HighPoint Resources Corp
Q3 2016 Earnings Call Transcript

Published: 4 Nov 2016

[Operator:]

Good day, ladies and gentlemen, and welcome to the Bill Barrett Corporation's Third Quarter 2016 Earnings 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 is being recorded. I'd like to introduce your host for today's conference, Larry Busnardo, Senior Director of Investor Relations. Sir, you may begin.

[Larry Busnardo:]

Good morning, and thank you for joining us today for the Bill Barrett Corporation third quarter 2016 earnings conference call. Joining me on the call today, Scot Woodall, Chief Executive Officer; and Bill Crawford, Senior Vice President, Treasury and Finance. Few quick notes before we begin, I'd like to remind you to read the disclosure statements provided within the forward-looking statements of our earnings release, which have 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. These documents can be found also on our website or at sec.gov. With that short intro, I'll turn the call over to Scot Woodall.

[R. Scot Woodall:]

Good morning, and thank you for joining us today to discuss our third quarter results. We continue to maintain positive operational and financial momentum by executing on the items within our control. This translated into an across the board beat for the quarter that included earnings, cash flow and EBITDA all coming in better than analyst expectations. We were also cash flow positive for the quarter and expect to be cash flow positive for the year. The outperformance for the quarter is primarily attributable to production coming in near the high end of our guidance range, a sequential reduction in lease operating expense and a marked improvement in our DJ Basin oil price differentials. Overall, it was a good quarter, and Bill will speak to each of these items in more detail. Operationally, we have placed two separate drilling spacing units on production during 2016. Development was focused on the Niobrara B, the Niobrara C horizons, and we have included a few minor variations in our wellbore design. Early production data from these drilling spacing units indicate that the wells are performing consistent with our expectations. Reported production volumes for these two drilling spacing units continue to trend higher and have not yet reached peak production rate. I would like to remind everyone that we utilize controlled flowback during our production operations. This practice is designed to maintain higher downhole pressures during early time production and has been found to maximize the peak oil performance. What this translates to is that a well can take up to six months to seven months to reach peak production before beginning to decline. We resumed our extended reach lateral drilling program during the quarter and recently completed drilling of the initial five well drilling spacing unit which targeted the Niobrara B, the Niobrara C, and the Codell horizons. This drilling spacing unit is in the southern area of our acreage position, south of the Platte River. As a reminder, we recently bored beneath the river providing access to the southern portion of our acreage position and allowing us to install the necessary infrastructure and gas lift equipment. Completion operations are expected to begin on this drilling spacing unit next week and should be completed in mid-December. We plan on increasing the proppant loading to approximately 13,500 pounds of sand per lateral foot. We anticipate that the wells will be placed on initial flowback in January and begin contributing to our production profile during the first quarter of 2017. We are estimating that the five well drilling spacing unit will be completed at a D&C capital of about $425 million (sic) [$4.25 million] (3

[William M. Crawford:]

Thank you. Scot. As Scot highlighted, we have done an excellent job of executing on our business plan, which has resulted in another solid quarter of results. For the quarter we generated discretionary cash flow of $37 million, a sequential increase of 11%. Year-to-date, we have generated $94 million of DCF, putting us on track to be free cash flow positive for the year. EBITDAX for the first nine months of 2016 totaled $137 million, and for the quarter was $50 million, a sequential increase of 5%. Q3 EBITDAX per Boe was $31.82, which we believe is top tier amongst our peers. Quarterly production volumes came in under 1.6 MMBoe, which was near the high end of our quarterly guidance range. Production was down slightly compared to the second quarter of 2016, primarily due to the loss of volumes associated with the sale of Blacktail Ridge, which closed in mid-July. We anticipate that the fourth quarter volumes will be similar to the third quarter as the DSU that recently finished drilling will not be completed until later this year and will contribute to late first quarter early second quarter 2017 production volumes. We are raising the low end of our 2016 guidance range to 6.0 MMBoe to 6.2 MMBoe to reflect the production sales volumes we have realized for the first nine months of the year. As Scot mentioned, we believe one of our differentiating factors that gives us the strategic advantage relative to many of our peers in the DJ Basin is our ability to capitalize on not having any firm oil transportation commitments. For the third quarter, our company-wide oil price differential averaged $3.02 per barrel less than WTI, a 47% improvement from the second quarter. The DJ Basin oil differential in Q3 averaged $2.21 less than WTI, as we were able to sell some of our July barrels at WTI flat with increased demand for barrels given the start-up of line pack for the Saddlehorn Grand Mesa pipeline that came on in Q3 and Q4. We expect fourth quarter differentials to be slightly higher than the third quarter, but see our operated DJ Oil differentials averaging approximately $3.00 per barrel off WTI for the foreseeable future as we have locked in some of this benefit without subjecting ourselves to potential take-or-pay penalties. LOE benefited seasonally and averaged $3.06 per Boe in the third quarter, compared to $5.28 per Boe in the second quarter. DJ Basin LOE averaged $2.45 per Boe in the third quarter, compared to $3.74 per Boe from the second quarter. We are lowering our 2016 LOE guidance to $29 million to $31 million from $31 million to $34 million as a result of an improvement in operating efficiencies, service cost reductions, the sale of higher operating cost properties in the Uinta Basin, and the DJ Basin becoming a greater proportion of our corporate operations. Third quarter CapEx totaled $8 million as we did not operate a drilling rig for much of the third quarter. CapEx for the first nine months of the year totaled $70 million as the DJ Basin – I'm sorry, the DJ Basin drilling program resumed in September and three wells spud prior to the end of the quarter. We expect that up to 15 XRL wells will spud before year-end and that the initial five-well DSU Scot mentioned south of the river will be completed before year-end. This will result in full year 2016 capital expenditures being approximately $100 million. Now on to the balance sheet. We ended the second quarter with $174 million of cash. I would note that the cash position was reduced by $26 million subsequent to the end of the quarter as we made our regularly scheduled interest payments. Our semi-annual borrowing base redetermination for the credit facility was completed in October with the bank group setting the borrowing base at $300 million, which was in line with our expectations. The reduction was primarily due to a combination of the sale of non-core assets and the effect of a lower hedge position. Importantly, there were no changes to the terms or conditions of the credit facility. We are in a great financial position as we exited the quarter with ample liquidity consisting of cash on hand and an undrawn credit facility. Our hedging strategy of layering in 50% to 70% of our forward 12 month to 18 months production has served us well, and we took advantage of the mid-October strength in the forward commodities curve to further protect our operating cash flow by layering in additional oil hedges for 2017 and 2018. For the fourth quarter of 2016, approximately 70% of our oil production is protected at a price of $72.57 WTI. We have also approximately 4,600 barrels of oil per day swapped in 2017 at a price of $60.60 WTI. You can find a full summary of our updated hedge position in the press release and in 10-K. In summary, we remain well positioned financially with strong liquidity that consists of cash in the bank and an undrawn credit facility that is underpinned by a solid hedge position. In addition, we maintain complete operating flexibility with respect to our drilling program. With that, we'll turn it over to questions. Thank you.

[Operator:]

Thank you. And our first question comes from Brian Corales from Howard Weil. Your line is open.

[Brian Michael Corales:]

Good morning, guys, and good quarter. Looking at the proppant load, can you just give us a sense of what you all did in 2015 versus I guess what's you're doing going forward?

[R. Scot Woodall:]

Sure, Brian. So I would say primarily in 2015, everything was at 1,000 pounds of sand per lateral foot. We did maybe 4 wells or so at, like, a 1,200 pounds or 1,250 pounds per square foot sand loading. So we kind of tested the concept a little bit in 2015, and I think looking at those results as kind of – as well as looking at others' results has led us to increase on these first five wells up to the 1,350 pounds, and then we do have plans on the second DSU that we're drilling right now, the nine well DSU, we will probably continue with the 1,350 pounds and probably even layer in a couple of 1,500 pounds on those nine wells.

[Brian Michael Corales:]

Okay. So we could even be going higher than the 1,350 pounds over time?

[R. Scot Woodall:]

Yeah, I think, we'll try a couple, Brian. Obviously that's – everybody seems to be going that direction a little bit, and I think, we just owe it to ourselves to test it on our acreage and make sure there's a cost benefit for doing it.

[Brian Michael Corales:]

And I know you all haven't done a monobore yet. Can you, I guess, from plans going forward, can you maybe tell us what it saves in terms of – or what do you think it could save for time and capital?

[R. Scot Woodall:]

Sure. So, in this nine well DSU that we're currently drilling, we're going to do 3 of the wells with the monobore technology. And so by our estimates, it seems like you could save a day or two days of drilling time because you're primarily eliminating one of the casing strings. And so, it could have a day or two days impact in terms of drilling time and then we'd have to, kind of, wait and see what the overall cost savings is. But it looks like it's worth trying in our estimation.

[Brian Michael Corales:]

All right, guys. Thank you.

[Operator:]

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

[Jason A. Wangler:]

Hey. Good morning, guys. Scot, you gave some pretty good color, kind of, on drilling activity. As you look at 2017, not being too specific, but as you look at your footprint, the – how do you see the cadence of your activity, whatever it is with one or two rigs just as you look at kind of developing your acreage? Are you going to bounce around? Or are there certain areas of focus? Just trying to get your thoughts there.

[R. Scot Woodall:]

I think, we'll just go back and forth probably between the north and the south. So, getting the river board this summer opens up that south area, so the first five wells are down there. We moved back up to kind of more the central area. I think, from there we may be going back to the north. I can't remember exactly. And I think, we'll wait to see the results from the south and go back down there. So, I think, we'll primarily move back and forth, and I think we've got a lot of flexibility kind of built into the schedule.

[Jason A. Wangler:]

Okay. And obviously you had a nice sale of part of the Uinta, and just kind of your thoughts there, obviously still not (16

[R. Scot Woodall:]

Right now, we're not actively marketing it. It is probably a lever that we could pull it some day. But it continues to cash flow and right now we kind of like the cash flow and kind of, I mean, with the similar trends as we're seeing in DJ, our LOE is down over there, the differentials have tightened over there. There's probably some additional opportunity for some lowering of LOE. Probably some additional opportunity to tighten those differentials and with a little bit of production operations, normal workovers and things like that, we're holding production flat. So it kind of seems like it's not that bad to keep it, if you know what I'm trying to say.

[Jason A. Wangler:]

No, I agree. Just that's why I kind of wanted to get your thoughts on it. I appreciate it. I'll turn it back.

[Operator:]

And our next question comes from Neal Dingmann from SunTrust. Your line is open.

[Neal D. Dingmann:]

Good morning, guys. Scot, you guys continue certainly to make great time on the drilling, I think, Canal most recently said 15 plus XRLs versus 12 prior plan. And I was looking at some of your older slides, how just over the quarters this continued to improve. Two questions there. One, do you see this trend continuing? I mean, are we kind of at a point where it might be tough? And then, two, what's the most recently the primary driver of this?

[R. Scot Woodall:]

Sure, so I would say that, yes, I think there's still a bit more room to go. As I said all the time, I think we always challenge our operation teams to do better, and the best they've done is like 6.5 days, and which you want them to perhaps do that more times than just a one-off type deal. As I was mentioning earlier, the monobore drilling may save a day or two days. So it seems like that they can continue to drive some efficiencies and maybe we would expect something in that six days or seven days as a repeatable ongoing thing. And you're right. It impacts things quite a bit, it didn't seem like it was too long ago, maybe a couple of years ago, we were talking about one DJ rig drilling like 26 wells, and now we're talking about it 40 plus wells. And so those guys continue just to make an awful lot of improvements. And I'm proud of the efforts. Obviously, shutting down for a few months, you always worry about if you're going to lose some of those efficiencies or lose some of that momentum. But it seems like the second well that these guys drilled, when we resumed activity was right back in line with where they left off a few months back.

[Neal D. Dingmann:]

Got it. And then just lastly, what would it take for you to, I guess, price wise or just I guess, cash flow wise to think about becoming more active in Uinta, given how good the economics continue to be in Wattenburg?

[R. Scot Woodall:]

Wattenberg is still probably our first choice, but we do have some of the members of the Utah team that are trying to present an argument for some capital. I think you will go out – you will see us in next year's plan maybe at least do a few recompletions in a few things because the economics are starting to look kind of compelling with the lower differentials and the lower LOE that maybe you do a few things out there. But still, by and large, the majority of the capital will be spent in the DJ.

[Neal D. Dingmann:]

Very good. Thanks for the detail, Scot.

[Operator:]

And our next question comes from Welles Fitzpatrick from Johnson Rice. Your line is open.

[Welles W. Fitzpatrick:]

Hey, good morning.

[R. Scot Woodall:]

Good morning.

[Welles W. Fitzpatrick:]

You guys have the differentials drifting back up a little bit in guidance. Is that due to just kind of typical conservatism? Or is that line pack effect that lets you get DI (20

[William M. Crawford:]

Yeah, this is Bill. Yeah, the differentials in July and August, I think, with the line pack, we probably got as aggressive for the marketers as we've ever seen. And I don't think we can replicate it. But I think we feel very good we can keep it in that $2 to $4 range for the foreseeable future.

[Welles W. Fitzpatrick:]

Okay. Well, that's great, yeah. And then the $4.25 million that you've talked about before, correct me if I'm wrong. But, if I remember, the last time you talked about the $4.25 million, it was with less than 1,350 pounds of sand per foot. A, is that right? And B, if so, what would the apples-to-apples drop in well costs be since the last update?

[William M. Crawford:]

Sure, I'll kind of try to answer that one. The first half of the year we D&C'd those wells at something probably less than $4 million. And so the $4.25 million is a projected cost increase to account for moving from 1,000 pounds of sand up to the 1,350 pounds of sand. And so, we think we've got that factored in, in the number that we're putting out there going forward.

[Welles W. Fitzpatrick:]

Okay. Perfect. Thank you. And then on the Morrow (22

[William M. Crawford:]

We've still got to see a few results. So, those Morrow (22

[Welles W. Fitzpatrick:]

Great. And then, any thoughts, positive or negative, on the reservoir (23

[William M. Crawford:]

Obviously, we're a supporter of one of the proposals which is called Number 71, which makes it tougher to put future ballot initiatives on the vote. And, I'm hopeful and encouraged that it's polling okay right now, but obviously we'll have to wait till Tuesday to see those results.

[Welles W. Fitzpatrick:]

Well, great. Knock on wood and congrats on the quarter.

[William M. Crawford:]

Thanks.

[Operator:]

Thank you. And our next question comes from David Beard from Coker Palmer Institutional. Your line is open.

[David E. Beard:]

Good morning, gentlemen. Nice quarter.

[R. Scot Woodall:]

Thanks, David.

[David E. Beard:]

Just two questions. A little bit just historical looking at your LOEs. Is there a way to delineate the significant improvement from a $6.50 level down to a $3 level, how much that was due to asset sales and what have you done internally to bring that number down? So that's my first question. And second question really relates to oil prices and spending next year and just philosophically how you would approach spending? Meaning, would you like to do a base level of spending? And if oil prices are stronger, can you put more money in the ground? Or do you let some cash build on the balance sheet? How do you modulate that next year given the vagaries of oil prices?

[R. Scot Woodall:]

Sure, David. So, I'll take the LOE one first, because I know I can answer that one. The LOE is really driven by two components. So, first off, when we think about just overall lowering the LOE, it's come out of the DJ and it's come out of being able to have more infrastructure. And so, as we continue to build our infrastructure, we have been able to lower that per unit cost down. And that has to come into just the normal things that you do as you start piping water over to disposal wells instead of having to truck it. You're more efficient on your gas lift operations and your compressor stations and you're able to spread those costs out among more barrels. And so it's just been kind of a normal course of business. Obviously, as commodity prices tighten, you do less and less contract labor and your employees do more of the labor. So I think it's just kind of a good base operation all the way around, which has driven the DJ LOE down. The sale of the part of Utah that we sold was the highest LOE in the company and so that definitely contributed to the total company's per unit cost going down. And similarly, when you look at the production mix now where we make 2,000 barrels in Utah, and whatever, 14,000 or 15,000 barrels in DJ, and DJ's a much lower cost operations, it starts to skew the whole total company down as well. So we feel good about the numbers and the job that our team has done. Looking into 2017, you're asking all the right questions and it's probably the same questions that we're asking ourselves about what kind of spending level you should do. And, golly, the way things seem to change, it seems like you could probably get a different answer every other day or every other week. But clearly, I think we've demonstrated in 2016 that we can have a lot of capital discipline, and we can be very prudent in the way that we spend capital, and that we can, with our assets being all HBP and the no drilling and pipeline commitments and things, we can manage our capital. And this year I think is a great year to sit here today and say that we're cash flow positive for the year. But we have lots of opportunities. I mean, if prices would firm up, say north of $50, and we're able to hedge production and things, we think we'd get a great rate of return above $50 that we should be deploying capital. Whether or not that's one rig or more, I think we as a company would be in a position to do that. And so we'll kind of have to kind of wait and see what commodity prices do, what service costs do, and what our hedging book looks like. And that will be kind of the balance that we'll do over the next few months.

[David E. Beard:]

No, that's great. Appreciate the color and I think you're right. People have to just understand the flexibility that you guys have and it's needed. So, appreciate it.

[R. Scot Woodall:]

Thank you.

[Operator:]

And at this time, I am showing no further questions. I'd like to turn the call back to Larry Busnardo for any closing remarks.

[Larry Busnardo:]

Okay, thank you again for joining us today. We appreciate you being here. We know it's been a busy week. Please feel free to contact us if you have any additional questions and we look forward to seeing you at future conferences and events. Thanks again.

[Operator:]

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