Louis Baltimore - Director of Investor Relations Mark Erickson - Chairman and Chief Executive Officer Rusty Kelley - Chief Financial Officer Matthew Owens - Co-Founder and President Tom Brock - Chief Accounting Officer Eric Jacobsen - Senior Vice President of Operations.

Kyle Rhodes - RBC Capital Markets David Cameron - Wells Fargo Securities Deckelbaum - KeyBanc Capital Markets Neil Dingmann - SunTrust Robinson Humphrey Ben Wyatt - Stephens Inc. Michael Hall - Heikkinen Energy John Nelson - Goldman Sachs Jeanine Wai - Citigroup.

Good morning. I'm 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. All lines have been place on mute to prevent any background noise. [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 new release issued yesterday in its filing 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 that 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..

Thank you, and good morning, everyone. I'm 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, our Chief Accounting Officer; and Eric Jacobsen, our SVP of Operations.

I would like to remind everybody today's call that, 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 statement and GAAP reconciliations in our earnings release and in our filing on Form 10-K, which we provided yesterday after the public trade. I'll now turn the call over to Mark Erickson, our CEO, to go through some of the highlights for the quarter and full-year..

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 will 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 have zero net debt and approximately 1.1 billion of liquidity. Operationally, our drilling and completion operations are on schedule.

Production exceed 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 acquisition adding roughly 23,000 net acres, bringing our total core DJ basin and net acreage to 116,000 acres.

Turning our focus to what is 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 continue to operational success, we will have strong momentum taking us into 2018. We are 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 winter time operations, while implementing this important transition to enhance completion.

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 flow back rates and pressures.

Our efforts in Broomfield continue to gain momentum and we expect to have permits before year-end.

In our [Grower] (Ph) 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 formation and complete them utilizing and 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 and Bayswater mutually agreed to terminate the option purchase agreement.

The option feature 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 opportunity. 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..

Thanks, Mark. I would 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 fully undrawn borrowing base of $475 million resulting in approximately $1.1 billion of available liquidity.

As if 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 the visible cash flow stream to maintain our rapid pace of operation without the need to further lean on our balance sheet.

And 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 is 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 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. Now turning to the fourth quarter financial results.

Adjusted EBITDAX un-hedged 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 unheeded was $164 million up 39% over 2015. Given the current forward strip in our attracted hedge book we are optimistic about our EBITDAX gross profile continue going forward.

We did see nice positive EBITDAX contribution from our hedges in the amount of $34 million during 2016. Before I turn the call over to Matt, I would 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 the function as the total number of producing wells rather than as a function of volumes.

So overtime as we turn on more new wells to sales we are going to expect to see that per unit LOEs come down. Conversely during first quarter when we forecast the 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 inline the wells associated with our large ongoing completion program and grow our volumes through the back half of 2017, we expect to see that per unit LOE significantly declined 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 is been associated with the increased headcount and related expenses as we ramp up our organization to effectively run the public Company. The majority of these expenses are largely independent of our production volume.

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'll turn it over to our President Matt Owens to cover our operational highlights..

Thanks Rusty. Before we get into the success we have been achieving on the admiration side, I would 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 months moratorium on processing applications for oil and gas permits.

This moratorium and 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 of 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, nine were completed using our latest Enhanced Completion design. Our operational efficiencies also continue to improve.

While we set Company drilling records during the fourth quarter, we recently spend a new Company record with a spud to total depth time of just 3.4 days or 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 falling back now and we are encouraged with what we have 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 for 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 will also like to once again thank our equity and debt holders for their continued support of Extraction’s effort to build a premier DJ Basin Company. This includes management’s prepared remarks. Operator, I would now like to open up the call for the Q&A session..

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

Hey. Good morning, guys. I understand it’s early.

But are there any early rating to kind of share on the encouraging results, you have got through enhanced completions referenced in the release?.

Hey Kyle. Right now, I mean we are in the very early flow back stage. If you look at what we kind of guided to is that these pads would all be starting to come online towards again of Q1. We feel like, we are on schedule, slightly ahead of schedule. But given it’s still a flow back period, we just aren’t comfortable sharing rates at this point in time.

But when we talk about being encouraged, these wells are looking very strong..

Okay, great. That’s helpful. I guess it seems offsetting completions had a decent impact on the first quarter of 2017 guide.

Have some of those shut-ins been restored at this point in time and is there are current production number, you guys can give?.

Right now there is 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 production. Those three wells are making about 150 to 200 a barrel a day when we shut them it and there are about 90% working interest..

Got it.

Any sense of kind of current production numbers you guys can give?.

I would just look at when you are looking at the Q1 guidance we have always looked at Q1 is kind been right ahead of the big increase that we are going to see going into second quarter. And so from our standpoint, we are I would say at the high end of what we guided to for the average of the quarter..

Got it that's helpful.

And if I could think one more in just on the Bayswater lease option termination, how much of that efficiently related to the oil price pull back and maybe how much of that decision is related to better lease hold opportunities you guys are seeing on the ground?.

We like the Bayswater asset it's just that part of the overfunding was for Bayswater or something like it or better than it. We have had good success in both the non-acreage and 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 that we are seeing..

Got it I will hop back in queue thanks guys..

Thanks..

Thank you. And our next question comes from the line of David Cameron with Wells Fargo. Your line is now open..

Good morning, Matt can you talk or Mark or whomever can you talk about the offsetting shut ins. If you are using if you kind a gone this block completion of block frac whatever you want to call the development mode type style.

Should we see less of that going forward?.

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 happen to three older wells that were already drilled off at this pad. So going forward we should have a lot less shut-ins due to offset completion activity..

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

Okay.

And currently what is your current completion, I guess I'm just thinking about the Enhanced Completion like is there upside your current numbers as far as is there upside you are going to try something bigger than what you just done on Enhanced Completion and what do you think the target development completion looks like going forward over the next two or three quarters?.

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

Okay and then just primarily more profit at this point, are you doing anything else on the completion side..

Primarily it's propane in the Niobrara and we have also experimented with the some different fluid volumes as well. so all of those different tests will be coming online once this entire Windsor block comes online..

We would appreciate that even the pumped the larger propane jobs require additional fluid..

Okay, yes, that makes sense. And then 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, how much of that regulatory hurdle to hit theses 2017 and 2018 production numbers?.

So on the regulatory hurdles, we are really pleased with the progress we have made as Matt alluded to in Broomfield, we are working cooperatively with the city leaders of Broomfield and the community there and we do expect to have permits by the end of the year as Matt alluded to.

Regarding your question on Boulder, I think we will work with parallel path cooperatively and Boulder some as we have done already in addition to waiting to see how the lawsuit in the state of Colorado flushes out.

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

Okay. I appreciate the color. Thanks..

Thank you. And our next question comes from the line of David Deckelbaum with KeyBanc. Your line is now open..

Good morning, guys. Thanks for taking my question. Just wanted to follow-up, I guess on one of the David’s question. The Broomfield permits you guys are planning or having in hand in 2018. I guess as you think about that 75% growth rate target for 2018.

Do you have sort of an alternative plan out there if the permitting takes too long? Are you going to be sort of simultaneously permitting sort of more like Windsor area or other areas that if you needed to that would be part of your 2018 plan as oppose to Broomfield?.

Our current goal is to have two years worth of permits in front of us at all time. But I appreciate, when you look at our guidance as well that we are going to exit the year with about 131.9 mile wells. So we are going to have a very robust inventory of wells in progress just entering into 2018.

Similar to this year, those are going to be the main drivers of our high growth in 2018..

I appreciate that.

So sounds like a lot of the tie-in levels are actually going to be somewhat similar to 2017 and 2018 sort of longer lateral advantage?.

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

Okay. And the current plan right now, I guess Matt is still to have Enhanced Completion on the remaining tie-ins this year or remaining completion this year. I know you have nine that we are in this first batch of wells.

We see like sort of the more legacy designs now are behind us in that first batch?.

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

But for the most part of plan right is to do some standard completion design. In the lower GOR areas like such as over by Windsor, we are going to continue to using the enhanced designs on the Niobrara's and we are also experiment with the few enhanced designs on the Codells as well..

That's helpful. The last one from me, I guess you have kind of - I guess you are flowing back some of the oil on some of these Enhanced Completion jobs.

But could you contrast maybe the cycle times that you have observed and the initial Enhanced Completion pads versus sort of legacy completions that you did in Windsor in 2016?.

When you it's cycle time are you referring to the times….

I guess I’m thinking like spud to sales or spud to [indiscernible] or completion time or however you think about communicating it?.

So on the block as a whole if you look from when we started drilling it trying to get 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 rig running, so it would go a lot faster in the future as far as the drilling time goes.

But for the completions, we are still averaging right as what we put in our guidance at 12 stages per day and we have got a lot of days that we have had recently where we have gotten up to 19 stages per day.

So we are 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..

And I guess in terms of the AFEs that you had set out you have factored in like a 20% increase in well cost, is that pretty much in line with what you have been seeing days early days here?.

Yes we have had a little bit increased cost just due to winter time 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 cost much higher than what our original AFPs were unless we see price inflation..

Okay thanks guys..

Thank you..

Thank you. And our next question comes from the line of Neil Dingmann with Suntrust. Your line is now open..

Good morning guys. Just two questions Mark for you or any guys there. One just looking into the prior slides for three rigs kind a turned full-time rigs.

Once that larger as you said padding in separate done, do you anticipate the rigs kind a stay in that where they are now I mean their outlook like to be in that sort of Southern [Lamar] (Ph) area maybe just an idea of where the most activity we will be seeing in the second half of this year?.

We are drilling a large pad in [Raleigh] (Ph) right now that will be our big pad that comes on for us in the second half of the year.

We are drilling some other wells kind of North East of Windsor and then down in that Southern Lamar area that I just mentioned will be another big couple pads that we will be developing simultaneously with multiple rigs..

Got it and then just one last one on, we have heard others talk about the earnings season locking cost and some say they can do it for the rest of this year as far as whether that's on the drilling side of your lock-in rigs or on the completion side.

How do you all view this on either drilling or the completion side, or do you view this sort of think about doing this?.

Our cost haven't completed too much. We typically always paid a little bit more per day , because we like to outfit the rigs at certain way allow us to drill as fast as we do. But we haven't seen much inflation there with the new rigs that we have 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 something that would be pass-through jobs if that does occur.

We are actively searching for alternative sources or different sizes to offset any increases that might happen with one sort of profit such as [40/70] (Ph). 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 should be, would the any material pass-through..

Sounds good. Thanks guys..

Thank you..

Thank you. And our next question comes from the line of Ben Wyatt with Stephens. Your line is now open..

Hey. Good morning, guys. Wanted to see if we could go a little deeper on the acquisition front. I know you guys have obviously terminated the Bayswater, 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..

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 we will have a higher working interest in them. We are actively permitted in the area.

And then additionally, we are in an around at finding some larger blocks that we are able to put together that we can allow for longer laterals and more operated wells that we will be able to add-on to what we are deliver right now. We actually very pleased with how the leasing effort has been going in the area..

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.

But 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..

Yes. The way that we view it, there is a lot of different alternatives. 40/70 is a high commodity in the sand market right now. We actually switched to using that property back in 2014 with everybody else was using 20/40. We couldn’t get 20/40 and which switched to 40/70, because it was in more supply for us and also it was a lower costs.

Right now everybody switching back that way. We already made changes on our Codell wells to a different sand size, that again is not being used as much of our peers and is in more supply and is also coming at a cheaper costs in the 40/70. And we are continuing to evaluate other sizes to switch the Niobrara wells to do.

Any event that the 40/70 right sand does increase the price or become harder to get our hands on..

Very good guys. I appreciate the time. Thanks..

Thanks..

Thank you. And our next question comes from the line of Michael Hall with Heikkinen Energy. Your line is now open..

Thanks good morning. I guess 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 to 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 is that provide a markup today on your wells or is your current contract term of that at current spot price for instance..

Our contract on the completion side is based differently than a lot of other companies. We work closely with our completion provider and we really go off following in that we are able to pump.

And since we switched to these enhanced completions we have been averaging anywhere between 5.5 million to 7.5 million tons 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 and volume wise the lower they have to charge us for the horsepower.

So we will revisit that again 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 by inflation to the horsepower charge..

Okay.

And does that is that horsepower charge like a basically paying a day rate for the horsepower as a first stage how as we think about that?.

It's a per stage cost that's kind a based off of how many stages per day that I think we are going to do. So right now it just fits on a first stage rate for more than [indiscernible]..

And can you disclose what that cost per stage is currently fixed at?.

Not right now, but it's very competitive..

Okay fair enough. And then I guess I wanted to also understand or just talk about obviously we had a bit of a over [indiscernible] lease and oil prices recently.

Can you kind a talk about the sensitivity of I guess more or so 2017 your 2018 plan around prices, I know what you are drilling this year is really what informs the completion in 2018? It would seem that you are pretty well set, but just any additional commentary around your activity profile sensitivity to price?.

Sure this is Rusty so part of the reason why we are probably more stable on that area just we typically saw hedging as we start spending capital in most of our larger projects.

Because we have these bigger pads and larger kind a lead time, we have been aggressive as you can see in our investor presentation on the hedge profile that we put on the lot of the stuff.

So while we are certainly going to be looking at our balance sheet strength as kind of 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 gaiting factor, if we have a substantial net debt-to-EBITDA is probably a little bit more sensitive just to what happens in the commodity price. We try to stay within a range kind of a near-term run-rate of 1 to 1.5 times net debt-to-EBITDA.

Obviously if commodity prices pull back substantially, we could we maintain the flexibility to reduce our activity levels. Having said that, we would likely continue to move forward with the products that are currently under way, which would get well into 2018.

So our 2018 program right now is probably not at risk substantially, just given the hedge profile of the balance sheet and the fact that we are already moving on that. But we obviously reserve the right to do what is, 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..

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

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..

I would just say more in general. But we have always looked at $40 of oil and up as being our sweet spot. And while we have done a lot of economic inventory below $40 a barrel, you have to really look at.

Do you really want to be kind of accelerating in that type of an environment? When you run the math, it pretty quickly shows you the balance sheet becomes the driver and that’s when you get below $40 that’s your signal to start pulling into more..

Very good. I appreciate the color, guys. Thanks..

Thanks..

Thank you. And our next question comes from the line of John Nelson with Goldman Sachs. Your line is now open..

Good morning and congratulations to Louis for joining the team. At the midpoint in your 1Q production guidance, I think you are suggesting or 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.

So 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..

Our guidance guides to an oil mix in the range of 46%, 48%. And that largely comes from even though were lower right now, obviously we are going to increase above that in the back half of the year when we are bringing on new wells.

When you look at the production on these wells, 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.

And then they taper off overtime with your GOR kind of increases over the course for the first 12 months and then stabilizes any kind of run the well, but even so, the decline curves are slightly different. So your gas curves tend to have a little bit more flattening quicker.

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

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

With regard to driving the oil as Mark said, it’s the new wells that are coming on and the Windsor area which is a low GOR area, they are newer which means a higher oil cut and they are in a low GOR area meaning there is a much higher oil cut.

And so that's really what is driving getting back to the levels we forecast for 2017 and we are reaffirming that guidance..

That's really helpful and I guess to follow-up - it’s fair to say them because some of the wells would have been shut in over the course of 1Q for those completion which is start to see that mix back within that full-year range by 2Q?.

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

Okay. That's helpful and then as a second question see in the 10-K took some additional I think net gas processing and NBCs as starting in late 2018. I just wondering if you could speak to how you see there some midstream capacity in the basin between turn down and in late 2018..

All the producers at the basin along with DCP, actually what they are creative pad on that down before the end of last year. And looking at put together everybody's forecast, and the result of that show that plant capacity was going to become constraint late in 2017 early in 2018.

When you look at that constraint that the earliest impact is going to be on people that have vertical production. The vertical wells out there may probably in the neighborhood of 120 million to 150 million a day so that becomes the incremental capacity for the horizontal wells.

Steps that we are 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 is typically shut-in at about 225 [indiscernible]. We are moving proactively ahead on some of our more mature pads with the installation and compression.

DCP has taken some steps, they are finishing out their Grant Parkways gathering system they are installing incremental compression as well as putting in incremental bypass capacity there.

so all those things the 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..

That's really helpful.

And just what percentage of total production now or for 2017 do you think will be vertical for the section?.

We only have about 1500 barrels a day or less the vertical production. It's not a big part of our portfolio..

Of which about half is in the our Southern area which is taken by Western Gas which is not in area that we see constraints in show even that's numbers cut of half of what we put at risk..

Right, we are pleased with the steps that DCP has taken and 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 I appreciate also that just because it's still is relatively new horizontal production in the basin or the production profile is dominated by new wells, even the basin gas production is still probably on a base decline I would say 30% up to 40%. So before we do anything we have to offset that base decline..

That's really helpful. Thanks again, I’ll let somebody else hope in..

Thank you. And our next question comes from the line of Jeanine Wai with Citigroup. Your line is now open..

Hi good morning everyone. comes from the line of Jeanine Wai with Citigroup. Your line is now open..

Hi. Good morning, everyone. 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 back in December prior to you seeing some of these new and enhanced levels up?.

Thanks Jeanine, this is Rusty Kelley. It’s a great clarification. It is in line with what we have forecasted internally back in December. Nothing is changed on our 2017 guidance, we are not kind of truing up for any over underperformance, we are right on track.

And that’s a big thesis of today’s call today is we are on schedule with the turn online data that we gave back in December. We are on schedule with bringing on pads and performance and everything that we are seeing so far is kind of in line on track..

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 will be able to update us on actual results?.

From a timing standpoint, but I will have Matt talk to the curve that we have used for our enhanced completion if you want a little more detail on how that was derived, we aren’t currently changing that right now.

But looking at timing of results, by the end of Q1, but we are coming out of our Q1 results that’s going to give us another 45, 60 days worth of production. Obviously in the early stages of well, that’s an important period from getting data points, but engineers love to have before they stick their neck out there and start given forecast.

We have also always said with the Enhanced Completions. But we tend to choke our wells back a lot in the early stages. So we have said, it’s going to take us a good 90-days at least before we start to see in the impact of the Enhanced Completion.

But we look for a modest 10% to 15% increased in the IP, but what we are trying to do is change and flatten the tail end of the curve. So starting after above three months of production is when we expect start to seeing that. Obviously, we did 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 for the wells. That’s where the real value is going to be created..

Okay, great. Thank you for taking my call..

Thank you..

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

Thank you everyone for attending our call and again welcome Louis on Board. He is available for calls in the future when you are 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.

And 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 by the way. Thank you..

Ladies and gentlemen thank you for participating in today's conference. This does conclude the program. And you may all disconnect. Every have a great day..