Civitas Resources Inc (CIVI) 2013 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first quarter 2013 Bonanza Creek Energy earnings conference call. My name is Lisa, and I will be the coordinator for today.

(Operator Instructions)

I would like to turn the conference over to your host, Mr. James Masters, Investment Relations Manager. Please proceed.

Thanks, Lisa. Good morning, everyone, and welcome to Bonanza Creek's first quarter 2013 earnings call and webcast. Yesterday afternoon we issued our earnings press release and filed our 10-Q with the SEC this morning. You can access both on our website at www.bonanzacrk.com. On today's call, Mike Starzer, President and CEO, will discuss the highlights for the quarter and Gary Grove, Executive Vice President, Engineering and Planning, will report results from operations. Other members of Management will be available during the Q&A portion at the end of the call.

I want to remind everyone that today's remarks will include forward-looking statements that are based on our current views and most reasonable expectations, but are subject to many risks and uncertainties that could cause actually results to differ materially. You should read our full disclosure as described in our 10-Q and other SEC filings which you can access through our website or the SEC's website. Also during this call, we will refer to non-GAAP financial measures because we believe they are good metrics to use in evaluating performance. Reconciliations of these measures to the most directly comparable GAAP measures are contained in our earnings releases. Also, all results discussed today reflect continuing operations, not counting the results from the remaining California property. With that, it's my pleasure to turn the call over to Mike.

Thank you, James. Good morning, everyone, and thank you for joining us today. We are pleased with the performance achieved this quarter while placing only seven horizontal wells into sales in the period, with four of those occurring in late March. Production for the quarter was as expected, and I think we are primed to have a really terrific year. We confirmed our annual guidance and look forward to accelerating activity leading to significant sales growth over the coming quarter.

Let me briefly explain our philosophy for managing growth. First of all, Bonanza Creek aims to be among the highest growth of our peers, and we laid out what I think to be a compelling case for organic growth in our Analyst Day presentation April 11. Second, and fundamentally important is that we maintain the strength and flexibility of our operating and financial structure. To that end, in January we expanded our shareholder base placing 13 million secondary shares on behalf of West Face Capital, significantly increasing the public float.

And then last month we completed our inaugural high yield bond offering, upsizing to $300 million and pricing with a 6.75% coupon, ensuring that we have ample liquidity to aggressively develop the tremendous assets we have in the portfolio. During our Analyst and Investor Day, we outlined a road map for peer leading growth over the next five years. Overall, actual results are meeting expectations. Our 3P reserve analysis with risked EUR assumptions shows tremendous growth potential through down spacing and additional zones, and we have a balance sheet and liquidity to execute on our strategy.

So, let's get to the results for the quarter. Sales volumes from continuing operations were 12,307 BOE per day, a 78% increase over the quarter a year ago, with a strong crude oil and liquids mix of 72%. The Rocky Mountain region continues to grow as a percentage of our Company production, increasing to 58% of total Company sales driven by our horizontal development program which accounts for nearly 80% of our Rocky Mountain region production. This is important as we enter into the summer months and the projected impact of high line pressures is once again felt across the Basin. We feel confident that with such a high mix of our production coming from horizontal wells, high line pressures will not be a material problem for us. I will let Gary get into the operational details in the Wattenberg Field, but overall, the horizontal program continues to impress.

Revenues increased 64% from a year ago to $78.3 million, supported by a strong crude production and pricing of $90.56 per barrel during the quarter. We also received $4.56 -- excuse me, $4.65 per MCF for natural gas and $53.40 per barrel for NGLs. Adjusted net income from continuing operations for the quarter increased 47% to $16.2 million, or $0.40 per share. Excluded from adjusted net income were unrealized losses from commodity hedges and stock based compensation expense. We achieves a 66% year-over-year increase in adjusted EBITDAX to $52.3 million thanks to continued strong per unit margins of 68%, or $47.07 per BOE on our increasing volumes.

Finally, subsequent to the end of the quarter, we completed the previously mentioned high yield debt issue which materially increased our liquidity position and introduced the Company to another deep capital market from which to periodically fund future growth. Pro-forma for the high yield and concurrent reduction of our borrowing base, we have over $300 million in total liquidity. We expect that our spring borrowing base redetermination currently underway will result in a modest increase to available borrowings.

Looking forward, we are on track operationally. We expect to drill 72 gross operated wells in the Wattenberg Field this year, including additional testing of the Niobrara C Bench in Codell, along with extended reach laterals and down spacing of the Niobrara B Bench. During the second quarter, we expect to drill three Niobrara C Bench wells and continue our 40-acre spacing Niobrara B Bench tests. Additionally, we recently added a fourth rig in Colorado and are targeting approximately eight frac jobs per month by the end of the second quarter. In closing, the first quarter was right in line with our expectations, and I think with the low average leverage on our balance sheet and ample liquidity, we are primed to deliver an excellent year for our shareholders. Now, I will turn the call over to Gary who will dive into more detail surrounding the operational activities.

Thanks, Mike. Much of the quarter's highlights were already covered in our Analyst Day in April, but we are in such a prolific area in the Wattenberg Field, it seems like something new is happening all the time. As Mike mentioned earlier, we produced 12,307 BOE during the day during the quarter, not including the small amount of remaining production from the Midway Sunset Field in California, which is in the process of being sold.

Production from the Rocky Mountain region was 7,164 BOE per day. We spudded 18 horizontal wells and put 7 wells on production. Two of the seven wells were drilled in 2012 while the remaining five were placed in production later in the quarter as a result of our 2013 drilling program. Volumes were negatively impacted by approximately 500 BOE per day from wells offline due to fracture stimulation of nearby horizontal wells. The nearby well impacts were expected, and the effects of this loss production are factored into the annual guidance.

By the end of the quarter, we had ramped up to four horizontal rigs and were averaging drilling times of 13 days spud to spud, which will result in a rate of approximately eight horizontal wells being drilled per month. Our catalyst well program continues to achieve very attractive results, demonstrating that we are still only in the early innings of Bonanza Creek's development protein. In the Codell, our first well was tracking a 313,000 BOE EUR, which is similar to the Niobrara B Bench wells. Our 90-day average producing rate of 335 BOE per day is 91% of the average 30-day producing rate. So, we are very pleased with what we are seeing from the formation.

In April, we drilled and completed the first of four planned Codell wells scheduled for 2013 and has just started to cut oil in the initial flowback period. Our initial Niobrara C Bench well also continues to hold in strong from its 30-day producing rate of 440 BOE -- 444, excuse me, BOE per day. The 60-day average producing rate of 383 BOE per day is consistent with the declines we've seen in the Niobrara B Bench. We plan to spud three Niobrara C Bench wells in the second quarter and look forward to reporting those results as well.

The Niobrara B bench extended reach lateral program continued in April with our second successful well and incorporated a number of key lessons from the first well we drilled late last year that resulting in setting 1,000 feet of liner less than we had planned. That first well produced 795 BOE per day in the first 30 producing days and averaged 680 BOE per day for the first 60 producing days. In the second well, we drilled and successfully placed a liner in the full 9,449-foot lateral section. The well was fractured stimulated using 40 frac stages the end of April, and operations are in progress to put the well on production. We expect to drill one more extended reach lateral during 2013 in the third quarter. Finally, we are excited about our 40-acre spaced well in the Niobrara B Bench.

We drilled and completed the first two test wells in the first quarter and are currently drilling a third of a planned six wells in 2013. The true 40-acre well, the one in the middle, if you will, has been flowing back for approximately 30 total days, but we are not really yet to call an IP on that well. I can say we are very encouraged by the response seen so far and are gaining increasing confidence in the 40-acre Niobrara B Bench inventory assumptions based on the data from our wells and our industry neighbors. Also in the Rockies, we recently signed a water source agreement in Weld County that not only secures the majority of the water needs for the rest of the year, but will result in a significant per-well cost savings. Water availability is one of the key components to our development, and I am proud of our team for securing such a positive arrangement for the Company.

Turning to the Mid-Continent region, production averaged 5,143 BOE per day. Our 2013 vertical Cotton Valley development is proceeding with 13 wells spud and 10 wells put on production during the quarter. In addition, we recompleted 26 wells during the quarter and are seeing rates come in above forecast for these highly economic Cotton Valley pay additions. Turning to our catalyst opportunities in the region, we fracture stimulated three five-acre infill wells in January that we had drilled in 2012. All three had pressure test data which indicated that more than 80% of the intervals tested had near original reservoir pressure. This is very encouraging as our down spacing testing program is looking specifically to determine if we are encountering undepleted or under depleted sands.

In addition, the average 60-day producing rate of 61 BOE per day exceeded our forecast which was based on our risk forecast of our 10-acre wells. The next step in evaluation of these wells will be the first planned Cotton Valley pay additions which are scheduled for the second quarter. We will continue to monitor these wells and their offsets for any signs of interference that would affect the infill program. But so far, we are encouraged by what we are seeing and the implications on the upside inventory in our Cotton Valley assets. Three additional five-acre test wells are scheduled to be completed during the second quarter of this year. We also brought online our latest expansion of the gas processing facilities during the quarter. This new addition added 12.5 million cubic feet per day of capacity to our gas processing infrastructure.

Moving over to expenses, LOE was in line but slightly higher than expected for the quarter due to the freezing conditions experienced in the Wattenberg Field. As we bring on significantly more volumes over the coming quarters, we will continue to see our per unit LOE decline. We remain focused on controlling costs. Cash, general and administrative costs were in line with expectations. We have continued to add to our employee base as we develop our large proved and unproven upside. As additional volumes come online during the year, our per unit GA costs will also continue to decrease.

Regarding the production guidance for the year, as Mike mentioned, we are in line and tracking our expectations of 14,500 to 16,000 BOE per day. As we have mentioned, our production for the year is back end loaded, and we look forward to the strongest production coming in the third quarter and fourth quarters of the year. In summary, Bonanza Creek continues to execute and hit our targets. We are at another inflexion point in our growth and have strong confidence in our ability to deliver. As we see it, the risk in the Wattenberg continues to drop while the potential continues to rise. It is a unique opportunity, and we are poised to take advantage of it. With that, I would like to turn the call back over to Lisa and open the call for questions.

(Operator Instructions)

Your first question comes the line of Irene Haas with Wunderlich Securities. Proceed.

Yes, hi. I would like to go into your extended lateral a little bit. If you can let us know what is the difference between your first well and second well and what you have learned. And since Bonanza Creek has some very interesting acreage that is very, very contiguous, in the long-run, how do you see these long lateral kind of play into your overall scheme of development?

Well, good morning, Irene. Gary, if you wanted to chime in on that since you looked at the extended reach very laterals closely.

Irene, we had, some of the things we did differently, if I heard your question correctly was, what are we -- what did we do differently on the second one and how did that work a little bit differently for us? We just changed a little bit of the operations to make sure we could get the liner to the bottom of the hole, quite frankly, added a little bit of weight and changed the lubricant we were using to push the liner towards the bottom. That al went really, really well.

As far as the acreage and what we see and that is available for extended reach, we are real excited about this opportunity as we go forward. Overall, we think the efficiencies that we can see from drilling longer, obviously from one well rather than using two well bores to intersect the two areas, that's something that we definitely have talked about plans for going forward. I think we mentioned that we would like to see a little more information coming from not only ourselves, but from our neighbors, which we are starting to see a lot more of that as Noble in particular talked about some of their extended reach results they are seeing just to the north of us as well. So overall, we are excited about it. We would see potentially moving more toward that obviously as our development continues to grow out there in the B bench, and quite frankly, we would look for those same things in the C bench as well.

I might interject there, Irene, just briefly, that with the work that Noble is doing, they're drilling as many as 60 extended reach lateral wells, many of them are going to be just north of our property, plus what we are doing this year, we hope to have a very full picture of what the extended reach potential across all our acreage can do. And so it's not just what Bonanza Creek, is doing but also looking at what Noble is doing nearby.

Yes, that's right. I think Noble is pretty excited about it, in fact, they would probably plan their whole development plan around these extended lateral. It will be curious as to what you guys come up with. You think it is going to be a six months to nine months time that would you get a full understanding of what would optimize development?

Yes, Irene, I think that is a good way to look at it. I think for us is, we are obviously very encouraged by the early time data, and so is Noble. I think in their most -- even in the analyst -- excuse me, their most -- their quarterly call, they went ahead and showed some different opportunities there, even pushing EURs as high as 1 million barrels on some of those wells. We see that opportunity on our property as well, quite frankly, because it's literally just the adjacent section away from us where two of those wells were in Noble sections. But as we move forward, yes, we still would like to see a little more data. So, six to nine months is probably the earliest that we would feel like we have enough date to make some additional additions, if you will, to our program. But at the end of the day, unless something changes from what we have seen to date, that is definitely the direction we are heading.

Great, thank you.

Your next question comes from the line of David Deckelbaum with KeyBanc. Please proceed.

Good morning, Mike, Gary and everyone. Thanks for taking my call.

Good morning, David.

My first question is just, in the mid-continent, how much of the production was lost there due to weather and freeze offs in the first quarter? Or are freeze offs only experienced in the Wattenberg?

Yes, David, mainly in the Wattenberg. We did had a little bit of down time there. We didn't really report it to you today because it was part of our plan as well. We did bring on our next facility there, as I mentioned earlier, and so we did have a little bit of testing when we do that. So, we have to bring a little gas into a facility, and sometimes we don't -- we are not always able to sell all of the gas right away. So, we did have a little bit of loss there. But overall, from a weather standpoint, no, we didn't have any impact in the mid-continent region in the first quarter. Nothing to speak of, if you will.

Okay, so the inefficiencies were all gathering and infrastructure driven.

Yes, down there, yes.

Okay. And I guess -- in the press release, you all commented that the 5-acre pilots are exceeding expectations. I guess what -- you guys laid out at the analyst day a 118,000 barrel equivalent curve for 5-acre wells versus 148 for the 10 -acre wells. What south of degree of exceeding your expectations are you seeing so far and what early conclusions are you drawing?

What I would say right now is, rather than -- when we say we are exceeding, it's actually almost tracking what we see from the 10 -acre locations today in terms of initial rate. I think that's obviously very positive, and we are encouraged by that. I think the next thing for us, though, will be as we continue to perforate the upper sands in the well bores, those results will be key to what we are looking for here because it's not just the first initial completion that we do in the wells in the mid-continent, specifically in the Cotton Valley down in Dorcheat and McKarnie, it's all the sands that are available to us.

The first third of the well that we did and we fracture stimulated was really good. We will be doing our next planned completion here in those wells. Actually, we are doing them right now, so we will have some results for those by the end of this quarter. And as we see those come in, that will give us the -- a little more information on how we are looking in terms of the sands that we feel that aren't depleted at 10-acre spacing or that are under depleted at 10-acre spacing, we can get that at 5. Right now, we are forecasting, like you said, about a 20% reduction in EUR just for, quite frankly, for maybe just an expected depletion at that spacing. But as the sands continue to show their lenticular nature. As I mentioned earlier, we didn't see as much -- maybe as much depletion in some of those sands that we -- as we might have expected based on the pressures in the intervals that we tested.

David, we are early on in the testing of our 5-acre spacing. And I think even though we presented 57-barrel a day IP, the 30 rates and 118-barrel recoveries, we still -- the 118,000, we still feel comfortable with those numbers right now and we are early on. The results are very encouraging, but we haven't internally changed any estimates for the type curve for our 5-acre in fills.

Got you. If I could ask one last quick one is, what was the cost of the second extended reach lateral, and will you be drilling a third one in the third quarter today with the identical method that you did for the second one?

Tony is with us, he is our vice president of engineering over the Rocky Mountains. And Tony, how did the second one come through?

The second one is on target for AFP costs of about $7.1 million, and we are targeting our next long reach lateral, we are targeting that to spud in the late second quarter.

Late second quarter. With the identical drilling design and completion design?

Yes, yes, I mean, for the most part.

Okay. Thank you, guys.

Your next question comes from the line of Brian Corales with Howard Weil, please proceed.

Good morning, guys. You started drilling 40-acre wells, I think you completed one of them. Can you maybe talk about anything that you have seen that is encouraging or maybe even discouraging?

Well, Brian, it's early. I think we have been encouraged by what we have seen so far to date. We haven't released the 30-day rate yet. As you, know some of the early days, it has been off of 30 total days. Some of those early days, we are just flowing the well back, it just starts to cut oil, so we like to give you a good 30 producing day rate, as we mentioned in our analyst day. But I think what we have seen today so far, we are encouraged by what we have seen from the 40-acre spacing. As far as interference, those are all a little bit early to tell at this point in time. The well fracked good, everything -- we went from an operation standpoint is as we expected.

I guess some of your peers are also talking about potentially going even tighter. Do you see that as a possibility?

This is one of those luxuries that you probably heard me refer to many times. Yes, if -- we would definitely use the results that we see from some of our peers out in the area that are continuing to spend a lot of capital testing spacing a little bit tighter maybe even than 40. Right now, we -- I guess when we look at it, we're -- obviously, we've talked about before at [80]-acre spacing, we are in manufacturing mode. At 40-acre spacing, we feel like the risk is being removed on that pretty quickly based on the results that we are seeing, not from our own -- not only from our own information, but obviously from the neighbors that we have as well. As we continue to look to bring out all the opportunity in this resource space, tighter spacing could definitely be another kind of step in that ladder, if you will. But, again, we haven't -- we don't have any plans to do anything this year, and we will go ahead and be watching very closely some of our neighbors testing some of those tighter spacing concepts.

Okay, and if I can ask one more, the balance sheet has been -- remains very strong, and you have more infrastructure, more takeaway gas process and whatnot coming into the play in the next couple of quarters. Could you see a further acceleration than what you laid out at the analyst day? Maybe even as early as third or fourth quarter bringing in additional rigs?

I think it's probably a little bit too early for us to commit to that at this point in time. As we look at our program and we see the pace that we are drilling on and what we think we can accomplish this year and yes, you are right, with the balance sheet that we have and the liquidity that we have in place, that is something we will look at here definitely in the next two to three months to see what we might want to do toward the end of the year as far as additions to the current planned budget.

All right, guys, thanks.

Your next question comes from the line of Mike Scialla with Stifel, please proceed.

Good morning, everybody.

Good morning, Mike.

Wondering with your -- you said you were pretty encouraged by the C bench well that you have that looks similar to the rates you are seeing now on the B bench. Any plans to put a C bench well near a B bench well to where you could see some -- or test the concept as to whether these are truly separate reservoirs by using tracers or micro seismic or anything like that?

I'm sorry. I was going to say, Mike, yes, I would like to let Tony comment a little bit more on that too as far as direct placement. But, yes, as you look at that, just one of the things that we are starting to concentrate more and more on as well as our neighbors is, what does the stacking arrangement look like here in the resource play in the Niobrara between the benches, between the A B C and also including the Codell? And so with that, I will let Tony comment on exactly what the remaining C bench wells look like the rest of this year.

Yes, Mike, this is Tony. We do have some C benches as we have targeted -- talked to you about earlier, and we do have several of those that are going to be in closer proximity to the B bench wells. And the intent is obviously to test that vertical stacking arrangement between the C bench and the B bench. I think you can see further down the road, obviously, probably even putting together even a more dense testing concept as we presented in our analyst day some of those concepts that we were talking about where we would be possibly B bench, C bench and Codells together. If you look at that analyst day slide, I think some of that would be something we are going to be looking at, and then some of the C benches that we are drilling this year are going to be close enough to the B bench to evaluate that spacing.

How far apart are you looking? Are they going to be inside that 40-acre spacing number that you are looking at for --

Right now they will be offset. We don't have one right now scheduled to be directly drilled underneath a B bench well. They are staggered. It would be at about approximately a 40-acre offset.

Okay, great. What is the timing on -- you said second quarter?

We are spudding -- we have three additional C bench wells to be spudded here in the second quarter, I believe that we have.

I think overall, Mike, we planned three in the second quarter, one in the later part of the third quarter. Of those C benches, I think we have got one drilled. We are drilling one now and we spud here one later this month, so.

Okay. And you'd mentioned in your prepared remarks that line pressures, you anticipated were going to be higher this summer but probably were not going to be a material issue for you because so much of your production now is coming from the horizontal wells. Can you talk about where line pressures are right now, and is it having any impact on any of your older vertical wells? I assume you planned for that, knowing that this was an issue for a while.

Yes, Michael, we do, we did plan for that. We didn't really mention that a lot in the prepared remarks just because we have taken that into consideration in our guidance already. But yes, we do have line pressures, we do have vertical wells that are still offline, are definitely hampered by that. Pat and Tony, as far as where the pressures are right running today, do you have an idea of that number, where we are sitting out there in the infrastructure today?

Yes, Gary, let me take a quick look at it. We are probably seeing pressures, what I'm looking at today, and again, this is just our weekly report that I'm looking at. We are looking at a couple hundred PSI, looking at over in our Pronghorn area. And as you get over into our Antelope area and PH Ranch area, which is over on our western side, anywhere between 135 PSI to 195 PSI line pressures.

Michael, ultimately we would like to see those numbers be below 100, quite frankly, for some of the older vertical wells. We are also looking at things that we can do to augment that and accelerate that, given an opportunity on the property that -- how we have it developed to date on some of the existing vertical wells. As we have talked about and as everybody knows, we expect to see the first bump up in capacity in the, probably the third quarter, maybe the later part of the third quarter, from DCP's first plant coming online. But we also look to see if there is something that we can do internally to augment that as well. So, we are always looking for those opportunities. And our whole goal here is to be as efficient as we can, not only with the newest wells we have, but with the existing wells that we have in our inventory.

Appreciate that. One last one for me. Curious on the first extended reach lateral, you gave us a 60-day rate. If I'm reading your chart right on analyst day, it looked like that had already been on 80 days in early April. Do you have a 90-day rate on that, or was there some reason you couldn't get 90 days there?

I just think we just probably need a few more days to put that together by the time this came out. So, as you know, we always look to see that we are communicating the right productibility of the formation at that point in time. So no, I don't think we had a 90-day rate that we shared at that point. It's just really just due to the timing of the call more than anything else.

Okay, great, thank you.

Your next question is from the line of Ipsit Mohanty, Canaccord. Please proceed.

Mike and Gary, let me talk about the completions from the eight that you've guided for the second half of the year, is that just B bench, or are you including the C and the Codell extended lateral tests in those as well?

Yes, go ahead, Mike.

Yes, 8 per month that we were referring to, it's for the entire 72 well program. That will include the Codells as well as B bench and the C benches that we are drilling.

Wonderful. And guys, is it only '13 that you are looking at, or do you think this plan is sustainable for '14 and forward as well?

I would say that on a per rig basis, yes, what we are seeing here in terms of spud to spud and subsequent completions based on a per rig count, yes, that we would say if we are running four rigs next year, that eight wells per month would be the right number to use. I think it's always keen for us to make sure that if we do, for some reason, turn a rig down for a short period of time and things like that, that we make sure that we are communicating correctly that to everybody. But if we were to assume that we continue on with four rigs through the end of the year, for example, and into next year, we would see that continued pace as we are seeing, as we're planning for the later half of the year, yes.

Yes, and then just sticking on that eight well for a second, with that plan and with the well rates that you talked about, which looks like it's holding up pretty well for C Codell, C as course, seems like production guidance might be modest, at least in my model. I was wondering what kind of disruption factors have you modeled into the guidance?

That is a great question. I think when you look at it, we always obviously put a little bit of risk in and around some timing issues and things like that as normal. We might put a slight mechanical risk in there, but honestly, with what we are seeing, there is not as much there as you might normally expect. As we -- I think the main thing that you would really need to take into consideration is some of the things we put in our -- a couple of our prepared comments and talked about on our analyst day is the impact that we may have on nearby wells when we drill horizontal. Since we are not totally drilling pad drilling all the time at this point in time, you will see us need to come back into a location when we will have some shut in time on some existing wells while we frac the horizontal. Not only for some of the verticals, but every once in a while, a horizontal well will shut in for a brief period of time as well. That's the first one.

The second one is, you need to take into consideration, again, the downtime that we just talked about earlier from the high line pressures and how that has affected the vertical wells. So, the combination of those two is something that we'd definitely take into accounting forward as far as them coming back and some of the implications that might have on the existing vertical wells we have today. Those are probably the two biggest key points that I would say that you need to place into that. Anything beyond that would be purely risk on downtime and things like that that would be very normal for modeling going forward.

The last one, you are still maintaining your CapEx guidance on your land as being denied further. And are those -- were those LOE G&A in the first quarter one off, or -- because you have shown lower guidance for '13 overall. So, I was just thinking if you could talk about the OpEx and the CapEx.

Sure. We are still within guidance on -- in our -- we are not changing any guidance, I should say, on capital at all. We are still planning to be at that $394 million at this point in time for 2013. But I think that's a good conversation about LOE and GA, especially on per unit costs. Our expectations, quite frankly, would be, since we give annual guidance and our volumes are definitely more weighted toward the back end of the year, on a per unit cost basis, we expect to see a little bit higher in the beginning of the year and as we move toward the end of the year, an increased volumes and not a commensurate increase in the pure hard dollar cost associated with those on both G&A and LOE that our per unit costs would continue to trail down. On top of that, a lot of the wells we are drilling, as we've mentioned before, the horizontal wells in the Rocky Mountain are some of the lowest LOE per BOE in the Company. As we continue to bring on more of that stream, we will also continue to see that per unit cost decrease through the year and definitely be within out guidance for annual guidance overall for the year.

Wonderful, thanks for taking my questions.

I might interject really quickly, I mentioned our $394 million program and the total project mix that we have for that, all the costs are coming in very nicely, as Gary mentioned, so we feel very comfortable with our capital guidance that that -- for the project mix that we have. So, I just wanted to clear that just in case you were looking at the total $394 million spend this year.

Sure, MIke. And that also incorporates your any additionally costs for gas lifts as well, am I right?

It does.

It does.

Wonderful, thank you, guys.

The next question is from David Beard from Iberia Capital.

Good morning. I wanted to talk a little bit about the vertical production rates up in the Wattenberg, and just when I look at what you released in the third and fourth quarter and what I backed into here for the first quarter was a pretty big sequential drop, I think, from around 3,800 barrels a day to a little over 1,600. Maybe just a little color, how much of that was the high line pressure, how much of that is a normal decline curve. And after the line pressures get better in the back half, what should we think for vertical production rate?

Well, David, what I would say is that we were obviously down versus the previous quarter I think as you mentioned. I think the components to that, again, are going to what we talked about earlier, that it's due to the offsetting horizontal fracs that knock off some of those nearby wells., Some of the high line pressures are also impacting that. So, that is the biggest two pieces of kind of fourth quarter of last year to first quarter of this year.

We also, as we know, some of the things, some of the gas processing equipment is getting expanded more toward the later part of the year. So, we have chosen to not spent the LOE dollars, if you will, to try and swab these wells on. We did some of that last year and just weren't as efficient, quite frankly, as we wanted it to be. Looking forward, it makes more sense for us to go ahead and continue with our program as we see fit, continue with our horizontal program, start to work on more of the legacy vertical wells when we have an opportunity to swab them back online and see them continue to produce rather than continually swabbing them during the quarter and quite frankly, spend some, in our mind, some inefficient lease expense dollars. Looking forward, obviously, as our production from our horizontals increase, the impact from the verticals goes down as well. But we obviously would want to bring those wells back online and get them producing in an economic fashion in the later half of this year and given that opportunity, we will take every advantage to do that.

Okay. So, it would be fair to say the vast bulk of that decline is going to happen in this year in the first quarter and we should see some stability at least for the rest of the year and then probably consider a normal decline curve out into years '14 and '15?

Yes, I think that's fair to say that, yes, David.

All right, great. Thank you. Appreciate the time.

Thank you.

Our next question comes from the line of Jeff Connolly from Brean Capital. Please proceed.

Good morning, and thanks for taking the questions. I just want to verify, you guys said that extended reach lateral came in at $7.1 million?

Yes, that's correct. This is Tony again. We have AFE'd that well for $7.1 million. We are not finished with all operations on that well, but right now, we don't see any over expenditures as we have AFE'd the wells. We are targeting that to come in at that point, but we are still in the operations to put that well on production. That's where we see it coming in right now.

Okay, great. And then after 90 days of production on the first C bench well on the first Codell well, is there anything that you plan to do differently in terms of either drilling or completion on the future wells?

This is Tony again. Actually, right now, probably not anything significant. Now, we will constantly watch those wells. Probably the most critical point is as these wells flow and they transition over to artificial lift is picking that point in time on when to turn on our gas lift systems. But since we are equipped to have gas lift on these wells initially, it's really more along the lines of looking at the data as it comes in and making the call at that point to optimally turn on the gas lift to smooth out that transition.

All right, that's all for me, thank you.

Thank you, Jeff.

Your next question comes from the line of Andrew Coleman with Raymond James. Please proceed.

Thanks a lot. Good morning, folks.

Good morning, Andrew.

Hi, Andrew.

I have a question. Did you guys give this earlier, I might have missed it, but an exit rate or a current rate for the mid continent and Rockies? I saw you hadn't released the 7164 for the quarter and 5143 for the mid continent.

We didn't, Andrew. You didn't miss it.

Okay, can you provide that, or is that something that shall be discussed on the next call?

I'm getting some evil looks, so I would say no.

Okay, fair enough. I want to dig into a little more on the assumptions. You said 13 days spud to spud. How much time after that, then, do you add for the stimulation and the facility hook up and all of that?

Andrew, I would -- go ahead, Tony.

This is Tony. Yes, typically after the rig moves off, we run swell packers and we let those packers swell for about two weeks, so about 14 days. Then at that point, we then move in, our stimulation company takes another day or so to rig that up, and then if we frac them at 24-hour basis, another of couple of days to execute the frac. Post that, it takes a few days to get the equipment out of there and then to move back in with coil tubing to clean the well out. Takes a day or so or two to do that, move back out, move back in with the rig to run the packer and gas lift equipment. If you add all that up, I don't know where that was going to, but that is several, three or four days after that.

I think, Andrew, if you use 45 days, I think you'll be right there from spud to first production, I think you will be right in that number.

Okay, and then the, looking at, I think it was slide on page 31 in your deck, so with the roughly 70-odd wells that you just are going to drill this year, to get to $400 million, that's, you only have got to complete, it looks like 62 of those. Is that correct?

No. Those are gross wells. When you talk about drilling those gross wells, we should -- I would expect us -- and I'm looking back at that deck too, just to make sure, yes, we are showing like maybe six or seven of those would fall into next year in January at this point in time, at least on that deck, the way we had it in the original plan.

Okay.

Sorry about that, you are correct. I'm sorry. I had to pull that particular slide up to make sure I was looking at the right information.

Okay. Fair enough. So basically, then the $400 million spending is roughly, you have got a little bit of carry over from last year that will fall in plus you'll have a little bit of work at the end of this when you're at the higher rig count tailing off into 2014?

As currently in our 394 plan or budget, that is correct, yes.

Okay. Great, thank you.

Thanks, Andrew.

Your next question is from the line of Ryan Oatman from SunTrust. Please proceeding.

Hi, good morning. I hopped on the call a little bit late, so I apologize if these questions have been asked already. In the first quarter, 17 net wells spud, only about 7 tied in. Can you provide any color around why that was and how you expect to work that backlog down? And is that essentially just the completions, or is there some other delay between completions and tying the wells in?

Yes, I think the biggest thing to think there is when we say a well is spud, it could have got spud in the last two days of a quarter and it gets called spud. That could be as many as four right there that could be spud in the last week of a quarter, as an example, to make up a lot of that gap, and that's truly what it is. So, it's just a timing issue. If you look at the way the rigs came into the quarter for us, we had one of our rigs in the Rockies in early January, the second rig in mid-January, the third rig in mid-February, and the last rig came on at the early to mid part of March.

So, that's -- when you see that and schedule that in, you can see where that gap shows up, at least in terms of drawing a line at the end of the quarter. As far as having a backlog and working that off, I think you have heard us say that we will continue to do those wells pretty quickly in line. From when we drill them moving forward, we don't have what I would consider a large backlog of jobs at this point in time. We are seeing some of those wells come on in April and May, obviously, that we drilled in the first quarter, and that will be the continuing pattern throughout the year.

Okay, and then with eight completions a month, it's fair for us to assume about eight tie-ins per month, there's not a difference between those two numbers.

That's correct, yes.

Okay, and then shifting to this extended reach lateral, it sounds like obviously pretty successful there getting that well drilled and then completed with 40 stages. Do you have any additional color on what you did differently there versus the first test? And then have you looked at the faulting of the acreage and seen how much of your acreage is prospective for these extended reach laterals?

I'll tell you what, I will comment early then I'll turn it over to Tony for any additional insight there. Really, the biggest thing we did differently on the second horizontal is we just changed a little bit of the way we mechanically placed the liner in the hole. And, quite frankly, some of the things that we learned from having such a long lateral section, a lot of liner hanging out there in the bottom of the well bore. We needed to change the way that we lubricated the hole and added some weight and the procedure that we needed to run the liner to the bottom, we were able to be very successful in that in the second well. That mainly was the biggest change well over well from that standpoint.

As far as the faulting and geologic look that we see across the property, there are going to be instances where we might have continuous sections available to us to drill an extended reach lateral that the geology would tell us we don't want to do that. There are going to be positions that at some point in time throughout the property where we don't want to do extended reach lateral, but would have mechanically the ability to do it. Just geologically, we don't want to do it. Other than that though, those more acute than they are the norm, I would say. Given the opportunity, we would look to put extended reach lateral continued success across the property. Tony, did you want to add anything else on the geologic side or mechanical side to that?

You bet, Gary. You touched on the geologic side. The other thing I do want to emphasize is that the optimum length of these laterals is still being determined. There could be some areas where a 9,000-foot lateral makes sense. There could be other areas where a 7,000-foot long reach lateral may make sense from that standpoint, that it could be driven either by acreage or it could be driven by geologic concerns where you might drill one 7,000-foot lateral one direction and one coming from the other direction to access the reservoir. As you have seen our neighbors to the north, Noble is doing some analysis on 7,000-foot and something in between on those laterals, so you might see us looking at some things like that also.

Okay, very good. And then one last one for me, if I may. Are you participating in non-operated tests around you with your neighbors nearby, whether that's Encana or Bill Barrett and or Carrizo? And have you learned anything from those guys as well?

We did participate last year in some non-operated wells. I don't know if I would call them test wells or not. They were all standard Niobrara B bench wells that -- and also operator-drilled that we had ownership in and did participate. As far as 2013, we would do the same thing given an opportunity where we own property and somebody wanted to drill. We do have plans for that in this year's budget. I think we planned a total of seven gross and two net positions that we would not operate during the year. We -- so far at this point in time, if we do get contacted to participate in some other additional testing, whether that's B, C, A or Codell, somebody else is going to operate. We think we have good neighbors and so, we would most likely be joining them in that endeavor.

Okay, appreciate the color. Thank you, guys.

You're welcome.

Your next question comes from the line of Gabriele Sorbara with Topeka Capital Markets. Please proceed.

Good morning, guys. Trying to get a sense of where you are seeing this cost savings on the extended reach laterals. Is it the drilling or the completion? And can you comment on the drilling time of the second extended reach lateral versus the first one?

Tony, go ahead on that.

I think where we are seeing the cost savings on the difference between the two wells is in the drilling time right now. Obviously, from last year to this year, we have increased our speed. I don't have exactly the days from spud to spud on that well in front of me, but I do know it was shorter. Secondly, we're also seeing an improved cost on the completion costs. The frac companies, obviously, the costs have come down from last year, so we are seeing some savings there. I think those were two of the main drivers, but the efficiency of the rig is a big portion of that.

Great, thank you. Then, can you comment on where the extended reach laterals are positioned? The first two and where you plan to position the third one across your acreage block?

Tony pulls that up. The first well is right in the middle of the acreage position. And then Tony, do you want to comment on the second and third?

Yes, sure. The second long reach lateral is in our -- if you look at our eastern part of our acreage, and it's going to be to the northwestern part of our eastern part of our acreage, if you will. On a map, it is going to be in section 12 of Township 5 north 62 west. And then our third long reach lateral is going to be back on our western side of our acreage, kind of on the eastern part of that acreage.

Okay, great. And then one final question, looks like you guys came in slightly gassier than I had modeled for the quarter. Do you have any guidance for the year? Should we expect a slight uptick in maybe the liquids volume throughout the next couple of quarters?

I think our mix that we put out in our guidance we would stay with at this point in time, Gabriele. We don't -- a little quarter to quarter move one or two ticks one way or the other doesn't really change what we expect to see going forward. We have seen a little bit more oil, quite frankly, in the mid-con from some of the recompletions that we've been doing and some of the initial completions 2013. But overall, not enough for us to come out and change anything on guidance right now.

Okay, thank you, guys. Appreciate the color.

Thank you.

Your next question is from the lied of Chad Mabry from KLR Group. Please proceed.

Thanks, good morning.

Good morning.

Most of my questions were answered, but I did have a quick one. Wondering if you could provide some more details on the new water contract that you secured up there in the Wattenberg. Typically, how much supply does that secure for you? And if you could potentially quantify the cost savings there?

The contract for us would probably provide water for us all the way through the first quarter of next year, it's an annual contract. What it does, it gives us the ability to get water closer to us. And as far as the cost savings goes, we are looking at the ability to maybe eliminate some trucking out in the area. We haven't really given a hard number on that at this point in time. But we do expect it to be something that will, applied across 72 wells, as an example, for this year, the 50 or so that are remaining to be significant enough for us that we look to go ahead and put in maybe some infrastructure to carry water across the property. So, as far as a hard number on that, I didn't think we were sharing anything on that today. We would like to get it into an operating mode and then we'll be able share with you true cost savings rather than what we are anticipating at this time.

Yes Chad, I might add in there that we haven't had a problem being able to source water historically. although it's talked about a lot with the about of horizontal activity that us and our neighbors are doing. We felt it was prudent to go ahead and capture an opportunity that has very positive economics for us but secures our water through first quarter 2014. But I don't want to say that we are worried about sourcing water because so far, we haven't had a problem.

Very good.

Your next question is a follow-up from the line of Ipsit Mohanty with Canaccord, please proceed.

Sure guys, just a couple of quick follow-ups. One being that, are gas lifts the way to go forward? What percentage of your current wells that you plan you're going to put on gas lifts?

Ipsit, we would say that every single well we drill out there horizontally, that's our plan going forward.

All right, great. And then with some of the competitors recently in their calls talking about reporting in three streams, do you see that deporting the production in three stream, is that something that you are looking at, or would you still stick to two.

We are looking at it. It's something that we are just making sure that we are very comfortable with our purchaser of the gas at this point in time.

I think you accelerated your C program a little bit, probably, from your analyst day, probably 2 in two quarters versus now you're saying you're going to do 3 C bench wells in 3 in the second quarter. Is that something that you are seeing positive, or am I reading more than I should?

Probably just timing more than anything else in terms of rescheduling. I wouldn't -- I will tell you this, we did not make a decision based on the results from any of the C bench testing we have done to date to accelerate into the second quarter, so.

All right. That's all I got, thank you.

Not saying that we are disappointed. We are not. I don't mean to infer that either. I just wanted to tell you that no, we haven't made any changes based on that to date.

All righty.

There are no additional questions at this time. Ladies and gentlemen, this concludes the presentation. You may now disconnect. Have a great day.

Super. Thanks, everyone.