HighPoint Resources Corp
Q4 2016 Earnings Call Transcript

Published: 3 Mar 2017

[Operator:]

Good day, ladies and gentlemen, and welcome to the Bill Barrett Corporation's Fourth Quarter 2016 Earnings Call. [Operator Instructions] As a reminder, today’s conference is being recorded. I'd like to introduce your first speaker for today, Larry Busnardo, Senior Director of Investor Relations. You have the floor sir.

[Larry Busnardo:]

Good morning, and thank you for joining us today for the Bill Barrett Corporation fourth quarter and year-end 2016 earnings conference call. Joining me on the call today, are Scot Woodall, Chief Executive Officer; and Bill Crawford, Senior Vice President, Treasury and Finance. Before we begin, I'd like to remind everyone to read the disclosure statements provided within the forward-looking statements of our earnings release, which has been posted at 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-K, which we filed yesterday afternoon. In addition, we will be referencing non-GAAP financial measures during our call. A reconciliation to GAAP financial statements can be found at the end of our press release. I'll now turn the call over to Scot Woodall.

[Scot Woodall:]

Thanks Larry, and good morning and thank you for joining us today to discuss our fourth-quarter and full-year 2016 results. Our primary goal for 2016 was to maintain a disciplined approach to preserving liquidity while retaining operational and financial flexibility in what was an uncertain commodity price environment. We accomplished this by reducing spending across the board as oil prices bottomed, executing a noncore asset divestiture that bolstered liquidity and completing initiatives that reduced debt and increased stakeholder value. Bill will touch on each of these things in more detail in his prepared remarks. As I look back on our accomplishments for 2016, I'm proud of the fact that our organization responded positively to the challenges we faced. We maintained disciplined business approach and achieved tangible benefits from resetting our operating and corporate cost structure. This strategy has served us well as we maintained positive momentum throughout the year and achieved numerous successes, including the following. Production sales volumes were consistent with our expectations at 11% above 2015 pro forma for the asset sales. This was achieved despite capital expenditure levels being 66% below 2015 spending levels. Capital expenditures were $98 million and we were cash flow positive. XRL well costs averaged $4.25 million per well, a 24% improvement over wells drilled in the second half of 2015. LOE per BOE was reduced by 29% as compared to 2015, cash G&A per BOE was reduce by 24% compared to 2015 and DJ oil price differentials improved by 58% compared to 2015. We generated peer-leading margins compared to our other basin company, DJ Basin companies. Lastly, we entered 2017, with a solid financial position consisting of $276 million of cash and an undrawn credit facility of $300 million. These achievements translate into earnings, cash flow and EBITDA all coming in better than analyst consensus estimates for 2016. It was a very solid year for the Company and our performance and actions during 2016 enabled us to take advantage of opportunities and return to a growth- oriented company. Now, as we turned towards 2017, consistent with our strategy of seeking to opportunistically expand our contiguous acreage position, we have closed on transactions to acquire 13,800 net acres in the DJ Basin for approximately $13 million, which we funded with our cash on hand. Clearly parts of the acreage were valued higher than others, but we were pleased with the aggregate price. The acquired acreage extends southwest of our current position and is prospective for the Niobrara B and Niobrara C and Codell horizons. This will increase our inventory, as we estimate that the acreage contains approximately 80 operated drilling locations as well as adding additional ownership in approximately 20 other gross operated wells. We restarted our extended reach lateral development program during the third quarter of 2016 and are bringing on another drilling rig during the second quarter of 2017. We will see an increase of 7% in our 2017 volumes, and are positioned to deliver growth of 30% to 50% in 2018, with an even higher growth in the oil volumes as we deploy increased capital during 2017. Our capital program is fully funded by our cash on hand and we expect to end the year with a cash position and nothing drawn on our bank revolver. As a reminder, we do not have any drilling, leasehold or marketing commitments, providing us complete flexibility to adjust our capital program. We demonstrated our ability to adapt to changes in market conditions during 2016 and we retain the flexibility to react and respond very quickly if necessary. Our DJ Basin acreage position is largely held by production and is located in a rural part of Colorado, providing us flexibility in our development program. Our position lies within a favorable regulatory environment and our team has done an excellent job of working with the COGCC and Weld County to stay ahead of our drilling activity. Our pace of development is not constrained by permitting times and the regulatory process has been very predictable. Our completion design continues to evolve and we plan to have further tests to benefit the effects of monobores and enhanced completions of 1,500 pounds of sand per lateral foot as part of our 2017 program. We have also adjusted our fluid system which allows for more sand to be placed. Tighter spacing from 175 foot and nominally 55 stages down to 120 foot, 80 stage completions were tested in 2016. Early results indicate a 10% improvement in the first year cumulative production. For 2017 we will test even tighter spacing, down to 100 feet per frac stage. We continue to utilize controlled flowback. This can limit initial production rates and push out peak production, but has led to enhanced recovery and improved economics. Therefore we would expect the Section 20 drilling spacing unit to begin to significantly contribute to our production in the second quarter of 2017. We continue to maintain drilling efficiencies and since resuming drilling operations in September, our extended reach lateral well drilling days to rig release have averaged approximately 7.4 days per well, including a best-in-class well that was drilled in approximately 5.6 days. This represents a 33% improvement from the average of 2015, so a great job by our operations team in achieving these results. Our team has also done a tremendous job of capturing significant cost savings. We continue to demonstrate an ability to maintain savings as drilling and completion costs for most recent extended reach lateral wells have averaged approximately $4.25 million per well, and I will note that that includes the cost of incorporating higher proppant. I would now like to spend a few moments discussing some of the observations from our operations. Since initiating our extended reach lateral program during 2016, we have drilled and completed 75 extended reach lateral wells. Geologically, we are seeing very consistent results across the different Niobrara benches and directionally across the acreage. Early time well performance has been influenced as we have utilized a variety of well construction designs, including sliding sleeves, plug-and-perf, varying the number of completion intervals, and increasing proppant sand volume and flowback techniques. We can now draw several conclusions about our completion design. Plug-and-perf outperformed sliding sleeve, utilizing controlled flowback improves results, larger sand volumes outperform smaller sand volumes, and smaller interval stages, or more stages per well, improve results. All of these things will be incorporated in our future planning. Our 2017 extended reach lateral program provides an attractive investment opportunity on our base assumptions and is expected to generate rates of returns of greater than 45% at the wellhead, assuming current strip pricing. As we continue to optimize our enhanced completion design and focus on efficiencies, we expect to see improvements in both well performance and cost structure. I will now turn the call over to Bill for a financial review and to go over our 2017 guidance.

[Bill Crawford:]

Thank you, Scot. From a financial perspective, we posted solid results for the fourth quarter that were generally in line with guidance and consensus estimates. We generated discretionary cash flow of $32 million compared to CapEx of $29 million, making us cash flow positive for the quarter as well as for the full-year. EBITDAX for the quarter was $46 million with EBITDAX per BOE of $29.55, which we believe is top-tier amongst peers. I'm sure you have all had a chance to review the details of our press release, so with that in mind I will spend a few moments going over the highlights for the fourth quarter. Our fourth quarter production volumes were 1.6 MMBOE, which were inline with expectations and comparable to the third quarter. Production volumes were weighted 62% oil, 20% gas and 18% liquids, which was weighted slightly higher to gas and NGOs than previous quarters. I would note that our XRL wells have a higher percentage of oil at the beginning of their production cycle, which leads to temporarily higher natural gas and liquids proportions in quarters with fewer wells being placed on flowback, which was the case during the fourth quarter. As a Scot mentioned. we were able to narrow our DJ Basin oil differentials to $3.67 per barrel off WTI, which was a 43% year-over-year improvement. We continue to believe that we have a strategic advantage relative to other DJ companies based on our ability to capitalize on not having any firm oil transportation commitments. We have locked in first quarter differentials to be in a similar range of $3 to $4 per barrel off WTI. We are also in the process of renegotiating our UOP marketing contract and expect to be able to secure differentials of $2 or less starting in the second quarter. This compares to a 2016 average for East Bluebell of $7.75 per barrel off WTI. We are taking advantage of changing market dynamics to capture this discount due to increased demand from local refineries in Salt Lake City, which are seeking additional crude barrels. A narrower differential will make our East Bluebell rig completion program returns very competitive. Moving on to the balance sheet, we opportunistically bolstered our liquidity through an equity offering in December that raised proceeds of approximately $110 million. This provided us with further financial flexibility heading into 2017. We ended the fourth quarter with $276 million of cash on hand which reduced our net debt to $442 million. We also have $300 million revolving credit facility with zero drawn, providing us sufficient liquidity based on our current operating plans. We continue to actively manage our hedge book to support our capital program and protect future cash flow. For 2017, approximately two-thirds of our oil production is swapped at $58.50 WTI. We also have 2,500 barrels of oil swapped in 2018. You can find a full summary of our updated hedge position in the press release or in the 10-K. I would like to spend a moment highlighting our 2017 capital program and guidance. It has been designed to accelerate development in Northeast Wattenberg and allows us to achieve significant growth in 2018, while maintaining flexibility to react to any commodity price changes. Now, for some of the key details. We've set a budget of $255 million to $285 million, which is reflective of adding a second rig during the second quarter of 2017. This will allow us to spud 70 to 75 gross wells. We expect that CapEx will be funded by cash flow from operations and cash on hand. We expect to exit 2017 with a positive cash balance and no need to draw on our credit facility. First quarter CapEx is expected to be about $60 million, which includes $12 million for the acreage acquisition that Scot just mentioned. 2017 production is expected to total 6 to 6.5 MMBOE, with an oil proportion of 60% to 65%. At the midpoint, this represents a production level that is 7% higher compared to our 2016 pro forma production of 5.8 MMBOE. This production level is consistent with our messaging of a one net rig program growing production 5% to 10%. Our second rig start contributes only minimally to 2017 due to pad drilling and controlled flowback timing. First quarter production is expected to average about 1.4 MMBOE, which is lower than the fourth quarter due in part to no new wells being placed on production in the fourth quarter and only minimal contribution from the wells being placed on flowback this quarter. The remainder of our guidance can be found in our press release. As you can see, we are pleased with our 2016 results and our execution in a challenging commodity price environment. We spent 2016 improving our capital structure and building our cash position. The debt for equity swap and equity raise brought our market cap to enterprise value from 25% at year-end 2015 to 55% at year-end 2016. In 2017, we will utilize some of our cash position to return to a growth oriented company which allows us to deliver a competitive 2018 growth rate compared to our peers. We will grow production volumes 5% to 10% this year and be in a position to deliver significant growth of 30% to 50% in 2018 with much higher oil volume growth. Our wellhead returns of 45% are competitive and we look forward to the next growth phase for the Company. With that, we are now ready to take questions.

[Operator:]

Thank you. [Operator Instructions] Our first question comes from the line of Gabe Daoud from JPMorgan. Your line is open.

[Gabe Daoud:]

Good morning Scot, good morning Bill. Maybe just starting with the 2017 guidance. Obviously the CapEx is going to set you guys up for some nice growth into 2018, but can you talk a little bit more about the details behind the 2018 budget or operating plan? Does that still assume two rigs into 2018 and a similar capital level?

[Scot Woodall:]

I think directionally I would say yes, Gabe, that the basis that would be to leave the two rigs running in 2018. Obviously we are doing 2017 guidance today, we're not doing 2018 guidance today. But I think even if you reduce the spending in 2018, you would still be achieving those growth levels of that 30% to 35% that you see quoted in this press release. So really, the spending in 2017 will drive most of that growth that we are referring to in 2018.

[Gabe Daoud:]

Got you, Scot. That's helpful. And then just on the some of the DSUs that are still cleaning up and still hitting peak great given controlled flowback, is there any early feedback that you can share in terms of performance relative to maybe the type curve of 700 MBOE? Are there any early reads there on production?

[Scot Woodall:]

Probably the pads that we are watching the most closely are the ones that we resumed when we started drilling in September. And so those pads were completed in December and – I don't know, they've been online maybe about 30 days or so. That's the first four well pad their south of the river. And I hate to comment on early production but they are making oil. You feel pretty good about it already, but as you know I think we like to have several months of data before we really speak hard to them, but I think initially we like what we are seeing. And then just further on that update, so there's a nine well pad that follows after that that we have fracked all nine of the wells and we are in the process of drilling out, and we're probably about halfway done drilling out that particular pad. And then we've drilled another DSU and it's awaiting completion and we'll probably start those completions sometime in the middle of March. So it seems like we're pretty on schedule in terms of execution.

[Gabe Daoud:]

Great. And then just one more from me. The acquisition I guess the 13,000 net acres or so, could you maybe just give a little bit more color on where the footprint sits relative to your current acreage and thoughts on developing the acreage, and just if that acreage is part of the 2017 plan? Or is that going to be delineated into 2018?

[Scot Woodall:]

If you trend off of our acreage position, south and west is where this position sits. And so, we think it will dovetail pretty nicely into our operations. We are actively going to develop it. I think we may have already even filed a handful of permits on the acreage or where we are set to go to the COGCC at the next hearing. So, whether or not that makes the end of 2017 or the beginning of 2018 by the time you get it all permitted up, but it is something that we like and something that I think we will fit into the drilling schedule pretty quickly all the way around. So, we think it was a pretty good purchase for us and actually it was two separate transactions that are part of that.

[Gabe Daoud:]

Great. Thanks, Scot. I'll hop back in queue.

[Operator:]

Thank you. Our next question comes from the line of Steve Berman from Canaccord. Your line is open.

[Steve Berman:]

Thanks and good morning. The 70 to 75 gross XRL wells you are going to drill this year, what's that on a net basis? And given the spend the CapEx spend this year is going to have a much bigger impact on 2018 with a 30% to 50% growth. I'm wondering what an exit rate this year looks like, call it what Q4 2017 might look like production wise versus Q1 to get a sense for how we enter 2018. Thank you.

[Scot Woodall:]

Sure. So first off, we assume probably basically a working interest of about 80% is a pretty good average. So if you take that well count, and then the way we are budgeting 2017 is at a well cost of $4.75 million. So as you heard me in the prepared remarks talk about $4.25 million was our most recent wells, and that included the higher sand concentrations, there will be a little bit more incremental cost to go to the higher stage count, reducing the stage size from 170 feet, say, down to 100 feet. So there's a little bit of additional cost that's built into our $4.75 million number as well as some service cost inflation that's built into that number. And if you'll use about 80% I think you'll arrive at about the capital number that you can see in our guidance today. Exit rate for 2017 is up some but I wouldn't say materially. We'll get some of these wells online but the real growth really does hit into 2018.

[Steve Berman:]

All right. And so of the 70 to 75 wells, how many of those do you think you'll have online this year?

[Scot Woodall:]

I think about half of those wells get completed in 2017 is the way I kind of recall.

[Steve Berman:]

All right, great. That's it for me. Thanks, Scot.

[Operator:]

Thank you. Our next question comes from the line of Welles Fitzpatrick from Johnson Rice. Your line is open.

[Welles Fitzpatrick:]

Hey, guys good morning. Just to jump back to the 13,000 acquired, I know you said it was to the south and the west of your core position, but is that all in Weld or does some of that bleed into Adams County? And are there any – what's the HBP timetable on it?

[Scot Woodall:]

Yes, I think – yes, it's all in Weld County, so none of it leads down into Adams County. And I believe it was all HBP'd by – there is some vertical wells and some vertical production that HBP in it. I don't think it has any horizontal wells on it, but like I say it is HBP, too. So it comes back to that point that I was trying to trying to make early – well, to maybe I'll digress on you for a second. But our entire acreage position is basically HBP'd as well as the new acreage being HBP'd, and with no marketing commitments and no really long-term service company commitments, we still do have the flexibility in 2017 and 2018 to react and respond as the environment changes. And I don't want people to lose sight of that a little bit, because clearly we demonstrated a lot of discipline in 2016. And I think if conditions warrant, you'll see us revert back and exercise that same discipline in 2017 and 2018 as well.

[Welles Fitzpatrick:]

Okay, perfect. And then on the state sale, if I'm taking the right one out of those state disclosures, it looks like all that acreage is between 3 and 6 North, 61 to 63 West, basically an overlay of your existing position. Is that about right?

[Scot Woodall:]

Yes, I think you are right.

[Welles Fitzpatrick:]

Okay, perfect. And then just a last one on modeling. I just want to make sure I'm in the right ballpark, but to get to around the midpoint of your guidance it looks like obviously down in 1Q, and then thereafter basically clear through year-end 2018, something like 5% to 10% quarter-over-quarter growth with – if I understand, I think it was Scot's comment in the prepared remarks – with a drop in GOR. Is that in the right ballpark?

[Scot Woodall:]

Yes, I think you are directionally correct, Welles.

[Welles Fitzpatrick:]

All right, perfect. Thank you so much.

[Operator:]

Thank you. Our next question comes from the line of Evan Templeton from Jefferies. Your line is open.

[Evan Templeton:]

Hi, thanks. I think everyone is just trying to get a better idea of the cadence of growth. One thing I was wondering is, could you give us an idea of just what the average pad size might be during the quarter? Does that help to explain some of the slow ramp up with only about 50% of the wells completed in 2017?

[Scot Woodall:]

Yes. And to give a little bit of color there, we drill probably 12 to 15 kind of wells per drilling spacing unit. And so I think of that as kind of like 640 acres wide and 1,200 acres long, if you will, to drill the 2 mile length laterals. And on a number of occasions we will split that into two or three pads. So maybe the pads are actually three, four, five well pads, and you may have three of those drilling a spacing unit. Which does try to accelerate that cash flow forward a little bit and then, where appropriate, you can do some SIMOPS work as well. But it really comes more back to how we do the controlled flowback, where we drill out everything and then place it on production. And we do, do a pretty limited choke size on our flowback trying to preserve the GOR and trying to preserve the reservoir energy that really makes you delay out for several months the actual production contribution and the corresponding peak production.

[Evan Templeton:]

Great, that's helpful. And then also, just curious. Did you happen to have just what reserves as well as maybe PV-10 might look like at strip as opposed to SEC?

[Scot Woodall:]

No, I don't have that sitting here right now.

[Evan Templeton:]

Okay. Great, thank you. That's it.

[Operator:]

Thank you. Our next question comes from the line of Jeff Robertson from Barclays. Your line is open.

[Jeff Robertson:]

Thanks. Scot, you alluded to it a little bit, but in terms of your flowback practices with the type of wells you are drilling now, in 2018 are you flowing them back longer, in other words, to get to your peak rates? Is it taking longer than what you all have done the last couple of years?

[Scot Woodall:]

Yes, I would probably say some of the most recent stuff – and I’m going back into 2016. Yes, I think we probably may have gotten a little conservative in the flowback and I think they took a little bit longer. And I think we're going to think about getting a little bit more – I hate to use the word aggressive, but perhaps speed up those flowbacks a little bit on the new sets of wells that are coming online, so like the section 20 drilling spacing unit as well. Still think it's the right way of managing the reservoir pressure and managing the GOR on our particular acreage position. I think we're still trying to evolve and fine-tune that a little bit.

[Jeff Robertson:]

Second question, you spoke a little bit about the marketing issues in the Uinta Basin. Can you – is there a point that you could improve the economics over there with $50 to $55 oil, where that would compete with the DJ? Or is it still going to lag what you think you could do in the DJ?

[Scot Woodall:]

Yes, well, to hit on the marketing piece first, Jeff, and I'll come back to the other question. Yes, our contract for crude in Utah rolls off at the end of April. And I don't know – we are nominally paying…

[Bill Crawford:]

19%.

[Scot Woodall:]

Yes, like 19% of WTI currently. And I think at the end of April we'll be able to renegotiate that contract, probably for something that's sub-$2. So you think about it's going to – it will have a positive impact on cash flow in 2017 and then clearly it has a positive impact on the well economics over there. So you'll see us in this capital plan that we are laying out today for 2017, we will at least go do 10 re-completions just coming up in the existing wellbores in the section and adding some additional production there. And we are in the process of looking at permitting some wells over there. Whether or not that activity will commence in 2017 or 2018 is still yet to be determined, but if the individual well economics does look pretty favorable the overall impact to the Company's cash flow and things isn't as material as a DJ well. And so it's just kind of trying to strike that right balance. But by and large, I still think the majority of the investment will still go towards DJ.

[Jeff Robertson:]

Thank you.

[Operator:]

Thank you. Our next question comes from the line of Jason Wangler from Wunderlich. Your line is open.

[Jason Wangler:]

Hey good morning, guys. Maybe just sticking on the Uinta there, again spending obviously most of the money in the DJ. Is there a thought to maybe revisit what you guys looked at last year and potentially monetizing that asset to add some cash as you ramp up in the DJ?

[Scot Woodall:]

I mean it is discussed, Jason. I'm not sure that it's immediately on the table, but it does cash flow probably at current strip something north of $20 million. And so I like the cash flow. Clearly if someone would come and offer a good multiple to that, would we take that and that would be able to really fund basically a rig in the DJ. So it's something that we are considering but we have not engaged a marketing process as of yet.

[Jason Wangler:]

Okay. And just maybe on the DJ, I think last quarter when we spoke with the one rig program, the plans to jump around with it. When you're bringing in the second rig can you just maybe talk about where we should think about those two rigs working throughout the year?

[Scot Woodall:]

Well, you are right. The first rig, as I described last time, is a mixture of – in the southern acreage position and the northern acreage position and kind of goes back and forth. So like, we've drilled south of the river already in 2016. We drilled just north of the river in 2016. And we've drilled one pad in the north section in 2017 and we are drilling a second pad north of the river right now in 2017. The second rig when it comes in will primarily be focused on that acreage that's on the southern acreage and really probably more directionally south of the river, in that southwest portion. So it will be on our own acreage position and then I think eventually it will walk down to this new acreage position that we are announcing today that we acquired as well.

[Jason Wangler:]

Okay, great. Thank you. I'll turn it back.

[Operator:]

Thank you. Our next question comes from the line of Chris Stevens from KeyBanc. Your line is open.

[Chris Stevens:]

Hey good morning, guys. There were some wells that came online in June of last year on the wider wellbore spacing. Did you see any benefit from the wells in that pad?

[Scot Woodall:]

I would say marginally, Chris, a little bit. So I still think we are trying to find that right recipe of stimulation with spacing. And I think that's where you are seeing us try and go to – really think the answer is probably maybe more related to number of stages in the well versus perhaps spacing, or still trying to tie those two things together a little bit. So you'll see the next sets of pads that we do will all go down to this 100 foot or this 120 foot frac interval size and trying to see how that would impact our well results as well.

[Chris Stevens:]

Okay. And then what sort of wellbore – inter-wellbore spacing are you going to be using on these upcoming pads?

[Scot Woodall:]

It's a mixture, but it's about 53 to 64. I think there's kind of some combinations that are in that size.

[Chris Stevens:]

Okay, got it. And then in terms of the bolt-on acquisitions, are you – are there additional acreage opportunities around the footprint down south, around this recent acquisition you made?

[Scot Woodall:]

We think there are, and so we do think there is the ability to perhaps gain some additional acreage or perhaps to do some swaps and core up some acreage and do some things. So, geologically, I think our people like it and it's a focus area for us to kind of walk down and march that direction a little bit.

[Chris Stevens:]

Okay. And just lastly, in terms of the Uinta marketing contract, how long is that $2 differential locked in for? And is it going to be a fixed fee or percentage off WTI?

[Scot Woodall:]

It's still something that's being negotiated, so I probably don't want to comment too much on it. But I think we can go out some part into the future, at least a year or two – and it would be a fixed dollar amount.

[Chris Stevens:]

Thank you.

[Operator:]

Thank you. There is no other questioners in the queue at this time. So I'd like to turn the call back over to management for closing comments.

[Larry Busnardo:]

Great. Thank you again for joining us today. If you have any additional questions feel free to contact us and we look forward to seeing you at future investor events. Thank you.

[Operator:]

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