HighPoint Resources Corporation's (HPR) CEO Scot Woodall on Q1 2020 Results - Earnings Call Transcript
HighPoint Resources Corporation (NYSE:HPR) Q1 2020 Earnings Conference Call May 5, 2020 9:00 AM ET
Larry Busnardo - VP, IR
Scot Woodall - CEO
Bill Crawford - CFO
Paul Geiger - COO
Conference Call Participants
Derek Whitfield - Stifel
Welles Fitzpatrick - SunTrust
Jason Wangler - Imperial Capital
Ladies and gentlemen, thank you for standing by, and welcome to the Q1 2020 HighPoint Resources Earnings Conference Call. At this time, all participants are in listen-only mode. After the speakers' presentation, there will be a question-and-answer session. [Operator Instructions]. Please be advised that today’s conference is being recorded. [Operator Instructions].
I'd now like to hand the conference over to your speaker for today, Mr. Larry Busnardo. Thank you. Please go ahead, sir.
Good morning and thank you for joining us today for the HighPoint Resources first quarter earnings conference call. Speaking on the call today are Scot Woodall, CEO; Bill Crawford, CFO; and Paul Geiger, COO.
Before we begin, I'd ask that you 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 other filings with the SEC or in our 10-Q, which we filed yesterday afternoon.
We will also be referencing non-GAAP financial measures during the call and a reconciliation to GAAP financial statements can be found at the end of our press release. This morning, we posted a new presentation to the Investor Relations portion of our website that we will be referencing on today's call.
With that, I’ll turn the call over to Scot, to begin our prepared remarks.
Good morning and thank you for joining us today to discuss our first quarter 2020 financial and operational results.
The COVID-19 pandemic has significantly impacted global supply and demand fundamentals, broader markets and economy. In conjunction with the precipitous drop in oil prices, we're operating in unprecedented and uncertain times that has severely hampered the macroeconomic environment for E&P companies.
Our first priority is the health and safety of our employees. And I would like to commend them for their commitment, dedication and professionalism and maintain the smooth functioning of our operations during these challenging times.
As an organization, we respond quickly to the COVID-19 pandemic by implementing our business continuity plan. This involves the implementation of remote workforce measures in both the Denver headquarters office and our field offices. The transition was seamless, and we have not experienced any notable challenges with respect to our operations, or obtaining oilfield goods and services. We also have not experienced any third-party related downstream issues up to this point.
We reacted decisively to the lower crude price environment by deferring all capital and depletion activity until oil prices improve. We're committed to preserving our balance sheet and liquidity and ensuring free cash flow generation for 2020. Given the uncertainties we're facing as an industry, we will be disciplined in our consideration of future capital investment. We will continue to assess changes in the broader market as well as current and future oil prices to determine the appropriate time to resume operations. We're cognizant of the changes required to operate efficiently and profitably in this lower commodity price environment.
In this regard, we have implemented several cost saving initiatives, which enable us to better align our cost structure to the current operating environment, and we're in the process of determining future saving measures.
Now, to recap the quarter, we had a good start to the year and experienced limited operational impact. This allowed us to deliver very strong results that were highlighted by oil volumes exceeding the high-end of our guidance range. We accomplished this with capital expenditures that were lower than our guidance, highlighting the efficiency of our operations. Operationally, we delivered strong well performance from our Codell completions at Hereford and high fluid intensity completions at Northeast Wattenberg, both of which are performing materially better than earlier wells. Paul will discuss this in more detail.
Lastly, our strong first quarter results allowed us to reduce our bank debt by 32% in the first quarter.
I will now turn the call over to Bill for his comments.
Thank you, Scot, and good morning all.
As Scot mentioned, we had a good start to the year from an operating perspective as our results generally exceeded consensus estimates in our quarterly guidance. Production volumes of 2.9 MMBoe and oil volumes of 1.6 million barrels were both ahead of guidance. This was a result of the strong Codell results that Scot mentioned, along with accelerated timing of our online and the quick recovery of our Hereford Section 17 area post cleanup.
Capital expenditures were $10 million below our guidance range at $70 million.
As Scot mentioned, our strong first quarter generated EBITDAX of $81 million which was an increase of 6% from the first quarter of 2019. This included $8 million for the early termination of a small portion of our Q3, Q4 2020 hedges because we reduced the activity near-term.
The remaining hedge protection sorry -- our remaining hedge position provides significant near-term protection from low oil prices. We have nearly all of our anticipated 2020 oil production hedged at WTI price that is greater than $57 per barrel and about half of our 2021 production hedge at about $55 per barrel. The mark-to-market value of our hedge book is about $170 million based on current WTI strip prices, providing significant near-term revenue protection. A full summary of our hedge position is in the press release.
Our strong first quarter results and focused capital discipline contributed to a $45 million or 32% reduction in bank debt during the quarter. We recently began the semi-annual redetermination of our credit facility and anticipate that the review will be completed in the coming week. As many of you're aware, the banks have faced significant challenges with many borrowers and have become more restrictive with commitments and structures. We are not immune to these effects as our bank meeting was delayed multiple times in April, and we're still in discussion with the syndicate.
Due to lower price decks on our reserve and hedge level, we expect our borrowing base could be reduced by up to 40% and our borrowing capacity reduced a little bit further as banks are seeking stronger cushion and reduced exposure to the space. We do not expect any material structural change but maybe higher pricing is.
Given the uncertainties of future oil prices and the impact that broader macroeconomic effects, including the pace of economic recovery, will have on the oil sector, we're currently providing guidance for the second quarter only at this time, in which we expect capital expenditures to total about $40 million as we finished up our work in April and anticipate that production will be in the range of about 2.5 to 2.6 MMBoe of which about 57% is oil. We expect to achieve this level of production provided; we do not experience any physical downstream production constraints or shutting.
We're preparing for the possibility of shut-ins based on the potential for downstream physical curtailment as crude storage may fill. But thus far have not seen any challenges due to our diversity of crude purchasers and markets along with the premium API gravity of our Niobrara crude. We have proactively shut-in a modest amount of production that was only marginally economic. We enjoy low lifting costs for our PDP base and will constantly monitor physical and financial markets to decide if further shut-ins are warranted.
Finally, a quick note on our large net loss for the quarter because of all the uncertainties in current commodity prices, we recognized a non-cash impairment of just over $1.2 billion related to the carrying amount of our approved and unproved oil and gas properties. We expect our DD&A rate to be about $8 per Boe going forward.
With that, I'll turn it over to Paul for an operational update.
Thank you, Bill, and good morning, everyone.
First, I would like to congratulate and commend our field and office personnel for the strong first quarter performance and for safely delivering on our targets. Our development program generated impressive results and we're very pleased with the production performance from our initial 2020 wells in Northeast Wattenberg and at Hereford.
I'll now refer you to Slide 8 in the presentation as we look first at Northeast Wattenberg. We brought online six wells in our Riverside unit in DSU 4-61-5 and employed our proven higher fluids Northeast Wattenberg Generation 4 completion design. We've been very encouraged by the results of these wells, with average per well cumulative oil production tracking approximately 90% above the offset analog wells that were completed with the previous standard completion design after 50 days. These results significantly improved the economic proposition for our Northeast Wattenberg inventory.
Our initial two Codell wells in the Fox Creek area of the Hereford field were completed with the larger Hereford Generation 4 designs of 50 barrels per foot and 2,000 pounds of sand per foot. These high rate high volume designs are based on the observed ability of these larger jobs to increase stimulated reservoir volume during our Hereford outlook. These wells replace online late in the first quarter and are demonstrating the increased productivity that we were targeting. After the first 30 days of continually inclining oil production, these wells are each producing over 400 barrels a day.
You can see on Slide 6, this is 30% higher than the Section 16 Southeast pad which is the analog for our Hereford reserved bookings and represents our economic baseline.
Also in the Fox Creek area, we placed five wells on flow back in April at DSU 12-63-34 which continue to ramp to peak production.
Completion operations recently concluded on two wells in the Fox Creek area DSU 12-63-33, the wells are awaiting drill out and anticipated their initial flow back will commence during the second quarter. We currently have 33 duck opportunities in our inventory post the completion of this work.
To summarize, we were very pleased with our operational performance year-to-date in 2020. We performed well against our first quarter targets. We brought our first high rate stimulation pad online in Northeast Wattenberg which is outperforming all offsets.
We brought our first high rate stimulation pad online in Fox Creek area of Hereford which is outperforming the previous best development on Section 16 Southeast pad. Our most recent performance in both assets demonstrates our best economic performance yet, which coupled with our basin leading margin, positions us very competitively to face the many challenges our industry is navigating.
Operator, we're now ready for questions.
Okay. And our first question comes from Derek Whitfield.
Perhaps for Scot, certainly appreciate the challenges of providing quarterly guidance in the current environment. With that said, assuming your CapEx plan is currently contemplated, could you offer any color on the broad bookings on where you could exit the U.S. oil production?
I don't know Derek. I think we aren’t really kind of trying to put out an absolute number, we are kind of looking at this thing on a quarter-by-quarter kind of basis looking to see how much capital we're going to end up deploying in the second half of the year and couple that with also just if there's any physical limitations, so I kind of hate to even kind of put out a range right now, Derek.
Understood, Scot, certainly the challenging time. Perhaps for Paul with my second question, with respect to the fireballs at Fox Creek could you speak to the well design and spacing for those wells more broadly and highlight the applicability of that design to the Niobrara interval, as I recall those are Codell wells.
Yes, Derek, the first two are Codell wells, the next five will be Niobrara. And so we've got the two Codell wells that will follow those Niobrara designs are there, the Generation 4 Hereford design, there's a higher fluid rate and higher fluid design, total volume completion. So we expect those to be similar to the original Codell. And then as a result of the larger job, we'll blow those back more aggressively as well to get that water off. Overall, those are about a six well spacing on the Niobrara effective spacing and with that Codell both. As compared to the Codells that are out there that are about four well spacing, as you've seen us continue to develop on in Hereford.
Okay. Our next question comes from Welles Fitzpatrick.
I was wondering if we could get an update on the politics in the state. Obviously, it's pretty tough to collect signatures these days. I mean, can we assume that there's likely not going to be a ballot initiative targeting the industry come November?
It's probably too early to draw that conclusion, Welles. But I think your assessment is probably right. Currently, we still require physical signatures in the state. And so that's probably going to be very difficult and very challenging to do, and to meet the deadlines for early August. There's been some discussion about doing it online, but it's not getting much traction. And I'm not even sure if legally, the state can go down that path. So we need to jump to conclusions. But it seems like it's trending that way.
Understood, makes sense. And I'd have to imagine the state needs that revenue more than ever now. Can you talk a little bit to the divestitures you might do in the math right that went from $27 million to $30 million. Can you -- was that just the sellers funding falling apart? And can you talk about the associated production with just the $3 million now if you could break that out, that'd be helpful.
Yes, Welles this is, Paul. Looking at those divestitures, as we progress through the downturn, we had some of those offers kind of re-trade there. So we had multiple offers on the not only the package that closed, but the package that -- the packages that we did not elect to transact on. The reason for that is as we saw that price continue to soften and the resulting offers continue to soften, they didn't look like there were accretive opportunities for us looking forward into 2020 and 2021 really specifically with those two with the development in the Permian on that acreage, and then as well as the position in Wattenberg with the continual improvement of the wells and designs that we're seeing weren't really compelled to divest those in the turn.
Okay. Next question comes from Jason Wangler.
Hey, good morning. I was just curious as you guys talk about the borrowing base redetermination, obviously, were able to pay some of the facility down in the first quarter as you kind of go-forward, you have to hedge your book, is that going to be the focus in terms of cash flows is trying to reduce that balance sheet further, or is there anything else we should be thinking about?
Yes, Jason this is Bill. Yes, I mean obviously we needed to get through the borrowing base here in the spring to determine what levels of liquidity and as we look out as through the summer, what are the best uses of our cash and how we think about using it. And so I think that's why we've made the decisions we have and have the liquidity we have and we have taken advantage of whatever we can.
Okay. And Scot, I know the production side, I certainly appreciate not more on the kind of put numbers around that. But as you think about the capital spend as you've kind of deferred everything, as you think about it, if you're running it, ex-April, I mean is it a pretty low number that you're thinking about in terms of CapEx that you think about May and June? And it obviously this continues, in the second half of this year, is there a range of numbers you'd say that's what you call maintenance CapEx obviously, but a number that you guys would be spending but as you move forward with that program?
Yes, in the beginning of Q2, we still were wrapping up some of the drilling and completion operations, and that's why you see that CapEx number of our guidance of about $40 million. Provided that we do not resume drilling and completion activities, that number probably falls is something that's more in the $10 million range per quarter or something which is just we've got to drill out the wells and do some maintenance and do some things, but it's probably a pretty low number subsequent quarters, if we do not resume activity.
Okay. Next question comes from Noel Park [ph].
I was interested in hearing, just how you are looking at well results with the updated completions, you've now got more completion history on a bunch of them and just as far as adherence to type curves and seeing roughly what you would expect given the strong IPs is how that looking little more history?
Sure, Noah, this is, Paul. Yes, we look at those, you saw that the plot there in the deck on six and eight we're very encouraged with those initially they've got a higher flow back rate, a higher observed productivity based on the significantly larger simulations we've put on those. And so at this point, as the worst case, I think that's you could say that's acceleration only in which case, you still have improved your rate of return five points or above. But best case is you've got incrementally EUR there. And that's what -- what we really believe having put a much larger completions on them, having has a higher total fluid productivity, and based on the georeference we're seeing, and so we were expecting that those are incremental performance improvements overall to the EUR and the improvements or type curves in those areas going forward.
Great, great. And talking about RORs, I'm looking at, or what I've heard from folks about the service environment. And I feel like this is probably the fourth year in a row, I thought well cost can't go any cheaper than this. And then for example, we have this year's events and it looks like they could go even cheaper. Just what are your thoughts and do you have a sense of -- and this of course assuming we get better, better visibility, a stronger strip that makes it more attractive to look ahead. But do you think where you would be right now if you were drilling, is this the absolute trough you think and looking ahead, where do you think sort of cost might be on a more normalized basis assuming we say in 2021 have more of a $50 world again?
Sure, so starting off at the top ROR, I mean our bigger driver there is going to be this double-digit improvement in recovery per well. And so we're very pleased with that is kind of the dominant input into that system.
From a cost standpoint, we had pretty attractive pricing coming into 2020 here and you'll see that flow through on the capital per well. So we're very encouraged about that.
From a flexibility standpoint, I think that's going to be a toss-up. I think you got an opportunity for some concessions to get back to work, but probably in this trough, you've got some service folks dropping out. So we'll see how that plays out.
As we look into the second half, we're continuing to test the market and talk to folks on the completion side to make sure that in addition to this improved type curves that we're looking at that we've got the best, the most current cost as we contemplate decisions going forward.
Great, great. And I guess just one more thing. What are you hearing from your certain midstream partners, I'm sure the visibility is not great but I did notice there in the guidance, you specified that these are our numbers. This can't really incorporate anything unforeseen that could happen as far as I guess Force Majeure or other curtailments sort of beyond your control. But just what are you hearing, how is it sound, we haven't had -- we haven't had crude go back negative again, we will see how it looks heading into the June expiration but any insight you can give there would be great.
Yes, this is Bill. Yes, we sell to three or four different purchasers. And with our API gravity, being mid-30s, I think it's a very desirable cut for what the refiners are looking for and some of it stays local, some of it goes down, Grand Mesa pipeline, some of it goes down to the Pony Express. And we've heard that, they found home for all of our May barrels and into June barrels. So, right now, we're not feeling the pinch to do anything more voluntarily, given our very low lifting costs. And so but it's, we're ready to act if it does come up.
And obviously on the gas side with all the expansions recently and people starting to cut back activity, they're taking advantage of this time to do some planned maintenance and some other stuff, but no, gas or NGL issues.
And I'm showing that there are no further questions at this time. I would now like to hand the conference back over to Larry Busnardo.
All right. Well, thanks again for joining us today on the call. And we'll be around all day, if you have any questions, feel free to reach out. And we will talk to you soon. Have a good day.
Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You all may now disconnect.
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