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Edited Transcript of HPR.N earnings conference call or presentation 1-Nov-18 2:00pm GMT

Q3 2018 HighPoint Resources Corp Earnings Call

Nov 8, 2018 (Thomson StreetEvents) -- Edited Transcript of HighPoint Resources Corp earnings conference call or presentation Thursday, November 1, 2018 at 2:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Paul W. Geiger

HighPoint Resources Corporation - COO

* R. Scot Woodall

HighPoint Resources Corporation - CEO, President & Director

* William M. Crawford

HighPoint Resources Corporation - CFO

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Conference Call Participants

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* David Earl Beard

Coker & Palmer Investment Securities, Inc., Research Division - Director of Research & Senior Analyst of Exploration and Production

* Derrick Lee Whitfield

Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst

* Jason Andrew Wangler

Imperial Capital, LLC, Research Division - MD & Senior Research Analyst

* Michael Dugan Kelly

Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research

* Welles Westfeldt Fitzpatrick

SunTrust Robinson Humphrey, Inc., Research Division - Analyst

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Presentation

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Operator [1]

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Good day, ladies and gentlemen, and welcome to the Q3 2018 HighPoint Resources Earnings Conference Call. (Operator Instructions) As a reminder, this conference call may be recorded. I would now like to introduce your host for today's conference, Mr. Bill Crawford, CFO. Sir, you may begin.

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William M. Crawford, HighPoint Resources Corporation - CFO [2]

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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-Q, 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 measures can be found at the end of our press release.

I will now turn the call over to Scot for prepared comments.

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R. Scot Woodall, HighPoint Resources Corporation - CEO, President & Director [3]

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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, 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 the future as Hereford development program is expended.

I am pleased with the initial results of the Hereford program as we have completed 2 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 are seeing positive early indications of performance from our initial drilling and spacing unit and from the DUCs 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 4 midstream outlets for our Northeast Wattenberg area, and we've 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 impacts that this proposal will have on the development of the state's oil and gas resources, along with the associated jobs impact, economy impact and state and local tax revenues, support for 112 drops 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.

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Paul W. Geiger, HighPoint Resources Corporation - COO [4]

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Thank you, Scot, and good morning, everyone. I would 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 a 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 9 months of 2018 totaled 7.4 million barrels oil equivalent, 62% of which was oil. And we estimate that 0.5 million barrels 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 pressure. 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 have 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 approximately this level for the fourth quarter due to seasonality.

Now turning to operations. At Hereford, production sales volumes for the third quarter averaged 4,255 barrels equivalent per day, of which 75% was oil. This clearly supports an increasing corporate oil percentage as we continue Hereford Field development activity. We drilled 14 wells and put 8 wells on flowback during the third quarter. Of the wells placed on flowback, there were 4 development wells and 4 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 6 were in the Niobrara and 4 in the Codell. Drilling was completed in June, and flowback began on the initial 4 wells in September. The fifth well had mechanical issues and is being used as an observation well. The 4 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 completions design and modified controlled flowback methodology. We are seeing positive early indications of performance that have confirmed our acquisition and development model as the wells have been on flowback for approximately 3 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 9 wells that were drilled by the previous operator on 3 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, established productive deliverability across the eastern and western areas of the acreage position and confirmation of our expectations of completion costs. The drilled uncompleted 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 forced us to pump diversion-style fracs versus the plug-and-perp methodology we employ as our standard.

Despite these issues, we are extremely encouraged as the best performing DUC, which has shown strong productive deliverability, reaching a peak initial rate of approximately 700 barrels oil equivalent per day from a shortened lateral of 8,377 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 DUCs reached a peak initial rate of approximately 620 barrels oil equivalent per day, of which 90% is oil. This establishes a production fairway across a 6-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, 3D seismic, 4 cores, 10 newer extended-reach laterals wells by the previous operator and data from other ongoing offset development. This level of technical data and production performance support have proven reserve definition for the majority of the field by a 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 increased liquids recovery by 15% versus our previous wells, and we expect similar performance enhancement at Hereford.

In our short time at Hereford, we have also been pleased with the demonstrated cost performance in being able to execute drilled wells at 17% below legacy well cost and completions at 29% below legacy well cost.

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 7 extended-reach lateral wells and placed 19 wells on initial flowback. Current development is focused on the central portion of our acreage, and we are seeing excellent results from our development program on the eastern edge of the DSU in 5 North and 61 West.

After 6 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 originating mechanical downtime, which resulted in fewer spuds and completions than anticipated. The most significant was a failure of a derrick 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 have 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 of 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 have developed additional processing capacity, which has facilitated record levels of production in the face of significant takeaway constraints. At Hereford, we have 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.

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William M. Crawford, HighPoint Resources Corporation - CFO [5]

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Thank you, Paul. The third quarter was highlighted by a strong production in EBITDAX growth, low operating cost and attractive oil differentials 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 through the end of the year and expect to maintain a WTI differential of less than $3. The trucking cost in the DJ Basin has 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 3 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 time frame 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 collars 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 to 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 confidence 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?

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question comes from Mike Kelly from Seaport Global Securities.

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Michael Dugan Kelly, Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research [2]

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I had a good conversation with Larry last night when he could still -- when he was still talking, about the 10-Q, where you had -- Page 35, you laid out that you might not be as impacted by Prop 112 if it indeed does pass. Seems to be in contrast -- what you talked about Scot in last quarter that may be 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 kind of think about this position for you guys?

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R. Scot Woodall, HighPoint Resources Corporation - CEO, President & Director [3]

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Sure, Mike. So I think what you're referring to is the risk section that we put in the Q. Under the advice of counsel, we tried 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 and development that we had 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 structure language of Proposition 112. Just as a precursor to -- 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, it is not optimum, I guess, is what I would say. So you're moving locations from section lines to middle of sections, you're drilling 2.5-mile linked laterals one way and 1.5-mile linked laterals another way; causes increased cost, causes increased gathering cost, causes increased surface disturbance. And so 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 around, albeit it is not in 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. It's 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.

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Michael Dugan Kelly, Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research [4]

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Really helpful color. And Good luck on that. Shifting gears a little bit just to 2019. You guys have previously laid out I think 18 million to 20 million barrels BOE as your expectations for 2019. You just got hit with this drilling derrick that kind of pushed things to the 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 hiccup here?

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R. Scot Woodall, HighPoint Resources Corporation - CEO, President & Director [5]

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Yes. 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 contracted rig that's going to come into the field in early November here. We think another one's 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 the first quarter.

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Operator [6]

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Our next question comes from Jason Wangler from Imperial Capital.

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Jason Andrew Wangler, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [7]

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Scot, I was wondering as you talked about the -- those initial Hereford wells that you guys drilled and completed, I think you said that has only been on for 3 weeks. I believe you've talked previously about -- obviously in your legacy DJ area it takes maybe as much as 6 months. But could you maybe talk about, now that you've got them for a couple of weeks and obviously the DUCs as well. How you see kind of that ramp-up in production and when you kind of think you'll get to that peak production level?

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R. Scot Woodall, HighPoint Resources Corporation - CEO, President & Director [8]

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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, we are like, as -- and that's compared to what you mentioned in the Northeast Wattenberg of more like a 5- to 6-month type of a ramp. And so obviously, we're learning as we're going. We learned some things on the DUCs. But we're kind of targeting something in that 60 or 90 days to get to peak production level.

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Jason Andrew Wangler, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [9]

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Okay. And then maybe just as a comparison with those wells versus the DUCs, you mentioned the variability in the DUCs and obviously, kind of walk us through some of the reasoning and obviously, it sounds like yours were more consistent. Could you maybe talk about the variability in 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?

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R. Scot Woodall, HighPoint Resources Corporation - CEO, President & Director [10]

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Well, I think that in the comparisons to the wells that we drilled and completed versus the DUCs, I think we highlight several of those things, the spacing is one of the big things that we think is different. So these -- this is a 10-well DSU versus an equivalent spaced 18-well DSU. So I think that is a one significant difference. And then, obviously, we think these wellbores are wine racked. The way that we would like to see them wine racked, you kind of know what I'm trying to refer to there. So we think that we have -- those 2 things are more of our base assumptions, along with the controlled flowback that we just talked about is how we developed our acquisition-type curve.

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Jason Andrew Wangler, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [11]

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Great. And maybe if I could just ask in a different way. Just as far as the actual productivity in the wells on a well -- you know you give us the averages so to speak? I mean are you seeing a more consistent production on a well by well basis from those initial 4 or so versus maybe those 9 that you -- the 9 DUCs or maybe just how you're seeing that, I guess, is what I was asking.

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R. Scot Woodall, HighPoint Resources Corporation - CEO, President & Director [12]

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Yes, absolutely. The wells that we drilled and completed, the variability is very tight -- or the lack of variability. Yes.

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Operator [13]

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Our next question comes from Welles Fitzpatrick from SunTrust.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [14]

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Yes. Hopping back to Page 35 in the Q, obviously, you're saying that nearly all of acreage can be drilled is a big upgrade from the 30%. Can you talk about -- I mean does that -- are you assuming anything longer than 10,000-foot laterals? I would assume that there's a shift in well orientation. What are the other adjustments that you guys have made to get up to that number?

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R. Scot Woodall, HighPoint Resources Corporation - CEO, President & Director [15]

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Yes. 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 drill 2 miles north then you drill 2 miles south. You lay a spine of infrastructure across those section lines, minimum surface damage, minimal gathering cost. Well, if you end up because you have some sort of sensitive area and you move a pad 0.5 mile or 1.5 mile up into the middle of a section, then yes, you're drilling -- to cover that same 4 miles you might be going 2.5 miles to the north and 1.5 miles to the south like in my example. And so one, would your landowner agree to placing a pad in the middle of the section? We're, obviously, going to have to renegotiate with landowners. You've got to repermit, you've got to restake. If you follow that scenario, it could be where you're zigzagging infrastructure, kind of all over the place. Yes, there's some where you switch in 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 needed to go through and clearly, our general counsel thought it was a disclosure that we needed to put in the risk section of the Q. I'll still come back to my earlier comments. 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's still the direction that we plan on going. I think the company has always a message 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 DNC economics. And it also brings a rural component, which we expect to be in our favor as we navigate through being an operator in Colorado.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [16]

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Okay, yes, no that makes total sense. Yes, I mean, it certainly helpful nugget of information. Given the lake work that you guys have done on this, are there opportunities to bolt-on acreage at a decent price or is the M&A market still somewhat seized up on account of 112?

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R. Scot Woodall, HighPoint Resources Corporation - CEO, President & Director [17]

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I think there's always opportunities but yes, I think all eyes are probably on politics. So I would -- 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.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [18]

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All right, all right. On -- and then just sticking with the 112. The polling seems to be looking pretty decent going into it. If you'll just indulge me and we assume a no on 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.

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R. Scot Woodall, HighPoint Resources Corporation - CEO, President & Director [19]

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Yes. I would agree with 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, 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.

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Welles Westfeldt Fitzpatrick, SunTrust Robinson Humphrey, Inc., Research Division - Analyst [20]

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Okay. Wonderful. And if I could just sneak in one last one, I know it's the Farm Bureau not you guys. But 74 also seems to be pulling well. Any thoughts on how that might create a line in the sand, a defense for the industry as we move forward?

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R. Scot Woodall, HighPoint Resources Corporation - CEO, President & Director [21]

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Yes, it could perhaps be viewed that way, as a defense of the industry, Welles. But I think the bigger thing that both 112 and 74 -- we're talking about the economic impact to the state. And I think it's just something that the state just needs 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, it's trying to protect the financial stability in the economic growth of the state.

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Operator [22]

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Our next question comes from Derrick Whitfield from Stifel.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [23]

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Scot, I seem to recall that you guys have a meaningful inventory of permits in hand in the event that prop 112 initially passes. Could you update us on that number as it stands, today?

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R. Scot Woodall, HighPoint Resources Corporation - CEO, President & Director [24]

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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 passed, is it the November 06, date that is the final date of getting additional permits, 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.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [25]

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Got it. And then as my follow-up, some of your peers have 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?

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R. Scot Woodall, HighPoint Resources Corporation - CEO, President & Director [26]

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Sure. So as what -- kind of Paul and -- talked about, we've got 4 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 online and are producing and that with our planned activity for 2019 with 2 rigs in Hereford and 1 in Northeast Wattenberg, there'll be minimum growth in gas production in Northeast Wattenberg in 2019. So we do feel like we have our bases covered. Obviously, it's not totally optimized with line pressures in the 350-pound range. Clearly, we all know that if the line pressure were 100 pounds, our volumes would be positively impacted. But we don't feel like that we'll be in a situation where we've got wells shut in or we've got to delay completions based on that diversification of the midstream outlets that we have created.

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Operator [27]

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Our next question comes from David Beard from Coker Palmer.

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David Earl Beard, Coker & Palmer Investment Securities, Inc., Research Division - Director of Research & Senior Analyst of Exploration and Production [28]

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Two questions, just on the longer-term mix in Hereford and also price discounts particularly for gas and NGLs. Gas used to trade at a, call it, $0.50 discount, now it's $1.50, and NGLs are minus $4 and now they're minus $10 or $11. What -- just what are your thoughts there near-term and long-term especially as capacity comes online?

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William M. Crawford, HighPoint Resources Corporation - CFO [29]

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I think, obviously, gas and NGLs, especially up in Hereford, are a minimal part of the revenue stream. And I think as you look that some of the legacy pricing you were just mentioning are a result of Summit's 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 it's going to improve.

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David Earl Beard, Coker & Palmer Investment Securities, Inc., Research Division - Director of Research & Senior Analyst of Exploration and Production [30]

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Okay, good. And next, just looking at the mix in Hereford. I know you target 80% crude and the current wells were pushing 90%. Is that -- are these wells tracking? Or are they a little bit ahead? And if they are tracking, would that imply a long-term sort of 70% crude number, 3, 4, 5 years out?

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Paul W. Geiger, HighPoint Resources Corporation - COO [31]

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So David, this is Paul. I think that overall, of those are confirming our expectations just by nature of a controlled flowback, you're going to have a little higher liquids at the beginning than you do over the life. And so that current performance that we see would be consistent with that long-term 80% type number that we've talked about, which is significantly higher than our -- what we see at Northeast Wattenberg continue to bring the overall company oil percentage up.

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Operator [32]

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And I am showing no further questions from our phone line. I'd now like to turn the conference back over to Bill Crawford for any closing remarks.

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William M. Crawford, HighPoint Resources Corporation - CFO [33]

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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.

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Operator [34]

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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.