Civitas Resources, Inc.
Q4 2013 Earnings Call Transcript

Published: 28 Feb 2014

[Operator:]

Good day, ladies and gentlemen, and welcome to the Quarter Four 2013 Bonanza Creek Energy Incorporated Earnings Conference Call. My name is Kathy and I'm your event manager today. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (Operator Instructions) As a reminder, this call is being recorded for replay purposes. I would like to turn the call over to Mr. James Masters, Investor Relations Manager. Please proceed sir.

[James Masters:]

Thanks, Kathy. Good morning everyone and welcome to Bonanza Creek’s fourth quarter and full year 2013 earnings call and 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 to introduce Marvin Chronister, our Interim President, and CEO in what is his first earnings conference call with the company. He will give an overview of the quarter’s results. Following his remarks Tony Buchanon, our Chief Operating Officer will provide an operations update. Bill Cassidy, Chief Financial Officer, Gary Grove, Executive Vice President of Engineering and Planning, Pat Graham, Executive Vice President of Corporate Development and other members of management are present and will be available during the Q&A portion at the end of the call. Today’s remarks will include forward-looking statements that are subject to many risks and uncertainties that could cause actual results to differ materially. You should read our full disclosures as described in our 10-K and our 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. Also, all results discussed today reflect continuing operations and do not include the results from our remaining California property. With that, I will turn the call over to Marvin.

[Marvin Chronister:]

Thank you, James. Good morning everyone, please forget my voice this morning I am fighting a bit of a scratchy throat. Regardless, thank you for taking time to join us as we discuss our fourth quarter and full year 2013 results which demonstrates again Bonanza Creek’s clear focus on execution and hitting our targets. We drilled over 100 horizontal wells in the Wattenberg Field since going public and have increased production in the Rocky Mountain region from approximately 2,000 BOE per day in the fourth quarter of 2011 to over 15,000 BOE per day this quarter, 95% coming from horizontal wells. As a member of the Board of Directors I have had the privilege of watching a small company transform itself into the third largest operator by drilling activity in the Wattenberg Field last year. In addition we have all witnessed and many of us participated in the outstanding returns that company has generated for its shareholders. Bonanza Creek’s assets, team and strategy remain firmly in place in the future’s pride. It is within that context that I would like to speak to Mike Starzer’s recent resignation. While his retirement came as a surprise to many on the Street, discussions between Mike and the Board have been ongoing for some time. The Board decided that it was in the best interest of the company to move forward without the loss momentum that offer the company’s a more formal transition process. However I want you to know that the Board is 100% behind the current management team and its capabilities to maximize shareholder value and is excited about the future of the company as ever. Mike [bolstered] a strong culture of integrity, team work and transparency that permeates throughout this organization. He remains an enthusiastic and steadfast supporter of Bonanza Creek and is available as a resource to the company through this transition. Meanwhile I consider the privilege to steward the company though this period. Now as it relates to the results we achieved in 2013, we had another outstanding year operationally and financially with significant additions to both proved and 3P reserves. Wells drilled in the Wattenberg Field performed as expected [variably] across the acreage and vertically between the Niobrara and Codell further de-risking our inventory runway. Meanwhile our Mid-Continent assets continue to function as the reliable orderly cash flow generator they have always been drilling production steadily 10% to 20% per year. Our production volumes are growing consistent with or just above our expectations. In 2013 we produced an average of 16,172 BOE per day exceeding the top-end of our annual guidance. For the fourth quarter, we reported sales volumes of 21,119 BOE per day, a 20% increase over the last quarter and 77% increase over the fourth quarter a year ago. These strong volumes compensated for weaker crude oil pricing received in both regions and drove net revenues for the quarter of $133 million. Before the effective commodity hedging our average sales price per BOE fell nearly 12% from last quarter to 68.48 per BOE. However, the company still managed an outstanding cash margin of approximately $52 per BOE. We reported EBITDAX of $99.5 million for the quarter and net income of $25.4 million or $0.63 per share. Per unit LOE expense was $5.55 per BOE in the fourth quarter and for the year LOE came in below our guidance range at $8.09 per BOE. The significant decline in fourth quarter LOE is due in large part to a true up of estimates made during the year. To a lesser extent, we also benefited from a high volume of new wells coming online in the Rocky Mountains during the quarter. Going forward we expect our per unit LOE to range from $8 to $8.60 per BOE for full year 2014. Per unit cash G&A expense decreased quarter-to-quarter to $6.34 per BOE. For the year, cash G&A expense was $7.24 per BOE, above our stated guidance range of $6.25 to $7. This is the niche we are happy to report as we exceeded our targets for production and other operating metrics and accrued for employees bonus payouts that exceeded the initial target levels set forth at the beginning of the year. Excluding the additional bonus expense, cash G&A would have been right on target at $6.49 per BOE. Finally, we maintain a strong liquidity position of approximately $600 million and attractive debt metrics at year-end of just 1.2 times debt to trailing 12 EBITDAX and a net debt to capital ratio of 30%. We also have an attractive hedging program that currently protects 61% of our forecasted 2014 crude production at approximately $90 per barrel and 63% of forecasted natural gas production at over $4 per Mcf. We are fortunate to face the future from our position of relative strength, while macro peers regarding crude oil prices have abated somewhat would position the company to both prosper and the good times and take advantage of opportunities in the downtimes. I will now turn the call over to Tony to discuss operations in more detail and the encouraging results we are seeing from our catalyst testing in the Wattenberg Field and in Southern Arkansas.

[Tony Buchanon:]

Thanks Marvin and good morning everyone. My hat goes off to the Bonanza Creek team for another terrific year, the year in which we grew production by 74% and increased proved reserves and Wattenberg horizontal 3P reserves by 32% and 30% respectively. We invested approximately $461 million, the majority of which we used to drill 134 wells and complete 121 wells in our two quarter regions. We guided the street to a significant ramp in production during the second half of 2013 and delivered growing volumes by over 30% in the third quarter and by 20% in fourth quarter to exceed the top-end of annual guidance by nearly 200 Boe per day. Crude oil and liquids volumes remained steady at approximately 71% of total production, accounting for 88% of company revenues, most importantly though, this was all accomplished without a last time incident for employees or contractors. For our 2013, as prepared, proved reserves report, we switched our third-party reserve engineer to Netherland, Sewell & Associates. At year-end, we reported proved reserves approximately $7 million Boe, a 32% increase over 2012, strong reserve replacement, -- and a TD 10 of our proved reserves increased from $835 million to $1.2 billion. In the Rocky Mountain region Bonanza Creek increased proved reserves by 16.5 million Boe or 51% overcoming a negative envision of approximately 7 million Boe due predominantly to the ongoing process of transitioning from a vertical well program. 2013 was an important year for further delineation and de-risking of the resource potential that exist in the Wattenberg Field. We have drilled over 100 horizontal wells in the Niobrara B bench and the Niobrara C bench, across the North, South, East and West except of our acreage and in the Codell formation across the western portion of our acreage. We have also drilled both standard length and extended reach lateral and we advanced from Niobrara B bench well down to 40 acres. We’ve been working in this area for over a decade and have put a significant amount of technical analysis into the evaluation of our 3-P reserves. Actual results achieved and the approximately 4,500 net acres acquired during 2013 gave us the confidence to boost Wattenburg horizontal risk 3-P reserves by approximately 30% of our last year’s estimate presented in our analyst day and 237 million Boe to 308 million Boe. In addition, we increased our well count to over 1,800 locations providing the company with approximately 15 years of drilling inventory. Moving on to this past quarter’s results, production from the Rocky Mountain region was 15,036 Boe per day. During the fourth quarter on 15 operated completions and 10,618 Boe per day for the year on 73 operated completions. Realized pricing declined 14% relative to third quarter to $84.13 as a result of lateral differences to WTI in the DJ basin caused by seasonal refinery maintenance, weather issues and a temporary inconsistent supply. Fortunately the worst of the spreads appeared to be behind us. We have seen deducts improve over the past 2 months as a result of less competition from Canada and Bakken barrels. Our weighted average realized crude price for February of 2014 with NYMEX less $11.43 and we expect further long-term relief with the (inaudible) expansion and increased utilization of the Tampa rail facility providing additional takeaway option out of the DJ Basin. With respect to our current operations, severe cold temperatures have had a negative impact on production at certain times in December, January and February. Our Rocky Mountain operations teams have been working around the clock to mitigate the impact of the extreme weather and we expect volumes to be within guidance for the first quarter. A large reason for this is the team’s operational execution of the Super-Section which commenced flow back almost two weeks ahead of schedule. I am speaking of the Super-Section early flow back results are showing strong flowing pressures and good hydrocarbon respond. Currently, all 50 wells are producing oil and natural gas. The two western most pads testing the tightest down spacing concepts are performing as expected we will continue evaluate flow performance and analyze pressure data that we are beginning to receive from the wells and we’ll have more to discuss during our first quarter call in May. As you all know the Super-Section test combined all the data and key learnings from our catalyst well program to-date and rolls it together into one section with the design to maximize recovery and capital efficiency. The [3/5] well pads stimulate potential pattern configuration and down basin concepts in the Niobrara B and C Benches and the Codell that could be the foundation of future patch style in section by section development. Since 2012 we have drilled five Niobrara C bench wells across our acreage these wells have produced within the range of an average Niobrara B bench and we see viability across our entire position. We have also drilled five Codell wells on the western half of our acreage which have performed above the average Niobrara B bench well. We are excited about the possibility of expanding the Codell program to the east unlocking additional inventory and reserves. And we will drill two wells this year near the eastern boundary of our western acreage. Another element of the Super-Section test is a downspacing to 40 acres in Niobrara C and D benches. The standalone test completed in the 2013 performed within the range of expected outcomes for 80 acre B bench wells. And we are encouraged by enabling operator’s comments stating that 40-acre spacing in the Niobrara B bench is viable. While the Super-Section test is about optimal configuration of laterals, we continue the testing application of extended reach laterals on our property. We believe the operational risk in drilling and completing a extended reach laterals have been reduced and plan to increase our exposure by drilling four 9,000 foot laterals and six 7,500 foot laterals in 2014. We are encouraged by the fact that the average 90 day rate on the two 9,000 foot wells drilled in 2013 reported only a 5% decline from the average 30 day rate. While still early we estimated an average EUR from B2B two wells in the 700,000 to 800,000 Boe range. Our data suggests that extended reach laterals are more capital efficient and have greater EUR collateral foot than one section laterals and we are excited about their potentials to add incremental value. Moving onto Mid-Continent region, I am pleased again to report strong and consistent results. This asset is so reliable and provides the stable base of liquids production and cash flow that it is a huge benefit to our business. Production from Arkansas properties averaged 683 Boe per day for the quarter, a 13% increase over fourth quarter last quarter 5,554 Boe per day for the year an 18% increase over 2012. Realized pricing in the region for crude oil and natural gas typically hovers around NYMEX. And our NGLs are sold without ethane and average approximately 54% of WTI in 2013. Also, we continue to be encouraged by our 5 acre downspacing test. As we have not observed interference between wells and initial production has been above expectations. We plan to drill another ten 5 acre spaced wells in 2014 an attempt to forward delineate the downspacing potential in the Dorcheat Macedonia field. I will conclude with the observation that this is an exciting for Bonanza Creek. I'm very pleased with the progress we have made over the past couple of years transforming a vertical well development program in the Wattenberg Field into one of the most dynamic horizontal oil plays in the United States. 2014 is off to a strong start with the super section ahead of schedule and early results looking positive. We have an ambitious program set for this year targeting production growth of approximately 50% with increased catalyst derisking activity, including a Niobrara A bench test in the Wattenberg Field and a Niobrara exploration test in the North Park basin. We will continue to test downspacing in sacking arrangements in the Niobrara B and C benches while expanding the Eastern boundary of the Codell formation. Execution as always is the key. Frankly, I think it’s what sets Bonanza Creek apart. I'm proud of our team and our asset and will go forward in 2014 with the same dedication to operational performance that we'll always have. With that, I will turn the call back over to the operator and open it up for questions.

[Operator:]

(Operator Instructions) Your first question comes from line of Irene Haas of Wunderlich Securities.

[Irene Haas:]

Hey good morning everybody great quarter. And my question has to deal with your natural gas liquids pricing for fourth quarter which was pretty strong and of course first quarter is going to be pretty good too, so should we kind of bump realizations versus WTI for first quarter and we taper it off for the rest of the year just like a low guidance on our natural gas liquid pricing?

[Gary Grove:]

Hey Irene, this is Gary. And so as you know when we just record liquids the bulk of that if not every bit of it coming from Arkansas and since it’s just the propane plus stream, we actually see stronger realizations versus WTI and as that post them. I think just to mark it down as (inaudible) is those liquids go and so our expectations are to just right along the same kind of range of pricing that we have received from Mont Belvieu over the last six months. So that's kind of how I guide you going forward if that’s helpful at all.

[Irene Haas:]

Okay. Great thanks.

[Operator:]

Thank you for your question. The next question comes from Welles Fitzpatrick of Johnson Rice.

[Welles Fitzpatrick:]

Good morning.

[Gary Grove:]

Good morning Welles.

[Welles Fitzpatrick:]

On the Codell step out wells to the east, are those the annual oil lease permits that look like they are pretty big step out? And if so are those going to be first half event?

[Gary Grove:]

Hang on one second; let me check that, for you exactly -- if I can -- I believe those wells are going to be in the second half of the year is what it’s looking like. And I am not sure on the actual name of the permits to be honest with you. I’ve got the section numbers it looks like, but I don’t have the names on that. Can we get back to you on that…

[Welles Fitzpatrick:]

Yes, absolutely. I’ll circle back.

[Tony Buchanon:]

In the second half, but they will be in probably the second half of the year.

[Welles Fitzpatrick:]

Great.

[Marvin Chronister:]

And I think Tony is talking about, they’re going to be more towards the eastern, kind of towards the center of all the acreage position if you will when you look at the entire acreage position that we have. So, like where we’ve talked about those wells in the Codell, only being on the west. These will be on kind of that eastern edge of the west, if you will.

[Tony Buchanon:]

The middle of the total, yes. Right here we go.

[Welles Fitzpatrick:]

Okay. Fair enough. And then one more, on the long laterals, the one that was I think in the 500s came on in 500s and it seems I think kind of flat, almost inclining on production. Can you talk a little bit about what you think is going on there? I mean is it the yield stages, maybe pension off some of the toes or what do you think is going on there?

[Tony Buchanon:]

This is Tony. I’ll go ahead and take that. Well, initially that well, one of the things we saw and we’re still trying to figure out a little bit is we saw really, really good oil production on that but a little bit of a suppressed gas rate. And so we saw the gas start to come up as the well continued to increase. You have 9,000 foot lateral. When you have 9,000 feet out there and you have 36 stages contributing, they’re all going to contribute in a different way. And of course pressure, the way those things work with the different pressures, at different stage can contribute at one point, one that be precious on other stage can kind of kick in. So it could be coming from the toe or it could be coming from lateral. Now, we will have to continue to evaluate that but we also put on our controlled flow backs, if you will. And we’re not over producing those things upfront. So that helps constrain probably a little bit of that volume on the IP 30s. But again, I would think that it’s just your natural performance on this well. And again, we saw the gas rates start to come up, the well is a little more overly early on. But other than that that’s a about all I have for you. We are very, very pleased with the results as I said on those last two wells with the average being in that 700,000 to 800,000 Boe -- EUR range, very comparable to the results we are seeing from Noble under wells ranch on their 9,000 foot lateral. So we’re very pleased with those results.

[Welles Fitzpatrick:]

And some folks (inaudible) goes west to try and mid lateral even long lateral Codell at this point; is there any temptation to do that or let them figure it out maybe?

[Tony Buchanon:]

Actually we have in our 2014 plans to do a mid and I believe a long rich lateral in the Codell.

[Welles Fitzpatrick:]

Okay. Thank you so much, great quarter.

[Operator:]

Thank you for your question. The next question comes from the line of Mike Kelly, Global Hunter Securities.

[Mike Kelly:]

On Bill Barrett conference call we spoke to increase variability on the northern part of their acreage for the Niobrara B just wanted to get your take on what you are seeing there in terms of the ultimate consistency across your acreage and maybe we will just start there? Thanks.

[Tony Buchanon:]

And again if I heard the question correctly it’s the consistency of the Niobrara B across our entire acreage position, I think…

[Mike Kelly:]

I think -- go ahead. I am sorry. You could explain C and Codell as well too.

[Tony Buchanon:]

Okay. I think if you look at our Niobrara B, when you look at the Niobrara B and the Niobrara C, it is present across our entire acreage position and it’s fairly consistent. We may see on eastern edge being a little more (inaudible) than it is on the western side. But again we think it’s fairly consistent across the acreage position, both in the B and the C. We also think it’s pretty consistent to what if you go back and look at our analyst day presentation, the cross-section that ties back the wells ranch, pretty consistent with what they have on wells ranch in the B and the C. The Codell, I think it’s very consistent across, we have it present across our entire acreage position. But when we talk about our present what’s kind of included in our 3P analysis is about 15,000 net acres on the western side and that Codell cut off that we are using right now is an 8 foot thickness with 10% porosity. So we think that the five wells that we drilled to date have pretty confirmed that that 8 foot thickness with 10% porosity across of 15,000 net acres is now very liable force, but the key for us is that the Codell thus then across to our eastern side and it’s about 2 foot thick as you edge our acreage on the eastern side. What we are going to be testing with those two wells as we move toward our eastern edge of our western boundary if you will, is testing down about a 6 foot thickness because the Codell actually sits on top of the Carlile shale, and the Carlile shale is about a 30 to 35 foot oil bearing shale that actually sources the Codell. And what we are seeing is that we may be having the opportunity to actually continue to abstract resource and not have to have an 8 foot thick Codell because the key on that is that we thought we had have 8 foot actually landing 4,000 foot lateral all the way in zone in the Codell, and what we found out on a couple of our wells, we can actually get into the Carlile somewhat and still effectively complete the wells. And so if that’s the case, we may be able to get on to the 6P, 4P and maybe even 2P. And that’s what we are hoping to expand via Codell potential. So, that’s kind of how I see the A -- the B, C and the Codell across our acreage.

[Mike Kelly:]

I appreciate that color. And follow up from me on the Super-Section pad here. Very encouraging to hear that early [floor dock] looks good. You tested quite a bit of different concepts there. And Just curious and it really success and out here across everything you’re doing there, the level of confidence, what kind of incremental that you gain just right off the pad there? Does it give you enough confidence to do another high figure in that location count or do you still need more history throughout the year? What could be going from it just on initial success, I guess my question?

[Tony Buchanon:]

Mike, my first pass on the initial success is that obviously it helped us continue to optimize what we need from a drainage standpoint of how many wells we need to put in the section. Of course this is helping us determine that more wells in a section is better for right now, very interested to see the 40 acre space test that we have in the B with the combination in the 40 acres in the C just below. That’s going to be a really key test for us. If that is successful, I think obviously yes, you can see us as looking in 2015 not so much ‘14, starting to alter our drilling plans, pad development to kind of more be in line with those patterns that we test there with those pads. The only thing I wanted to caution that’s on is that, obviously we talk about the extended reach lateral testing that we’re doing too. So that’s something that we’re going to want couple of that together right. So, we’re going to want to look at some pads possibly in 2015 as we continue to execute on our extended reach lateral program demonstrating that we can mechanically and operationally execute those as we do our 4,000 foot laterals and can find that with the data that we’re getting out of the Super-Section. So we may see something in ‘15 that looks like a Super-Section that has extended reach laterals in it. I think you might be seeing some examples of that maybe to our neighbors to the north a little bit. But that's how I see that coupling together. As for increasing well count and all those kind of things, it’s really kind of a little early to tell right now. I’m really, really not sure, what we’ll do from that standpoint obviously, but the data will just kind of bear out as go forward.

[Mike Kelly:]

Great, thanks guys.

[Operator:]

Thank you. Your next question comes from the line of David Amoss of Howard Weil.

[David Amoss:]

Good morning guys.

[Marvin Chronister:]

Good morning David.

[David Amoss:]

I really appreciate the conversation about or the color on the thickness threshold of the Codell as you move west to east and the potential to go into Carlile to some degree. Can you kind of give us a little bit more on, I mean I assume that these two wells are going to be somewhere in the middle of that 8 to 2 foot thickness grade and then what and for how long and then possibly move further, how are you going to go about testing the rest of your acreage and what’s the timing of it?

[Tony Buchanon:]

Sure. This is Tony again. With the way I see this, we have those wells scheduled in the second half of the year. We would like to drill those wells, get some production data off those guys. I’m going to say, we’d like to get a good six month production history out of those, just to ensure that they are performing within our normal Codell, our range of expectations. But I think you can look for us if those are successful that’s going to give us plenty of opportunity to test that concept in 2015. I would suspect right now that we would gradually step it out, we probably wouldn’t reach all the way across to the far eastern edge of our acreage position to test that. But again, however we’ll look at the data that comes in from these two wells. If they are very successful, we might see that; if they are right in range, we may probably continue with our gradual step up. But I think you can see us probably pushing that in 2015 for sure.

[David Amoss:]

Okay, great. That’s really helpful. And then just one more, you guys have been pretty successful adding acreage this year, can you kind of give us what you’re seeing today in terms of a competitive landscape, I mean is that kind of the 3,000, 4,000, 5,000 acres a year, is that kind of the run rate to expect in ‘14, ‘15 as well?

[Tony Buchanon:]

Yes. Actually we do, we’ve done a number of these small high bolt-on acquisitions that we’re looking at. And right now we’re kind of seeing that same 10% acreage for this year compared to or similar to last year.

[David Amoss:]

Okay, great. Thank you very much.

[Operator:]

Thank you. The next question comes more the line of David Beard of IBERIA.

[David Beard:]

Good morning everyone.

[Tony Buchanon:]

Good morning.

[Marvin Chronister:]

Good morning.

[David Beard:]

Could you just talk a little bit about near-term and longer-term crude oil differentials in the Wattenburg?

[Pat Graham:]

Sure. I think as we released we are probably in the lower teens on our differentials at this point. Certainly and that’s compared to the historical differentials of about $8 that we’ve seen over the past couple of years. All we’ve seen that’s kind of impacted us some short-term some a little bit longer term. The weather issues that we’ve seen over the last I guess 6 months [reporting now] some of the macro refinery issues that kind of popped up last fall and then the takeaway capacity that we’re starting to see coming into the basin capacity that’s been augmented overtime. In addition to [Wycliff] increasing their capacity for the express hiring into the basin and then take some capacity away from there, so our long-term I guess as an example we are probably in the 11 to 15 range or so over the last couple of months. We see that maybe stabilizing in the near-term going to the 10 and then as some of these other projects come on hopefully getting backed down in the $8 range, the historical range.

[Gary Grove:]

Yes. And this is Gary, just a little color on we started we just started seeing these kind of bumps up from historic right around the October timeframe of last year and we kind of crescendo it up in the December maybe being slightly more than $17 off of WTI. The first quarter I think when you look at the number we’re right around 13.40 off of WTI, excuse me for the fourth quarter of last year on average and then as Pat just mentioned, we’re currently in that $11 to $12 range for the first quarter of this year and continue to move downward we think. So that kind of a short-term acuteness of it and then as Pat well described what we think it’s coming in the future.

[David Beard:]

Got it. And as a follow-up on different topics, one of my favorite topics, just talk a little bit about North Park Niobrara and what your development plan is and maybe over the next 18 months what you see up there?

[Tony Buchanon:]

This is Tony. We are planning for North Park; we are planning to drill two exploratory tests in North Park in 2014. We are planning that first one is scheduled for about May. We will drill a pilot hole and then backup from there and drill a horizontal Niobrara well. We’ll then extract the data from that horizontal Niobrara well, the key learning that we get from the pilot hole the key data that we get out and then apply that for our second well that we will drill up there in probably towards the end of the summer, somewhere in August before the weather sets in and get back down at that point. But the both horizontal Niobrara tests probably be most [intriguing] thing about what we’re testing up there is a highly fractured part area of the Niobrara and our technical analysis looks like that this could be a situation where we control horizontal in this, one of the liner, but have to frac. And so we will evaluate that, and if you don’t have the frac obviously there is a great improvement to the economics. But that’s our status. As for what the upside is, we’ve got about 20,000 or so net acres up in the North Park Basin. And we just have to really extract the data from these two wells to see what kind of running we would have, but obviously our technical analysis that has been done, has been to the point of wanting us to go drill a couple of wells up there, so we do definitely see some potential for sure.

[David Beard:]

Okay, great. I appreciate it. Thank you.

[Operator:]

Thank you. The next question comes from the line of Adam Michael of Miller Tabak.

[Adam Michael:]

Hey, good morning, guys. If I could follow-up on the North Park Basin, I think your comment was there is about 20,000 net acres up there, can you run through the current state of the leases and do you have options extend leases there, there are opportunities to pick up more acreage up in that area?

[Pat Graham:]

Adam, this is Pat. We have done some drilling up there over the last couple of years, some of the drilling that we’ve done has shown that, maybe a better picture than what we’ve had in the past as far as where we are in the Niobrara and the gas zone and the oil zone. Some of the -- probably two of the wells that we drilled over the last couple of years have shown that Niobrara be deeper than what we originally anticipated, so with that in mind whenever some of those leases expire. Some of the kind of mid-structural leases that we have, we drilled one well maybe kind of 1.5 wells maybe best way to put it kind of that part of the structure? And Tony had given us a better picture of where maybe the oil and gas contactor is if you will. So we’ve retained a number of leases on that trend where Tony is talking about drilling is really help. Almost not quite to the half of the structure, but really within the North and South units that we tell since 2006 I guess it is. So I think we're comfortable right now with the acreage position that we have and that substantial part of it is in the oil window of the Niobrara.

[Gary Grove:]

Adam, this is Gary. So those two units that Pat referred that have a large portion of acreage up there, they are held by production from other zones, which have been on product – been producing for quite a while. So as far as expiry there, there is no issue on that particular part of the acreage.

[Adam Michael:]

Okay. That's helpful. And then I could you go back to the extended rich laterals, I heard a 700 to 800 EUR for a 9,000 foot lateral. I'm just wondering what the current costs look like when you compare them to 4,000 foot $4.2 million horizontal.

[Tony Buchanon:]

Yes, good question. This is Tony again. The cost, right now we're looking at $7.5 million on those extended rich laterals at 9,000 feet.

[Adam Michael:]

Okay. And then one final question on the super section you guys are moving more towards the pad drilling and drilling these wells closer together, are you seeing any kind of cost savings, is there an opportunity to drive cost down even lower in 2014?

[Tony Buchanon:]

I think inherently from an infrastructure standpoint, once we get this thing up and running there is probably going to be some cost savings with facilities and combined infrastructure and all that. To be honest with you this is our first pass out of the box at this and so I don’t really want to give you any direct numbers on that, but I think going forward directionally, yes, I mean you can combine facilities and combine infrastructure there is going to be strategies there that will help us drive down the cost which is part of the economic and capital efficiency piece of the equation that we’re trying to improve.

[Adam Michael:]

Okay. Great quarter guys, thank you.

[Tony Buchanon:]

Thanks Adam.

[Operator:]

Thank you. The next question comes from the line of Andrew Coleman of Raymond James.

[Andrew Coleman:]

Hey guys, thanks a lot for taking my questions and good morning. Let me ask Adam’s question in a slightly different way I guess thinking about the facilities, synergies, could you just give me a rough, I guess a little [aroma] how do you think about fixed versus variable split between the cost (inaudible) right now?

[Tony Buchanon:]

Andrew, you’re talking about on the capital side or on the lease operating?

[Andrew Coleman:]

On the OpEx side, are you getting improvements or I guess with some of the synergies comp and in fact we’re getting new facilities going out in the field and I’ll recognize that you might not be the anchor tenants on some of those facilities. But do you still get a bigger fixed cost that you can kind of ramp up until you get your synergies there or is everything variablized?

[Tony Buchanon:]

Andrew I think the biggest thing on the operating expense side is that we obviously are combining facilities with this pad drilling. And so that gives us some opportunity there to go from one location rather than multiple locations actually some advantage is there on infrastructure as you can imagine. Just on how we daily operate all of those facilities, so there is some incremental advantages to that. As far as trying to put a hard number on that and great spread between fixed and variable I mean you’re still going to see quite frankly a lot of variable expense out here just because that’s the nature of the asset and low cost operating has also been a key for the DJ Basin and I think you’ll continue to see it be that way going forward with the opportunity to lower them as we do these kind of larger and larger areas if you will together.

[Andrew Coleman:]

Yes, yes. And I guess looking at the other side on I guess can you tell me what you’re doing completion I guess in time and time I think last year at the Analyst Conference you guys were talking about something like 45, 50 days. I guess has that improved much over the last few months or do you have a view on a target as you may from pad drilling what you could see in terms of total start to finish time on those wells?

[Marvin Chronister:]

Well I guess we are making improvements. Our spud rig release times and spud to spud times not considering when you’re on pads. We have dropped down to about 11 days. Obviously when you get on pads we can even reduce that down to spud to spud times, actually we’ve seen days at 8 and 7 days because of the lack of needing to move the rig. But the trick is on this obviously as you get on pads when you start talking about spud the first production though of course depending on the size of the pad the first well you spud it’s a 5 well pad i.e. on the super section that well will sit and waiting for the 5th well on the pad is and drilled and then you have to come back in and complete all 5 wells. And then you have to obviously do the cleanups in all 5 wells and then production equipment hookups on all 5 wells before you turn that first well on the pad online. So that’s going to be very skewed when you look at that. As we get into pad development I think it’s going to be more as you’ve mentioned is you’re going to be more along the line to how fast can we do pads but then you’re going to have to meet similar size pad. So I think we focused what we’ve really focus is on is the operational efficiencies like on the spud to rig release on the well part, how fast we can frac the wells, how fast we can get in with the coil tubing and it’s on a well by well basis to clean the wells out and then run tubing. That’s where the efficiencies will be built. And then it will all run together in the pad development, but if you just look at it from the outside it could be very skewed because of pads, because of that timing delay, waiting for other wells to come online. And that delay is on purpose because at the end we want to maintain pressure on those well bores while we’d complete the other wells so that we maximize [realization] of the reservoir.

[Andrew Coleman:]

Okay. Presumably though as you go to pads you are going to have less downtime waiting for the crews to kind of move form location to location and I guess just curious as we I expect once the pads get up and running you are going to get the economies of scale which will lead to ultimately net reduction in the per well time and just may not be super laid out at this point then is that fair?

[Marvin Chronister:]

That’s probably pretty fair. And then I would say for going forward I know you are trying to dig probably get go, what can you use for a model standpoint. I think sticking with that 45 days right now is probably the best way to go, we could start to modify that as we get more and more pads for you to compare that case, but right now I would stick with the 45.

[Andrew Coleman:]

Okay, alright. And then last question I had was, still got our pretty clean balance sheet. I guess what with 1,700 locations kind of inventory, what’s the time line or sign pose that we might see and additional step up in activity to accelerate the development there?

[Bill Cassidy:]

This is Bill Cassidy. We have got our plan laid out for 2014 and I don’t think we are going to see a whole lot of change from that. We want to get the results from Super-Section that may affect the back half of 2014 but certainly ‘15. And I think really we will be absolutely focused on keeping a clean balance sheet. Our trading as four months at EBITDAX is 1.2 and 1.3 times, we want to keep it like that. So we will make sure we manage the operations accordingly and keeping eye on balance sheet.

[Tony Buchanon:]

Yes. This is Tony. Bear in mind, one of the key lending factors to accelerating and making sure, we’ve got the technical data and as Bill has mentioned in the Super-Section as we acquired that. What we don’t want to do is drill so fast and get wells out there that we regret we have drilled and I will take you back to important well drilling, have we known what we could with horizontal wells right now. We would probably wish, we wouldn’t had drilled those vertical wells even though they seem they were a good idea at a time.

[Andrew Coleman:]

Okay. Fair enough and wait for the Super-Section wells and nice quarter, thanks.

[Marvin Chronister:]

Thanks, Andrew.

[Operator:]

The next question comes from John Malone of Mizuho Securities.

[John Malone:]

Yes. Good morning, guys. Just go back for a moment upside from (inaudible) Codell drilling, certainly actually able to make 60 or even 40 work, what is that due to that 15,000 acres, how is that increasing?

[Tony Buchanon:]

Yeah, well, again. I would direct you if you came back about the cross section we had for Codell back in our analyst day presentation, but the Codell is present across 15,000 net that we talk about has really kind of centered on the western side of our acreage and not our acreage is kind of broken up, we kind of have the western side and the eastern side. If we can make six foot, four foot and two foot Codell thickness work that would expanded across our entire eastern acreage position, which would be we have got about 35,000 net acres total these days. So that would probably expand that potential almost across that entire amount.

[John Malone:]

Okay. But if…….Go ahead.

[Marvin Chronister:]

I am just going to say if you think of this as obviously have these Codell things done, and its sitting above Carlile Shale that Tony has mentioned earlier. So what we are looking at right now is we are looking more of maybe a Codell/Carlile complex as it moves to the east. And if we are successful with that and we continue to see good results, obviously that could march to the farthest eastern part of our acreage. And as Tony mentioned, you go from let’s say 15,000 acres on the west to encompassing the entire acreage position, just like in the B and the C in the Niobrara.

[John Malone:]

Okay, that’s helpful. Thanks. And then my second question is more of a sort of a high level reserve accounting question. By my read, it was about 10 million barrels that you took off from -- about 70% of that 10 million barrels that you took off and negative revisions came from those from vertical to horizontal. How do you make that back? I mean obviously those hydrocarbons are still in the rocks, so what’s the pass; could that be added back in a year or how long would it take to kind of bring those back on to the books?

[Lynn Boone:]

This is Lynn Boone. I think we’re taking those reserves off the book as we drill horizontal wells and plan to drill in the next year additional horizontal wells. So we’re actually replacing those reserves with our horizontal pad. There was a significant amount in our revision this year that was associated with behind pipe work that we are no longer committed to doing the vertical well program. So, I think over this coming year or 2014, we will be taking the remaining 12% of our vertical reserves which equals our PUDs off the book. And at that point, we’ll just have PDP reserves in our verticals. And I think over the next year or so, we’ll actually make up the difference completely with regard to -- including those reserves in the horizontal numbers.

[John Malone:]

Okay, thanks. So, I can think of the PUDs as being the vertical program that's going to come up to books.

[Lynn Boone:]

That’s correct.

[John Malone:]

Okay. Thank you

[Lynn Boone:]

You’re welcome.

[Operator:]

Thank you for your question. We have no further questions. Thank you for your participation in today’s conference. That concludes the presentation. You may now disconnect. Good day.