questions. Operator?

[Operator:]

[Operator Instructions]. And our first question comes from Derrick Whitfield with Stifel.

[Derrick Whitfield:]

Congrats on your progress at Hereford.

[Scot Woodall:]

Thanks, Derrick.

[Derrick Whitfield:]

So perhaps for Scot, in light of the recent negative headlines associated with Initiative 97, could you kindly share your thoughts on state and local government sentiment? And then also, if you could, kindly address your thoughts on the implications of Initiative 108 as it relates to Initiative 97.

[Scot Woodall:]

Sure. So first off, I guess, I would just say, Derrick, kind of my big picture, when we talk about regulatory and govern affairs, things, in the State of Colorado, historically, as I look back over my 10 year in Colorado, it seems like we've always found a balance between the needs of our citizens and the oil and gas industry trying to be good corporate citizens. And it seems like that we've -- we generally have reached that balance over the last several years. And while initiatives have been proposed in '14 and in '16, collectively, the industry and local politicians and the systems groups have come together, and we've never been prohibited from doing our oil and gas operations and executing our business plans as we would like to do so. Obviously, we want to do them in an environmentally friendly way and in a safe manner in all of our operations. When I look at the ballot proposal for the initiative of 97, it just feels like it's just gone too far. And I think it's been well documented in a number of the studies that are out there where it basically takes 90-plus percent of the land away from oil and gas development. And that just feels like it's gone too far. And so I guess, I would say that it doesn't have the support, I don't think, of any of the current candidates for governorship, both on the Democratic side and the Republican side nor does it have the support from the current governor. And I think almost at any of the key candidate races, you aren't seeing much support for it because I think it has gone too far, and it's not the balance that we have enjoyed over the last several years. So we will see. As you know, we're in the early phases of signature validations, and it's just a process we have to go through with the Secretary of State over the next 30 days. So I would say that I would think that the State of Colorado will strike that balance again as we historically have always been able to strike over the last 100 years of oil and gas development in the State of Colorado. Specifically to your question on the ballot proposal 108, which is one that has been put forward by the Farm Bureau, it also collected enough signatures. But the Secretary of State is reviewing the validity. But I think there was over 200,000 signatures turned in on that proposal. And really, what that proposal does is it solidifies, I think, the rights of landowners and mineral owners that if the government imposes some restrictions that keeps them from recouping the entire value of their acreage or lowers the value of their acreage and minerals, they have the right to get compensation for that. There is also a study that's out similar to the study that talks about the land being taken away. And ballot proposal 97, there's a study out that talks about this costing. If 108 was implemented and if 97 was implemented that the effects of 97 would lead to about $26 billion of taking that with the State of Colorado would have to reimburse mineral owners for the loss of being able to develop their properties. So it's a very significant impact. It's definitely a piece of a ballot proposal that protects landowners, protects mineral owners and how the two -- if both of them got on the ballot and if both of them were voted favorably by the voters, it will probably cause a lot of legal headaches about how you administer the two of them over the next several years.

[Derrick Whitfield:]

Scot, that was quite helpful. And then as my follow-up, some of your larger-cap peers have recently noted inflationary pressures in the basin. Could you speak to what you've experienced to date and what you're expecting in the second half?

[Scot Woodall:]

Sure. So we entered the year with like in our Northeast Wattenberg area, we were budgeting about a 10% inflation number, 2018 over 2017. And so that was taken our well cost in the Northeast Wattenberg up to like a $4.8 million, $4.9 million type of expected number. Through the first half of the year, we're dead on track at $4.85 million. So we have experienced some inflation. But the team continues to be able to offset some of that inflation by their continued decrease in cycle times and drilling efficiencies. There will still be some pressures in the second half of the year, but I guess, that's the challenge to our operations team is to be able to mitigate that through future efficiencies. And so we expect that we'll be able to manage that, and we expect that to be in our capital guidance range for the full year.

[Operator:]

Our next question comes from Welles Fitzpatrick with SunTrust.

[Welles Fitzpatrick:]

Kind of a follow-up on Derrick's question, and I hate to make this about 97. But can you talk a little bit as to the rural advantage? If I remember correctly, in the past, you guys have quantified the impacts that are either 2,000 or 2,500 footstep backward would have on you all. And it was relatively minimal, if I'm remembering correctly. Do you mind talking to that?

[Scot Woodall:]

Sure, Welles. There's actually kind of two numbers, though. One of the earlier proposals talked about 2,500 feet from occupied structures. And I think that's when the company put out numbers that said we would be -- about 3% of our acreage would be impacted if the proposal was written from occupied structures. And that's still a true statement. However, 97 is written so honestly that it is from occupied structures and anything that is deemed a sensitive area. And so we throw in sensitive areas, it throws in a tremendous amount of streams, potential streams and a lot of other areas. And so the study that's been done talks about 90-plus percent of all nonfederal acreage in the State of Colorado being off-limits. When we've done the studies for ourselves, we're impacted pretty heavily as well. We would estimate that about 70% of our acreage would be off-limits the way 97 is written.

[Welles Fitzpatrick:]

Okay. All right, great. So the 2% to 3% was for occupied structures, not including the kind of intermittent streams and those other words. I suppose -- and this is probably unfair to ask, so if you have 30% of the acreage, presumably, you would have a larger, maybe significantly larger, percent left of the well locations and so much as you guys can do three, sometimes even four mile type of step-outs. Is that accurate? And do you have any quantification of that?

[Scot Woodall:]

Not really. We just kind of basically look at we continued our normal development of the two mile link laterals, what that impact would be on the drilling and spacing units. So we haven't run a scenario that 97 passes and then how do we build the development plan around that.

[Welles Fitzpatrick:]

Okay, that's perfect. And then, could you talk a little to line pressures? What have you all been seeing before Mewbourn came on? And what are they looking like now?

[Scot Woodall:]

I don't think that we've seen much difference yet, Welles. So we, for most of the year, have experienced about 400 pounds. And yes, we burnt on and are starting to take some volumes. But I don't think you've seen that ripple through the system yet and significantly change our line pressures yet.

[Welles Fitzpatrick:]

Okay, perfect. And just last one. Have you guys signed up for capacity on O'Connor or Big Horn?

[William Crawford:]

The other part of the DCP super system that we have access to.

[Welles Fitzpatrick:]

Okay, great. So that just goes with the acreage commitments? Okay, that's perfect.

[Operator:]

Our next question comes from Jason Wangler with Imperial Capital.

[Jason Wangler:]

I wanted to ask up in Hereford as far as now you're up there drilling actively, it looked like the DUCs as well as your first pad were all pretty kind of right in the middle of the acreage. Can you talk about what the 2 rigs kind of where your expectations are to drill the rest of this year and maybe even into early '19 as you kind of build that position out?

[Scot Woodall:]

Sure. So that first drilling and spacing that we drilled, we basically moved the 2 rigs to the drilling spacing unit immediately to the west. And the plan is to do the next 3 or 4 just keep stepping to the west. That takes us, I think, into '19. And then I think we come back, and we start. We go up north, right on top of those drilling and spacing units and go east to west again. So we're just right in the core, drilling up the core. Obviously, it's right next door to where the existing summit plant is. And so it minimizes infrastructure cost which is part of the intent as well. And obviously, you can look and see that we're trying to drive efficiencies. As I noted in my prepared remarks, we're already realizing some of those efficiency gains and cost gains, so that's our intent.

[Jason Wangler:]

Okay, I appreciate it. And then, obviously, I appreciate the issues that have been going on with the infrastructure in the Wattenberg specifically. As you guys now are two rigs up in Hereford, and I would think that production growth at least in the Wattenberg would start to slow as you're seeing more both from yourselves and DCP bringing on more infrastructure, do you think that, that will help lessen it? Or do you think that from your basis -- or do you think that there still is going to be an issue in the Wattenberg side just because the basin overall is having so much production versus their midstream capabilities as you kind of move forward?

[Scot Woodall:]

Yes. Well, let me kind of speak specifically to that. If we talk about this Wattenberg field, yes, a majority of our volumes flow through DCP, and we have experienced, similar to everyone else, some constraints in the first half of the year. But we have signed agreements with other third-party gatherers and processors to take volumes out of the Northeast Wattenberg area, which would reduce our reliance on DCP. Most of those things -- one of those things started in the first quarter of this year, and it's continuing to ramp up, and we think there's going to be some additional capacity come online here over the next few weeks that will continue to enable us to take gas to that particular purchaser as well as we think over the next month or 2, there's going to be 2 other gatherers and processors that will start taking volumes out of our Northeast Wattenberg. So we'll be able to diversify that position quite a bit. And then you couple that with the DCP strategy that's out there at the new plant that came on here in the 1st of August. And then they have subsequent facilities that are coming on over the next 12 to 18 months. So no, I don't think it's a perpetual issue in the Wattenberg field. I think it's going to be resolved, hopefully, near term for us with the other marketing outlets that we have secured. And the entire basin, I think, you would start to see a relief over the next several quarters. But you are also bringing up a key point with just the high oil cut that exists up there in Hereford, it really takes your reliance on midstream, reduces it quite a bit. And clearly, Hereford gives us a lot of flexibility because it goes to a totally different outlet than the Wattenberg field.

[Operator:]

Our next question is from Gabe Daoud with JPMorgan.

[Gabriel Daoud:]

And Scot, thanks for all the prepared remarks and the commentary on and what's going on in Colorado. Maybe just at Hereford, the DUCs, could you maybe just elaborate a little bit more on what exactly you could do differently moving forward, whether it's landing the lateral in a different area, tinkering with the completion design a little bit more? Just trying to get a sense of how you could drive some upside results relative to the base-type curve.

[Scot Woodall:]

Sure. So I think, initially, the drilling spacing unit that we drilled, we widened the spacing a little bit. So we did 10 wells in the first drilling spacing unit, and we're going to try some other spacing test on subsequent spacing units kind of between 16 and 10 wells. So it -- there'll be a spacing like that. And the DUCs were drilled more at an 18 to 20 well per drilling spacing unit, so a much tighter spacing. And then I think we want to make sure the laterals are placed really more in that wine rack between the Niobrara B and the Codell and not underneath each other, if you kind of know what I'm trying to say there a little bit. So just a few little tweaks, and obviously, spacing is a balance between how you stimulate them well. And so there's a couple of things that we need to learn as we go forward. But I think we've got a pretty good strategy and a pretty good testing program lined out for the next several quarters.

[Gabriel Daoud:]

Thanks, Scot. That's helpful. And then, as you think about 2019 and with the growth rate kind of reiterated and you hit cash flow neutral by the middle point of the year and then ultimately, [indiscernible] will start to generate some free cash, could you just maybe just give us some thoughts on what the use of cash would be? Do you accelerate a bit more on Hereford if things are going well? Or do you try to bulk up and take on some more acreage? Just any thoughts around use of cash.

[Scot Woodall:]

Yes. The first, since you loud out '19, I feel like I got to make a comment. In the prepared remarks of either mine or Bill's, we definitely wanted to communicate to you, as an analyst, and to the investment community that these are all short-term issues that are driving the change in guidance. And it's short-term issues associated with gas and NGLs which really have very limited impact on our revenues and EBITDA. And so -- and I think all of those will be resolved over the next couple of months with all that diversification that we did on midstream. So the '19 outlook is way intact, and we're excited for the future of the company, and we're excited for where the company is going to go in '19. And yes, I love taking questions that talk about when you're cash flow positive. Things have changed a lot over the last 12 or 24 months in the company. And so I like to talk about those types of things. And I guess what I would say is it just gives us so much flexibility to, like you said, if commodity prices are favorable, that we could increase activity. We could look to do bolt-on transactions. I mean, I think there's just all kinds of flexibility that we can do out there. And I think we'll be in a nice position, and it'll be kind of fun to be in that position.

[Operator:]

[Operator Instructions]. And we have a question from the line of David Beard with Coker Palmer.

[David Beard:]

I realize -- the oil cut is a driver of value. But could you just give a little detail on realized natural gas prices, and just how the -- those pricings relate to a build-out in infrastructure, meaning could we see better prices over time?

[Scot Woodall:]

Yes. I mean, I think current Rockies prices are just above $2 per MMBtu. And I think compared to Henry Hub of, what, $2.75, $2.80. And so yes, there's a little value there. But well, almost like 88% of our revenue is crude. And so those gas volumes really just don't drive it. And so I think gas is probably going to be in that range for the foreseeable future, which is why we've done everything we can to maximize the crude volumes and crude revenue.

[Operator:]

And I'm not showing any other questions in the queue. I would like to turn the call to Larry Busnardo with his final remarks.

[Larry Busnardo:]

Great. Thank you, again, for joining us today. As always, please feel free to contact us if you have any additional questions regarding the results or our outlook. And we look forward to seeing many of you in a couple of weeks here in Denver at the upcoming conference. Thanks.

[Operator:]

And ladies and gentlemen, thank you for participating in today's conference. This concludes the program, and you may all disconnect. Have a wonderful day.