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Edited Transcript of XOG.OQ earnings conference call or presentation 14-Mar-17 2:00pm GMT

Thomson Reuters StreetEvents

Q4 2016 Extraction Oil & Gas Inc Earnings Call

Mar 14, 2017 (Thomson StreetEvents) -- Edited Transcript of Extraction Oil & Gas Inc earnings conference call or presentation Tuesday, March 14, 2017 at 2:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Louis Baltimore

Extraction Oil & Gas Inc - Director of IR

* Mark Erickson

Extraction Oil & Gas Inc - Chairman & CEO

* Rusty Kelley

Extraction Oil & Gas Inc - CFO

* Matt Owens

Extraction Oil & Gas Inc - President

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Conference Call Participants

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* Kyle Rhodes

RBC Capital Markets - Analyst

* David Tameron

Wells Fargo Securities - Analyst

* David Deckelbaum

KeyBanc Capital Markets - Analyst

* Neil Dingmann

SunTrust Robinson Humphrey - Analyst

* Ben Wyatt

Stephens Inc. - Analyst

* Michael Hall

Heikkinen Energy - Analyst

* John Nelson

Goldman Sachs - Analyst

* Jeanine Wai

Citigroup - Analyst

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Presentation

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Operator [1]

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Good morning. I am Chelsea and I will be your conference facilitator today. I would like to welcome everyone to the Extraction Oil & Gas fourth quarter and full year 2016 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 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. The 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.

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Louis Baltimore, Extraction Oil & Gas Inc - Director of IR [2]

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Thank you and good morning to everyone. We're glad you could join us today for our fourth quarter and full year 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, the Chief Accounting Officer, and Eric Jacobsen, our SVP of Operations.

I'd like to remind you that in 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 Form 10-K which we provided yesterday evening after the close of trading.

I'll now turn the call over to Mark Erickson, our CEO, to go through some of the highlights far this quarter and full year.

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [3]

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Thanks, Louis, and welcome to Extraction as our new Director of Investor Relations. I would like to thank everyone for joining our earnings call.

We think you'll be pleased with Extraction's current outlook as we execute our near-term growth plans, and continue building upon our strong private company track record now as a public company. In spite of a difficult commodity price environment, 2016 was a transformational year for the Company. We finished the year strong both financially and operationally.

Our cash position was approximately $589 million. We had zero net debt, and approximately $1.1 billion of liquidity. Operationally, our drilling and completion operations are on schedule.

Production exceeded the midpoint of our guidance on all three streams for both the fourth quarter and full-year 2016. Production grew by 57%, and our proved reserves increased by 50%. We entered into three acquisitions, adding roughly 23,000 net acres, bringing our total core DJ Basin net acreage to 116,000 acres.

Turning our focus to what's to come in 2017. Operations are on track for our large expected production ramp during the second quarter, with our largest expected sequential growth occurring during the third quarter of 2017. We expect 2017 average production to grow by about 70% at the midpoint over 2016. And with continued operational success, we will have strong momentum taking us into 2018.

We're pleased with the progress we are making with our completions program in Windsor, which is going to be the main driver of our near-term robust production growth. On our first two pads, we are already selling oil and remain on schedule with our completion program. It is another real achievement by our dedicated operations team to meet the schedule throughout wintertime operations while implementing this important transition to enhanced completions.

In addition to our large upcoming production ramp, we have several near-term developments that I would like to provide more color on today. We look forward to continuing to provide additional information on our enhanced completion program, which we believe are yielding encouraging results based on high initial flowback rates and pressures. Our efforts in Broomfield continue to gain momentum, and we expect to have permits before year end.

In our Grover project within the northern extension area, we anticipate commencing operations to drill and complete two new extended reach laterals during the second half. One in each of the Codell and Niobrara formations, and complete them utilizing enhanced techniques which have demonstrated successful results by offset operators.

Last but not least, we look forward to providing additional details surrounding leasing and operational results in our new acquisition area. As disclosed in our 10-K, extraction in Bayswater mutually agreed to terminate the auction purchase agreement. The auction featured in this agreement was very attractive to us, as it provided flexibility with respect to our capital allocation options.

We like the asset, but we are allocating our capital to what we think are the best available opportunities. With that, I'm going to turn it over to Rusty to go through our financial highlights. Additionally, Matt will be covering our operating results.

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Rusty Kelley, Extraction Oil & Gas Inc - CFO [4]

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

We entered 2017 with no net debt, $589 million of cash on our balance sheet and a fully undrawn borrowing base of $475 million, resulting in approximately $1.1 billion of available liquidity. As of year-end 2016, nearly 85% of our forecasted 2017 oil production and 80% of our forecasted 2017 gas production was hedged. Which provides us with a visible cash flow stream to maintain our rapid pace of operations without the need to further lien on our balance sheet.

Let's get into some details of our 2017 production guidance, starting with the first quarter. We currently expect our first quarter 2017 average production to be in the range of 31,000 to 33,000 BOE per day, with 12,000 to 14,000 barrels of crude oil per day. These production levels are consistent with our plan and stated full-year 2017 guidance.

While pad drilling does lead to lumpy production profiles, we strongly believe it's the most efficient way to invest our capital. Consistent with our stated completion schedule, after the first quarter, we expect three straight quarters of rapid sequential growth.

I will point you to slide 8 in our investor presentation to give you a better picture of our completion schedule. We remain very pleased with our current financial position, and feel confident we have 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.

Now turning to the fourth quarter financial results, adjusted EBITDAX unhedged was $58.6 million, a 34% increase sequentially and 96% increase compared to the fourth quarter of 2015. For the full year, our adjusted EBITDAX unhedged was $164 million, up 39% over 2015.

Given the current forward strip and our attractive hedge book, we are optimistic about our EBITDAX growth profile going forward. We did see a nice positive EBITDAX contribution from our hedges in the amount of $34 million during 2016.

Before I turn the call over to Matt, I'd also like to make a few quick comments on our per-unit LOE and G&A expense over the next few quarters. First, we did see a nice reduction in our per-unit LOE throughout 2016, which has largely been a function of our growing production volumes. We look at our LOE more as a function as the total number of producing wells, rather than as a function of volumes.

So over time as we turn on more new wells to sales, we're going to expect to see that per-unit LOE come down. Conversely, during the first quarter when we forecast a modest decline in production, we would expect our LOE on a per BOE basis to increase the levels we outlined in our first quarter guidance. As we turn in line the wells associated with our large ongoing completion program and grow our volumes to the back half of 2017, we expect to see that per-unit LOE significantly decline, bringing the full-year average in line with our 2017 full year guidance range.

We expect to see a similar trend in 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 ramp 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 an even greater magnitude than what we see on the LOE side. So now, I will turn it over to our President, Matt Owens, to cover our operational highlights.

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Matt Owens, Extraction Oil & Gas Inc - President [5]

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Thanks, Rusty. Before we get into the success we've been achieving on the operations side, I'd like to first touch on the recent progress we have achieved with respect to the regulatory environment in our Broomfield development area.

At the end of February, the Broomfield City Council made the decision to indefinitely suspend its previous proposal for a six-month moratorium on processing applications for oil and gas permits. With this moratorium being suspended indefinitely, we now see a clear pathway to working collaboratively with the community and ultimately receiving the permits necessary to begin our operations in this area by year end.

Regarding operations, we had another successful quarter. While we did not turn on any operated wells to sales during the fourth quarter, we remained busy on the drilling and completion front.

During the fourth quarter, we reached total depth on 34 gross, 31.5 net wells with an average lateral length of approximately 8,000 feet. During the quarter, we also completed 17 gross, 16 net wells with an average lateral length of approximately 8,000 feet. Of these 17 gross wells, 9 were completed using our latest enhanced completion design.

Our operational efficiencies also continued to improve. While we set Company drilling records during the fourth quarter, we recently set a new Company record with a spud to total depth time of just 3.4 days for a 2.5 mile lateral with a total measured depth of just under 20,500 feet. Our one continuously running rig during 2016 drilled what we believe to be a record of 932,000 feet during the calendar year.

Back in November, we began a large completion program, primarily in our Windsor area, that includes approximately 92 gross wells with an average working interest of 94% and an average lateral length of just under 8,000 feet. The first two pads in this program are flowing back now, and we are encouraged with what we are seeing so far.

For the full year 2017, we are currently on track to drill 185 to 190 gross wells, complete 190 to 195 wells and turn 145 to 150 wells to sales. We expect to exit 2017 with approximately 130 gross wells in process with an average lateral length of 9,200 feet, which should set us up with great momentum going into next year. We are currently forecasting 75% year-on-year production growth for 2018.

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 for the Q&A section.

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Questions and Answers

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Operator [1]

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(Operator Instructions)

Kyle Rhodes with RBC.

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Kyle Rhodes, RBC Capital Markets - Analyst [2]

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Understand it's early, but are there any early rates you can share on the encouraging results you've got on the two enhanced completions referenced in the release?

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [3]

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Kyle, right now, we are in the very early flowback stage. If you look at what we've guided to is that these pads would all be starting to come online towards the end of Q1.

We feel like we're on schedule, slightly ahead of schedule. But given it's still a flowback period, we just aren't comfortable sharing rates at this point in time. But when we talk about the being encouraged, these wells are looking very strong.

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Kyle Rhodes, RBC Capital Markets - Analyst [4]

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Okay, great. That's helpful. It seems like offsetting completions had a decent impact on the first quarter 2017 guide. Have some of those shut-ins been restored at this point in time, and is there a current production number you guys can give?

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Matt Owens, Extraction Oil & Gas Inc - President [5]

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Right now, there's three wells that are still currently shut in. We have two more wells that we need to finish completing, and once those are done those original three wells will come back in production. Those three wells are making about 150 to 200 barrels a day when we shut them in, and they are about 90% working interest.

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Kyle Rhodes, RBC Capital Markets - Analyst [6]

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Got it. Any sense of a current production number you guys can give?

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [7]

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I would just look at -- when you are looking at the Q1 guidance, we've always looked at Q1 as being right ahead of the big increase that we're going to see going into the second quarter. So from our standpoint, we're I would say at the high end of what we guided to for the average of the quarter.

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Kyle Rhodes, RBC Capital Markets - Analyst [8]

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Got it. Okay, that's helpful. If I could sneak one more in. On the Bayswater lease-option termination, how much of that decision was related to the oil price pull back and maybe how much of that decision is related to better leasehold opportunities you guys are seeing on the ground?

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [9]

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We need like the Bayswater asset. It's just that part of the over funding was for Bayswater or something like it or better than it. We've had good success in bolting on acreage in our acquisition area. That's obviously is a focus for us, and we want to make sure that we preserve dry powder for opportunities like that we are seeing.

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Kyle Rhodes, RBC Capital Markets - Analyst [10]

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Got it. I will hop back in queue. Thanks, guys.

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Operator [11]

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David Tameron with Wells Fargo.

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David Tameron, Wells Fargo Securities - Analyst [12]

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Matt, can you talk about -- or Mark, or whomever, can you talk about the offsetting shut-ins? If you are using -- if you've gone to this block completion or block frac, whatever you want to call it, development mode type style, should we see less of that going forward?

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Matt Owens, Extraction Oil & Gas Inc - President [13]

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Yes, David, this is Matt. We should see a lot less of that going forward since we are drilling pretty much everything in the area as we move forward. This just happened to be three older wells that were already drilled off of this pad. So going forward, we should have a lot less shut-ins due to offset completion activity.

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [14]

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We ended up with some legacy wells on some of our properties that we acquired in acquisitions. That's not our typical mode of development.

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David Tameron, Wells Fargo Securities - Analyst [15]

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Okay. What's your current completions? I'm just thinking about the enhanced completion, is there upside to your current numbers, or as far as -- is there upside you're going to try something bigger than what you've just done on the enhanced completion? And what do you think the target development completion looks like going forward over the next two or three quarters?

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Matt Owens, Extraction Oil & Gas Inc - President [16]

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We're still experimenting right now in the Windsor block with some larger jobs, and we'll have those results once the whole block comes on and we get three months or so of production to see if there's any benefit there. So we're still testing what could be optimal in these lower GOR areas.

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David Tameron, Wells Fargo Securities - Analyst [17]

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Okay, Matt. And is there just primarily more profit at this point, are you doing anything else on the completion side?

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Matt Owens, Extraction Oil & Gas Inc - President [18]

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We've done -- primarily its profit in the Niobraras, and we've also experimented with some different fluid volumes as well. So all of those different tests will be coming online once this entire Windsor block comes online.

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [19]

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But appreciate that EBITDA pumped the larger profit jobs require additional fluid.

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Matt Owens, Extraction Oil & Gas Inc - President [20]

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Yes.

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David Tameron, Wells Fargo Securities - Analyst [21]

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Okay, yes, that makes sense. Last and then I will let somebody jump on.

If I just think about the regulatory in Broomfield, we haven't heard a lot about Boulder. Can you just address that, and then just remind me, and you might have mentioned it and I missed it if you did. But remind me, if we think about 2018 production, I guess back half of 2017 and 2018, from a -- how much of that regulatory -- how much regulatory hurdle is in -- to hit theses 2017 and 2018 production numbers?

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Matt Owens, Extraction Oil & Gas Inc - President [22]

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On the regulatory hurdles, we're really pleased with the progress we made, as Matt alluded to in Broomfield. We are working cooperatively with the city leaders of Boulder and or excuse me, Broomfield and the community there, and we do expect to a permits by the end of the year, as Matt alluded to. Regarding your question on Boulder, I think we will work a parallel path of cooperatively and Boulder, similar as we've done already in addition to waiting to see how the lawsuit from the state of Colorado flushes out.

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [23]

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At this point in time, we'll have our drilling inventory and permits in place for 2018, whether we have drilling opportunities in Broomfield or Boulder County.

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David Tameron, Wells Fargo Securities - Analyst [24]

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Okay, appreciate the color. Thanks.

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Operator [25]

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David Deckelbaum with KeyBanc.

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David Deckelbaum, KeyBanc Capital Markets - Analyst [26]

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Just wanted to follow up on one of David's questions. The Broomfield permits you guys are planning on having in hand in 2018, as you think about that 75% growth rate target for 2018, do you have an alternative plan out there if the permitting takes too long? Are you going be simultaneously permitting more in the Windsor area or other areas if you needed to that would be part of your 2018 plan as opposed to Broomfield?

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [27]

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Or current goal is to have two years worth of permits in front of us at all times. But appreciate when you look at our guidance as well, that we're going to exit the year with about 130 1.9-mile wells. So we are going to have a very robust inventory of wells in progress just entering into 2018. Which similar to this year, those are going to be the main drivers of our high growth in 2018.

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David Deckelbaum, KeyBanc Capital Markets - Analyst [28]

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Got it. I appreciate that. So it sounds like a lot of the tie-in levels are actually going to be somewhat similar to 2017 and 2018, in the longer lateral vintage?

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [29]

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It will be. But as we bring on this big pad here, you are going seeing a more smoother transition in the future. This was a big, big project that we've been working on for a 15 to 18 months to bring on this big group of wells in Windsor. But now we are already well in progress on doing the same thing for 2018.

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David Deckelbaum, KeyBanc Capital Markets - Analyst [30]

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Okay. The current plan right now, Matt, is still to have in (technical difficulty) on the remaining tie-ins this year or remaining completions this year? I know you had nine that were in this first batch of wells. Will we see the more legacy designs now are behind us in that first batch?

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Matt Owens, Extraction Oil & Gas Inc - President [31]

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It all relates to the really the GOR of where we're going to be completing wells. So some of those wells if we're drilling more in the high GOR areas, we're going to be utilizing what our older or our more standard design was in the Niobrara. We're going to be still doing some tests here and there in those areas.

But for the most part, our plan is to just use our standard completion design. In the lower GOR areas, like such as over by Windsor, we're going continue using the enhanced designs on the Niobraras, and we are also experimenting with a few enhanced designs on the Codells, as well.

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David Deckelbaum, KeyBanc Capital Markets - Analyst [32]

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That's helpful. The last one for me, you are not full -- you are flowing back some of the oil on some of these enhanced completion jobs. But could you contrast the cycle times that you've observed in the initial enhanced completion pads versus the legacy completions that you did in Windsor in 2016?

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Matt Owens, Extraction Oil & Gas Inc - President [33]

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When you say cycle times, are you referring to -- (multiple speakers)?

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David Deckelbaum, KeyBanc Capital Markets - Analyst [34]

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I'm thinking spud to sales or spud to TB or completion time or however you think about communicating it?

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Matt Owens, Extraction Oil & Gas Inc - President [35]

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So on the block as a whole, if you look from when we started drilling it to turning it online, it's not a very good proxy for going forward since we started with one drilling rig drilling in that area. We now have several drilling rigs running, so it would go a lot faster in the future as far as the drilling time goes.

But for the completions, we're still averaging right as what we put in our guidance at 12 stages per day and we've got a lot of days that we've had recently where we've gotten up to 19 stages per day. So we're going to spend the next quarter hopefully getting better at these larger jobs, and move that average from that 12 number up into the higher teens.

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David Deckelbaum, KeyBanc Capital Markets - Analyst [36]

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Okay. And in terms of the AFEs that you would set out, you had factored in I think a 20% increase in well costs. Is that pretty much in line with what you've been seeing early days here?

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Matt Owens, Extraction Oil & Gas Inc - President [37]

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Yes. We've had a little bit increased costs just due to wintertime and pumping more water and having to heat that water. But as long as we can hold that 12 stages per day, we shouldn't see costs much higher than what our original AFEs where, unless we see price inflation.

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David Deckelbaum, KeyBanc Capital Markets - Analyst [38]

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Got it. Thanks, guys.

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Matt Owens, Extraction Oil & Gas Inc - President [39]

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Thank you.

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Operator [40]

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Neal Dingmann with SunTrust.

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Neil Dingmann, SunTrust Robinson Humphrey - Analyst [41]

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Two questions, Mark, for you or any of the guys there. One, just looking up at the prior slides for the three rigs, the current full-time rigs. Once that larger, as you said, pad and stuff are done, do you anticipate the rigs staying in that where they are now? They all look to be in that southern Larimer area, maybe just an idea of where most of the activity we will be seeing for the second half of this year?

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Matt Owens, Extraction Oil & Gas Inc - President [42]

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We are drilling a large Pad in Greeley right now, that will be a big pad that comes on for us in the second half of the year. We are drilling some other wells northeast of Windsor, and then down in that southern Larimer area that you just mentioned will be another big couple pads that we will be developing simultaneously with multiple rigs.

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Neil Dingmann, SunTrust Robinson Humphrey - Analyst [43]

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Got it. Then one last one. We've heard others talk about earnings season locking and cost, and some say they can do it for the rest of this year as far as whether that's on the drilling side where you lock in rigs or on the completion side.

How do you all view this on either drilling or the completion side? Are you able to do this, or do you think about doing this?

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Matt Owens, Extraction Oil & Gas Inc - President [44]

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Our rig costs haven't inflated too much. We typically always paid a little bit more per day because we like to outfit the rigs a certain way to allow us to drill as fast as we do. But we haven't seen much inflation there with the new rigs that we've picked up.

On the completion side, we haven't seen really any inflation at this time. But we are hearing the rumblings of sand prices possibly going up, and that's something that would be passed through to us if that does occur.

We are actively searching for alternative sources or different sizes to offset any increases that might happen with one province such as 4070. But as far as the completion service price goes, we expect to be locked in on the horsepower charge for all of 2017 and the only price increases we should see would be any material pass throughs.

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Neil Dingmann, SunTrust Robinson Humphrey - Analyst [45]

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Sounds good. Thanks, guys.

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Matt Owens, Extraction Oil & Gas Inc - President [46]

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Thank you.

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Operator [47]

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Ben Wyatt with Stephens.

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Ben Wyatt, Stephens Inc. - Analyst [48]

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Wanted to see if we could go a little deeper on the acquisition front. I know you guys have obviously terminated the base water. I believe that was about 9,000 acres.

Just curious if you could give us any color on maybe what the assets that you guys are looking at now are like? Is it getting a whole lot bigger in the core of the Wattenburg? Is it more bolt on so you can drill longer laterals? Just curious how you are thinking of this asset to be coming into the Extraction fold before too long.

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [49]

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Sure. It's a little bit of both, Ben. We are bolting on working interest and adding to that so that the wells that we do drill will have a higher working interest in them.

We are actively permitting in the area, and then additionally we are in and around it finding some larger blocks that we're able to put together that are going to allow for longer laterals and more operated wells that we will be able to add onto what we are doing right now. We're actually very pleased with how the leasing effort has been going in the area.

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Ben Wyatt, Stephens Inc. - Analyst [50]

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Got it. Very good. Then maybe a follow up on what Matt just touched on. You said it sounds like if there is any vulnerability on the pricing side of things that it could come on the sand side.

Just curious you guys thoughts on do you really care what kind of sand you are using on these completions, and more specifically on the enhanced completions? I guess my point is, is there quite a bit of alternative there other than the sand you are using right now? Thanks.

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Matt Owens, Extraction Oil & Gas Inc - President [51]

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Yes. The way that we view it, there's a lot of different alternatives. 4070 seems to be the hot commodity in the sand market right now. We actually switched to using that proppant back in 2014 when everybody else was using 2040.

We couldn't get 2040, so we switched to 4070 because it was in more supply for us and it also was a lower cost. Right now, everybody seems to be switching back that way.

We've already made changes on our Codell wells to a different sand size, that again, is not being used as much by our peers and is in more supply and is also coming at a cheaper cost than the 4070. And we are continuing to evaluate other sizes to switch the Niobrara wells to in the event that the 4070 white sand does increase the price or becomes harder to get our hands on.

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Ben Wyatt, Stephens Inc. - Analyst [52]

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Very good, guys. Appreciate the time. Thanks.

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Matt Owens, Extraction Oil & Gas Inc - President [53]

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Thanks.

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Operator [54]

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Michael Hall with Heikkinen Energy.

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Michael Hall, Heikkinen Energy - Analyst [55]

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Maybe just keeping on the completions side of things or the cost side of things as it relates to completions. Just want to make sure I heard you right that the current contract you have in place is a term through 2017. So should we think about you then floating to a more market type rate in 2018?

And if that's the case, what sensitivity would that be today? If you assume that change, would that provide a markup today on your wells? Or is your current contract the current spot type pricing, if that makes sense?

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Matt Owens, Extraction Oil & Gas Inc - President [56]

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Our contract on the completion side is [based] a bit differently than a lot of other companies. We've worked closely with our completion provider and we really go off the volume that we are able to pump. And since we've switched to these enhanced completions, we've been averaging anywhere between 5.5 million and 7.5 million pounds of sand per day per frac fleet which is a very substantial amount of sand compared to what they pump for most operators.

And because the volume of our throughput has been so high, that is why we were able to lock in the horsepower charge for all of 2017. And it's because the completion companies, they make money a little bit on the materials too. So the more that we are able to pump in volume wise, the lower they have to charge us for the horsepower.

So we will revisit that again come probably late 2017, early 2018 about what that stage price would be for the horsepower. But if we are able to increase our volumes from the 12 per day that we are averaging right now up into the higher teens, then that will also help us offset any inflation to the horsepower charge.

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Michael Hall, Heikkinen Energy - Analyst [57]

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Okay. So is that horsepower charge basically you are paying a day rate for the horsepower or is it per stage? How should we think about that?

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Matt Owens, Extraction Oil & Gas Inc - President [58]

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It's a per stage cost that is based off how many stages per day we think we're going to do. So right now, it's fixed on a per stage rate. The more that we can do per day, the better.

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Michael Hall, Heikkinen Energy - Analyst [59]

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Can you disclose what that cost per stage is currently fixed at?

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Matt Owens, Extraction Oil & Gas Inc - President [60]

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Not right now, but it's very competitive.

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Michael Hall, Heikkinen Energy - Analyst [61]

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Okay, fair enough. Then I wanted to also understand or just talk about -- obviously we've had a bit of a wiggle, to say the least, in oil prices recently. Can you talk about the sensitivity of more so 17, your 2018 plan around prices?

I know what you are drilling this year is really what informs the completions in 2018. So it would seem that you are pretty well set, but just any additional commentary around your activity profile sensitivity to pricing?

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Rusty Kelley, Extraction Oil & Gas Inc - CFO [62]

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This is Rusty. So part of the reason why we are probably more stable on that area is we typically we start hedging as we start spending capital in most of our larger projects. Which because we have the bigger pads and larger leadtimes, we've been aggressive, as you can see, in our investor presentation on the hedge profiles that we put on a lot of this stuff.

So while we are certainly going to be looking at our balance sheet strength as the guide, we look at two different things. One is our net debt to EBITDA levels, and the other is the liquidity. Obviously, right now, liquidity is not a gating factor.

We have a substantial net debt-to-EBITDA is probably a little bit more sensitive just to what happens in the commodity price. But we try to stay within a range, a near-term run rate of 1 to 1.5 times net debt-to-EBITDA. Obviously if commodity prices pull back substantially, we maintain the flexibility to reduce our activity level.

Having said that, we would likely continue to move forward with the projects that are currently under way, which would get well into 2018. So our 2018 program right now, it's probably not at risk substantially, just given the hedge profile, the balance sheet and the fact that we are already moving on that.

But we obviously reserve the right to do what's -- to protect the balance sheet in the event that commodity prices do take a significant negative downturn. But I would see that affecting the back half of 2018 if you saw a substantial decline.

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [63]

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And we've continued our previous practices of not locking in long-term service contracts.

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Michael Hall, Heikkinen Energy - Analyst [64]

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Got it. So is there price threshold today that would impact the activity or investment programs for 2017 which would impact 2018? If I think about that right.

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Matt Owens, Extraction Oil & Gas Inc - President [65]

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I would just say more, in general, that we've always looked at $40 oil and up as being our sweet spot. And while we've got a lot of economic inventory below $40 a barrel, you have to really look at do you really want to be accelerating in that type of an environment. When you run the math, it pretty quickly shows you that the balance sheet becomes the driver and when you get below $40 that's your signal to start pulling at your horns.

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Michael Hall, Heikkinen Energy - Analyst [66]

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Very good. Appreciate the color, guys. Thanks.

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Matt Owens, Extraction Oil & Gas Inc - President [67]

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Thanks.

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Rusty Kelley, Extraction Oil & Gas Inc - CFO [68]

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Thanks.

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Operator [69]

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John Nelson with Goldman Sachs.

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John Nelson, Goldman Sachs - Analyst [70]

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Good morning and congratulations to Louis for joining the team. At the midpoint in your 1Q production guidance, I think you are suggesting you're pointing to about a 41% oil mix.

I know you guys gave some comments about how we see a pretty big production ramp in 2Q and 3Q. I was just hoping if you could similarly give us some color or thoughts on how we should be thinking about the trajectory of oil mix to get to your full-year 46% to 50% guidance.

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [71]

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Our guidance guides to an oil mix in the range of 47%, 46%, 48%. And that largely comes from -- even though we are lower right now, obviously we are going to increase above that in the back half of the year when we're bringing on new wells. When you look at the production on these wells, when they come on, they are going to be well north of 60% and in some cases, approaching 80% in the lower GOR areas of your oil rates initially.

Then they taper off over time with your GOR increases over the course of the first 12 months, and then stabilizes and you run the well out. But even so, the decline curves are slightly different. So your gas curves tend to have a little bit more flattening quicker.

But we focus on what our oil rates are, and consistently we've met our targeted oil production rates that we've been forecasting. And if we end up producing more gas or seeing a higher GOR, it typically has just been that we are exceeding our gas volumes by more than we are exceeding our oil volumes.

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Matt Owens, Extraction Oil & Gas Inc - President [72]

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John, I think what Mark said, with your specific to your question on how do you get to our guidance, we are reaffirming our guidance, including our oil percentage. We've also broken out the absolute oil, just to make sure that in the event that we outperform on gas even more and have a higher GOR, we are giving guidance on oil itself.

With regard to driving the oil, as Mark said, it's the new wells that are coming on in the Windsor area which is a low GOR area. They are newer, which means as higher oil cut and they're in the low GOR area, meaning there's a much higher oil cut. So that's really what's driving getting back to the levels we forecasted for 2017, and we are reaffirming that guidance.

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John Nelson, Goldman Sachs - Analyst [73]

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That's really helpful. And if I can just follow up, fair to say then because some of the wells that would have been shut in over the course of 1Q for those completions, we should start to see that mix back within that full-year range by 2Q?

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Matt Owens, Extraction Oil & Gas Inc - President [74]

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Yes, I would say that's true, especially as all the new wells that need come online that are right offset those wells that were shut in.

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John Nelson, Goldman Sachs - Analyst [75]

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Great, that's helpful. Then as a second question, I've seen the 10-K. You all took some additional I think NAT gas processing NBCs starting in late 2018. I was just wondering if you could speak to how you see spare mixture and capacity in the basin between now and late 2018?

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [76]

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All the producers in the basin, along with DCP actually put their creative hat on and sat down before the end of last year and looking at putting together everybody's forecast. The result of that showed that plant capacity was going to become constrained late in 2017, early in 2018. When you look at the constraint, the earliest impact is going to be on people that have vertical production.

The vertical wells out here make probably in the neighborhood of 120 million maybe 150 million a day, so that becomes the incremental capacity for the horizontal wells. Steps that we're taking to address this are, number one, our new horizontal wells should not be as impacted by the higher line pressures that materially impact vertical wells, which typically shut in at about 225 PSI line pressure. We are moving proactively ahead on some of our more mature pads with the installation of compression.

DCP has taken some steps. They are finishing out the Grand Parkway gathering system, they are installing incremental compression as well as putting in incremental bypass capacity at Lucerne. So all those things for that decline in vertical production, additional capacities, along with having newer wells should address our needs through the time period that new plant capacity will come online.

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John Nelson, Goldman Sachs - Analyst [77]

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That's really helpful. And what percentage of total production now or for 2017 do you think will be vertical for Extraction?

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [78]

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We only have about 1,500 barrels a day or less of vertical production. It's not a big part of our portfolio.

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Matt Owens, Extraction Oil & Gas Inc - President [79]

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Of which about half is in our southern area, which is taken by Western Gas, which is not an area that we see constraints in. So even that number is cut in half for what would be put at risk.

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [80]

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We're pleased with the steps that DCP has taken and the industry cooperation in putting together the plan for up to an additional 400 million a day of processing capacity out here in the basin. And appreciate also that because it still is relatively new horizontal production in the basin or the production profile is dominated by new wells, the basin gas production is still probably on a base decline I would say of 30% up to 40%. So before we do anything, we have to offset that base decline.

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John Nelson, Goldman Sachs - Analyst [81]

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That's really helpful. Thanks again. I will let somebody else hop in.

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Operator [82]

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Jeanine Wai with Citigroup.

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Jeanine Wai, Citigroup - Analyst [83]

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Just to get back to the Q1 guide, in terms of what you provided last night, we are sitting here in the middle of March right row. And in your prepared comments, I think I wrote down that you said it was consistent with your plan and stated 2017 guidance.

So I just wanted to clarify whether that means that the Q1 2017 guide is actually trued up for a year-to-date performance and is just in line with your previous projections? Or is it as it stood in December prior to you seeing some of these new and enhanced [levels] up?

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Rusty Kelley, Extraction Oil & Gas Inc - CFO [84]

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Thanks, Jeanine, this is Rusty. That's a great clarification. It is in line with what we forecasted internally back in December. Nothing has changed on our 2017 guidance.

We are not truing up for any over or under performance. We are right on track, and that's a big thesis of the call today is we are on schedule with the turn online date that we gave back in December. We are on schedule with bringing on pads, and the performance and everything that we are seeing so far is in line, on track.

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Jeanine Wai, Citigroup - Analyst [85]

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Okay, great. thanks, that's really helpful. Then following up on a prior question, and fully understanding that it's too early for you to give numbers, we heard you say that.

Can you just give us a feel for how the completions that you are seeing right now are performing relative to say the initial Windsor test on that graph that you have in your presentation? And when do you think you'll be able to update us on actual results?

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [86]

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From a timing standpoint, I will have Matt talk to the curve that we've used for our enhanced completion. And if you want a little more detail on how that was derived, we currently aren't changing that right now. But looking at timing of results, by the end of Q1 when we are coming out with our Q1 results, that's going to give us another 45, 60 days worth of production.

Obviously in the early stages of a well, that's an important period from getting data points that engineers love to have before they stick their neck out there and start giving forecasts. We've also always said with the enhanced completions that we tend to choke our wells back a lot in the early stages. So we said it's going to take us a good 90 days at least before we start seeing the impact of the enhanced completions.

We look for a modest 10% to 15% increase in the IP, but what we're trying to do is change and flatten the tail end of the curve. So starting after about three months of production is when we expect to start seeing that.

Obviously, we could open these things up and let them rip and we could give you any number you wanted. But what this is all about is really it's about changing the shape of the curve and the long-term performance of the wells. That's where the real value is going to be created.

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Jeanine Wai, Citigroup - Analyst [87]

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Okay, great. Thank you for taking my call.

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [88]

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Thank you.

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Operator [89]

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Thank you, and I'm showing no further questions at this time. I would now like to turn in the call back to Mark Erickson, Chairman and Chief Executive Officer, for closing remarks.

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Mark Erickson, Extraction Oil & Gas Inc - Chairman & CEO [90]

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Thank you, everyone, for attending our call, and again welcome to Louis on board. He's available for calls in the future when you're looking to track somebody down.

And if he needs to, he will track down Rusty or I or Matt and get us all in touch together. If you have any additional questions we couldn't address today in the call, please feel free to reach out to Louis and we will get those addressed right away. Thank you.

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Operator [91]

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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 great day.