HighPoint Resources Corp
Q3 2014 Earnings Call Transcript

Published: 6 Nov 2014

[Operator:]

Good day, ladies and gentlemen, and welcome to the Third Quarter 2014 Bill Barrett Corporation Earnings Conference Call. My name is Lacey, and I'll be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Jennifer Martin, Vice President of Investor Relations. Please proceed.

[Jennifer C. Martin:]

Thank you, Lacey. Good morning, everyone. Thank you for joining us. Speaking today will be Chief Executive Officer, Scot Woodall; and Chief Financial Officer, Bob Howard. A few quick notes before we get started. Our Form 10-Q was filed about half an hour ago. It's available on our website under SEC Filings. Second, as usual, I need to remind everyone to read the forward-looking and other cautionary statements provided in this morning's release. In addition, during our discussion, we will make reference to non-GAAP measures, such as discretionary cash flow and adjusted net income. Reconciliations to the appropriate GAAP measures may be found in the earnings release, which is posted to the homepage of our website. Also, we posted an investor presentation to the website this morning. This includes the third quarter information and well results that we announced this morning. We will give[ph] that presentation at the upcoming Barclays Multi-Industry Small Cap Conference, the Ladenburg One-on-One Conference and the Goldman U.S. Emerging/SMID Cap Growth Conference, all to be held in the next couple of weeks. I hope to see many of you at these events. And with that, I will turn it over to Scot Woodall to get started. Scot?

[R. Scot Woodall:]

Thanks, Jennifer. Good morning, everyone, and thank you for joining us. I'd like to discuss a couple of key points today. First, the transition of our company we undertook a few years ago is now complete, the portfolio transactions we completed in the third quarter were the final steps in the process of transforming this company into a highly focused, more profitable company. Additionally, the monetization of nonstrategic assets repositioned our portfolio and strengthened the company's balance sheet by reducing our net debt by half. Our transition was well executed, timely, and I'm proud of the accomplishments of our organization. Now let's turn our attention to the operations, and I will focus today on the DJ Basin. I can tell you that we're right on track. We have now drilled 27 mid to extended reach laterals in the Northeast Wattenberg area. The first 4 wells averaged 7,300-foot laterals, the remaining 23 wells averaged 9,300-foot laterals. We have drilled nearly 250,000 feet of lateral and completed 23 of these wells with nearly 1,000 completion stages. Execution is going very smoothly. Further, results-to-date have met our expectations. I couldn't be more pleased with our team. Let me reiterate to be clear. Drilling and completion operations have gone nearly flawlessly with all of the extended reach laterals to-date. Our reported results today on the mid -- on the 4 mid-length laterals are in line with our expectations for both the 30-day and 60-day volumes. Of the 27 wells drilled to-date, we referenced today the results of 4 southern area wells. The breakdown of the remaining 23 drilled wells includes 17 in the flow back stages, 2 wells frac-ed and about to be placed online, and 4 wells being completed. The wells are evenly located between the north and southern areas. Our company and several of our peers are testing a number of new completion techniques intended to optimize completions in the Northeast Wattenberg area. Here are few things that we are actively working on. Down-spacing to 40-acre width per section, we are actively pilot testing down-spacing in 3 areas, primarily in the southern block. 1/3 increase in sand volumes from 9 million pounds to 12 million pounds has been done on 4 wells. We have done the perf-and-plug completion technique versus sliding sleeve completion technique on 5 wells to-date. We have increased the number of stimulation stages up to 55 stages per lateral, which is perforating about every 170 feet. We have done that to-date on 7 wells. Half of those 7 wells have been done with 9 million pounds of sand, the other half has been done with 12 million pounds of sand. Results from these tests will come in 2015. We want to incorporate these results into our future development plans to continue to drive efficiencies. However, directionally and including peer data, plug-and-perf technology and increased profit per foot appears to be the most effective way. In summary, DJ Basin operations are on track with our objectives. All wells expected to contribute to our production volumes in 2014 are already online either in the flowback stage or in the initial production stage. Drilling completion efforts are going extremely well, and we have implemented numerous drilling, completion and production optimization techniques that we are currently monitoring. We have a step-change growth in production in our sites. It is an exciting time, and we look forward to sharing more results with you as they become available. In regards to guidance, we have made some changes to accommodate a wider range of outcomes, as we placed a large number of wells to sales over the past few weeks. We have slightly increased our total capital expenditures range for the year to $560 million to $570 million. The increase relates to changes in the drilling schedule to include drilling on locations with higher working interests, subsequent to completing the asset exchange in the Northeast Wattenberg area. The increase is also attributed to certain higher drilling and completion cost associated with the testing of the plug-and-perf completion technique, increased sand volumes and increased stimulation stages. The combination of these 2 changes and well design adds approximately $700,000 to $1 million to our well costs. We'll be watching well results to determine the cost benefit from these changes, and I also expect that we will gain some efficiencies of scale going forward. Production guidance is lowered to between 9 million and 9.4 million barrels of oil equivalent from 9.4 million to 9.8 million, our previous range, or about 4% from the midpoint. We have observed a wide range of flowback periods on this extended reach laterals wells, some up to 45 days. Also, we have reserved variability based on percent load recovered on wells when they begin to produce hydrocarbons. We also continued to control the flowbacks on all of our extended reach laterals wells. This may sacrifice early-time high IPs and production but we believe improves overall well performance. Execution of the program is absolutely on schedule, and reservoir quality is as anticipated to-date. However, due to the high-growth generation from the DJ Basin program in the second half of this year, total production is highly sensitive to a couple of weeks of timing. Now I'd like to make some general comments on operating in this changing commodity price environment. Over the past few years, we have been managing this company with a few guiding principles, and those principles still apply in a changing commodity price environment. We are committed to preserving the balance sheet. We are committed to high-grading our portfolio and allocating capital to those projects that generate the best internal rate of return and payback. And also, we are committed to

[Robert W. Howard:]

Thank you, Scot. This morning's press release provided our typical financial information, including additional tables for easier reference. In addition, we've provided detailed pro forma information to show the recent performance of the assets that we owned following the recent property sales. As these schedules illustrated, and as Scot discussed, our core DJ and Uinta Basin oil development programs have been performing very well on a standalone basis. The financial statements in this schedules included in the earnings release are straightforward and Scot touched on the significant changes for this quarter, so I'll briefly cover a few items for modeling purposes. First, gathering transportation and processing expenses. As a reminder, beginning in the fourth quarter, our long-term firm gas transportation contracts for the Overthrust and Ruby pipelines will be classified as a separate operating expense apart from our gathering transportation and processing expense line item. These obligations are approximately $4.5 million per quarter through July 2021. They are not associated with any of our current production but will impact our operating cash flow. Increases in production tax expense year-over-year, and on a pro forma basis, relate to the sale of our lowest-production tax rate areas, the West Tavaputs and Piceance fields, along with production declines in those areas prior to the asset sales. Our oil production is in higher production tax areas, such as Weld County, where production taxes are running up to 10% of wellhead sales value. The increasing DJ production as a proportion of the production mix will drive higher overall production tax rates. Corporate DD&A has increased following the asset sales. As presented in the Pro Forma section, the DD&A costs related to the DJ Basin and Uinta oil program production is about $34 a barrel. We expect our DD&A rate to be about that range going into 2015, but the rates will be adjusted based on year-end reserves and costs. General and administrative expenses were lower in the third quarter than indicated by our previous guidance. As part of the asset sales, certain professional fees and employee compensation costs were incorporated in the closing cost for the sales, giving us about a $3 million reduction in the G&A line for the quarter. Our run rate for the fourth quarter G&A should be about 12 -- $11 million to $12 million. I'll remind you that the company is well positioned as we wrap up 2014 and moving into 2015. On the financial side, we have cut our net debt in half with ample liquidity, and we are well hedged. A fundamental strategy of the company is to utilize hedging to protect future cash flows. This strategy protects our cash flow under the current drop in commodity prices. For 2015, we have approximately 11,000 barrels of oil per day swapped at $90 per barrel and 20 million cubic feet of gas per day swapped at over $4 per mcf. As a result, the $10 swing in oil prices will impact our 2015 operating cash flow by less than $20 million. On the planning side, our 2 excellent assets provide competitive returns in today's oil price environment. We are currently preparing our 2015 plan, and we'll approach our capital expenditure program with a well thought-out balance of achieving acceptable returns on our capital investments in the current commodity price environment and maintaining conservative leverage position. And to wrap up, I'd like to reiterate the financial principles for the company that Scot discussed earlier. We are committed to maintaining a strong balance sheet, and we'll continue to high-grade our portfolio by allocating capital to projects that generate the highest returns, while continuing to focus on the cost structure across all facets of our business. These are the principles that we have applied as we transition to our core oil projects and that we'll continue to apply in a lower commodity price environment to create value for our shareholders. With that, that wraps up our prepared remarks, and we'll open up the line for questions.

[Operator:]

[Operator Instructions] And our first question comes from Jason Wangler with Wunderlich Securities.

[Jason A. Wangler:]

Curious. With what you've seen so far, obviously the extended reach laterals look pretty solid, at least the initial readings. And as you're bringing these on -- you've even mentioned in the release that you have the 3 rigs kind of drilling predominantly XRLs. Could you just maybe walk through the plans for even the rest of this year as you look at '15 as far as drilling extended reach versus other ideas, whether it's hold in production or anything else?

[R. Scot Woodall:]

Sure, Jason. In general, the company has -- is going to drill extended reach laterals. Currently, today, the 3 rigs that are operating in the Northeast Wattenberg area, 2 of those are drilling extended reach laterals and we have 1 rig that's drilling a 640-acre-spaced pad. And really, it just comes down to kind of the contiguous nature of our position. And we think we have a very good contiguous position. And we think the XRLs are going to give a superior financial rate of return. And so that's why the focus is on there. There will be a few isolated pads as the one we are drilling right now that just from a location, they have to be drilled at 640s. But predominantly, we're pretty committed to going forward with the XRLs. And that should carry forward into '15 as well.

[Jason A. Wangler:]

Okay, that's helpful. And understanding kind of the moving parts, obviously, I think you mentioned around the divestitures you're looking around an exit rate of around 21,000 a day for the year. Is that still a fair number? Or is that kind of an adjustment based on kind of what you're seeing from the flowback?

[R. Scot Woodall:]

I think it's a wide range, and that's kind of why we had to alter our production guidance a little bit, Jason. As you know -- and I'll put a little color on that. As we are -- for example, in one area in the north, we actually drilled 14 wells spaced on 80 acres up 2 sections wide, and you're seeing that the time that those wells started making hydrocarbons vary from as little as just a few days to some of them as greater than 45 days. We were seeing a variation of, like, some of the wells start making hydrocarbons, say, maybe with 1% load recovery, some of them are up and approaching 6.5% load recovery and are not making hydrocarbons yet. And so when you think about all that, that kind of impacts the timing -- impact that production exit rate. But when you look at how the wells are performing, how they're cleaning up the rates in which they're flowing at, all of those things have been very positive indicators and makes us excited that the program is on track and is going to fulfill our expectations.

[Jason A. Wangler:]

That's helpful. If I could just sneak one in on that, just kind of in general, as you're seeing that load coming off, are you seeing any differences in the rates, whether they respond more quickly or maybe even takes a little bit more time?

[R. Scot Woodall:]

Not really because, you have to remember, we are also controlling the flowback on all these things. And so we are purposely maintaining a pressure and/or maintaining a volume of barrels per hour based on the way that we're operating the choke sizes. Now that comes back to, it may impact some 30-day IPs, it may impact production in the fourth quarter, but we're firmly committed to that we think it's the right way of doing things for the long-term overall productivity and a long-term recovery of the reserves on a per-well basis. And so, as I've said many times, I'm not sure that gauging the play on 30-day IPs or 60-day IPs really means that much. When you think about all the variations in completion techniques that I described earlier, it's going to take more data than 30 days or 60 days to draw some of those conclusions. However, like I said, we're pretty committed to -- we basically artificially holding pressure on the wells during these flowback periods, and we're dictating how quickly they clean up and how quickly we convert them over to gas lift and some of those things. And we think that we're going to improve the overall well performance of those individual wells and of the entire area.

[Operator:]

Our next question comes from the line of Ryan Oatman with SunTrust.

[Ryan Oatman:]

On these mid-reach laterals, can you just describe how you're lifting those wells, and kind of whether those wells are flowing back naturally, or if they're on gas lift or rod pump now?

[R. Scot Woodall:]

They are on gas lift now.

[Ryan Oatman:]

Okay. And I presume they were for the 30- and 60-day rates as well?

[R. Scot Woodall:]

Yes, for the majority of that 60-day period, I would say yes.

[Ryan Oatman:]

Got it, got it. And this was a sliding fleet [ph] with 7 million pounds of sand. I mean, I know it's early days here with a ton of different things going on in terms of how you guys are looking to complete these wells. Do you feel that was an optimal completion? Or would we look for that well, if you had the knowledge to do even just a couple months here later, would you do something different, whether it's plug-and-perf, greater sand, et cetera?

[R. Scot Woodall:]

As I kind of said, I think the early indications are that the plug-and-perf and probably more sand volumes look like that's probably the trend in the direction to go. I'll back up and say that

[Ryan Oatman:]

That's helpful. And then I wanted to kind of speak to the incremental working interest that you guys picked up following the closing of this acquisition. Can you just describe what that does in terms of your ability to operate and how that might change your go-forward plans?

[R. Scot Woodall:]

I guess, a couple things. One, it is nominally about a 20% increase in working interest across all of the southern acreage. So nominally, is what I'm trying to say there. So -- and then you also think about all the comments that I have been making over the last 6 months or so that our geologic organization would prefer the location of the southern acreage block over the northern acreage block, and so we are extremely happy to have additional working interest in the southern block. The wells that we have drilled in the southern block -- and as I indicated, we've drilled about half of the extended reach laterals, are in the southern block. Some of those are already on flowback and some of those are already cutting hydrocarbons. And they look very positive to us on the early indicators. So we kind of think that we are in the right place to be. The other subtle thing that happened in that asset exchange that, perhaps we haven't spoken to as much as what we could speak to, is the relationship that we had with the previous owners of that working interest kind of regulated the pace of development, because it was clearly something that was undeveloped, and the intent of the arrangement with that previous working owner is that we would drill at a very slow pace, gather data and make informed decisions. Clearly, we think that we have a lot of strong indicators that this is very productive area, and we want to move at a little quicker pace. And that's what you've seen us start to do in both the third quarter and fourth quarter, as we're moving a little quicker pace, and thus, kind of the additional CapEx I referred to earlier.

[Operator:]

And our next question comes from the line of David Tameron from Wells Fargo.

[David R. Tameron:]

Scot, can we talk about -- obviously, the timing slip from some of those wells, the completions, and you've talked about that. But can give us any range around an exit rate or 1Q level or something just to give people some comfort about what those wells are tracking to?

[R. Scot Woodall:]

I'm not sure I necessarily want to give an exit rate. I guess, it probably comes back to, David, that all the wells are online. And so that's where I have a pretty -- I don't think that there is any execution risk to the wells being placed on production. We're not still drilling them. We're not still completing them. We're not drilling them out. We're not gas-lifting them. I mean, we don't have to install gas lift. All of those things are done. It is really waiting on the response from the wells. And we have made an assumption of how long we think it takes before those wells start cutting hydrocarbons and go on their 30-day IP rates. If we missed that by a couple of weeks, it's pretty significant. We ran some internal numbers and even looked it like a 10-day thing and how many barrels that, that can or cannot lead to in terms of production in the quarter. And it's fairly significant, and that's why you saw us change those production ranges, we still think that when you look at the pressures and the rates, we're very happy with the way those things are flowing back. We've just seen a little bit of variability as to when they start cutting hydrocarbons. And unfortunately, we built a model based on a 4-well pad of results for Q4. And those were the mid-range laterals, who used to say how the 9,300 ones are going to react and respond. And so we're kind of learning as we go here a little bit. But I want to come back and reiterate the point that all of the wells that we expect to contribute to our production volumes in the fourth quarter are already online.

[David R. Tameron:]

Okay. And how would you -- I mean, could you guys put some -- is it a P50 forecast, P80 forecast, P20? How would you characterize that if you care to, as far as what that fourth quarter -- the current fourth quarter guidance?

[R. Scot Woodall:]

I think, when we put out guidance, our expectations is pretty certain. And that's the only qualifying thing I'd make there, David. I think, historically, you would think, on the fourth quarter, we'll be tightening that range a little bit, and we had to kind of keep that range high. Just based on a few days of additional water production, our earlier hydrocarbons kind of creates that range.

[David R. Tameron:]

Okay. And then if I think about -- and I think you've mentioned this. But 2015, CapEx aside, how would you characterize the amount, the length of laterals? Everything 9,000, 9,300 going forward, is that kind of the plan?

[R. Scot Woodall:]

That's kind of the plan. There might be an isolated section here or there that would be a shorter-length lateral. But by and large, we will go the extended reach laterals.

[Operator:]

And our next question comes from the line of Mike Kelly with Global Hunter.

[Michael Kelly:]

Scot, I was expecting a few more results on the longer laterals to actually be quantified here. And just wanted to get -- just is this a timing issue? Or is this maybe these wells aren't -- just, I'll go out and say it, cherrypicking your data here a little bit.

[R. Scot Woodall:]

No, I don't think we ever cherrypicked the data. So I would say no on that. There were 2 other wells, that is maybe is where your question is coming from, that we put on a few weeks ago that are in the northern area, and just to due to the logistics of completing drilling wells on either side of them, we end up shutting those wells in for a few weeks, and they just went back online and are resuming their production. So we interrupted the flowback period on those 2 wells while we were continuing the drilling and completion operations. As I said, if you look at, in our northern area, we drilled on 80-acre spacing basically 14 wells. And all of those wells are in some various stages of flowing back, making hydrocarbons or finishing up some of those completion operations. And just logistically, 2 of those wells that are probably what you're referring to, we shut in for a few weeks, and now they're back online, back on production. So I would say that when you think about all of the activity, we think, very shortly, you're going to see a huge slug of wells.

[Michael Kelly:]

Okay. And then with the fourth quarter update -- and we'll get those 30-day rates and 60-day rates at that time. Is there anything -- I mean, it seems like a decent amount of science is being -- it is really in place here as well. But if we want to compare, which I think all of us in the financial community are going to do versus leaders in the play there, Noble, Bonanza Creek, is there any reason that your results and IP rates on 30, 60 days shouldn't stack up to them? Or should it be comparable?

[R. Scot Woodall:]

I think they're comparable if the geology is comparable. So, if you're talking about Noble's wells ranched within 1 mile of us, yes. If you're talking about Bonanza Creek that is next door to us, I think the answer is yes.

[Operator:]

[Operator Instructions] And our next question comes from line of Chris Stevens with KeyBanc.

[Chris Stevens:]

What's the rate of return that you guys are estimating that you're generating on these extended reach laterals at the current strip pricing?

[R. Scot Woodall:]

If you're talking about the current, like $75 strip pricing that sits out there, you're probably in that plus or minus 50% type of a range.

[Chris Stevens:]

Okay, so those are pretty good returns, I guess. For 2015, I guess, what metrics are you most focused on when putting your budget together? Are you guys looking at like a debt-to-EBITDA that you're targeting for 2015 to try to stay at? And I guess, is it just trying to stable at 2.5x? How do we think about that?

[R. Scot Woodall:]

Yes, that is definitely one of the factors that will be considered. So we'll be weighing the balance sheet, the debt-to-EBITDA, and we'll be looking at profitability, cash flow, kind of all those multiples of things. I would probably take the opportunity to say one more time that we just spent the last 2 or 3 years repositioning this company, improving the portfolio, improving the balance sheet, paying down debt, doing all those types of things, and I think we will continue that philosophy through in '15. We're not going to destroy all the things that we just did and spent so much hard work doing over the last couple of years.

[Chris Stevens:]

Okay. So then, I guess -- I mean, can you talk a little bit about your core Wattenberg Field? How that fits into your thoughts on future development? And is that something where maybe you would divest it, just given the lack of capital that you're allocating there? And I guess, same thing for Chalk Bluffs and maybe Blacktail Ridge, is that something you guys have been thinking about at all?

[R. Scot Woodall:]

I'm not sure that we're definitely -- that we're thinking about divesting of those areas. I think, we're looking at kind of all of our areas and we're going to continue to rank those based on where we think we're seeing the highest internal rate of returns. I think you'd probably drawing the right conclusion that the extended reach laterals in the Northeast Wattenberg are probably going to be our highest rates of return. So you'll probably see the focus there in '15 over some of those other areas to mentioned. But those other areas, I still think are important for the company, and so I don't think that we are out trying to market those at this time.

[Operator:]

And our next question comes from the line of Dan McSpirit from BMO Capital Markets.

[Dan McSpirit:]

First question on commodity prices. Actually, 2 questions. Are you bullish or bearish on oil prices?

[R. Scot Woodall:]

I guess, I would say, personally, Dan, I think that $75 might be a little low. But we've always planned and stress tested all of our capital spending on lower commodity prices than what we have observed for most of '14. I just think that's the good way of running your business. So we never had an internal deck that was $100 or $90. We always run decks that were much lower than that. Clearly, we like to see the forecast and the strip take the volatility out and land where it's going to land. But as I indicated earlier, we've spent a lot of time in the last couple of years building pretty good acreage positions in 2 great unconventional resource plays, and so we're pretty pleased with the positioning of the company.

[Dan McSpirit:]

That's great, and that leads me to my next question. What are the lowest oil and gas prices at which you've run sensitivities internal to build Barrett? And second to that, what prices are you seeing from the banks?

[R. Scot Woodall:]

We run -- we stress test everything all the way down to cost of capital or some fixed price. So we run things down to, say, an internal rate of return of 20%. And if you look at some of those extended reach laterals, they'll go all the way down to, like, $40. I'm not saying that a $40 -- banking on $40 oil price is coming nor telling you that we're going to drill wells all the way down to $40 oil pricing, but I think it speaks to the quality of the project areas that we have positioned ourselves into. In terms of the bank deck...

[Robert W. Howard:]

Regarding the bank deck, the bank said -- the most recent numbers we got from the banks who shared those decks with us are about $75 oil. We haven't got any indications that will be changed. Of course, that was said with anticipation that there is volatility in the oil prices. So $75, not aware of any changes pending.

[Operator:]

And our next question comes from the line of Jeffrey Connolly for Mizuho Securities.

[Jeffrey Connolly:]

Some of the industry results up in Chalk Bluffs, Wyoming border area looked pretty good recently. Do you guys have any plans to go up there and drill 2 more wells?

[R. Scot Woodall:]

We'll look at all of that as we talk about making our 2015 plans.

[Jeffrey Connolly:]

Okay. And then can you give us any update on the remaining PRB assets and kind of thoughts on what you're going to do with that?

[R. Scot Woodall:]

We've repackaged the assets that we retained, and we are actively marketing them. So we are in the process.

[Operator:]

And at this time, we have no further questions in queue. I would like to turn the call back over to Jennifer Martin for any closing comments.

[Jennifer C. Martin:]

Thank you, everyone, for joining us. And I know it's a busy day, so please feel free to call me any time this afternoon with any follow-up questions.

[Operator:]

Thank you for your participation in today's conference. This concludes your presentation. You may all disconnect. Good day, everyone.