HighPoint Resources Corporation. (NYSE:HPR) Q3 2018 Earnings Conference Call November 1, 2018 10:00 AM ET
Scot Woodall - President & CEO
Bill Crawford - CFO
Paul Geiger - COO
Mike Kelly - Seaport Global Securities
Jason Wangler - Imperial Capital
Welles Fitzpatrick - SunTrust
Derrick Whitfield - Stifel, Nicolaus & Company
David Beard - Coker & Palmer Investment Securities
Good day, ladies and gentlemen, and welcome to the Q3 2018 HighPoint Resources Earnings Conference Call.
At this time, all participants are in a listen-only mode. Later, we'll conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions]. And as a reminder, this conference call may be recorded.
I'd now like to introduce your host for today's conference Mr. Bill Crawford, CFO. Sir, you may begin.
Thank you, Crystal. Good morning and thank you for joining us this morning for the HighPoint Resources third quarter 2018 earnings conference call. Joining me on the call today are Scot Woodall, CEO and President, Paul Geiger, COO. I'm Bill Crawford, CFO. Larry Busnardo, Vice President of Investor Relations is here as well, but he's a little under the weather and so we'll do the speaking today.
Before we begin, please review the disclosure statements provided within the forward-looking statements of our earnings release, which you can find on our website at hpres.com. You can also find and review these disclosures as they are referenced in our other filings with the SEC or in our 10-Quarter-to-quarter, which was filed yesterday afternoon.
In addition, we will be referencing non-GAAP financial measures during our call and a reconciliation to the appropriate GAAP financial statements can be found at the end of our press release.
I will now turn the call over to Scot for prepared comments.
Good morning and thank you for joining us today to discuss our third quarter financial and operational results. I will lead off with an overview of the third quarter before turning the call over to Paul and Bill for review of the operations and financial results.
Highlighting our third quarter results was a 14% sequential increase in equivalent production and oil volumes, a 24% sequential increase in EBITDAX tax and a 16% sequential decrease in LOE per BOE.
Oil represented 63% of total production sales volumes and we anticipate that the percentage of oil volumes will continue to grow in future at Hereford development program is expanding.
I am pleased with the initial results of the Hereford program as we have completed two full quarters since the acquisition. Our recent results have confirmed our acquisition and initial development model for this large oil-weighted and rural acreage block.
We're seeing positive early indications of performance from our initial drilling and spacing unit and from the ducts in Hereford, which highlights the quality of the Hereford asset. Paul will discuss our increasing midstream flexibility in further detail, but our foresight to proactively diversify our Northeast Wattenberg gas processing to alternative outlets has clearly positioned us to maintain a consistent development pace going forward.
We currently are utilizing four midstream outlets for our Northeast Wattenberg area and we have approximately 50% of our total capacity going to outlets other than DCP. This diversification will limit our exposure to future midstream issues in Northeast Wattenberg and mitigates our reliance on DCP to ensure that we can continue to bring wells on in a consistent manner.
As everyone is well aware, the people of Colorado will conclude voting on Proposition 112 next Tuesday. We are proud members of the oil and gas community and have a strong record of health and safety and providing a strong and positive impact to the Colorado economy.
The business community has banded together to defeat this proposal. The industry has funded an educational campaign regarding Proposition 112 and it is clear that when Colorado voters are shown the draconian impact that this proposal will have on the development of the states oil and gas resources along with the associated jobs impact, economy impact and state and local tax revenues, support for 112 will drop significantly. I am confident that this misguided proposal, which is bad for Colorado will be defeated.
I will now turn the call over to Paul.
Thank you, Scot and good morning, everyone. I'd like to start by thanking our field and office personnel who've worked diligently to navigate midstream constraints and to develop solutions, which helped us to achieve our third quarter guidance safely and with operations consistent with the responsible member of the community.
For the third quarter, production volumes totaled 2.74 million barrels equivalent of which 1.72 million barrels or 63% was oil. This is our highest oil production and percentage ever and represents a 43% increase over the comparable 2017 period.
We look for both of these to continue to increase as we develop the Hereford field where produced volumes are about 80% oil.
Through September, our producing rate has increased 30% since the addition of Hereford Field in March and over 60% year-to-date. We exited the third quarter with record levels of production in both our Northeast Wattenberg and Hereford assets.
Our pro forma production for the first nine months of 2018 totaled 7.4 million barrels oil equivalent, 62% of which was oil and we estimate that 0.5 million barrels of oil equivalent of Northeast Wattenberg production has been adversely impacted due to midstream constraints.
Examples of this include curtailed wells, lower yields, higher flared volumes and continued high line pressures. While our third quarter production was within guidance, it was slightly lower than our internal expectations based on these gathering and processing constraints in Northeast Wattenberg, which persisted through much of the quarter.
The DCP addition of capacity with Mewbourn 3 started during the beginning of August and worked to achieve design capacity by mid-September. We've continued to strategically reduce our reliance on DCP through alternate, contractual third-party processing capacity and are currently moving approximately 30% of our Northeast Wattenberg gas volumes through these alternate outlets.
We do expect that total gas processing and takeaway capacity supporting our Northeast Wattenberg asset will continue to increase during the fourth quarter. In aggregate, we have increased our Northeast Wattenberg gas processing capacity by approximately 70% during the second half of the year.
I'm also pleased with our ability to maintain cost control as lease operating expense for the third quarter totaled $2.65 per BOE and marks a 16% sequential improvement. We anticipate that per unit lease operating expense will remain at approximate this level for the fourth quarter due to seasonality.
Now turning to operations, at Hereford, production sales volumes for the third quarter averaged 4255 barrels equivalent per day of which 75% was oil. This clearly supports an increase in corporate oil percentage as we continue Hereford field development activity.
We drilled 14 wells and put eight wells on flowback during the third quarter. Of the wells placed on flowback, there were four development wells and four drilled and completed wells. The development wells are located in DSU 11-63-14.
As a reminder, drilling operations commenced in April and these are the initial development wells that were drilled and completed by the HighPoint team. The DSU includes 10 extended reach lateral wells of which six were in the Niobrara and four in the Codell.
Drilling was completed in June and flowback began on the initial four wells in September. The fifth well had mechanical issues and is being used as an observation well. The four wells were drilled and completed for an average cost of $5.1 million, which has already achieved our expectations for the Hereford field development. They were completed utilizing our standard completion design and modified controlled flowback methodology.
We're seeing positive early indications of performance that have confirmed our acquisition and development model as the wells have been on flowback for approximately three weeks and have ramped up to an average rate of approximately 480 barrels oil equivalent per day, per well with a high oil cut of 90%. Production rates continue to increase and we're very pleased with the early results of this pad.
Now turning to the nine wells that were drilled by the previous operator on three pads that came to us as drilled uncompleted wells through the merger. Flowback began in June and July and we've gathered significant technical data that supports our modeling for full scale field development, including high oil content, establish productive deliverability across the eastern and western areas of the acreage position and confirmation of our expectations of completion costs.
The drilled and completed wells have exhibited some production variations due to a combination of the following. First the wells were drilled on considerably tighter 18-plus well per DSU effective spacing. Second, some of the wells were drilled as vertical offsets versus the wine rack pattern we're utilizing for development.
And third, there were some mechanical issues that force us to pump diversion style fracs versus the plug and perf methodology we employees are standard. Despite these issues, we are extremely encouraged as the best performing duck, which has shown strong productive deliverability, reaching a peak initial rate of approximately 700 barrels oil equivalent per day, from a shorted lateral of 8377 feet and utilizing controlled flowback.
This well is located on the eastern side of the field and is adjacent to the initial development wells in DSU 11-63-14. We've also seen solid production on the Western portion of the field in DSU 11-63-18 as one of the ducts reached a peak initial rate of approximately 620 barrels oil equivalent per day of which 90% is oil.
This establishes a productive fairway across a six mile section of the Hereford field and supports our modeling for full scale Hereford development program.
As a reminder, we have significant technical and operating data that supports our Hereford asset assessment and our development plan. The data set over this acreage position includes 62 short reach legacy wells, 3-D seismic four cores, 10 newer extended reach lateral wells by the previous operator and data from other ongoing offset development.
This level of technical data and production performance support a proven reserve definition for the majority of the field by well-known engineering firm. The improvement that the HighPoint technical team is bringing to the asset includes the efficiencies gained from larger scale execution as well as the enhanced liquids recovery proven in our legacy assets through controlled flowback.
In Northeast Wattenberg these methods increase liquids recovery by 15% versus our previous wells and we expect similar performance enhancement at Hereford.
In our short time at Hereford, we've also been pleased with demonstrated cost performance in being able to execute drilled wells and 17% below legacy well costs and completions and 29% below legacy well costs.
Turning to our legacy Northeast Wattenberg asset, we produced an average of 25,477 barrels oil equivalent per day during the third quarter of which 61% was oil. This represents a 38% increase over the third quarter of 2017. We drilled seven extended reach lateral wells and placed 19 wells on initial flowback.
Current development is focused on the central portion of our acreage and we're seeing excellent results from our development program on the eastern edge of the DSU in five North and 61 West.
After six months of production, the wells continue to produce at an average of approximately 615 barrels oil equivalent per day on controlled flowback of which 80% is oil. These wells have exceeded our expectations and highlight the remaining development opportunity of the 15 undeveloped sections in this portion of the field.
Our third quarter drilling program incurred rig and service originated mechanical downtime, which resulted in fewer spuds and completions than anticipated. The most significant was a failure of dirt on one of the drilling rigs. Repair work is underway and we expect that the rig will be able to return to service in early December.
We've made changes to the composition and count of our service providers to mitigate the impact of these issues to our future development plan. While we have made adjustments as quickly as possible, the delay will likely push the completion of a couple pads from December to January of 2019, resulting in slightly fewer spuds this year and capital being at the lower end of our guidance range.
Overall we are pleased by the operational progress made in the third quarter. At Northeast Wattenberg, we've developed additional processing capacity, which has facilitated record levels of production in the face of significant takeaway constraints.
At Hereford, we've continued to ramp our development program, which has demonstrated the high oil cuts, reduced drilling completion costs, significant well performance and high rate of return investments that originally attracted us to this asset.
I'll now turn the call over to Bill.
Thank you. Paul. The third quarter was highlighted by a strong production and EBITDAX growth, low operating costs and attractive oil differential that allowed us to generate what we expect to be peer-leading basin operating margin of $40.69 per BOE for the quarter.
We also generated $78 million of EBITDAX, which represents a 63% increase over the third quarter of 2017 and a 24% increase sequentially. Our oil differential to WTI was $2.51 per barrel for the quarter. We have term contracts on all of our expected volumes for through the end of the year and expect to maintain a WTI differential of less than $3.
The trucking cost in the DJ basin have increased approximately 30% since mid-2018 and we expect a modest increase to our corporate differential to WTI next year as we are locking in prices for our 2019 production levels.
Touching on the balance sheet, we successfully refinanced our credit agreement in September. This extended the maturity date of our facility by over three years to 2023 and increased the borrowing base and commitments by 67% to $500 million.
The increase in our borrowing base highlights the greater value of our legacy Northeast Wattenberg asset development and also reflects the contribution from our early Hereford field results. We maintain ample liquidity with a quarter end cash balance of $93 million in the undrawn credit facility.
This was an example of how we are always monitoring our capital resources and market availability to manage maturities and strengthen liquidity.
On the hedging front, we continue our strategy of being 50% to 70% hedged on a rolling 12 to 18 month timeframe and have taken advantage of the recent strength in crude prices to layer in support for our capital program to provide predictability and visibility into our future cash flows.
The current pricing environment has presented us with attractive options for incorporating favorable swaps as well as callers with $55 and $60 floors to our portfolio. You can find a full summary of our updated hedge position in the press release or in the 10-Q.
I'll now take a few moments to provide an update to our operational outlook. Taking into account the deferral of activity that Paul highlighted, which impacts the timing of some new wells coming online, we anticipate total production sales volumes for the fourth quarter to be 3.1 to 3.3 MMBoe and oil volumes to be in the range of 2 million to 2.1 million barrels.
This represents an oil weighting of approximately 64%. Our production guidance for the fourth quarter is a sequential increase of 17% at the midpoint as we begin to benefit from our initial DSU development at Hereford coming online and our legacy Northeast Wattenberg acreage continuing to contribute along with fewer midstream constraints.
CapEx for the fourth quarter is expected to total $120 million to $130 million, which incorporates the lower activity due to the recent third-party rig and service related downtime Paul just reviewed as the remainder of our fourth quarter guidance is within expectations and may be found in our press release.
To summarize we are proud of our ability to mitigate the midstream constraints that persisted in the third quarter and our confident in the Hereford field continues to be affirmed by recent well results and we are excited about the opportunities that we have in place.
With that, we are now ready to take questions. Operator?
Thank you. [Operator Instructions] Our first question comes from Mike Kelly from Seaport Global Securities. Your line is open.
Hey guys, good morning.
I had a good conversation with Larry last night when he was still talking about the 10-Q where you had, 35 you laid out that you might not be as impacted by Prop 112 if in indeed just past. It seems to be in you talked about Scot last quarter it maybe up to 70% of your acreage would be affected if the vote was yes.
Maybe you could just walk us through that and how we could think about this position for you guys, thanks.
Sure Mike. So I think what you're referring to is the risk section that we put in the queue under the advice of counsel, we try to share with our stakeholders our assessment of risk associated with the company's performance.
You're right and I think on the second quarter call, I said that if we did the plan of development that we originally outlined for Hereford that about 70% of our drilling and spacing units would be impacted. We really come into the impact based on the sensitive areas language, not the occupied structured language of Proposition 112.
Just as a precursor to you if 112 were to pass, is there latitude in the development program to move things to where you could access most of your acreage and that's the commentary that you're seeing in the risk section.
There is probably a scenario where we can move a significant number of our pads and be able to access most of our acreage is not optimal I guess what I would say. So your moving locations from section lines to middle of sections, you're drilling 2.5 mile linked laterals one way and a mile and half linked laterals another way, causes the increased cost, causes the increased gathering cost, causes increased surface disturbance and still a number of things that are not optimum, but we thought that it was important based on our assessment preliminarily that there's a solution that we could work howbeit it is not our optimum way of development in our solution. So that's what you're seeing being referenced in the risk section of our Q.
I still think that the Proposal 112 is not good for Colorado, is not good for any of the operators in the state and we continue to think that our positive messaging that we've done on 112 is making progress with the Colorado voters and I still expect for it to be defeated come next week.
That really helpful color. Appreciate it and good luck on that. Shifting gears a little bit, just to '19, you guys had previously laid I think 18 million to 20 million BOE for your expectations for 2019, you just got hit with this drilling derrick that push things right a little bit in Q4.
Is 2019 guidance is that still a decent range for you guys or should we kind of bump that down a little bit post this little hick up here, thanks?
Yeah, I don't know anything today that would change that view Mike. We're obviously trying to bring additional equipment into the field to offset the delays that have occurred and so we've got another contractor rig that's going to come into the field in early November here.
We think another one is going to come in. So we think that we'll be able to make up that lack of activity, but clearly we will see how the next couple of months goes. Obviously, we'll kind of continue the planning process and typically we release formal guidance kind of the end of first quarter.
Got it. Appreciate it. All right, guys. That's it for me. Thank you.
Thank you. Our next question comes from Jason Wangler with Imperial Capital. Your line is open.
Hey good morning, everybody. Scot, I was wondering as you talked about those Hereford wells that you guys drilled and completed, I think you said they were on for three weeks. I believe you've talked previously about obviously in your legacy DJ area it takes maybe as much six months, but could you maybe talk about now you got them for a couple of weeks and obviously the ducts as well.
How do you see kind of that ramp-up in production and when you kind of think you get to that peak production level?
Sure. So and Paul can jump in here in a second as well, but I think initially we were targeting something like about a 90-day ramp and that's compared to what you mentioned in the Northeast Wattenberg more like a five to six month type of a ramp and so obviously we're learning as we're going.
We learned some things on the ducts, but we were kind of targeting something in that 60 or 90 days to get to a peak production level.
Okay. And then maybe just at a comparison with those wells versus the ducts, you have mentioned the variability in the ducts and obviously kind of walked through some of the reasoning and obviously it sounds like yours were more consistent. Could you maybe talk about the variability and the productivity of your wells that you guys drilled and completed versus maybe those and how you kind of see that variability playing out going forward?
Well I think that in the comparisons to the wells that we drilled and completed versus the ducts I think we highlight several of those things the spacing is one of the big things that we think is different.
So this is a 10 well DSU versus an equipment space 18 well DSU. So I think that is one significant difference and then obviously we think these wellbores are wine rack the way that we would like to see them wine racked, if you know what I'm trying to refer to there.
So we think that we've -- those two things are more of our base assumptions along with the controlled flowback that we just talked about is how we developed our acquisition tight curve.
And maybe if I could just ask it in a different way, just as far as the actual productivity of the wells on a well by well, you gave us the averages so to speak. Are you seeing a more consistent production on a well by well basis from those initial four or so versus those nine that you've the nine ducts or maybe just how you're seeing that I guess was what I asking?
Yes absolutely the wells that we drilled and completed, the variability is very tight for the lack of variability.
I appreciate it. Thanks Scot.
Thank you. Our next question comes from Welles Fitzpatrick from SunTrust. Your line is open.
Hey. Good morning.
Good morning, Welles.
Hopping back to page 35 in the queue obviously saying that nearly all of the acreage can be drilled is the big upgrade from 30%. Can you talk about does that -- are you assuming anything longer than 10,000 foot laterals? I would assume there is a shift in well orientation. What are the other adjustments that you guys have made to get up to that number?
Some of all of that like I alluded to Welles. If you think about our optimum development plan would be to place pads along a section line and you drilled two miles north and you drilled two miles south, you lay a spine of infrastructure across those section lines, minimum surface damage, minimal gathering cost.
Well as you end up because you have some sort of sensitive area and you move a pad half-mile or a mile and half have up into the middle of a section, then yes, you're drilling to cover that same four miles as you might be going 2.5 miles to the north and 1.5 miles to the south like in my example.
And so one what your landowner agreed to placing a pad in the middle of the section we're obviously going to have to renegotiate with landowners, you got a re-permit, you've got a re-stake. If you follow that scenario, it could be where you're zigzagging infrastructure all over the place.
Yes, there somewhere you switch the orientation from north, south to east west. So it was an attempt of our technical team to see what you can do. Obviously this is in a very preliminary phases of development, but just thought that was some exercise that we need to go through and clearly our General Counsel thought it was a disclosure that we need to put in the risk section of the queue.
So come back to my earlier comment, I still feel like that we're not going to have to go down that path and that Proposition 112 will be defeated and that still the direction that we plan on going.
I think the company is always that stage that the way that we put together our acreage position was very specific in trying to target high oil cut areas, which the legacy position being 60%. The new area being 80%, which delivers those margins that we talk about, which delivers those favorable capital efficiency and D&C economics and it also brings a rule component, which we expect to be in our favor as we navigate through be an operator in Colorado.
Okay. No that makes total sense and it's certainly helpful information. Given the legwork that you guys have done on this, are there opportunities to bolt on acreage and a decent price or is M&A market still somewhat seized up on account 112?
I think there's always opportunities, but yeah I think all eyes are probably on politics. So the mega announcements this past week of some of our peers in the M&A market, I don't think you'll see much in Colorado between now and Tuesday.
And sticking with the 112, the poling seems to be looking pretty decent going into it. If you'll just indulge me and we assume no 112 scenario. Can you talk to the industry plans to make sure this doesn't repeat in 2020? It seems like people are pretty focused in on it?
Yeah I would agree that Welles and I would say that I think my industry peers and myself are pretty committed to trying to do something that prohibits this from becoming a reoccurring event and whether that is continuing our messaging that we've done over the last several months about the value that our industry provides to Colorado on how safely and environmentally friendly we are to Colorado.
So I think that is a consistent message that we are going to want to continue because I think it has made a lot of progress about the reception of the oil and gas industry the last several months.
I would also probably say that we want to work out a solution with our communities to make sure that this doesn't happen again in a couple of years. So I think myself along with my peers, all plan to work with the incoming governor and the incoming legislative groups to make sure that we find a solution that kind of works for all the stakeholders.
Okay Wonderful. And if I can sneak in one last one. I know it's a Farm Bureau not you guys, but 74 also seems to be polling well and any thoughts on how that might create a line in the sand decent for the industry as we move forward?
Yes, it could perhaps a view that way that it's a defense of the industry Welles, but I think the bigger thing that both 112 and 74, if we're talking about the economic impact of the state and I think it's just something that state just need to be aware of as we make decisions what is the financial repercussions of those decisions and 112 obviously has a huge financial impact on the state and Proposition 74 could as well if there was a Takings Claim made based on some other type of government action.
So I think it's just trying to protect -- Colorado is trying to protect the financial stability and the economic growth of the state.
Okay No. That makes sense. Fingers crossed for the same.
Thank you. Our next question comes from Derrick Whitfield from Stifel. Your line is open.
Thanks. Good morning, all.
Scot, I seem to recall that you guys have a meaningful inventory of permits in hand in the event the Prop 112 initially passes. Could you update us on the numbers as it stands today?
It is a -- we clearly have I think more than 100 permits in hand. We have others that have been submitted. I'm not sure exactly how the interpretation of if 112 pass, is it the November 06 date that is the final date of getting additional permit if it's when the Attorney General certifies the election.
I think there's a little bit of a gray area there, but I think that internally the company feels like that we can navigate and execute and implement our 2019 program as planned.
Got it. And then as my follow-up, some of your peers had recently noted gas processing delays and impacts leading into next year, understanding that you guys were exposed to line pressure impacts in Q4, could you speak to your outlook on gas processing into 2019 for Northeast Wattenberg and to what degree you have your needs covered?
Sure. So is what Paul talked about. We got four outlets now for that Northeast Wattenberg area and so we have been able to create some additional markets, which has enabled us to flow more gas and so right now we're flowing about 30% of that gas away from DCP if you will and to these other markets.
Those other markets are going to continue to expand in Q4 and in Q1. So we feel like that we have enough capacity that all of our wells are on line and are producing and that with our planned activity for 2019 with two rigs in Hereford and one in Northeast Wattenberg, there will be minimal growth in gas production in Northeast Wattenberg in 2019. So we do feel like we have our bases covered.
Obviously it's not totally optimize with line pressures in the 350 pound range. Clearly we all know that the line pressures were 100 pounds, our volumes would be positively impacted, but we don't feel like that we'll be in a situation where we got wells shut in or we've got delay completions based on that diversification of the midstream outlets that we've created.
Thanks for taking my questions.
Thank you. Our next question comes from David Beard from Coker & Palmer. Your line is open.
Good morning, everybody. Two questions just on the longer-term mix in Hereford and also price discounts particular for gas and NGLs. Gas used to trade at call it $0.50 discount and now it $1.50 NGLs were minus $4 and now they are minus $11.
What are your thoughts there near-term and long-term as far as capacity comes online?
I think obviously gas and NGLs are especially up in Hereford are a minimal part of the revenue stream and I think if you look that some of the legacy pricing you're just mentioning are a result of Summit plant being a little less efficient as that gets upgraded to Cryo, I think you'll see improvement in those to that level. So again, it's not a big driver of the revenue and its going to improve.
Okay. Good. And next just looking at the mix in Hereford I know you target 80% crude and current wells were pushing 90%. Are these wells tracking or are they a little bit ahead and if they are tracking, would that imply a long term of 70% crude number three, four, five years out?
David, this is Paul. I think that overall those are confirming our expectations just by nature of a controlled flowback, you're going to have a little higher liquids at the beginning then you do over the life and so that current performance that we see be consistent with the long-term 80% type number that we've talked about which is significantly higher than what we see at Northeast Wattenberg of continue to bring the overall company oil percentage up.
Good. That's helpful. Appreciate the color and good luck next Tuesday.
Thank you. And I am showing no further questions from our phone lines. I would now like to turn the conference back over to Bill Crawford for any closing remarks.
Well, thank you everybody for joining us today and please feel free to contact myself or Larry if you have any additional questions. Thank you all and have a nice day.
Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone have a wonderful day.