Civitas Resources Inc (CIVI) 2014 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the quarter four 2014 Bonanza Creek Energy Incorporated earnings conference call. My name is Kathy, and I will be your operator for today.

(Operator Instructions)

As a reminder, this call is being recorded for replay purposes. I would now like to turn the call over to Mr. James Masters, Investor Relations Manager. Please proceed, sir.

Thank you, Kathy. Good morning, everyone, and welcome to Bonanza Creek's fourth-quarter and full-year 2014 earnings conference call webcast. Yesterday afternoon we issued our earnings press release and this morning filed our 10-K with the SEC. You can access both on our website.

It is my pleasure this morning to introduce Richard Carty, Bonanza Creek's President and Chief Executive Officer, for his first conference call with the Company. Richard officially took over the role in November and has since been actively engaged in finalizing the 2015 budget and getting to know key stakeholders in the midst of a very challenging market environment. On this call, he will provide a brief overview of 2014 results and 2015 strategy. Following his remarks, Bill Cassidy our Chief Financial Officer, will discuss financial highlights and our recently completed equity offering.

Finally, Tony Buchanon, Chief Operating Officer,

will review operations. As usual, we have endeavored to keep prepared remarks short to leave ample time for Q&A. Please be aware that our remarks will include forward-looking statements that are subject to many risks and uncertainties that could cause actually results to differ materially.

You should read our full disclosures as described in our 10-K and other SEC filings. 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.

With that, I will turn the call over to Rich.

Thank you, James. Good morning, everyone, and thank you for spending time with us today. I've enjoyed meeting many of you over the past several months and appreciated the chance to share our vision of Bonanza Creek. For others that I have not yet had the pleasure to meet, I look forward to having the opportunity soon. 2014 was a very successful year in many respects.

In operations, we grew sales volumes by 45% and increased EBITDAX by 33%, and our recent improvements in hydraulic fracturing methods with 28 stages, demonstrated 21% increases in 30-day production rates with a 7% increase in well capital. On the strategic front, we doubled our acreage footprint with an important $213 million acquisition in the Wattenberg Field. And in corporate finance, we turned out our balance sheet with a timely issuance of $300 million of high-yield bonds with a 5.75% coupon and a 2023 maturity to much the investment horizons of our acquisition.

With respect to execution, our results for the first three quarters of the year matched our internal engineering forecast for measured growth. But as we previously disclosed, the fourth quarter was impacted by disruptions related to weather, third-party infrastructure downtime, and a delayed five-well pad. That said, I'm very pleased with the overall achievement demonstrated by the Bonanza Creek team and acknowledge this as another milestone year for the Company.

This is a first-class organization that I am proud to lead on behalf of our stockholders. We have demonstrated the value of our high-quality asset base, which is complemented by prudent financial stewardship and a capable execution team. Together we have positioned the Company for sustained success.

Looking ahead, 2015 will be a challenging environment that will test the E&P industry. Our senior leadership team is well prepared to lead the organization through this complex environment, to be tactical and preemptive when opportunity provides and to be disciplined and deliberate in affecting our mandate. In this lower price environment, we are focused on maximizing the productivity of our capital expenditures. As such, our 2015 budget is designed to drive efficiencies by maximizing our ability to leverage fixed assets in surface infrastructure while producing the multiple sub-service intervals in our full field development strategy.

To complement the rigor of the budget plan, the Company's financial condition has been structured with a margin of safety, given the evident increase in the volatility of externalities in our business environment. We enter the year with liquidity availability of approximately $750 million, a competitive balance sheet without debt maturities before 2021, and pro forma net debt to 2014 EBITDAX of 1.7 times.

To speak briefly about the circumstances in the oil markets, it is a time of contradictions. For instance, it's curious that an approximate 2% global excess supply of oil, which equates to seven days of global consumption, has impacted oil prices by greater than 50%. Apparently, the implied marginal value of storage for seven days consumption is considerable, indeed. In contrast, preliminary 2014 figures indicate that discoveries of new oil and gas reserves around the world continue to deteriorate, with 2014 marking perhaps the worst year for finding oil and gas since 1952.

So small changes in short-term supply have trumped large ongoing deficiencies and long-term reserve replacement. If only we could each store our share of the oil we consume for a rainy day. Nevertheless, we are very pleased at Bonanza Creek to reflect upon our 2014 reserve replacement ratio of 330%, our 28% growth in proved reserves, which comprise 52% proved developed and 48% proved undeveloped, and our 40% growth in 3P reserves.

Our aggregate 3P reserves now register in excess of 550 million barrels of oil equivalent, which when compared to our current enterprise value, represents approximately $3.82 per Boe. As many of you may appreciate, our unconventional oil resource, which resides in the 6,500 foot deep reservoir, can be brought onto production and into sales lines in less than 45 days, and is thereby effectively an oil storage mechanism enabled by the matrix porosity of our sub-service geology. So storage we have.

As T Boone Pickens once said, and as may yet be relevant again, it has become cheaper to look for oil in the floor of the New York Stock Exchange than in the ground. Notwithstanding, it seems that the only certainty on the horizon will be the shortage of things that will surprise as many future outcomes appear plausible in the industry.

Well, we promised to keep it short, so I'll yield the floor to Bill to give a quick overview of the quarter's results and the equity offering completed earlier this month. I look forward to taking your questions.

Thanks, Rich, and good morning, everyone. As Rich mentioned, we grew production by 45% in 2014, proved reserves by 28%, and 3P reserves by 40%. A very successful year and I add my congratulations to the Bonanza Creek team.

I wanted to briefly comment on three notable topics in yesterday's release. The first is the non-cash impairment charge of $167.6 million. The significant decline in oil prices triggered the Company to assess its proved oil and gas properties for impairment.

If the field's net book value exceeds its future net cash flows, then the cost of the property is written down to a value based on discounted future net cash flows estimated using commodity prices established in our 2015 budgeting process. (Inaudible) impairment charge relates to the Dorcheat Macedonia Field, which represented the majority of the Company's proved reserve value at the time when the Company restructured from an LLC to a C-Corporation in December 2010 in the much higher oil price environment. None of the impairment charges is related to the Wattenberg Field.

The second topic to address is DD&A. For the quarter, DD&A was approximately $29.50 per Boe and $26.66 for the year. This DD&A per Boe level is a consequence of three primary factors. First, higher startup production growth rates, 45% in 2014, outpacing historical reserve growth of 28%. Second, the legacy effects of the cost attributable to the vertical well portfolio. And the third relates to the purchase accounting basis of our Mid-Continent assets that resulted from the 2010 corporate restructuring.

That said, when we isolated our DD&A rate to the current horizontal program in the Wattenberg and removed the costs associated with vertical wells, 2014 DD&A is more than 10% below the 2014 rate. This is more in line with what we would expect to see for these assets.

I would also like to highlight that contributing to the higher DD&A rate is a conservative booking philosophy for proved reserves. Currently, 95% of our PUDs are direct offsets to existing PDP producers, leaving only 5% of PUDs that are more than one direct offset from a producing well. In addition, we are very cognizant of the SEC's five-year PUD development rule and are diligent in only adding PUDs that are in our development plans resulting in a PUD percentage for the total Company of 48%.

The third topic to address relates to severance and ad valorem taxes. During the fourth quarter 2014, we decreased our Colorado severance accrual rate on increased ad valorem tax credits related to the 2013 production year. 2013 was our first year dedicated entirely to horizontal drilling in Weld County. The ad valorem credits are not eligible for deduction in the year the well is completed. We are now seeing the effect of more ad valorem tax credits eligible for deduction against severance taxes generated in the current year.

As you look to 2015, the guidance of 10% we had given for 2014, could have some downward bias but we are not adjusting our guidance to you at this time. Finally, I wanted to mention the equity offering we conducted on February 6. We raised just over $200 million of net proceeds, and after paying off borrowings on the revolver, ended the year pro forma with $172.5 million in cash.

We were very pleased by the market reception that allowed us to upsize by 75% from the original offering and still be 4 times oversubscribed. It was very reassuring to us that the market viewed positively our proactive response to the current environment. Now I'll turn the call over to Tony for an operations update

Thanks, Bill. As Rich discussed earlier, the confidence we have in embarking on the 2015 program stems directly from the success we achieved in 2014. Full-field development isn't a buzz word; it's where we are after four years of progressively intensive exploration, delineation, and optimization of the sub-surface. Everything we said we would do, we have done.

Remember, one year ago, the super section was our first initiative to understand well downspacing, interval stacking, and full-field infrastructure development. The super section showed us that stacked wells in the Niobrara B and C was an improvement over single zone pads. It was also the first time we used centralized processing facilities with multi-well pads, a model that will be utilized to a great degree in 2015. The 40-acre downspacing test with 18-stage fracs showed good early results, but clearly we had room for improvement.

We began testing 28-stage fracs in various 40-acre spacing configurations that each showed significant improvement culminating in a successful five-well stacked 40-acre spaced Niobrara B and C bench pad that checked the box for us that 40-acre downspacing and stacking between the Niobrara benches is the preferred way to develop this asset. Tremendous progress in one year, and we are fortunate to have largely completed it when we did.

During the fourth quarter, the Company finished its field level gas gathering infrastructure project, and in this current quarter is completing the installation of the remaining compression facilities. This system is expected to achieve lower and more stable line pressures at the wellhead as well as quicker recovery times in the event that third parties experience unplanned midstream downtime.

Moving on to reserves. As Rich and Bill have mentioned already, we increased proved reserves by 28% to 89.5 million Boe, [core] 97 million barrels on a three-stream basis, 76% of which is assigned to the Rocky Mountain Region. In Rocky Mountain Region, our PDP reserves increased by 55% and the associated PUD reserves increased by 26%. Reserve replacement for the Company was a strong 336%, and the total Company 3P reserves also increased by 40% to 497 million Boe or 558 million Boe three-stream, with net potential drilling locations increasing to over 2,300 locations company-wide.

Finally, as it relates to declining well costs, we are seeing encouraging movement from our service partners augmenting the already impressive efficiency gains we're seeing from our own efforts. We are inherently conservative and avoid aspirational projections about well costs, but rest assured that we are taking full advantage of our own efficiencies and with our supply chain organization working with our service partners, we expect to see 4,000-foot laterals before $4 million in the new future.

When we have sufficient clarity on our longer-term expectation for well costs, we'll happily update you all. I'll stop there and turn the call back over to the operator for Q&A.

(Operator Instructions)

Irene Haas, Wunderlich Securities.

Yes, my question has to do with now that in 2015 you're going to go into full development mode, so can you maybe give us a little color as to which part of the field you are going to start and what configuration then?

Interestingly, the acquisition acreage, when would we see some activity in that particular area? Would you need more time to have that figured out? Just want to have some sequencing just to get a feeling as to how you're going to tackle your very contiguous land base.

Yes, hi, Irene. What we are going to focus on, Irene, is the -- basically the middle part of our acreage, so what we call our heritage legacy position where the infrastructure is currently built out so the 35,000 net acres that we have previously developed. So our 2015 program is going to be broken up into about 70 plus wells with 14 pads with basically most of that all taking place on that middle position.

And again, it's because we are leveraging the existing infrastructure. As for the new acreage that we acquired last year, we'll have some limited exploration, or I should say development wells up there on the north side. Three wells is what we're planning for right now, but again with limited infrastructure we're going to plan to stay in that legacy position

Got you, and all the pads, I presume, has been built and are ready to go?

Well, the early part of our pads are being built, yes, Irene, and we are going to leveraging the existing infrastructure that's there but the pads are being built as we speak as we move through the program.

Great, thank you.

Brian Corales, Howard Weil.

Good morning. Maybe the first question for Bill.

Where do you feel comfortable on the balance sheet, or is there a metric that we should look at to assume going forward? And then when do you all think you can start putting on some additional hedges for 2016?

Well, I guess by metric by you mean on a leverage -- on the leverage side, Brian.

Yes. Yes.

You know, we've always been very conservative on the balance sheet, and I think the equity deal will -- it kind of demonstrates that we'll continue in that vein. On the metric, we had spoken that we had a metric in the past and we will endeavor to continue to keep a very prudent balance sheet going forward.

I'm not sure there's an exact number. We had two times in the past, and we'll endeavor to hold the very strong balance sheet going forward. On the hedging side, I think with the equity deal, it's given us a little bit more liquidity to assess where the market's going to go over the next few months.

I'm sure folks probably wouldn't want us to hedge at the current level, and we'll assess the market as it progresses. I think this gives a little bit more breathing room.

Okay, and then just one more.

And then also Brian, we want to see where costs are settling down. That's key.

Right, okay. And on the 3P inventory, I noticed that Codell increased a decent bit. Can you maybe comment? I know in the past, you all have tested thinner zones. What are all including right now for the Codell in that 3P inventory?

Brian, we are right now, we have the Codell on 160-acre spacing. On our legacy position, it's focused on the 15,000 acres on the western side, and then we do have some Codell locations on the new acreage position that we had picked up from DJR last year on the north side and on the south side.

And Tony, just to add to that, I know you all have tested the thinner Codell down to six feet. Have you included any of that into the 3P inventory yet?

Brian, no we have not. We did do a couple of tests and we're still evaluating that. We were encouraged with our first test that we had talked about previously at the 426 barrel-a-day IP rate for a 30-day rate. So we are still testing that, but no, we do not have included in our current 3P inventory.

Okay. Thanks.

David Deckelbaum, Keybanc.

Good morning, Rich, Bill, and Tony. Thanks for taking my questions. Sorry if I missed the color on this, but it looks like you are above plan, at least in the Mid-Continent in the fourth quarter. At 6,500 a day, I think the guidance for 2015 was to hold like 5,900 a day basically flat throughout the year. Can you give any color around that?

Yes, sure, David. Part of that production increase in 2014 fourth quarter in the Mid-Con was associated with our recompletion program. And those recompletion programs, it's a statistical play. We had a good run on those recompletions, but those recompletions do decline at a certain rate and so that is what we factored into our 2015 planning.

Do you have those recompletions declining at a higher rate than the standard well completion there or does it basically exhibit the same sort of curve shape?

Yes, it demonstrates similar decline rates as our current wells, but I think the biggest part of that, David, is the statistical nature of those recompletions. We do X number during the year knowing that a certain number will work out there, but, again, it's statistical and difficult to predict which best ones are going to happen at what time. That's why we do the number that we do.

Got it. And then, you mentioned the added compression helping with line pressures, and obviously fourth-quarter Rockies production was impacted by up 750 barrels a day from industry and downtime. What sort of downtime have you experienced so far in the first quarter? And can you contextualize any improvement from the investments you've made?

Well, I will say that obviously we've had cold weather and third-party downtime in the first quarter, specifically in January, but we want to reaffirm that we are confirming our guidance for the year. We do have the R compression in place; that is assisting us.

As you know, David, we have additional compression coming online with DCP, specifically with the 70 Ranch compressor station, the Rocky compressor station, along with the expansion at Lucerne 2 here in second quarter that will greatly assist us in line pressure. And one other addition is with the Grand Parkway. We will have a connection line connecting our eastern acreage to our western acreage, which will give us two takeaway points for the gas that's produced on our eastern acreage that now currently all runs through the Sullivan plant.

We will have some flexibility here in early second quarter to move that gas either to Sullivan or through the 70 Ranch compressor station onward to Lucerne 2, which will provide us a lot more, I think, consistency in our line pressures, that coupled with our own compression helping us out. And then our own compression also helping us recover from their downtimes as they go down and come back up.

Okay, so that at least -- it sounds like at least from the first quarter the percentage of downtime that you've experienced is much lower than fourth quarter. Is that fair?

We're not all the way through the quarter though, David, but I would say yes, but I do want to emphasize that obviously there has been cold weather in January, but we would reaffirm our guidance for the year.

The delays from the pad that was supposed to come on in the fourth quarter, that came on in the beginning of the year, right? So that would benefit your first quarter, as well.

That's correct, but we do have that factored into our production guidance.

Got it. I appreciate the color.

Phillips Johnston, Capital One.

Hello, thanks.

Just to follow up on Brian's question earlier on the Codell, you have expressed confidence that close to 30,000 net acres is prospective. Do you view that as a minimum type number that has upside potential as you continue to test that new acreage that you acquired, or do you think that's close to the final answer, so to speak?

I would say at this point that the 30,000 is probably a good number, but again, as with we've done with other zones, I hesitate to say that that's the extent of it. We will continue to test those boundaries and as we have success, we'll continue to push that. But again, we don't have that captured in our 3 feed, but I would think that we have additional potential, yes.

Okay, thanks. And then just with the shift from 4 rigs to 2.5 in the Wattenberg, can you walk us through the quarterly progression of your production volumes throughout this year? It seems like we should maybe up sequentially in Q1 and Q2 and then maybe flatten out for the remainder of the year. Is that safe to assume?

Yes, we have 14 pads that we are drilling this year. The intent of our plan for 2015 is to maintain exit rate from December of 2014 to December of 2015, so we expect a fairly linear progression through the year.

But as we've talked about with 2014 pads, pads tend to provide lumpiness in production, but there's been no intent to have a higher quarter or a lower quarter throughout the year. Our intent is to try to keep this flat as possible. But as for how it actually occurs, we are a little bit dependent on how those pads come online in each quarter

Okay, and then if I can follow-up on that. If we kept the 2.5 rig program in place throughout all of this year and pretty much all of next year, what would you expect your 2016 production to look like, at least from a directional point of view? And what would it take on the oil price front just to cause you to either further slow down activity or accelerate activity?

Well, I'll take your -- the first one is that we have not laid out our 2016 plan yet, and so we'll continue to address that as we go through the year based on the macro circumstances. As for which price, there's a lot of variables that go into what we would be planning to move, price, cost, forward-looking price curves, all that is stuff that we look at that all the time from our end. But we're not ready to, obviously, talk about 2016 at this point, and we'll just take those as we go through the year and evaluate a little bit further in the year from that standpoint

Sounds good. Thanks.

Paul Grigel, Macquarie.

Hi, good morning.

Just focusing on the differentials that continue to make progress in tightening up in the Wattenberg. Could you speak to what you guys view as a trend and is there potential for even inside the kind of 9 to 10 range as more takeaway capacity on the oil side comes on in 2Q and into later in the year?

Yes, at the moment we're looking at 10 to 2 with the guidance to head lower to that number, and the DJ lateral is coming on the second quarter and then clearly you have the Grand Mesa pipeline coming on next year. We're seeing some we real capacity open up into the West Coast and I think that all these factors are going to drive those differentials down to historical levels where I think September 2013, we're about $8 as the differential. So I think we're going to see that trend head in that direction again.

Great, and then, Bill, just following up on the DD&A comments you made earlier. I just want to make sure I understood them, saying that DD&A for the Wattenberg horizontals was 10% lower. As you look at 2015, would you expect 10% off of the 4Q number to be held for the Company as a whole or would we expect to be closer to the 29 and change number for the Company?

I think it would be 10% off the annual number, which is the $26.66, approximately 10% off for the whole Company.

Okay, thank you.

David Beard, IBERIA.

Hi, good morning, gentlemen. My question follows along Bill's line of thinking. But maybe you could talk a little bit about your decline rate going into 2016, just given you have a much different correction profile this year than previous years? And how much money it would take to spend to keep that flat again in 2016?

So our decline rate was at 45% in 2014. We're going to have a flash production exit to exit 2014 to 2015. I think if you look at the cost to keep that or maintain that, our budget we came out, which was at $420 million.

If you back off some of the infrastructure and back off, you probably get to 400, maybe a little bit below 400, and that basically is the main intentions for 2015. For 2016, we haven't gotten into that at this stage, but I think given more flat year to year on production, you should see 400 as the maintenance capital there.

Okay, so decline rates about the same. Of that 35, maybe a touch lower going to 2016 and a little less capital. Is that fair?

Yes, you would assume the decline rate should come down if you look at the trend from 2012, 2013, 2014, it's 54%, 53%, 45% the last three years. And with the larger base production, you should see that decline rate being a little bit lower for the year ahead.

Great. That's very helpful. I appreciate the time. Thank you.

Ipsit Mohanty, GMP Securities.

Good morning. My first question on oil realization. On one hand, your Wattenberg differentials are going down, which is great, but on the other hand, you have little for proportion of our cancelled property production in the mix for 2015 going further out, and historically it did give you an uplift on the pricing.

So net net, if you look at 4Q 2014 going forward to 2015, how does your oil realization look like as opposed to FPI? Is it going to be similar to 4Q? Any color on that?

We haven't really guided on the overall differentials for the year ahead. I think we can be just looking at Mid-Con, we would see those differentials staying the same. And then the Rockies from my earlier comment, I think that's what we should be looking at, so haven't really guided.

It's tough to look at quarter over quarter into the Rockies given the amount of changes going on. We've seen it come down from the high of kind of 15, 6 differential on the oil side. In 2014, all the way down to the $10, $12 range, and we see that going down further. We don't see a whole lot of change in Maycon.

Okay. And then second question on the production taxes. Is what you've seen in 4Q, is that sort of -- is that trend likely to continue into 2015, or is it going to -- the production's tax is going to go down even further.

I think you should really look at the annual basis, which I think we've guided at about 10% and we should just continue with that and moving forward into 2015 to be conservative on that side.

Be conservative, okay. And then you talked about well costs going down even further beyond $12 million on standard lateral. I see the model that one of the reasons the service and vendor cost reduction, it's hardly 5% in your current slide. Is that where you are going to see a substantial change as you look at the well cost reduction, or are there any other aspects behind going down below $4 million?

Yes, Ipsit. As we factored into our cost for 2014, changing to 2015, the two biggest pieces so far were the two things that we can control, which was reducing the number of stages from 28 to 25, and then of course leveraging our fixed infrastructure for the program, as I mentioned earlier. But the remaining cost reductions we would think would come from our service partners as we continue those ongoing negotiations with them, and so I think that's where that will come from in 2015

Just give us an idea of how you look at the train? Right now where it is, and where do you see that going to at the end of the year.

Well again, I hate to say it, but we -- I don't want to aspirational in my projections. When we looked at those costs at $4 million, that's where we stood at the beginning of January. And those were costs we knew that we could capture, and we were seeing evidence of that and we're very comfortable for putting that into our budget as that, as the known quantity. I would suspect as oil prices continue to remain lower that those costs will come down, but I can't tell you is what kind of percent those will be.

As you know, our basin in the Wattenberg is an active basin. Costs will come down faster in other basins where economics are more challenged. We have strong economics in the Wattenberg, so the activity levels will be slower to come down. And I would also say that we also are going to be hopefully seeing additional iron moving into our basin and that will be something we can take advantage of, but as soon as we get those numbers we'll get those to you.

Wonderful, and then my final question is on extended laterals. You've got as much of a contiguous block of acreage as anybody else among your peers, so and then some of them have guided for a higher proportion of extended laterals in 2015. I understand that's a jump for you, as well, given where you are, but would you see that sort of going up in terms of your comfort level? Doing these extended laterals, would there be any uptick in your current guidance of the proportion of extended laterals?

Yes, again, I would emphasize, our acreage is very well set up for extended reach lateral drilling, but the focus of our program in 2015 was to maximize returns on the wells we were going to drill in 2015. And the biggest part of that was leveraging the existing infrastructure and that existing infrastructure that we have is in the middle part of our acreage, that 35,000 net acres that made our legacy position.

Our northern position and southern position that we had recently acquired has less infrastructure, so we focused our drilling in that infrastructure area. Anywhere in that area where we could drill an extended reach lateral, because it is an improved economics over standard reach lateral, and leverage existing infrastructure, we did that.

But leveraging the infrastructure provided a more positive impact to the return on the well in 2015 than it is by drilling an extended reach lateral versus standard reach lateral. So a standard reach lateral with existing infrastructure yields better economics than an extended reach lateral that I would actually have to build infrastructure too.

So our program focuses on that, and if you look at investor presentation, we obviously have that slide of where our pads are. The pads on the western side of our legacy position are going to be 4,000 foot laterals, and that's because we actually started with 4,000 foot laterals in that. But the remaining parts of our position, you'll see us go to extended reach lateral drilling in the future

Thank you. Great color.

Ken Beyer, Stifel.

Hello. First question, I'm just wondering if you have any data available for your 25-stage wells, and how those are tracking against your type curve?

We have just started to implement the 25-stage technique. Again, we expect no degradation to the type curve. When we want to the 28-stage fracs from 18-stage fracs, the key there was we -- the 18 stage fracs on a 4,000 foot lateral had 220 feet approximately between stage.

When we went to the 28-stage frac, that dropped it down to about 145 foot between stage. We saw the benefit. As we would've done in a $90 world or a $45 world, we would then continue to optimize our completion techniques. With our engineering teams looking at it, we felt that we could come back on those 145-foot stages that add about 15 feet and bring us to about 160-foot first stage, which carves off those three stages taking us from 28 to 25 and still yield those same results that we have seen from the 28 stages.

Okay, perfect. And then in your 10-K release this morning, I noticed that it says that you're planning on developing the Niobrara B and C at 1,640-acre spacing. I was just wondering does that imply that you're seeing any well communication at the 40-acre spacing or are you still planning on developing the entire acreage on 40 spacing?

Our plan is to develop the Niobrara B and C on 40-acre spacing across our acreage position. We do have some areas of our field where we're drilling the extended reach laterals, but we are drilling those on 80-acre spacing at this time, but our intent is to go down to 40-acre spacing.

Okay, and then was just wondering if you could speak to the legislative environment in Colorado given the recent findings and proposals from the Colorado Oil and Gas Task Force? And kind of what percent of your acreage could be affected, or rather what percent of your acreage is located near suburbs or recreational areas?

So the Colorado Commission is reporting to the governor, so we're waiting to hear back from that. They have finished all their open mic sessions, which they had over the last number of months. When we looked at this in the past, the 2004's offset proposal, we were at 3% approximately affected using regular reach laterals. If you move that to long reach laterals, none of our acreage is affected by any setback rules proposed.

Okay, and then just one more quick one. Have you seen any consolidation in the bid-ask spread for a possible bolt-on acquisitions?

No, not really. We've seen there are opportunities come up. We look at the opportunities, and if they're appealing, we'll go after them.

We've got over 2,000 locations to drill in the basin, and we think we're attractively positioned from a contiguous acreage position. If we see bolt-ons, we'll go after them. We really haven't seen any changes in pricing at the moment.

Okay. Thanks for taking my questions

Andrew Coleman, Raymond James.

Thanks for taking my call here, questions. I don't think you covered this on the call, but I was just kind of looking through the notes there. With the slowdown in the Cotton Valley activity, I noticed that had a nice uptick in volumes, or about 10% percent growth in the fourth quarter there. What would the shape of that trajectory look like as you go through 2015? If you can give any color on that please?

Yes, hello, Andrew. The uptick again in the fourth quarter was associated with our recompletion program. That recompletion program is a statistical program, so have to do a certain number of recompletions to get those. What we can't project is exactly which ones are going to be the good ones throughout the year, so that's why we do a certain number of those.

The decline rate on those are approximated by what we have for our regular drill wells, so that's kind what we factor in there. But again, that production can be lumpy quarter to quarter as we do as those recompletions depending on how the statistics play out.

Okay, and you all added capacity out there, added a second plant I thought. That was maybe 18 months ago, Is there still capacity at that plant and does that factor into the equation, or is it a just probably the statistical nature of all those recompletions?

Yes, absolutely. We have the plant capacity. We have an integrated midstream asset that ties into our production out there. We have the capacity to handle the gas that we produce, and we do have additional room at those plants.

Okay, awesome. Thanks very much.

Jeffrey Connolly, Clarkson Capital Markets.

Hello. Good morning. Thanks for taking the questions. What kind of opportunity do you have to grow the lease position just through others either nonconsenting or just through organic leasing on your part?

Obviously, nonconsenting is a great way for us to continue to release our interests, certainly at the well bore. And we have seen opportunities come up and as we see them we'll take advantage if we think they are going to work with our position. Clearly, our contiguous nature of the acreage puts us as an advantage, as Tony has outlined earlier, and we continue to look at opportunities as they come up.

Let me ask one more for Tony. It's been harped on a little bit. But the $4 million well costs for the 4,000 foot lateral as of January, can you give us a number for what current AFEs are at?

Again, I want to reaffirm that the 4 million that we had at the beginning of January was a known number at that point factoring in our infrastructure, factoring in our completion design, and the current captured pricing that we had from our service partners. We are in the process of working with our service partners to see what those cost reductions can look like going forward, and as soon as I have more clarity on that, I'll sure get that out to you. We do suspect in this lower pricing environment for oil prices that we would suspect that the cost will come below that $4 million and as soon as I have the opportunity to have more clarity on that, we'll get that out.

I figured I'd give it another shot. Thanks.

You bet, no problem.

Mo Dahhane, Northland Securities.

Good morning. Thank you for taking my questions. Just very quickly, you talked drilling a second step out eastern Codell well. Any updates on that well?

No, not at this time. We have some additional Codell wells that are testing that thinner Codell acreage that are in progress, and as soon as we have some additional results on that, we'll get that out. But again, we're encouraged by the first one that we have done, but we have not factored that in to our 3P analysis at this time.

Got it. Appreciate it. And my second question about the Niobrara A well. Do you have a 60-day average for that well, or no?

The Niobrara A, again we had our IP 30 of 325 Boe a day. We are continuing to watch that well. We suspect that we'll have to do some work on the Niobrara A going forward, but that will not be something we're pursuing currently in 2015 as we've reduced the risk profile of our program to reduce catalyst testing.

Got it. Appreciate it very much. Thanks.

Matt Sorenson, Global Hunter Securities.

Thanks for taking my question. As you convert to three-stream, can you help us understand the impact on your gas and NGL differentials?

We're -- we haven't really quantified that in the public yet. And we're assessing that as we go through it, so there will be some minor impact, but we don't expect a whole lot, and we'll come back with more details as we get that information.

Okay, thank you. One more. As you move into 2016, about what portion of your undeveloped acreage at that time will have existing infrastructure on it?

I'm sorry, Matt. Could you repeat the question, please?

Yes. As you move into 2016, about what portion of your undeveloped acreage will have existing infrastructure on it?

In 2016, if I heard the question right, which portion of our acreage will have more infrastructure. I think, as you know in 2015, we're focused on developing our legacy position, because that's where the infrastructure is currently. And so we are not going to be investing a whole lot of money in infrastructure on the new acreage position ourselves in 2015 as we focus our capital to just strictly as much as we can to D&C. So really not much will change from 2015 to 2016 as we go into that year.

Okay, thank you very much.

Operator, I'm sorry, Kathy. Hold on just a second. Matt, I'm sorry. This is James Masters. I wanted to address your realization question on gas NGLs in the Rockies on the three-stream basis. Right now, it's a little bit hard to nail down, as Bill alluded to, because this is the first time we've really been selling our own NGLs for our own account.

But as far as we look forward to 2015 for our model, the NGL pricing is approximately 30% of WTI, and the natural gas realization is approximately 80% of Henry Hub, and that's pretty consistent across the Company. As you recall in the Mid-Continent, NGL has historically had a stronger pricing relative to what we see out of the Rockies, more in the 50% to 60% range. So, corporately we're seeing 30%, and as I said, gas probably about 80% of Henry Hub.

I would now like to turn the call over to Richard Carty, President and CEO, for closing remarks.

Thank you very much for your time on the call today. We appreciate the ongoing commitment of our investors in the Company, encourage ongoing rapport with them, and we look forward to a very successful 2015. Have a very good day.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.