Louis Baltimore - Director of IR Mark Erickson - Chairman & CEO Rusty Kelley - CFO Matt Owens - President Eric Jacobsen - SVP of Operations.

Kyle Rhodes - RBC Capital Markets Jeffrey Campbell - Tuohy Brothers Ben Wyatt - Stephens, Inc. David Deckelbaum - KeyBanc Capital Markets John Nelson - Goldman Sachs Neal Dingmann - SunTrust Robinson Humphrey Michael Hall - Heikkinen Energy David Tameron - Wells Fargo Securities.

Good morning. I am Nicole and I will be your conference facilitator today. I would like to welcome everyone to the Extraction Oil & Gas first-quarter 2017 financial and operating results conference call. [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 risks and uncertainties that could cause actual results to be materially different from those currently anticipated.

Those risks include, among others, matters the Company described in its financial and operating results news release issued yesterday and it's finally 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. The Company's drilling schedules and capital plans and other factors may cause the 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 to everyone. We are glad you can 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 disclosure 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'll now turn to the call to Mark Erickson, our CEO, to go through some of the highlights from this quarter..

Thanks, Louis. I would like to thank everyone for joining our earnings call. As it stands today, the growth we had been forecasting for the future is now here in the present. Production continues to climb. We are currently producing in excess of 40,000 barrels of oil equivalent per day, of which over 50% is oil.

As we look at our first-quarter results, sales exceeded the high end of our guidance on an equivalent basis, while oil volumes exceeded the midpoint of our guidance by over 3%. Our operations continue to exceed expectations on all fronts and we remain on schedule with drilling, completion and our CapEx budget.

As it relates to our ongoing production ramp, our second-quarter guidance of 42,000 to 45,000 barrels of oil equivalent per day is an impressive 30% growth over our first-quarter volumes. But more importantly, I want to highlight our second-quarter oil production of 21,000 to 22,000 barrels per day.

This represents 60% growth over our first-quarter volumes.

As we have discussed on our previous calls, our wells produce a significantly higher percentage of oil at the beginning of their life cycle, so our production mix is expected to get more oily in the upcoming quarters as we see contribution from the remaining wells we expect to turn to sales this year.

We are extremely encouraged by the early results we are seeing on our initial pads in our Windsor development area completed with our latest completion designs. Matt will talk about these in greater detail later on the call.

We exited the first quarter with a cash position of $285 million and $265 million in net debt, which equates to about 1.4 times net debt to EBITDAX. We currently have approximately $760 million in liquidity. Given the steep ongoing production ramp underway, we continue to expect to exit 2017 around 1.5 times net debt to EBITDAX.

With that I'm going to turn the call over to Rusty to go through our financial highlights. Additionally, Matt will be covering our operating results, including the very encouraging results we are seeing from our enhanced completions in our Windsor program..

Thanks, Mark. I would like to quickly touch on some financial highlights from the reporting period. First, I want to once again take the chance to reiterate the strength of our balance sheet and our attractive liquidity position.

We exited the first quarter with $285 million in cash on our balance sheet and a fully undrawn borrowing base of $475 million, resulting in approximately $760 million of available liquidity and a net debt to EBITDAX ratio of 1.4 times on both a 12-month and 6-month annualized basis.

We look at six months trailing EBITDAX, which is how our bank covenants are structured given our significant growth rate. At the end of the first quarter, nearly 85% of our forecasted 2017 oil production and 73% of our forecasted 2017 gas production was hedged.

And we continue to layer and hedges for our 2018 program which provides us with a visible cash flow stream to maintain our rapid pace of operations without the need to further lean on our balance sheet. With respect to maintaining our efficient low-cost operating structure, we are right on track with our internal drilling and completion budget.

When you think about our CapEx, we expect to run a three drilling rig program and three frac crews on a full-time basis for all of 2017. I'd like to point out though that given our high working interest in the Windsor program, we expect our CapEx to be weighted toward the first half of the year.

As such, we remain right on track with our annual CapEx budget. We also remain very pleased with our current financial position and feel very confident that we have the liquidity and balance sheet strength to execute our goals while allowing flexibility to quickly react to potential acquisitions and other opportunities within our core areas.

Turning to our first-quarter financial results, adjusted EBITDAX unhedged was $51.5 million, a 125% increase compared to the first quarter of 2016. Given our robust hedge positions and our rapid production growth, we are optimistic about the EBITDAX growth profile going forward as well.

Our LOE came in right at the midpoint of our guidance and we look at our LOE more as a function of the total number of producing wells rather than as a function of volumes.

So as we turn in line the wells associated with our large ongoing completion program and grow our volumes through the back half of 2017, we expect to see the per unit LOE significantly decline bringing the for your average right in line with our guidance range. We also expect to see a similar trend on the cash G&A side.

If you think about the major components of our G&A expense, much of that has been associated with the increased headcount and related expenses as we ramped up our organization to effectively run a public Company. The majority of these expenses are largely independent of our production volumes.

So as we increase production, we expect to see a meaningful reduction in our per unit cash G&A expense of even greater magnitude than what we see on the LOE side. Lastly, during the quarter, we were able to contract with a marketing firm to lay off our near-term deficiency volumes in exchange for an exclusive marketing arrangement.

This has removed the charges for expected deficiencies in the first and second quarters resulting in more steady differentials. As such, we expect to have no further deficiencies going forward. What that, I will turn it over to our President, Matt Owens, to cover our operational highlights..

Thanks, Rusty. Let's jump right into the encouraging results we are seeing from our enhanced completions. On our last conference call, we had just started flowing back the initial pads in our Windsor development program.

All Niobrara wells on these pads were completed using our latest completion designs and we are very happy with the early results we are seeing. While it's too early to quantify the improved EUR of these wells, they are beginning to flatten nicely and are producing at or in excess of our enhanced Niobrara type curve.

As these wells continue to clean up under our restricted choke flow back procedures, we are particularly pleased with the exceptionally high initial percentages of oil which are currently averaging around 85%.

In addition to the lower GORs, we are seeing no material declines on these pads leading to the potential for additional positive separation from the type curves. Regarding operations, we had another successful quarter.

In just the first quarter of this year, we reached total depth 147 gross, 38 net wells with an average lateral length of 7,900 feet and completed 54 gross, 47 net wells with an average lateral length of 7,000 feet. Of these 54 gross wells, 30 were completed using our enhanced completion design.

We also turned to sales 26 gross, 25 net wells with an average lateral length of 7,000 feet. Since we resumed completion activities in the fourth quarter of 2016, we have completed 95 gross wells with an average lateral length of 7,400 feet. Our operational efficiencies continue to improve.

During the first quarter, we pumped an impressive 2,273 total frac stages while placing approximately 765 million pounds of proppant. We set an Extraction record by pumping 23 frac stages and over 9.2 million pounds of proppant in one day with one frac fleet. We also set multiple records on the drilling side.

We drilled a 2.5 mile well spud to TD in under 3.1 days and a two mile well in just 2.2 days. I would like to point out that we executed our first-quarter operations while remaining within our overall budgeted drilling and completion costs. Our program remains right on schedule to deliver our second-quarter and full-year 2017 guidance within budget.

I would like to thank everyone for your time on the call today. I would also like to once again thank our equity and debt holders for their continued support of Extraction's efforts to build a premier DJ basin Company. This concludes management's prepared remarks. Operator, I would now like to open up the call to the Q&A session..

[Operator Instructions]. Our first question comes from the line of Kyle Rhodes of RBC. Your line is now open..

Certainly seems like your mitigation efforts on the potential MBC deficiencies were successful this quarter.

Just any additional color on how you were able to achieve that? And what's the best way to think about oil differentials going forward? Should those be turning down towards $7 or $8 or below that as you get more barrels on Grand Mesa for that discounted anchor ship array? Just any thoughts on how we should be modeling that would be helpful..

Yes, the takeaway is we were effectively able to remove the deficiency payments for the first and second quarter, contractually lay those volumes off. So we don't expect any deficiencies going forward. There's some more details to exactly how it works in the 10-Q. If there are any other questions, I'm happy to get on the line and walk you through it.

But it's really just we gave an exclusive marketing contract to a third party and they are taking the responsibility of those deficiency volumes. And from a ZIP Code going forward, I think the right way to model it would be differentials in the highest 7s, low 8s. In fact, the last month was I think in the mid-7s.

That can go up and down just based on market forces. We do expect though over time, as we get more of our production on pipeline versus trucking, that we'll trend down toward the lower end of that range..

Great, that's helpful color. And then my follow-up was just on the 12,000 acre acquisition referenced in the Q. Is that in the same general area as your prior acquisition from the end of 2016? And I guess when do you think you will unveil more details to the market on those transactions? Thanks and congrats again, guys..

Yes, Kyle, that acquisition was within our stealth area. And additionally, we are looking forward to providing more color, but the fact that we are not should be taken as a positive sign that we are continuing to add to our position there..

Got it. I will stay tuned then. Thanks..

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

Congratulations on the strong quarter. I wanted to ask you first, what's the typical oil cut for a standard completion in the Windsor area of production? The 85% oil cut is really huge.

How do we account for that relative to the norm?.

I would refer to our current corporate presentation where initially in the first 30 days we target low 60s type percent oil cut. So it's very safe to say that we are very pleased with the 85% oil cut.

And we are relating that to the very high intensity that we are fracking our wells with which we believe are contacting more rock which is leading to higher bottom hole pressures, which tends to keep the gas in solution and keeps us below the bubble point for a longer period of time..

Okay, great. Yes, that makes sense. Since it's not part of your -- my understanding is that it's not part of your current guidance.

When do you believe the results of the enhanced completions might become obvious enough to suggest an upper revision to production estimates?.

Within our guidance, we are using the 20% uplift in our standard type curve for the Niobrara formation. When you look at the results that we are seeing to date, all the wells have been performing on or above that type curve. We are not yet in a position to increase our guidance at this point in time.

We want to get more production history to see where it ultimately settles out. And typically where we would start getting comfortable with providing that information is when we get -- reach bubble point and the wells start to go on natural decline..

Okay, so just to re-phrase what you just said, you've assumed a 20% production uplift in current guidance. If there's a revision upward that's going to be based on a better than 20% production uplift as the data begins to become more obvious.

Is that fair?.

Yes, we are not saying that we're going to be revising upward right now at this point in time. We are sticking with our current guidance..

Right, understood. And my last question was I was wondering if there was any update on the Northeast extension area plans or data.

Have you defined when you're going to start drilling some tests with enhanced completions? And has there been any significant industry data that's come to light since the last call?.

We are still planning on a Q3, late Q3 spud up there. Were currently working through several permits across the position while we fine-tune our geologic models and where we want to target the Codell and the Niobrara with these first wells up there. There is some drilling rigs back in the area.

I believe there's a few just over the border on the Wyoming side and there's an operator that drilled a handful of wells about 5 to 10 miles west of our Grover position. So there has been recent activity up there. But as for us, we're still on track for the same schedule, hopefully having those wells online before year-end..

Okay, perfect. Thanks for the color..

[Operator Instructions]. Our next question comes from the line of Ben Wyatt of Stephens. Your line is now open. .

Maybe one quick one here for Matt. Matt, you referenced a record kind of 23 frac stages per day. Just curious any update on maybe what you guys are averaging on stages per day now..

Yes, so our initial guidance when we switch to the full-time enhanced completions we model 12 stages per day, like we relayed to everybody. We've stated that we thought we'd get better as time went on, just like we did previously with the old completions. And obviously we have been with the new completions thus far.

We've had days where we've gotten as high as the 23. Our average is beginning to creep up, but until we get a solid run rate with all three of the frac crews averaging something higher we're going to leave it at the 12 stages per day..

Very good. Appreciate that. And then maybe as a follow-up. I imagine someone will bring it up, but just wondering if you guys could give us any update on what's happening on the political side with Colorado. If there's any kind of read through on maybe how Broomfield or Boulder is affected.

Really just kind of any update you guys can give us on that side of things. Thanks..

I'll start by saying that along with people across this area and throughout Colorado, we have been very saddened by the Firestone tragedy and our thoughts are with the families affected. As far as Extraction's response to Firestone, our actions were swift and decisive.

Within three days after the governor's order, we had already tested successfully all of our 178 flow lines within 500 feet of occupied structures and we will be completed testing the remainder of the flow lines within 1,000 feet of occupied structures prior to June 30.

We have been in very close communication with a number of the communities and local governments as well as the state on the path forward. All of our wells in Broomfield and Boulder have been tested and successfully passed. And we remain committed to plugging and abandoning 41 wells in Broomfield as part of our development plan going forward there.

So, we're in close communications, we remain on track, we are addressing concerns. We are testing and successfully passing everything and our permitting efforts will continue to move forward..

Our next question comes from the line of David Deckelbaum of KeyBanc. Your line is now open..

I was hoping to get some color I guess on the enhanced completions side. Your initial guidance I think was about a 20% increase on well costs.

Could you say how the Windsor wells, or your initial enhanced completions are shaping up in terms of your AFEs?.

So far, we are looking very in line with that on an average across all the wells we've done. We've completed quite a few up there right now and everything looks pretty solid to exactly what we were forecasting with that 20% uplift..

Okay and my follow-up is I guess on the two pads in Windsor -- or I guess the three pads in Windsor.

Was there a significant difference in initial oil cut between the Codell and the Niobrara there?.

The Codell usually comes along with a little bit more gas and we saw the same thing here, but it still was relatively low across the board compared to what we've seen in the offset sections..

Did the 85% describe the Niobrara and the Codell or just the Niobrara?.

That was the Niobrara wells only..

Thank you, guys..

Our next question comes from the line of John Nelson of Goldman Sachs. Your line is now open. .

Congrats on the update. I wanted to circle back to the earlier questions on potential fallout post Firestone.

Could you just update us on when we look at your development plans over the next maybe 6, 12 or 18 months, what level of permits do you currently have in hand or how do you view any change to the development risk profile post the incident?.

As far as permits looking forward, we are in great shape for the rest of 2017. We are working diligently on 2018 across our entire acreage position.

Broomfield, Greely, Windsor, the northern extension area that Matt mentioned, up and down the chain we are actively permitting and looking to be in very good shape for 2018 as well as a very solid position as mentioned in the rest of 2017..

Is there a ballpark you could say for 2018 or maybe speak to the flexibility to reallocate activity to more northern areas like Greeley? Should it be more challenging to get permits to the south? Any kind of help in thinking about the development risk there?.

Yes, good question. We are permitting for at least up to a four to five rig type of scenario, not that we are going to run that many rigs necessarily. But we are permitting for enough flexibility in our inventory to make adjustments depending on geographic considerations, commodity price adjustments.

Whatever the environment brings us we are permitting throughout 2018 to have enough flexibility for a variety of scenarios..

That's helpful. I'll let somebody else hop on. Congrats..

Our next question comes from the line of Neal Dingmann of SunTrust. Your line is now open..

Just trying to get a sense, Matt -- you guys have laid out I think through those at least first eight pads. I'm just trying to get an idea of optimal pad size going forward as you go into 2018 part of your development.

How do you see that? Kind of still on these 10 well pads or what's optimal as you see starting next year?.

Optimal for us has always been 12 wells per pad. So ideally if we are drilling a full unit -- section wide unit we'd like to have two pads that we could run in with two rigs and that speeds up our cycle time significantly.

But there's a lot of areas where we aren't fortunate to have two pads and that's when we would have to put more onto a single pad..

Okay. And then just one follow-up either, Matt, for you or Mark. I'm looking at one of your slides that does a great job, it shows enhanced completion and the flatter decline. Obviously the market seems to me incorrectly a lot of times the word for IP rates.

So how do you show or what do you think is still the best way to show that these flatter declines -- is there a way somewhat early to show that that's still the most economical? Or as these are sort of playing out as you'd envision and with this enhanced completion, how should we follow along to know other than just tracking early production rates?.

It's really difficult to show that with the limited amount of production that we have so far. Ideally we'd like to see the wells reach bubble point pressure. And once that happens that usually means the wells aren't being choked back by the production equipment that we are using.

And at that point we'd start to see the matrix contribution from the reservoir itself and that's when we could actually forecast something out. Just this early in time when the wells are producing so flat you can't put any sort of type curve to that. So time is really going to dictate when we'll be able to do that..

Understood.

Matt, how long usually is that bubble point?.

In the Windsor area where these wells are drilled it's typically around -- somewhere between three and five months and that was on our old-style completions. So, on these ones we don't know. It might be the same time but, given the fact that the GOR is so much lower right now, it might be a little bit longer..

Neal, one of the things that we've done here is we've maintained a very similar choke program to what we did with our standard completions. And we did that because we wanted to have an apples-and-apples comparison with our standard type curve and standard well performance with our older frac.

But given the flat production and the low GOR and it staying like that, we are very encouraged by what we are seeing..

Great details, guys. Thanks so much..

Our next question comes from the line of Michael Hall of Heikkinen Energy. Your line is now open. .

Just want to follow-up a little bit on that last line of questioning.

As it relates to a bubble point, what is the typical pressure at which you would pass through the bubble point and where are the bottom hole pressures today on those initial wells?.

We don't have bottom hole gauges in these wells, so all we can infer is from the surface pressures that we have. But typically in this area the bubble point pressure has been in the neighborhood of 3,200 to 3,500 psi. So, all we can go off of is what the timing was to reach that bottom hole pressure off of our older completions.

And again, based off the early results, I think it's going to take a little bit longer for these wells to reach that same point..

Okay.

I guess what are the surface pressures on the current wells right now? Do you have a read on that or --?.

They are all varying. They are slightly higher than what we are used to seeing in that area. But it's different for one-mile wells versus two-mile wells and that sort of thing..

Okay..

The other thing -- it does vary based on what stage you are in the flow back. Obviously very early on you are flowing back a lot of water which tends to be heavier. And then as your oil cuts increase your pressure increases and then as your gas increases it will continue..

Okay, great.

And just to be clear then, as it relates to this variance in initial oil cut, you think it's purely a function of the enhanced completion or is there potentially some geographic factor at play here as well relative to the type curve?.

I don't think there's anything geographic since we have so many wells drilled on the same 16 Niobrara per section density directly adjacent to this area. So geologically it all looks the same the way that we look at the models.

The only real difference here is, like Mark mentioned, we kept the choke program be exact same because we want to see what the actual enhanced frac is doing to the production. So we've kept the choke program the same. All we did was pump a lot more sand, a lot bigger stimulation.

And it appears that we have a lot more energy coming out of these wells and that's why the GORs remain low..

Got it. That's helpful and encouraging.

And then I guess last of mine is do you have an estimate for what your I guess gross and net turn in lines are expected to be in the second quarter?.

We haven't disclosed that beyond what was in our investor presentation on that pad table that we had, which just shows the wells that were drilled as they were drilled and uncompleted as of year-end..

Right, okay..

One thing -- one good take away Mike, Michael, is that we have not updated or changed the turn in line dates, but obviously we are very, very confident that we are going to meet or exceed that schedule..

Yes, certainly with production where it's at currently things are looking pretty good. So, congrats on a solid quarter, guys. Thanks for the time..

Our next question comes from the line of David Tameron of Wells Fargo. Your line is now open. .

So, if I'm just following up on Michael's questionnaire, when I look at that chart you put in the presentation in the little slide deck, I'm just looking at the BOE, and looking at that high oil cut.

What's the gas and NGL component doing of the other piece? I'm just trying to figure out if you are seeing an overall uplift yet in the EUR or if it's just -- if that oil is coming I guess in place of, for lack of a better word, some of the gas and NGLs..

David, are you referring to slide 5 in the deck we put up last night?.

Yes, the deck you put up last night, yes..

So that's not showing BOEs; that's showing oil..

Yes, and I was just wondering what's the other component doing I guess? What's the total BOE doing?.

It's 85% oil, so we're a little bit higher on the BOE number. But until the gas starts to break out at the bubble point pressure we'll probably stay significantly weighted to oil..

Okay..

But during the early 30 days, which I mean we've got a lot of information to gather still. But during the first 30 days we have been meeting or exceeding the 20% uplift on all of our wells with a much higher oil cut..

Yes, no, I'm just trying to get a handle for -- just to see where the total EUR was tracking, but I know you are 30 days in, so --. second question, let me go back to Colorado one more time. Can you guys talk about -- I don't think it's a big percentage of wells you have that are vertical; I think we've talked about that.

But can you give us what percentage of your wells are vertical? And then if we think about horizontal wells that are near residential areas, can you talk about -- do you have any -- can you give us any color on that?.

So, the percentage of vertical wells, I think I'd answer that by saying we have about 3% or so of our current production is from vertical wells, 3% to 4%, so about 1,500 BOE a day net from vertical. So a very, very small percentage and dwindling.

Sorry, was the second part of the question about horizontal wells?.

Yes, within whatever -- within 1,000 feet of a residential area, how much --? I know obviously legacy vertical wells are, but how much of your horizontal program are within residential areas?.

So going forward, probably about a third of our horizontals are within 1,000 feet of occupied structures, something of that order and 500 feet. So we are well outside the 500 feet of -- the vast majority of all our program going forward is outside the setback of 500 feet..

Yes, no, I'm talking about existing production from horizontal..

Within 1,000 feet we have about 150 or so..

Okay. And last clarification, the 3% you referenced, that number -- the 41 wells you mentioned in Boulder you are shutting in now, that 3% has got to go to 1%.

Am I thinking about that right, once you shut in those Boulder wells?.

Why would we shut--?.

You're talking about Broomfield wells?.

Broomfield wells -- I'm sorry -- Broomfield wells, not Boulder wells, yes..

Yes, that's a real small percentage and even less than that..

Okay..

It's probably 100 barrels or so, a couple hundred barrels of production..

But we are not shutting in any production. We are well ahead on the testing, we've always maintained a very robust testing and maintenance program for all of our wells and facilities. What Eric was referring to as part of the Broomfield development program, we will be plugging out the 41 vertical wells.

And that's been real key in the permitting process of basically taking wells that are scattered throughout the community that are vertical and produce very little and moving that into concentrated facilities that are in more benign locations..

And that's my -- I use the word shut in rather than P&A. I was talking about those P&A wells, so that makes sense. Thanks..

Our next question comes from the line of David Deckelbaum of KeyBanc. Your line is now open. .

I just wanted to ask, I know last time you guys had shared the exit rate I think of about 65,000 to 70,000 equivalents a day for the year, which I assume, considering you're not changing your full-year guidance, that number is not changing.

But do you have a sense on what you think your corporate oil mix would be on the 2017 exit rate?.

I would stick to -- I think we did update our guidance the last time we gave it to break out both BOEs as well as oil. So that hadn't changed; I think you can get an implied oil mix on that.

But we just wanted to make sure we gave absolute oil barrels in that guidance and that's really what's been driving our economics, which again is why we're so pleased with what the amount of oil that we are seeing out of these new wells is. But at this point we haven't changed anything on exit or full-year guidance..

Okay, thanks, Rusty..

Thank you. And I'm showing no further questions at this time. I'd like to hand the call back over to Mark Erickson for any closing remarks..

I just want to thank everybody for joining us on our call today. We obviously -- we believe we had a great quarter. And we're looking forward to Q2 and Q3 as our ramp accelerates. So look forward to providing you future updates and it's fun to get this thing rolling..

Ladies and gentlemen, thank you for participating in today's conference. That does conclude today's program. You may all disconnect. Everyone have a great day..