Louis Baltimore - Director, Investor Relations Mark Erickson - Chairman and CEO Matt Owens - President Rusty Kelley - Chief Financial Officer Tom Brock - Chief Accounting Officer Eric Jacobsen - Senior Vice President, Operations.

Paul Grigel - Macquarie Welles Fitzpatrick - SunTrust David Deckelbaum - KeyBanc Gabe Daoud - J.P. Morgan John Nelson - Goldman Sachs Claire Ye - Imperial Capital Brad Heffern - RBC Capital Markets Oliver Huang - Tudor, Pickering, Holt Marshall Carver - Heikkinen Energy Jeffrey Campbell - Tuohy Brothers.

Good morning. I am Latif, and I will be your conference facilitator today. I would like to welcome everyone to the Extraction Oil & Gas First Quarter 2018 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.

[Operator Instructions] Please be advised that the remarks today, including answers to your questions, include statements that the company believes to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act.

These forward-looking statements are subject to risk and uncertainties that could cause actual results to materially different from those currently anticipated.

Those risks include, among others, matters that the company described in its financial and operating results news release issued yesterday 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, company’s drilling schedules, capital plans and other factors may cause its results to differ materially.

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

Thank you and good morning. We are glad you could join us today for our first 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 disclosures on forward-looking statements and GAAP reconciliations in our earnings release and in our filing on Form 10-Q, which we provided yesterday evening after the close of trading. I will now turn over the call to Mark Erickson, our CEO to go through some of the highlights for this quarter..

Thanks, Louis. Good morning, everyone. Welcome to our first quarterly earnings call of 2018. Before we go into some details on our first quarter, I’d like to take the chance here to reiterate our long-term strategy. First, we will continue to focus on improving our capital efficiency through optimizing our well designed and operations for the long-term.

We continue to remain right on track to become cash flow positive on an all-in corporate basis sometime during the second half of the year. And we will continue to strengthen our balance sheet, which will be further bolstered by our divestiture program of non-strategic acreage.

Once we have finished strengthening our balance sheet, we expect to initiate additional shareholder friendly uses of our free cash flow. Now turning to our first quarter results, our total equivalent production grew 4% sequentially, driven almost entirely by crude oil volumes, which grew 7%. Our natural gas volumes were flat, while our NGLs grew 3%.

Our ability to grow our crude oil volumes, despite largely flat gas and NGL volumes, demonstrates the value of diversification across multiple gas processors allowing us to manage our production, while maximizing revenue. Crude oil accounted for 78% of our first quarter revenues and over 52% of our volumes.

We expect -- we estimate that high line pressures and line freezes negatively impacted our production by almost 13,000 BOEs per day during the quarter, including 8,000 barrels per day of crude oil. Once the new plant comes on, we expect to see a significant uplift in our base production as the constraints are removed.

Over the past two quarters, we have been drilling and completing some of our best wells in our company’s history, which you can see on pages 11 through 14, both our Niobrara and Codell wells are strongly outperforming our type curves. This is a testament to the quality of our operations and technical teams along with the quality of our acreage.

Given the outstanding performance of the wells we have been turning on recently, we have remain confident in our ability to hit our previously discussed -- disclosed 2018 guidance and this bodes very well for us long-term. During the quarter, we turned to sales 31 gross, 18 net wells, all on the Western Gas gathering system.

We will continue turning wells on to systems other than DCP until their new plant comes on later this summer.

On the operational side, we remain right on track with our drilling and completion capital budget and while our lease operating expense came in higher on a per unit basis than we were forecasting internally, that was really just a function of lower than expected gas and NGL volumes, as we worked through the near-term constraints.

But keep in mind, it’s the oil that’s the real driver of our economics and cash flow.

I’m extremely proud of what we have built here when I look at the capabilities of our team combined with our decades of extremely high quality drilling inventory and while many of you are focused on the midstream picture over the next two months or three months, I want to remind you all that the DJ Basin is currently undergoing the largest midstream capacity expansion in its history, with several different projects underway and even more planned from multiple different companies across the basin.

Before we open this call up to Q&A, I’d like to thank everyone for your time on the call today and for your continued support. If we are not able to get to your questions today, please feel free to reach out to one of our team and we will always make ourselves available to you..

[Operator Instructions] Our first question comes from the line of Paul Grigel of Macquarie. Your line is open. .

Hi. Good morning, guys.

Could you expand a little bit maybe looking past the next couple of months as you look into the back half of ‘18 and then more into ‘19 on just the plant expansions and the build-out, and if this is an issue that should be relatively solved over the next couple of months, and just the view that you have on that one?.

Sure. After DCP comes on early Q3, we expect to see a third-party midstream plant come on and then as you look forward over the next couple of years, we are seeing almost a doubling of the existing capacity in the basin..

And in terms of timing that should be sufficient for managing through the continued growth plan in ‘19 that you guys have in your internal plans laid out?.

Yes. With our diversified acreage position our ability to go to multiple plants, we will look at systems that may potentially be constrained, we will be staging our production into those systems as they get expanded, and we will be actively developing and targeting systems that have available capacity..

Okay. And I guess, just turning a little bit to the asset sales that you guys closed.

Any update or color you can provide there and then what’s the thought going forward on continued asset sales for the rest of the year?.

Sure. So you have seen that we went ahead and closed the $72 million. That was largely from folks that proactively came to us, so those were done very quickly. As mentioned previously, we did engage an advisor and are actively in a marketing process as we speak.

So we are not done and so far we are seeing very good and positive interest in the remaining packages that we are marketing just given the commodity price and the well results around the areas that we are marketing..

And on a going forward basis, I would just look at kind of our asset sale strategy is really portfolio management. We are always going to be looking for opportunities to move stuff from the backend of our drilling inventory and replace it with higher working interest in the front-end of our drilling inventory ahead of our bit.

So I would just kind of look at asset sales are part of our ongoing business and we will be using those to offset any spend on increasing working interest and such as we consolidate and block and tackle on ahead of the drill bit..

Okay. Yeah. That’s helpful. Thank you very much..

Thank you. Our next question comes from Welles Fitzpatrick of SunTrust. Your line is open..

Hey. Good morning and congrats on the solid quarter..

Thanks..

I was wondering can we talk a little bit about these two -- the two operated pads a little bit north of Denver in the Hawkeye Area, I mean, obviously, those are a little bit between sort of the legacy core area and the newer Arapahoe test, and can you talk to the completions there and maybe the spacing as well?.

Yeah. I can give a brief update on what we have been doing up in that area. So we drilled two pads just northwest of Denver, Denver International Airport. If you look on page 17, you can see a circle up there that shows the area of the six new wells that we drilled.

One of the pads was on the eastern side of that circle and the other pad was on the Western side. We drilled both Codell and Niobrara formations on each one of those pads. We just recently turned those pads on and the pad on the eastern side, we have got one Codell and one Niobrara there that have been online for roughly 30 days.

The Codell has been increasing in production, as well as the Niobrara, the Codell is up to about 600 BOE a day, with the Niobrara up to 800 BOE a day, normalize the two miles and both are producing at about 85% oil cut. On the pad on the Western side, that pad just recently came on within the last five days.

So only two of the wells, one Codell and one Niobrara, have been producing for about five days, Codell is up to 950 barrels of oil equivalent per day, while the Niobrara is up to 725 and those are both also averaging in the mid-80s for percent oil. So we are really encouraged early time with what we are seeing there.

But typically we don’t like to start showing production plots until we have got 90 or more days of production..

No. Fair enough. Do those oil cuts surprise you guys a little bit, that seems pretty high for that area.

Is that -- am I just missing something there or is that something that was better than what you all had modeled?.

The way that the oil cuts -- that we look at the oil cuts really has to do with the API of the gravity of the oil and in this particular area, just northwest of the airport there, we are in the low to mid-40s, which is about the same as Windsor. So we expected internally for these to come on similarly to the Windsor wells which they are.

The Windsor wells, if you remember, last year they all came on about mid-80s on percent oil as well..

Okay. Perfect. And then if we can jump to slide 13 and kind of forget about the DCP wells, we all know what’s going on there.

But can you all talk to the spread on the Western results, is that a completion thing, is -- are there still some pressure issues or what’s going on there?.

So the spread on that plot for the blue lines on page 13 that really has to do with lateral lengths. So the wells that come on higher early time on a per thousand foot or normalized basis are the 1 mile wells.

And then the 2 mile wells, you can see, are the ones that come on a little bit closer to the type curve, but they have a much straighter line, because they are choked back more than a 1-mile well is. So the 2 mile wells you can definitely tell which ones are 2 miles versus which ones are 1 mile, just looking at the profile of the curve..

Okay. Okay. Perfect.

And then just one last one, any update on those Broomfield permits, I think, we are expecting them maybe sometime early summer?.

Yeah. I think that’s still the timing that we are looking for. We have got the 14 permits that have already been approved and 10 of those have actually already been drilled and are being completed. The rest of Broomfield has had all of the permits submitted except for half of one pad.

So we virtually have about 85% or so of the permits submitted that we wanted to develop our acreage there and they are all now sitting with the state waiting approval..

Okay. Perfect. That’s all I have. Thanks so much..

Thank you. .

Thank you. [Operator Instructions] Our next question comes from the line of David Deckelbaum of KeyBanc. Your line is open..

Hey, Mark, Rusty and Matt. Thanks for taking my questions and Eric..

Hi, David..

Just -- and Mark, I know in the prepared remarks, that there was, obviously, the downtime in the first quarter.

Just thinking about with your tie-ins in the first half of the year being on the Western side, do you expect incremental downtime in the second quarter on top of that 13,000 a day or I guess, how do we think about the quarter kind of shaping up here going into 2Q.

I know, obviously, there you will get the benefit of line pressures alleviating in the third quarter, so it would be helpful if you could remind us how many wells you are planning to bring online in the third quarter?.

Sure. I mean, our growth in the second quarter is going to be driven largely by wells that were tied into the Western Gas system and Discovery system.

If you look at DCP, I would say in the first quarter one of the things that surprised us a little bit was the amount of freeze-offs that we had on the system and it just -- as you -- as the line pressures came up, it really just got in the window where hydrate formation was very likely and we bought hydrates all the time.

So we could see, I would say, fairly flattish on the DCP system with the possibility of a little bit of incremental production there as we get some of the freeze-offs cleared. But most of our growth in Q2 was going to be driven by our stuff going into Western.

In Q3, you should see probably the largest sequential ramp of the year and that’s as a result of the new wells that we are adding into Western, as well as DCP coming online where we should see the uplift in our base production, as well as we do have a significant pad similar to Triple Creek time for the opening up of the new DCP plant..

I appreciate that. That’s helpful.

Also just interested if you could give us an update on any of the midstream conversations you have been having, particularly around the build-out in the Arapahoe Area and some of the Broomfield Area?.

Sure. This is Rusty. Those continue to go very well. We are largely moving toward our goal in line with what we have communicated to the market previously about looking at joint ventures or third-party financings with folks. We should have an update here very shortly.

It’s not completely done, but it is moving in the direction that we want and is largely there. So stay tuned for more updates, but very positives..

Okay. Thanks, guys..

Thank you..

Thank you. Our next question comes from the line of Gabe Daoud of J.P. Morgan. Your line is open..

Hey. Good morning, everyone. I guess, just a quick one from me.

Is there an update on those two Northern extension wells that I think were turned on maybe earlier this year, any thoughts on those or any update there?.

Those wells were completed at the very end of last year and we really started to flow back as -- right around Christmas time.

So we are letting some of them flow naturally to see what the reservoir pressure is going to do and then we are also experimenting with different types of artificial lift on them up in that area and we will release the results once we get more production results or data on how the artificial lift changes affect the volumes..

We remain pretty optimistic by what we are seeing by our wells, as well as third parties up in that area. There’s been a lot of interest in our leasehold position up there. I think probably following up to some of the stuff with HighPoint and as well as some of the private equity companies that are out there.

So, we continue to follow it and we are benefiting greatly from all the work that’s being done by offset operators to our acreage position. I still believe there’s stuff to be learned up there on the best completion techniques and so you all stick with us here on this that we think there’s a lot of value there..

Okay. Great. Thanks a lot everyone..

Thank you..

Thank you. Our next question comes from the line of John Nelson of Goldman Sachs. Your question please..

Good morning and congratulations on the quarter. I guess, following up a bit on Dave’s question and I’m not sure that we have kind of all the data to know what your volume allocation is between DCP and Western.

So can you just maybe comment on how we should think about sequential oil growth in 2Q?.

Our current split of production in the first quarter were about 70% DCP and that’s growing -- that should grow significantly in the second quarter with all the wells that we turned on to the Western system halfway through the first quarter. The oil volumes on the Western wells will continue to grow.

The DCP system it will be just like the first quarter will be fighting the high line pressures along with the line freezes that have been happening..

But remember in third quarter when we turn on the next pad up in Greeley, you will see a significant ramp up in our DCP volumes going into that system. But the growth in the second quarter like we stated will continue to be driven by our Western Gas operations.

When you think of oil mix that, we are all kind of in the similar areas within the Balta oil window, so similar to the results that Matt announced on our stuff in the Hawkeye Area, we would expect most of our acreage even in the Western and Southwestern parts of our acreage position to behave similarly..

Okay. Just to make sure I kind of heard that right. So 70% of volumes are on DCP. So even with maybe the Western benefit.

We should still think something kind of sub 5% kind of on a total company basis sequentially for 2Q, is that fair?.

We haven’t given any guidance on Q2..

Okay. I guess, maybe to come out another way, we weren’t really sure what to do with the 13 Mboe number.

As you have had these freeze-offs and kind of line pressure to some degree it was expected, as we look at your full year guidance number, should we think about these may be surprising us and we should be more in the bottom end of that range for the full year or has kind of the setbacks really not caused that much of a downside relative to the full range you guys originally laid out?.

When you think of the freeze offs, I mean, both wells are producing flat instead of -- at a lower rate instead of being at a higher rate and declining. On a full year basis, we really expect them to produce a similar amount, which is why we haven’t -- we reaffirmed guidance.

What we are kind of trying to say to people in your modeling and to help you guys out there a little bit is kind of expect our volumes going at DCP will kind of flattish to potentially up just a little bit in Q2 as a result of maybe cleaning up some of those line freezes, but the growth will be driven by the development in the wells that we turn in line on the Western Gas system, which should flow unconstrained.

And then when you get into Q3, Q4, a lot of our production growth is going to be driven by the large pad. I think it’s in the neighborhood of 20 or 22 wells of 2 mile long laterals that are going to be turned on in the Greeley area. So that’s where we will get our big sequential step up for the back half..

Okay.

And then just one other for me, have you guys dedicated the Hawkeye acreage to midstream providers or are you guys funding some of that build out for the time being?.

As previously communicated, we -- the midstream build out, we anticipate will be done off of Extraction’s balance sheet, whether it’d be through dedications or through third-party financing that’s non-recourse to Extraction. So we -- again we are very close to wrapping all of that up.

So I want to be quiet on until we have the whole thing completed, but that again continues to go very much in line with what we have previously communicated..

Great..

But we don’t really anticipate….

I will let somebody else hop up..

We don’t anticipate stepping into the shoes of a traditional gathering processing company or something like that.

When we look at taking care of our needs, we are looking at really from like a CGF back to the well as something that Extraction would want to operate and maintain control of, whereas from the said CGF through the upstream or the downstream part of the business we would look to be doing that through joint venture or traditional contract with third parties..

Great. Thanks for taking the questions. I will let somebody else hop on..

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

Good morning. This is Claire Ye asking in the place of Irene.

And just following up on that Northern areas and now that HighPoint has acquired Fifth Creek, so any upcoming well results that we should pay attention to?.

From us we only have the two wells that we drilled and completed right at the end of last year. I believe HighPoint or when they acquired Fifth Creek, they had a decent amount of drilled and uncompleted wells that they will be moving up and completing this quarter. So we could look forward to those results. .

Okay. Thank you..

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

Hey. Good morning, everyone. I want to start with sort of a philosophical question I guess. So you have the chart in the deck slide eight that shows XOG being the lowest multiple in the group, but one of the highest CAGRs just kind of how we see it here too.

So I was just wondering any thoughts about why you think that that’s the case and anything you can do about it if there is anything?.

I -- really we have got a great business plan, a great story, the company, we have got decades of high quality drilling inventory, we have very much demonstrated our management’s team and ability -- and management and operations team’s ability to execute.

And from our standpoint, we are going to hit free cash flow in the second half of the year and as we move through the cycle, we are really looking at the long-term business strategy for the company and we are not stock pickers or price pickers, we will let the market watch our performance and judge for itself..

Okay. I know it’s kind of a tough question to answer. Thanks for that. And then, I guess, on the 13,000 barrels a day that you guys called out. I noticed that the oil percentage on that was higher than the oil percentage for the portfolio.

So, is that just related to where the freeze offs were or any other color on why that would be the case?.

Yeah. That’s exactly what it was.

So it came mostly from freeze-offs and then even Triple Creek has been producing above 55% oil, but then the remaining oil percentage above that was the newer wells in the Windsor area that we have turned on that’s come online at that 80% to 85% oil number and some of those had line freezes that affected them for anywhere from one weeks to two weeks during the quarter, so we lost a decent amount of oil percentage volumes there..

Okay. Thanks. Appreciate it..

Thanks. .

Thank you. Our next question comes from Oliver Huang of Tudor, Pickering, Holt. Your line is open. .

Good morning, everyone, and thanks for taking my questions..

Good morning..

Just on the operations side of things, completely understand that early 2017 wells which are choked back to bring online new higher oil cut DCP oil to flow.

But I was wondering if you could provide some more color on what is driving the uplift on the front end of the wells in the back half of the year comparatively speaking to those in the first half of the year and I think I’m referring to what I’m seeing in slides 11 and 12?.

So for that I would attribute a lot of that to the way that we are bringing these enhanced completions online versus the way that we originally did. So we have adjusted our choke management on some of the enhanced completions given the much larger volumes that we pump on the fracs.

So we have been bringing them on larger chokes than we traditionally did back in 2015 and ‘16.

And when we did the initial enhanced completions, we wanted to keep the same smaller chokes that we used to use on those wells to try to see if we can correlate actually better reservoir deliverability instead of just having a higher IP number because of a larger choke.

So we have kind of thrown and gotten more efficient in the way that we are bringing these on online early time, and I think, it’s really benefited the production for the first six months to 12 months..

Thanks. Appreciate the color there. And just as a follow up with the news on White Cliffs recently and the partial NGL conversion of that pipe, any impact to your longer term plans. Now know you all are an anchor shipper on Grand Mesa.

So I figure you all are pretty well-positioned there, but just curious on your take?.

I think it points to the fact that we chose the right pipeline in Grand Mesa in that it’s a BAP system and you can run multiple grades in it. It’s good news because it provides additional takeaway capacity for NGLs as all these new processing plants come online.

And the other kind of look on it is longer term as development ramps up in the basin, it can take our transportation and turn that into a real asset for the company..

Okay. Thank you. That’s all I have..

Thank you. Our next question comes from the line of Marshall Carver of Heikkinen Energy. Your question, please..

Yes.

How many wells do you plan to put into sales in 2Q in the Western Gas system and what would be the timing of those wells?.

We haven’t provided any quarterly guidance on numbers of wells. But we do -- we will be on track and will achieve the similar number as what we have offered up in our guidance, but....

Firstly, everything we turn online in the second quarter will be going into Western Gas and I would expect the actual gross well numbers to be relatively similar to Q1 with a lot more coming in Q3 with the DCP DUCs that we are completing in the second quarter..

Okay. Thank you..

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

Good morning.

I just want to check on rigs and completion crews, your outlook said that it reflected two plus rigs and two plus completion crews, I’m just wondering because you kind of update what you are running right now and maybe some cadence for the rest of the year?.

Yeah. We manage the drilling and completion crews to match up with our capital guidance. So with the rigs getting faster and faster, we don’t need as many rigs this year as we did last year to drill the same amount of net wells. So we will be picking them up and dropping them periodically just really one rig.

For the completion crews, we have got two full time crews running for us at all times and then we have got another -- again a third one that we will use periodically when we need it..

Okay. Great. Thank you..

Thank you. Our next question is a follow-up from David Deckelbaum of KeyBanc. Your line is open. .

Thanks, guys.

Just trying to listen to the two question limit rules, but I wanted to queue back and just ask, in your sort of historical experience of the Windsor area and maybe some in the line pressures in 13 and 14, did you see a sort of full return to production from impacts of line pressure issues and constraints, I guess and how we think about this getting into the third quarter is the probability here that that we see sort of that the full volumetric impacts coming back in the third quarter?.

Yeah. Based on what happened a couple of years ago when line pressures were close to this level, we did see most of the wells come back above the type curve that they should have been on at that point in time, had there been no constraints, only difference is how long will it take to make up that volume.

So I wouldn’t expect if a well was producing under curve for six months because it was choke back, it’s not going to make that entire volume back up in the first 30 days. But it will make it up based on past experiences, but it would probably take more like a quarter or two..

That’s helpful. Thanks for the follow-up, guys..

Thank you..

Thank you. At this time, I’d like to turn the call back over to Mark Erickson for any closing remarks.

Sir?.

Again, I’d just like to thank everybody for participating in the call this morning..

Thank you, sir. And thank you ladies and gentlemen for your participation. That does conclude today’s conference. You may disconnect your lines. Have a wonderful day..