Bonanza Creek Energy's CEO Discusses Q1 2013 Results - Earnings Call Transcript

May.10.13 | About: Bonanza Creek (BCEI)

Bonanza Creek Energy, Inc. (NYSE:BCEI)

Q1 2013 Earnings Conference Call

May 10, 2013 11:00 AM ET

Executives

James Masters - Manager, IR

Michael R. Starzer - President and CEO

Gary A. Grove - EVP, Engineering & Planning

Tony Buchanon - VP, Rocky Mountain Region Engineering

Analysts

Irene Haas - Wunderlich Securities

David Deckelbaum - KeyBanc Capital Markets

Brian Corales - Howard Weil

Michael Scialla - Stifel Nicolaus

Ipsit Mohanty - Canaccord Genuity

David Beard - IBERIA Capital Partners

Jeff Connolly - Brean Capital

Andrew Coleman - Raymond James

Ryan Oatman - SunTrust Robinson Humphrey

Gabriele Sorbara - Topeka Capital Markets

Chad Mabry - KLR Group

Operator

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 your coordinator for today. At this time, all participants are in listen-only mode. We will facilitate a question-and-answer session toward the end of this conference. [Operator Instructions].

I would now like to turn the conference over to your host, Mr. James Masters, Investor (sic) Relations Manager. Please proceed.

James Masters

Thanks Lisa. Good morning everyone and welcome to the 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 actual results to differ materially. You should real our full disclosures as described in our 10-Q, and our other SEC filings, which you can access through our website or the SEC’s website.

Also during this call, we will refer to certain 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 release. Also, all results discussed today reflect continuing operations, not accounting the results from our remaining California property.

With that, it's my pleasure to turn the call over to Mike.

Michael R. Starzer

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 prime 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 very compelling case for organic growth in our Analyst Day presentation on 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 by placing $13 million secondary shares, on behalf of West Face Capital, significantly increasing our public float. And in 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 the roadmap for peer-leading growth over the next five years. Overall, actual results are meeting expectations. Our 3P reserve analysis with [risked] EUR assumptions, show tremendous growth potential through downspacing in 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 more of 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 4.65 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 achieved a 66% year-over-year increase in adjusted EBITDAX to $52.3 million. Thanks to the 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 and Codell, along with extended reach laterals and downspacing 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 8 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 our low leverage on our balance sheet and ample liquidity, we are prime to deliver an excellent year for our shareholders.

Now I will turn the call over to Gary, who will dive into more detail surrounding our operational activities.

Gary A. Grove

Thanks Mike. Much of the quarters 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 was happening all the time.

As Mike mentioned earlier, we produced 12,307 BOE per day during the quarter, not including the small amount of remaining production in our 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 7 wells were drilled in 2012, while the remaining five were placed on 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 stimulations of nearby horizontal wells. These nearby well impacts were expected, and the effects of this lost production are factored into our annual guidance.

By the end of the quarter, we had ramped up to four horizontal rigs, and we are averaging drilling times of 13 days by the spud, which will result in a rate of approximately eight horizontal wells being drilled per month.

Our catalyst well program continued to achieve very attractive results, illustrating that we are still only in the early innings of Bonanza Creek's development potential.

In the Codell, our first well is tracking at 313,000 BOE EUR, which is similar to our 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 it has just started to cut oil in the initial flow back period.

Our initial Niobrara C Bench well, also continues to hold in strong from its 30 day producing rate of 444 BOE per day. The 60-day average producing rate of 383 BOE per day, is consistent with the declines we see 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. We incorporated a number of key lessons from the first well we drilled late last year, that resulted 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 the liner in the full 9,449 foot lateral section. The well was fracture stimulated using 40 frac stages at 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 wells 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 the planned six wells in 2013.

The two 40-acre well -- excuse me, the one in the middle if you will, has been flowing back for approximately 30 total days, but we are not ready 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 our 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 our 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 this highly economic Cotton Valley (inaudible) 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, have near original reservoir pressure. This is very encouraging, as our (inaudible) spacing testing program is looking specifically determined, if we aren't counting undepleted or underdepleted sands. In addition, the average 60 day producing rate of 61 BOE per day exceeded our forecast, which was based on a 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 on the gas processing facility 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 are continuing to add to our employee base, as we develop our large proved and unproved upside. As additional volumes come online during the year, our per unit G&A costs will also continue to decrease.

Regarding our production guidance for the year, as Mike mentioned, we are in line in tracking our expectations of 14,500 to 16,000 BOE per day. As we had mentioned, our production for the year is back-end loaded, and we look forward to the strongest production coming in the third 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'd like to turn the call back over to Lisa, and open the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions]. Your first question comes from the line of Irene Haas with Wunderlich Securities. Please proceed.

Irene Haas - Wunderlich Securities

Hi. I would like to kind of 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?

Michael R. Starzer

Well good morning Irene. Gary, do you want to chime in on that one, since you look at the extended reach laterals very closely?

Gary A. Grove

Irene, we had -- some of the things we did differently. If I heard the question correctly was, what do 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 are using to push the liner towards the bottom. That all went really-really well.

As far as the acreage and what we see -- that's available for extended reach, I mean, we are really excited about this opportunity, as we go forward. Overall, we think the efficiencies that we can see from drilling longer, obviously from one well to rather than using two well bores, to intersect the same areas. Well that's something that we definitely have plans for going forward. I think we have mentioned that we'd 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, which they are seeing just to the north of us as well.

So overall, we are excited about it. We would see potentially moving more towards that obviously, as our development continues to grow out there in the D Bench. And quite frankly, we would look for those same things in the C Bench as well.

Michael R. Starzer

I might interject there, Irene, just briefly that, with the work that Noble is doing, 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 wholesome 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.

Irene Haas - Wunderlich Securities

That's right. I think Noble is really excited about, in fact, they would probably plan their whole development around these extended lateral. So we will be kind of curious as to what you guys come up with. Do you think it's going to be sort of a six month to nine month time, that you would get a full, sort of understanding of what would optimize development?

Gary A. Grove

Irene, I think that's 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, and I think in their most, even in their analyst -- excuse me, their most -- their quarterly call, they went ahead and showed some different opportunities there, even pushing the EURs as high as 1 million barrels on some of those wells. So we see that opportunity on our property as well, quite frankly, because its 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 the six to nine months is probably the earliest that we would feel like we'd have enough data to make some additional additions, if you will, to our program. But at the end of the day, unless something changes from what we've seen to date, that's definitely the direction we are heading.

Irene Haas - Wunderlich Securities

Great. Thank you.

Operator

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

David Deckelbaum - KeyBanc Capital Markets

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

Michael R. Starzer

Good morning David.

David Deckelbaum - KeyBanc Capital Markets

My first question is just, in the Mid-Continent, how much of the production was lost there due to weather and freeze-outs in the first quarter, or a freeze-out was only experienced in the Wattenberg?

Gary A. Grove

Yeah David, mainly in the Wattenberg. We did have a little bit of downtime 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 bit of gas into the facility, and sometimes we don't want -- we are not always able to sell all the gas right away. So we did have a little bit of loss there. But overall from a weather standpoint, no, we didn't really have any impact in the Mid-Continent region first quarter. Nothing to speak of, if you will.

David Deckelbaum - KeyBanc Capital Markets

Okay. So the inefficiencies are all sort of just gathering and infrastructure driven?

Gary A. Grove

Yes down there, yes.

David Deckelbaum - KeyBanc Capital Markets

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

Gary A. Grove

What I'd say right now is, rather than -- when we say we're 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 those wells in the Mid-Continent, specifically down in the Cotton Valley, down in Dorcheat and McKamie, is all the sands that are available to us.

So the first third of the well that we did, and we fracture stimulated, looks really good. We will be doing our next plan completion here in those wells, actually, we are doing them right now, we will still have some results from those by the end of this quarter. And as we see those come in, that will give us the -- kind of a little more information on how we are looking, in terms of the sands that we fill, that aren't depleted at 10-acre spacing, or that are underdepleted, the 10-acre spacing, we can get that [bought].

Right now we are forecasting, like we said, about 20% reduction in EUR. Just quite frankly, for maybe just some expected depletion at that spacing. But as the sands continue to show their lenticular nature, as I mentioned earlier, we didn't see maybe as much depletion in some of the sands that we actually might have expected, based on the pressures in the intervals that we tested.

Michael R. Starzer

And David, we are early on in the testing of our five acre spacing, and I think even though we presented 57 barrel a day IP, the 30 rates, and 118-barrel recoveries, we still -- about 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 of our estimates or the tight curve for our five-acre infills.

David Deckelbaum - KeyBanc Capital Markets

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

Michael R. Starzer

Tony is with us, he is our Vice President of Engineering over the Rocky Mountains. And Tony how did that second one come through.

Tony Buchanon

The second one is on target for our [ASP] costs, of about $7.1 million. And we are targeting our next one reach lateral, we are targeting that spud in the late second quarter.

David Deckelbaum - KeyBanc Capital Markets

With the sort of identical drilling design and completion design?

Gary A. Grove

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

David Deckelbaum - KeyBanc Capital Markets

Okay. Thank you guys.

Operator

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

Brian Corales - Howard Weil

Good morning guys.

Michael R. Starzer

Good morning.

Brian Corales - Howard Weil

You started drilling 40-acre wells, I think you completed one of them. Can you maybe cover anything you have seen that was encouraging or maybe even discouraging?

Gary A. Grove

Well Brian, it's early. I think we have been encouraged by what we have seen so far to date. We have not released that 30-day rate yet, as you know, some of the early days. It has been on for like, 30 total days, and 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 (inaudible) from an operational standpoint is as we expected.

Brian Corales - Howard Weil

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

Gary A. Grove

This is one of those luxuries that you've probably heard me refer to many times. Yes, we would definitely use the results that we see from some of our peers out in the area, that are continuing to spend lot of the capital, testing spacing, a little bit tighter, maybe even on 40. Right now, we -- I guess when we look at it, we are -- obviously we've talked about it before, at 80-acre spacing, we are in manufacturing mode. At 40-acre spacing, we feel like the risk has been removed on that pretty quickly, based on the results we are seeing, not only from our own information, but obviously from the neighbors that we have as well, and then as w 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 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.

Brian Corales - Howard Weil

And if I can just ask one more. The balance sheet remains very strong, and you have more infrastructure or more takeaway, gas process and what not coming into the play, you know, in the next couple of quarters. I mean, could you see a further acceleration than what you've laid out at the Analyst Day, maybe even as early as third or fourth quarter, bringing in additional rigs?

Gary A. Grove

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's something we will be looking at here and definitely in the next two to three months to see what we might want to do, towards the end of the year, as far as any additions to the current plan budget.

Brian Corales - Howard Weil

All right guys. Thanks.

Operator

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

Michael Scialla - Stifel Nicolaus

Good morning everybody.

Michael R. Starzer

Hi Mike.

Gary A. Grove

Good morning.

Michael Scialla - Stifel Nicolaus

Wondering what -- you said you're pretty encouraged by the C Bench well that you have, looks similar to the rates you are seeing on the B Bench. Any plans to put C Bench well near a B Bench well, where you could see some -- or test the concept, as to whether or not, these are truly separate reservoirs by using tracers or micro-seismic or anything like that?

Gary A. Grove

I am sorry, I was going to say -- Mike yeah, I'd like to let Tony comment a little bit more on that too, as far as direct placement. But yes, as you look at that, one of the things that we are starting to concentrate more and more on as well as our neighbors is, what does that 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 for the rest of this year?

Tony Buchanon

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 us further down the road, obviously, probably putting together, even a more dense testing concept, as we presented in our Analyst Day, some of the concepts that we are talking about, where we would be possibly stacking B Bench, C Bench and Codells together. So if you look at that Analyst Day slide, I think that 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.

Michael Scialla - Stifel Nicolaus

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

Tony Buchanon

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

Michael Scialla - Stifel Nicolaus

Okay great. What's the timing on the second quarter?

Gary A. Grove

We are spudding -- we have three additional C Bench wells to be spudded here in the second quarter. I think overall, Mike, I mean, we plan three in the second quarter, one in the latter part of the third quarter. Of those C Benches, I think we have got one drilled, we are drilling one right now, we will spud one here, later this month.

Michael Scialla - Stifel Nicolaus

Okay. 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 just 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?

Gary A. Grove

Yeah Michael, we did plan for that, and so, we didn't really mention that a lot in our 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 running right today, do you have an idea of that number, where we are sitting out there in the infrastructure today?

Tony Buchanon

Gary, let me take a quick look at it. We are probably seeing pressures, what I am looking at today, and again this is just kind of a weekly report of what I am looking at. We are looking at a couple 100 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.

Gary A. Grove

Michael, ultimately we'd like to see those numbers be, you know, 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 all talked about, and as everybody knows, we expect to see, the first bump-up in capacity in probably the third quarter, maybe the latter part of the third quarter from [BCP'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 on our inventory.

Michael Scialla - Stifel Nicolaus

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

Gary A. Grove

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

Michael Scialla - Stifel Nicolaus

Okay. Great. Thank you.

Operator

Your next question comes from the line of Ipsit Mohanty with Canaccord. Please proceed.

Ipsit Mohanty - Canaccord Genuity

Mike and Gary, let me talk about the completions per month. The 8 that you have 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?

Michael R. Starzer

(Inaudible).

Ipsit Mohanty - Canaccord Genuity

Yeah, go ahead Mike.

Michael R. Starzer

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

Ipsit Mohanty - Canaccord Genuity

And guys, is it only 2013 that you are looking at or do you think this kind of a plan is sustainable for 2014 and forward as well?

Gary A. Grove

Well I would say that, on a per rig basis, yeah, what we are seeing here in terms of spud to spud, and subsequent completions based on a per rig count, we would say, if we were running four rigs next year, that eight wells per month will 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 as an example, and into next year, we would see that continue pace, as we are seeing, as we are planning for the latter half of the year, yes.

Ipsit Mohanty - Canaccord Genuity

Thanks. And then just sticking on that 8 wells for a second, with that plan and with the well rates that you have talked about, which looks like its holding up pretty well for C, Codell, B of course, seems like production guidance might be modest, at least in my model. I was wondering, what kind of disruption factors have you sort of modeled in, into the guidance?

Gary A. Grove

That's 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, is pretty normal. We might put a slight mechanical risk in there, but honestly, with what we are seeing, it's 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 have put in our couple of the prepared comments, and talked about on our analyst day is, the impact that we might have on nearby wells, when we drill the horizontal. Since we are not totally drilling pad drilling all the time, at this point in time, you will see us maybe come back into, locate, and then 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, just for a brief period of time as well.

So 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's affected our vertical wells. So the combination does deal with something that we definitely take into account going forward, as far as -- then coming back and some of the implications that might have on the existing vertical wells we are having 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 just downtime and things like that, that would be very normal for modeling going forward.

Ipsit Mohanty - Canaccord Genuity

And the last one, you are used to maintaining CapEx guidance on your Analyst Day in the Niobrara and are those -- were those LOE and G&A in the first quarter kind of one-off, because you have shown a lower guidance for 2013 overall? So just thinking if you could talk about the OpEx the CapEx?

Gary A. Grove

Sure. We are still within guidance on -- we are not changing any guidance, I should say on capital at all, but 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 towards the end of the year and increase volumes, and not a commensurate increase in the pure hard dollar cost, especially with those, on both G&A and LOE, but our per unit cost, we continue to trail down.

On top of that, of all the wells we are drilling, as we have mentioned before, the horizontal wells in the Rocky Mountains, they are some of the lowest LOE per BOE in the company. And so, as we continue to bring on more of that stream, we will continue to see that per unit cost decrease through the year, and definitely be within our guidance -- for annual guidance overall for the year.

Ipsit Mohanty - Canaccord Genuity

Wonderful, thanks for taking my questions.

Michael R. Starzer

I might interject real quickly, I mentioned, the $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 -- for the project mix that we have. So just wanted to clear that, just in case you are looking at the total $394 million spend this year.

Ipsit Mohanty - Canaccord Genuity

Sure Mike, and that also incorporates your -- any additional cost for gas lifts as well? Am I right?

Michael R. Starzer

It does. It does.

Gary A. Grove

Yes it does.

Ipsit Mohanty - Canaccord Genuity

Wonderful. Thank you guys.

Michael R. Starzer

Thank you, Ipsit.

Operator

Your next question comes from the line of David Beard with IBERIA Capital. Please proceed.

David Beard - IBERIA Capital Partners

Hi. Good morning.

Michael R. Starzer

Good morning.

Gary A. Grove

Hi David.

David Beard - IBERIA Capital Partners

Wanted to talk a little bit about the vertical production rates up in the Wattenberg. And just when I look at what you'd released in the third and fourth quarter, and then what I backed into here for the first quarter, was a pretty big sequential drop, I think from around 3,800 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's a normal decline curve, and after the line pressures get better in the back half, what should we think about for our vertical production rate?

Gary A. Grove

Well David, what I would say is that, we were obviously down versus the previous quarter, I think, as we mentioned. I think the components to that again, are going to what we talked about earlier that, its -- and its due to the offsetting horizontal fracs, that kind of knock-off some of those nearby wells. Some of the high line pressure issues are also impacting that, and so that -- the biggest two pieces of -- kind of fourth quarter of last year to first quarter of this year. Also, as we know some of the things, some of the gas processing equipment including expanded - more towards the latter part of the year. So we have chosen to not spend the LOE dollars, if you will, to try and swap these wells. We did some of that last year, and just weren't as efficient as quite frankly as we wanted to be.

So looking forward, it makes more sense for us to go ahead and continue with our program, as we seek to 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 swab them during the quarter, and quite frankly, spend some -- in our minds, some inefficient lease expense dollars.

So looking forward, obviously, as our production from our horizontals increase, the impact of the verticals goes down as well. But we obviously, we'd want to bring those wells back online, and get them producing in an economic fashion in the latter half of this year, and given that opportunity, we will take our advantage to do that.

David Beard - IBERIA Capital Partners

Okay. So it would be fair to say, the vast bulk of that decline is going to happen for this year, in the first quarter, and we should see some stability, at least for the rest of the year, and then probably considering a normal decline curve out into years 2014 and 2015?

Gary A. Grove

Yes I think that it would be fair to say that. Yes David.

David Beard - IBERIA Capital Partners

All right. Great. Thank you. Appreciate the time.

Michael R. Starzer

Thank you.

Operator

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

Jeff Connolly - Brean Capital

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?

Tony Buchanon

Yeah. That's correct. This is Tony again. We have [ASP'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 [ASP'd] the well. So we are targeting that, to come in at that point. But we are still in the operation, to put that well on production. So that's what we see coming in right now.

Jeff Connolly - Brean Capital

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

Tony Buchanon

This is Tony again. Actually right now, probably not anything significant. We will constantly watch those wells, probably the most critical point is that, 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 (inaudible) of looking at the data that comes in, and making the call at that point, to optimally turn on the gas lift to smooth out that transition.

Jeff Connolly - Brean Capital

All right. That's all for me. Thank you.

Michael R. Starzer

Thank you, Jeff.

Operator

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

Andrew Coleman - Raymond James

Thanks a lot and good morning folks.

Michael R. Starzer

Good morning Andrew.

Gary A. Grove

Hi Andrew.

Andrew Coleman - Raymond James

I had a question, did you guys give this earlier, I might have missed it, but an exit rate or a current rate for the Mid-Continental and Rockies. I thought it was out in the release, 71.64 for the quarter and 51.3 for the Mid-Continental?

Gary A. Grove

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

Andrew Coleman - Raymond James

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

Gary A. Grove

I am getting some evil look, so I would say no.

Andrew Coleman - Raymond James

Okay fair enough. I guess just wanted 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 facility hook-up and all that?

Gary A. Grove

Andrew I would -- go ahead, Tony.

Tony Buchanon

This is Tony, Andrew. Yeah typically, after the rig moves off, we run 12 packers and we let those packers swell for about two weeks or about 14 days, and 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 on a 24-hour basis, another 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 a rig to run the packer and gas lift equipment. So if you add all that up, I don't know where that was going to, but that's -- (inaudible).

Gary A. Grove

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

Andrew Coleman - Raymond James

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

Gary A. Grove

No. Those are gross wells. So when you talk about drilling those gross wells, I would expect us -- and I am looking back at that deck, just to make sure. Yeah, we are showing that like may be 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 our original plan.

Andrew Coleman - Raymond James

Okay. Sorry about that.

Gary A. Grove

You're correct. I am sorry. I had to pull that particular slide up, to make sure I was looking at the right information.

Andrew Coleman - Raymond James

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

Gary A. Grove

Currently, in our $394 million plan, our budget, that is correct.

Michael R. Starzer

Yes.

Andrew Coleman - Raymond James

Okay. Great. Thank you.

Michael R. Starzer

Thanks Andrew.

Operator

Your next question comes from the line of Ryan Oatman with SunTrust. Please proceed.

Ryan Oatman - SunTrust Robinson Humphrey

Hi good morning.

Michael R. Starzer

Good morning Ryan.

Gary A. Grove

Good morning.

Ryan Oatman - SunTrust Robinson Humphrey

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

Gary A. Grove

Yeah, 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 the quarter, and it gets called spud, and so, I mean, that could be as many as four right there, that could be spud in the last week of the 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 and mid-January the third rig and mid-February, and the last rig just came on at the early to mid part of March. So that's -- when you see that and kind of schedule that in, you can kind of see where that gap shows up, at least in terms of just drawing the line at the end of the quarter.

As far as having a backlog and working that off, I think you've heard us say, that we will continue to do those wells pretty quickly in line, from when we drill them and moving forward, we don't really 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.

Ryan Oatman - SunTrust Robinson Humphrey

Okay. And then with eight completions a month, I guess, it's fair for us to assume about eight times per month, there is not a difference between those two numbers?

Gary A. Grove

That's correct. Yes.

Ryan Oatman - SunTrust Robinson Humphrey

Okay. Then shifting to this extended reach collateral, it sounds like, obviously pretty successful there in that well, drilled -- I mean, 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 prospected for these extended reach laterals?

Gary A. Grove

I will tell you what, I will comment early, and then I will turn it over to Tony, for any other additional insight there. Really the bigger thing we did differently on the second horizontals, we just changed it a little bit, the way we mechanically placed the liner in the hole, and quite frankly, just 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 very successful with 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. So there are going to be positions 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, those are more acute than they are the norm, I would say, and so, given the opportunity, we will look to put extended reach lateral with continued success across the property.

Tony, do you want to add anything else on the geologic side, or the mechanical side to that?

Tony Buchanon

Yeah, 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, it could be driven either by acreage or it could be driven by geologic concerns, or you might drill one 7,000 foot lateral one direction, and one coming from the other direction to access the reservoir. So as you have seen our neighbors, 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.

Ryan Oatman - SunTrust Robinson Humphrey

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 or Carrizo and have you learned anything from those guys as well?

Gary A. Grove

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, and also operator drilled, that we had ownership then and did participate. As far as 2013, we would plan to 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.

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 in that endeavor.

Ryan Oatman - SunTrust Robinson Humphrey

Okay. Appreciate the color. Thank you guys.

Michael R. Starzer

You're welcome.

Operator

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

Gabriele Sorbara - Topeka Capital Markets

Good morning guys.

Gary A. Grove

Good morning Gabriele.

Gabriele Sorbara - Topeka Capital Markets

Just trying to get a sense of where you are seeing these 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?

Gary A. Grove

(Inaudible). On the difference between two wells is in the drilling time right now, and 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 are also seeing improved costs on our completion costs, the frac companies, obviously the costs have come down from last year, so we are seeing some savings. So I think those were kind of two of the main drivers. But the efficiency of the rig is a big portion of that.

Gabriele Sorbara - Topeka Capital Markets

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

Gary A. Grove

Tony will pull that up. As the first well was right in the middle of the acreage position, and Tony, do you want to comment on the second and third?

Tony Buchanon

Yeah sure. The second long reach lateral is kind of in our -- it's on our (inaudible). 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 the map, it's going to be in section 12 of township 5, north 62 west. Then our third long reach lateral, it's going to be back on our western side of our acreage, kind of on the eastern part of that acreage.

Gabriele Sorbara - Topeka Capital Markets

Okay great. Then one final question. Looks like you guys came in slightly [daftier] 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 volumes throughout the next couple of quarters?

Gary A. Grove

I think our mix that we put out in our guidance, we would still stay with at this point in time, Gabriele. We don't -- you know, 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 have been doing, and some initial completions in 2013, but overall, not enough for us to come out and change anything on guidance right now.

Gabriele Sorbara - Topeka Capital Markets

Okay. Thank you guys. Appreciate the color.

Michael R. Starzer

Thank you.

Operator

Your next question comes from the line of Chad Mabry with KLR Group. Please proceed.

Chad Mabry - KLR Group

Thanks. 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. I guess, specifically, how much supply does that secure for you, and if you could potentially quantify some of the cost savings there?

Gary A. Grove

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 is, 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 may be eliminate some trucking out on 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 be applied across 72 wells, as an example for this year, the 50 years of that are remaining, to be significant enough for us to -- when you look to go ahead and put in maybe some infrastructure to carry water across the property.

So as far a hard number on that, I didn't think we were hearing anything on that today. We'd like to get it into an operating mode, and then we will be share with you, true cost savings, rather than what we are anticipating at this time.

Michael R. Starzer

I might add in there that, we haven't had a problem being able to source water, historically. Although its talked about a lot, with the amount of horizontal drilling activity, that us and our neighbors are doing. We just 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.

Chad Mabry - KLR Group

Very good.

Operator

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

Ipsit Mohanty - Canaccord Genuity

Guys, just a couple of quick follow-ups. One being that, are gas lifts the way to go forward? I mean, what percentage of your current work that you plan, you are going to put on gas lifts?

Gary A. Grove

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

Ipsit Mohanty - Canaccord Genuity

All right, great. Then with some of the competitors recently I their calls, talking about deporting into these streams. Do you see deporting the production in three streams? Is that something that you guys are looking at, or would you still stick to two?

Gary A. Grove

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

Ipsit Mohanty - Canaccord Genuity

I think you accelerated your C program a little bit probably from your Analyst Day. Probably two in two quarters versus now you are saying, you want to do three C Bench rows in the second quarter. Is that something that you seem positive, or am I reading more than I should?

Gary A. Grove

Probably its timing more than anything else, in terms of rescheduling. So I wouldn't -- I will say 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, end of the second quarter.

Ipsit Mohanty - Canaccord Genuity

All right. That's all I had. Thank you.

Gary A. Grove

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

Ipsit Mohanty - Canaccord Genuity

All right.

Operator

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

Michael R. Starzer

Super. Thanks Lisa. Thanks everyone.

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