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Extraction Oil & Gas, Inc. (NASDAQ:XOG)
Q3 2018 Earnings Conference Call
November 6, 2018, 4:30 p.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Good morning. I am Amanda and I will be your conference facilitator today. I would like to welcome everyone to the Extraction Oil & Gas third quarter 20158 financial and operating results conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer period. If you would like to ask a question, simply press * then the number 1 on your telephone keypad.

Please be advised that the remarks today, including answers to your questions, include statements the company believes to be forward-looking statements within the meanings of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different than those currently anticipated.

Those risks include, among others, matters that the company described in its financial and operating results news release issued earlier this afternoon and its filings with the Securities and Exchange Commission. Extraction disclaims any obligation to update these forward-looking statements.

While the company believes these forward-looking statements are reasonable, they are subject to factors, such as commodity prices, competition, technology, and environmental and regulatory compliance, companies' drilling schedules, capital plans, and other factors may cause results to differ materially.

I would now like to turn the call over to Louis Baltimore, Extraction's Director of Investor Relations.

Louis Baltimore -- Director of Investor Relations

Thank you and good afternoon to everyone. We're glad you could join us today for our third quarter earnings call. With us today on the call, we have Mark Erickson, our Chairman and CEO, Matt Owens, the company's President, Rusty Kelley, our CFO, Tom Brock, our Chief Accounting Officer, and Eric Jacobsen, our SVP of Operations.

I'd like to remind you that today's call, in addition to the aforementioned forward-looking statements also includes a discussion of certain non-GAAP financial measures. Please be sure to read our full disclosure on forward-looking statements and GAAP reconciliations in our earnings release and in our filing on form 10-Q which we provided earlier today after the close of trading.

I'll now turn over the call to Mark Erickson, our CEO, to go through some highlights for this quarter.

Mark Erickson -- Chairman and Chief Executive Officer

Thanks, Louis. Good afternoon, everyone. Welcome to our third quarter earnings call. First, I would like to recap some of the outstanding achievements our team has made this year.

We still expect to grow our production by over 45% and we demonstrated the high productive potential within each of our Broomfield and Hawkeye areas. Our wholly owned midstream company, Elevation, is funded on a non-recourse basis requiring no capital outlays by the upstream company, exposing our shareholders to significant future upside.

Currently pipelines are being laid in Broomfield area, which is now fully permitted with development expected to commence in early 2019. We've been able to monetize over $150 million of assets.

Our operations team continues to lead by example, setting a new milestone of over 1.2 million man hours without a single recordable employee incident, along with being awarded a Gold Leadership Award by Colorado in recognition for our efforts to go beyond compliance with state and federal environmental regulations, commitment to continual environmental improvement, and demonstrating leadership in partnering with local communities.

Finally, we expect to achieve free cashflow in Q4 and expect to continue to grow our production base in 2019 while generating free cashflow for the year, excluding the impacts of Elevation Midstream.

Now, I want to touch on the impressive results from our first pad of operated wells in the Broomfield area. Next, we'll talk about the difficulties we've been having related to constraints on the DCP system. After that, we'll open the call up to Q&A.

In late August, we started turning on a batch of ten wells with two-mile laterals testing spacing of 16 to 18 wells per section drilled on our Coyote Trails pad within our Broomfield project area. The pad's surface location sits in Weld County, but is producing our Broomfield County minerals.

We've always had very high hopes for this area, ranking the quality of this acreage potentially as a close second to our acreage in Greeley, which generates some of the absolute best returns anywhere in the lower 48. We're very pleased to show that early time, these wells are nicely exceeding our highest published type curves in both the Codell and Niobrara, performing almost on par with our Greeley wells.

Each of these areas benefit from thick pays in the Codell and all benches of the Niobrara along with little past drainage due to very few vertical wells in either zone nearby. Referring to page 14 in our new investor presentation, you'll see the results from the Coyote Trails pad with the three Codell wells achieving average 60-day IP rates of 1,200 BOE per day, 68% of which is crude oil and 1,175 BOE per day for the seven Niobrara wells, 69% of which is oil.

These ten wells are still averaging over 1,100 BOE per day, which demonstrates the very flat production profile we've been seeing. The results from this pad are particularly important as they go a long way to demonstrating the potential of the 12,000 gross, 10,000 net acres we have in our Broomfield project area.

On this page in our investor presentation, you can see the production plots from several pads drilled by other operators that also show strong results. We've gotten all the necessary permits and the project is under way. Getting to this point took a lot of hard work from everybody involved, particularly those Broomfield staff and community volunteers who work so diligently with our team to develop this best in class development plan. I want to, again, thank everyone involved in the effort.

Now, turning to the difficulties we've been experiencing on DCP's Midstream system. Shortly after DCP's Plant 10 came online, we were producing up to 93,000 BOE per day, until DCP imposed its production allocation. Our gross allocation represents about 13% of DCP's total capacity.

In mid-August after the plant came online, we were producing almost 220 million cubic feet per day gross on their system prior to being cut back by over 35%. So, as it stands today, we're planning to be limited to our current allocation until mid-2019 when Plant 11 comes online.

For the full year 2018, we estimate our net production will be constrained by approximately 17,000 BOE per day, net. After Plant 11 comes online, we expect that our allocation will only grow by approximately 30 million cubic feet per day based on the current allowable. Under this scenario, we believe we have ample existing base production to meet our allocation with relief expected in 2020 as our constrained wells go on natural decline.

As a result, we will be tailoring our investment in the DCP area to continue to meet our allocated production rate. We will continue to work on solutions with third parties for our non-dedicated and constrained production in this area. Further, we will continue directing our activity to our southern acreage, which is served by Anadarko's western gas and discovery, now part of Williams. Our diversified acreage position with access to multiple processing partners offers us a tremendous amount of flexibility not enjoyed by most other producers in the DJ basin.

I would like to thank everyone for your time on the call today. Before we open it up for Q&A, I'd like to remind everybody that it's still election day. So, we don't have any results yet. Let's try to keep the questions focused on our results and plans rather than the election.

With that, Operator, let's open up the call for Q&A.

Questions and Answers:

Operator

Thank you. Ladies and gentlemen, at this time, if you do have a question, please press the * and the number 1 key on your touchstone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the # key.

Our first question is from the line of Welles Fitzpatrick of SunTrust. Your line is open.

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Managing Director

Hi, good afternoon. Can you talk a little -- obviously, the Coyote wells, they look like they can compete with just about anything in the basin. Can you give us a little bit more detail on maybe the pressure you're seeing? Are you seeing a significant pressure drawdown? I guess I'm just looking for any more color that might help us understand what those EORs might look like at the end of the day.

Matt Owens -- President

Yeah, Welles. This is Matt. It's difficult to quantify exactly what that's going to be. Early on, those wells haven't really started declining yet, but their pressures have been a lot higher than what we normally see in our other areas, say, Windsor or in North Hawkeye. I would say they're not as strong as what we see in Greeley, but they're the closest wells we've seen so far to date pressure-wise compared to our Greeley asset.

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Managing Director

Okay. That makes sense. Then just one follow-on -- there's been some speculation of what to do with the free cashflow in '19 and about the potential for a buyback. Is that on the near-term to-do list for you guys or can you talk to how you might deploy that free cashflow?

Matt Owens -- President

Welles, our plan hasn't really changed from what we previously stated. Our first planned use of free cashflow is to get our net debt ratio inside of 1.5 and we would achieve that by paying down our RBL. Once we get that done, then all options will open for identifying and returning cash on the most advantageous way to shareholders.

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Managing Director

Okay. Thank you so much.

Operator

Thank you. Our next question is from the line of Jeoffrey Lambujon of Tudor, Pickering, Holt. Your line is open.

Jeoffrey Lambujon -- Tudor, Pickering, Holt and Company -- Analyst

Good afternoon. Thanks for taking my questions. My first one is just a follow-up on Broomfield. I appreciate the comments on the pressure and the spacing configurations. Can you give any additional color on the completions recipe you utilize there and how it's different from what you've done in wells? Based on this first pad, are there any learnings or changes you'll apply to the go-forward program in 2019?

Mark Erickson -- Chairman and Chief Executive Officer

Yeah. So, we drilled 10 wells on this pad, testing about 16 to 18 wells per section. We had three in the Codell and seven in the Niobrara. We did do a few different completion techniques on these just to get everything tested early on and see how the results are comparing. The sand loading that we went with was anywhere from under 1,000 pounds per foot to up to 1,500 pounds per foot.

We also tried some slick water and some gel completions like we've done in some of our other areas. We do have a very wide array of completion tests going on with this pad and we'll be able to see if there's any differentiation in the production results once we get a few more months under our belt.

Jeoffrey Lambujon -- Tudor, Pickering, Holt and Company -- Analyst

Got it. My second question is just a clarifying one on DCP. It sounds like from the release and the commentary that the allocations that have been applied or essentially based on relative levels of production by operator from August of last year. I guess I first wanted to confirm that and second, I wanted to get your thoughts on if that's something they've communicated any interest in changing just given how it doesn't really give credit to the growth operators like yourselves and some of your peers that have delivered since that timeframe.

Mark Erickson -- Chairman and Chief Executive Officer

They were set based on August of 2017. That was a time period before our production ramp started. In addition to that, that was even before Grand Parkway was built as well as new compressor stations added. Obviously, the situation has changed substantially since then. During the time period between August and with the plant turning on, we obviously produced at rates much higher than that continually throughout the period.

So, we continue to have dialogue with DCP wrapped around what is the proper allocation method. But as you know in our budget, we haven't taken any of that into account. We've assumed that nothing changes.

Jeoffrey Lambujon -- Tudor, Pickering, Holt and Company -- Analyst

Got it. Thank you.

Operator

Thank you. Our next question is from the line of Brad Heffern of RBC Capital Markets. Your line is open.

Brad Heffern -- RBC Capital Markets -- Analyst

Hey, afternoon, everyone. You guys mentioned the 90 to 93 you produced at before you got the allocation from the DCP system. I was wondering if you could give some sort of indication or range as to what you're producing at now.

Matt Owens -- President

That would be the 93 that we were up to total before we were curtailed back to the 13%. Now, I'd say we're closed to what you could imply for the Q4 volumes, which I believe is right around 78,000.

Brad Heffern -- RBC Capital Markets -- Analyst

Okay. Got it. And then looking at Hawkeye, I saw the updated zero time plots in the deck. Can you just talk about what you've been seeing on the performance there? Additionally, it looks like the longest history is sort of on the one-million-barrel type curve and then as time goes on, it sort of moves more toward the 900. I was wondering if that's the behavior that you would expect or if there was any color on why that would be the case.

Matt Owens -- President

Yeah. We're seeing good results out of the North Hawkeye curves there in both the Niobrara and the Codell formations. We've got six wells there producing that make up those two lines. The South Hawkeye line is only made up of two wells, the one that we drilled about 20 months ago and then the second one that's got just about a year of production. One of the wells is performing a lot better than the other one.

So, I think that's what's bringing that curve down, but we will be drilling several more wells this quarter in the South Hawkeye area along with completing another seven-well pad in the North Hawkeye area testing both formations again. So, we'll have a lot more data points to add to this chart as Q1 rolls along.

Mark Erickson -- Chairman and Chief Executive Officer

But we're pleased with the results that we're seeing today.

Operator

Thank you. Our next question is from Irene Haas of Imperial Capital. Your line is open.

Irene Haas -- Imperial Capital -- Managing Director

Yeah. Can we have a little color on your Broomfield project? Glad that it's finally happening. With your one rig, I suppose you'll be engaged in pad drilling. So, how does it synchronize with elevations, midstream buildout? I just want to have a rough timing as to how you put all the pieces together.

Matt Owens -- President

Yeah. The midstream buildout is happening as we speak right now. Obviously, that's going to take place first as we lay pipelines in the right ways across the area where we'll be drilling our pads. We will start drilling in Broomfield full-time, coinciding the turning lines of those first pads with the turning lines when the pipelines are ready to go. So, first drilling will be in Q1 and then it will be a couple quarters after that for the wells to go through the cycle times of being turned in line.

Irene Haas -- Imperial Capital -- Managing Director

Thank you.

Operator

Thank you. Our next question comes from the line of Paul Grigel of Macquarie. Your line is open.

Paul Grigel -- Macquarie Group Limited -- Analyst

I was hoping maybe you guys could discuss the thoughts on any impact to the reservoir or lack thereof on sustained ongoing midstream constraints over time.

Mark Erickson -- Chairman and Chief Executive Officer

I would point you to slide 13. I'll have Matt kind of talk through -- the Triple Creek is probably the best example of a highly constrained well or pad right now.

Matt Owens -- President

Yeah. If you look at slide 13, where we have the Triple Creek pad on there. It's called out with the arrow. You can see how it was performing kind of in a straight line, but well below the type curves because it was choked back for several months. After about 240 days or so, you can see that line starting to change angle as we were able to open up those wells a little bit more when we saw some relief in line pressure.

Now, after the first 360 days, we went from a decent amount below the 825,000-barrel curve to on track to pass that million-barrel curve on a cume basis shortly after this first year is up. So, we don't think we lost any reserves there and we're making that up rapidly now that we've been able to open up some of those wells.

Mark Erickson -- Chairman and Chief Executive Officer

We expect the same type of production profile for the C Street Pad as well.

Paul Grigel -- Macquarie Group Limited -- Analyst

That's helpful. Thanks. Turning to the outlook on Plant 11 as you guys move to the south, is the view there that with existing production and wells that are waiting on completion for that area that you'll be able to sufficiently fill that up into 2020 and what ultimately do we need to see in 2020 to alleviate the problem in the north, in your view?

Mark Erickson -- Chairman and Chief Executive Officer

Well, if there's no additional plant construction up there or for some reason the Plant 12 is delayed, we would be able to add production in the DCP system in 2020 as our wells go on natural decline. So, they should produce pretty flat until that 2020 time period with the base production that we have established.

But in addition, we continue to have ongoing discussions with third parties, private equity-backed that are adding plant and pipeline infrastructure in the northeast part of the field. Because we have a lot of uncommitted acreage in the area, we feel pretty strongly that we're going to be able to take advantage of that. We're just kind of waiting to see how things play out here over the next quarter or so to get firmer grip on the timing associated with those.

Paul Grigel -- Macquarie Group Limited -- Analyst

Great. That's very helpful. Thanks. Good luck.

Operator

Thank you. Our next question comes from the line of Jeffrey Campbell of Tuohy Brothers. Your line is open.

Jeffrey Campbell -- Tuohy Brothers -- Analyst

It sounds like the 2019 investment is going to avoid overloading the DCP system for all the reasons you've already detailed. I was just wondering -- is that a full-year strategy or do you expect some second half '19 relief when O'Connor comes online?

Mark Erickson -- Chairman and Chief Executive Officer

We're going to pick up. If our allocation remains at 13%, we pick up about 13% of the new plant that comes online, which would be about $30 million a day net to our interests. We've accounted for that in our 2019 guidelines. The biggest relief that we could see of anything that could change, whether it be '19 or '20 would be incremental processing capacity in the area beyond Plant 11.

Jeffrey Campbell -- Tuohy Brothers -- Analyst

Okay. My other question is kind of a capital allocation question as well. It sounds like you're going to target investment in the south. I was just wondering if you've got any color about how you're going to do that around the elevation midstream buildout. I assume it's going to have some effect on both Broomfield and Hawkeye investment.

Matt Owens -- President

Yeah. We do have acreage that is outside of the elevation buildout area that we can drill that would include some western gas processing or some other discovery processing that can go straight to the plant before the CGF is done being built and then hooked in later. We're carefully planning our drill and completion timeline around that buildout.

Jeffrey Campbell -- Tuohy Brothers -- Analyst

Okay. Great. Thanks. I appreciate that color.

Operator

Thank you. Our next question is from the line of Jacob Gomolinski of Morgan Stanley. Your line is open.

Jacob Gomolinski-Ekel -- Morgan Stanley -- Analyst

Hey, good afternoon. Thanks for taking questions and congrats on the nice Broomfield results. I guess it was a little bit maybe visually shocking to see the August production versus where you came in for the quarter due to the DCP curtailments and their decision to use that August 2017 production data to determine allocations.

I think in your last answer you hinted at -- you said if our allocation remains at 13%. Is there any room for negotiation with DCP and how they're making these allocation decisions? It sounds like I don't know if the August 2017 date was arbitrary. It seems a little misaligned if the goal was to focus on single-basin producers incentive to grow.

Mark Erickson -- Chairman and Chief Executive Officer

To say we were surprised by that pick of a date is an understatement, especially during the same time period when -- throughout 2018, we were in close communication with DCP. None of the discussions we had with them led us to believe there would be any allocations associated with the new plant. Historically, it's not the way they've operated. Then to have them come out and put allocations on the system after they told us there would be no allocations and we made our investment decisions based upon that, we were very, very surprised.

It's safe to say, though, at this point, we're not going to stretch our necks out again based on what we think DCP will do or not do, which is why I would say we've taken the most -- we're saying that we don't expect to get anything greater than the 13%.

Jacob Gomolinski-Ekel -- Morgan Stanley -- Analyst

Got it. You've obviously got a carrot and a stick given you have your own elevation system and can move those CapEx dollars elsewhere?

Mark Erickson -- Chairman and Chief Executive Officer

We do.

Jacob Gomolinski-Ekel -- Morgan Stanley -- Analyst

I appreciate the request not to talk about the vote, but you did say talking about the plans and I know we'll get the results later. Maybe just hypothetically if the vote were to pass, could you speak to your long-term plans and how you would look to -- just thinking about your options, would you be looking to diversify out of basin, similar to PDCE or would you develop what you have and then go into run-off mode or are there other options maybe the investor community is not currently thinking about that we should be?

Mark Erickson -- Chairman and Chief Executive Officer

We talked about this quite a bit. I'm going to have Matt walk through some specific numbers. Going into this election starting over a year ago, we started building a significant number of permits in the Basin. In fact, I think we hold the highest number of permits in the basin and the highest number of permits in the core of the basin. We feel very strongly that all those will be grandfathered through.

So, getting in at some specifics, we expect that our PDP at the end of this year will be substantially higher than our debt and that we'll have a very high inventory of permits. Matt will go through the specific numbers. We look at our equity value today as it has to assume a worst case scenario in the election with a substantial discount attached to it. Matt, do you want to talk about our permitting strategy and where we're at today?

Matt Owens -- President

Yeah. We've been very active for about a year now, like Mark said, with our permitting strategy. We've secured in hand over 400 permits approved in the quarter of our acreage position with an additional 400 permits pending. So, we believe we still could get some permits approved over the next 40 days, but regardless, we should have about three years, if not slightly more of drilling inventory at a three-rig pace and also that could increase depending on what we're able to get through in the next 30 days.

Then outside of that, we do have about another 100, slightly over that approved permits in our northern extension area. So, we have quite a long runway of inventory if there are any legal issues that ensue after tonight's vote.

Mark Erickson -- Chairman and Chief Executive Officer

And also appreciate that these permits are located in some of our highest-value areas. We're talking about Greeley, Broomfield, Hawkeye -- these are the areas that yield the highest NPVs per location in our whole inventory.

Jacob Gomolinski-Ekel -- Morgan Stanley -- Analyst

Got it. That's really helpful. Thanks for all the color and good luck tonight.

Operator

Thank you. At this time, this does conclude the question and answer session. I'd like to turn the conference back over to Mr. Mark Erickson for any closing remarks.

Mark Erickson -- Chairman and Chief Executive Officer

Thanks, everybody for participating in the call today. If you're from Colorado and haven't voted, please load up your stuff and head up to the polls right now. We need every vote we can get. Thanks. Bye.

Operator

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

Duration: 28 minutes

Call participants:

Louis Baltimore -- Director of Investor Relations

Mark Erickson -- Chairman and Chief Executive Officer

Matt Owens -- President

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Managing Director

Jeoffrey Lambujon -- Tudor, Pickering, Holt and Company -- Analyst

Brad Heffern -- RBC Capital Markets -- Analyst

Irene Haas -- Imperial Capital -- Managing Director

Paul Grigel -- Macquarie Group Limited -- Analyst

Jeffrey Campbell -- Tuohy Brothers -- Analyst

Jacob Gomolinski-Ekel -- Morgan Stanley -- Analyst

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