Civitas Resources Inc (CIVI) 2013 Q4 法說會逐字稿

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 the event manager today.

(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.

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 been a 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 updates. 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 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 properties. With that, I will turn the call over to Marvin.

Thank you, James. Good morning, everyone. Please forgive my voice this morning, I'm 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've 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've all witnessed, and many of us have participated in, the outstanding returns the Company is generated for its shareholders. Bonanza Creek's assets, team, and strategy remain firmly in place and the future is bright.

It is within that context that I'd 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 was of the best interest of the Company to move forward without the loss of momentum that often accompanies 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 fostered a strong culture of integrity, teamwork, 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 it a privilege to steward the Company through 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 proven and free 3P reserves. Wells drilled in the Wattenberg field performed as expect aerially across the acreage and vertically between the Niobrara and the Codell, further derisking our inventory runway.

Meanwhile, our Mid-Continent assets continue to function as the reliable oil and cash flow generator they've always been, growing 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 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. (Inaudible) 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 a miss we're 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 level 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 maintained a strong liquidity position of approximately $600 million and attractive debt metrics at year end of just 1.2 times debt to trailing 12 month 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 a position of relative strength. While macro fears regarding crude oil prices have abated somewhat, we've position the Company to both prosper in the good times and take advantage of opportunities in the down times. 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.

Thanks Marvin, and good morning everyone. My hat goes off to the Bonanza Creek team for another terrific year, a year in which we grow production by 74% and increased proved reserves in 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 core 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 the 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 lost-time incident to employees or contractors.

For our 2013 As Prepared Proved Reserves Report we switched our third-party reserve engineer to Nederland Civil and Associates. At year end we reported proved reserves approximately 7 million boe, a 32% increase over 2012; strong reserve replacement, 393%; and a PV-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 revision 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 derisking of the resource potential that exists 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 extent 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 laterals, and we have (inaudible) for Niobrara B Bench wells down to 40 acres. We've been working this area for over a decade and have a significant amount of technical analysis into the evaluation of our 3P reserves.

Actual results achieved, and the approximately 4500 net acres acquired during 2013, gave us the confidence to boost Wattenberg horizontal risked 3P reserves by approximately 30% over last year's estimate presented in our Analyst Day from 237million boe to 308 million boe. In addition, we increased our well count to over 1800 locations, providing the Company with approximately 15 years of drilling inventory.

Moving onto 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 wider differentials to WTI in the D-J Basin caused by seasonal refinery maintenance, weather issues, and a temporary increase in supply at Cushing.

Fortunately, the worst of the spreads appear to be behind us. We have seen oil deducts improve over the past two months as a result of less competition from Canada and Bakken barrels. Our weighted average realized crude price for February 2014 was NYMEX less $11.43, and we expect further near-term relief with the [well] plus expansion and increased utilization of the Tampa well facility providing additional takeaway options out of the D-J 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 teams' operational execution of the super section, which commenced flowback almost two weeks ahead of schedule. Speaking of the super section, early flowback results are showing strong flowing pressures and good hydrocarbon response.

Currently, all 15 wells are producing oil and natural gas. The two westernmost pads testing the tightest downspacing concepts are performing as expected.

We will continue to evaluate flow performance and analyze tracer data that we are beginning to receive from the wells, and we will have more to discuss during our first-quarter call in May. As you all know, the super section test combines 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 three five-well pads simulate potential pattern configurations and downspacing concepts in the Niobrara B and C Benches and the Codell that could be the foundation of future pad style 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 well, 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 wells. We are excited about the possibility of expanding the Codell program further to the east and locking additional inventory and reserves. We will drill two wells this year near the eastern boundary of our western acreage.

Another element of the super section test is the downspacing to 40 acres in the Niobrara C B Benches. The standalone test completed in 2013 performed within the range of expected outcomes for 80-acre B Bench wells. We are encouraged by neighboring operators comments stating that 40-acre spacing in the Niobrara B Bench is viable.

While the super section test is of about optimal configuration of laterals, we continued to testing application of extended-reach laterals on our property. We believe the operational risk in drilling and completing extended-reach laterals has 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 estimate an average (inaudible) each of these 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 per lateral foot than one-section laterals, and we are excited about their potential to add incremental value.

Moving onto Mid-Continent region. I'm pleased again to report strong and consistent results. This asset is so reliable and provides a stable base of liquids production and cash flow that it is a huge benefit to our business.

Production from our Arkansas properties average 6,083 boe per day for the quarter, a 13% increase over fourth quarter last year, and 5,554 boe per day for the year, an 18% increase over 2012. Realized pricing in the region for crude oil/natural gas typically hovers around NYMEX. Our NGLs are sold without ethane, and average approximately 54% of WTI in 2013.

Also, we continue to be encouraged by our five-acre downspacing test, as we have not observed interference between wells, and initial production has been above expectations. We plan to drill another 10 five-acre spaced wells in 2014, an attempt to fully delineate the downspacing potential in the Dorcheat Macedonia field.

I will conclude with the observation that this is an exciting time for Bonanza Creek. I'm very pleased with the progress we have made over the past of couple 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 and stacking arrangements in the Niobrara B and C Benches while extending 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 assets, and we'll go forward in 2014 with the same dedication to operational performance that we have always had. With that, I will turn the call back over to the operator and open it up for questions.

(Operator Instructions)

Irene Haas of Wunderlich Securities.

Great quarter. And my question has to do with your natural gas liquid pricing for fourth quarter, which was pretty strong. Of course, first quarter is going to be pretty good, too.

So should be kind of bump up realization versus WTI for first quarter, and then we taper it off for the rest of the year? Just like a little guidance on the natural gas liquid pricing?

This is Gary. As you know, when we just report liquids, the bulk of that, if not every bit of it, is coming from Arkansas. Since it is just a propanes plus stream, we actually see stronger realizations versus WTI, and that's how we posted them.

I think just the market down at Mount Belvieu is where those liquids go. So our expectations are to just ride along the same kind of range of pricing that we've received from Mont Belvieu over the six months. That's kind of how I guide you going forward, if that's helped will at all.

Okay, great. Thanks.

Welles Fitzpatrick of Johnson Rice.

On the Codell stepout wells to the east, are those the Antelope lease permits that look like they are pretty big stepout, and if so, are those going to be a first half event?

Hang on one second. Let me check that for you exactly, if I can. I believe those wells are going to be at -- in the second half of the year, is what it's looking like.

I'm 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?

No, that's fine. Yes, absolutely. I'll circle back.

(Multiple speakers) But hey will be in, probably in the second half of the year.

Great.

Welles, And I think as Tony's talked about, there going to be more toward the eastern, kind of towards the center of all the acreage positions, if you will. When you look at the entire acreage position that we have. 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.

The middle.

The middle of the total, yes.

Right, there you go.

Okay, fair enough.

Clear as mud, right?

Then one more. On the long laterals, the one that was, I think, in the 500s, came on in the 500s, and it seems to have been kind of flat, almost inclining on production. Can you talk a little bit about what you think is going on there? Is that the heels stages maybe pinching off some of the toes? Or what do you all think is going on there?

This is Tony. I will go ahead and take that. Initially, that well, one of the things we saw and we are still trying to figure out a little bit, is we saw really, really good oil production on that, but a little bit of expressed gas rate. We saw the gas start to come in as the well started to increase.

You have a 9,000-foot lateral. When you have 9,000 feet out there and you have 36 stages contributing, they are all going to contribute in a different way. Of course, pressure, the way those things work with the different pressures, a different stage can contribute at one point, One [depressure], another stage can kind of kick in.

It could be coming from the toe or it could be coming from the lateral. Now, we will have to continue to evaluate that.

We also put on our controlled flowbacks, if you will. We are not overproducing those things upfront. That helps constrain, probably, a little bit of that volume on the IP 30s.

Again, I would think that it's just your natural performance on this well. Again, we saw the gas rates start to come up. The well was a little more oily early on.

Other than that, that's about all I have. We are very, very pleased with the results, as I said. In those last two wells, with the average being in the 700,000 to 800,000 boe EUR range.

It's very comparable to the results that we are seeing from Noble, on their wells ranch on their 9,000-foot laterals. So we are very pleased with those results.

Some folks to you all's west are trying mid-lateral, even long-lateral, Codells at this point. Is there any temptation to do that, or let them figure it out, maybe?

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

Great. Thank you so much. Great quarter.

Mike Kelly, Global Hunter Securities.

On Bill Barrett's conference call they spoke to increase variability in the northern part of their acreage for the Niobrara B. I just wanted to get your take on what you are seeing there in terms of the ultimate consistency across your acreage, and let me just start there. Thanks.

Again, if I heard the question correctly, the consistency of the Niobrara B across our entire acreage position?

Yes. (Multiple speakers) Go ahead. I'm sorry. You could expand C and Codell's as well, too.

If you look at our -- the 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 it on the eastern edge being a little more oily 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 to Wells Ranch, pretty consistent with what they have on Wells Ranch in the B and the C. The Codell, we think it's very consistent across our -- we have it present across our entire acreage position.

When you 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 cutoff that we're using right now is an eight-foot thickness with 10% porosity. So we think that the five wells that we've drilled to date have pretty much confirmed that that eight-foot thickness with 10% porosity across that 15,000 net acres is now very viable for us.

But the key for us is that Codell does thin across to our eastern side, and it's about two foot thick as you kind exit 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 to about a six-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.

What we are seeing is, is that we may be having the opportunity to actually continue to extract resource and not have to have an eight-foot thick Codell, because the key on that is, is that we thought we had to have eight foot to actually land a 4,000-foot lateral all the way in zone in the Codell. What we found out on a couple of our wells, we can actually get into the Carlile somewhat and still effectively complete the wells.

So if that the case, we may be able to go down to six feet, four feet, and maybe even two feet, and that's where we are hoping to expand the Codell potential. So that's kind of how I see the B, C, and the Codell across our acreage.

Good. I appreciate that color. Follow-up from me on the super section guide, here. Very encouraging to hear that early flowback looks good.

You tested quite a bit of different concepts there. Just curious, if really success pans out here across everything you are doing there. The level of confidence, what kind of incrementally do you gain just right off the bat here?

Does it give you enough confidence to do another hike to your net location count? Or do still need more history throughout the year? What can you glean from it just on initial success, I guess is my question?

My first pass on the initial success is, is that obviously it will help us continue to optimize what we need from a drainage standpoint of how many wells we need to put in a 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 spaced test that we have in the B with the combination in the 40 acres in the C just below it. That's going to be a really key test for us. If that is successful I think, obviously, yes, you can see us looking in 2015, not so much 2014, starting to alter our drilling plans pad development to more be in line with those patterns that we've tested there with those pads.

The only thing I want to caution us on is that obviously we talked about the extended-reach lateral testing that we're doing too. That is something that we are going to want to couple that together, right?

We are 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 combine that with the data we are getting out of the super section. So we may see something in 2015 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 not sure of what we will do from that standpoint, obviously. The data will bear out as we go forward.

Great. Thanks, guys.

David Amoss of Howard Weil.

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 the Carlile to some degree. Can you kind of give us a little bit more on, assume these two wells are going to be somewhere in the middle of that eight- to two-foot thickness gradient, and then you'll watch them for how long? And then possibly move further east. How are you going to go about testing the rest of your acreage, and what's the timing of that?

Sure. This is Tony again. The way I see it, is we have those well (inaudible) scheduled in the second half of the year. We'd like to drill those wells, get some production data out of 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 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 will look at the data that comes in from these two wells. If they're very successful, we might do that. If they are right in range, we may probably continue with our gradual step-out. But I think you can see us probably pushing that in 2015, for sure.

Okay, great. That's really helpful. Then just one more. You guys have been pretty successful adding acreage this year. Can you give us what you are seeing today in terms of the competitive landscape?

Is that kind of the 3,000, 4,000, 5000 acres a year? Is that the run rate to expect in 2014 and 2015, as well?

Yes, actually, we do. We've got a number of these small type of bolt-on acquisitions that we are looking at. Right now, we are kind of seeing that same 10% acreage add for this year compared to or similar to last year.

Okay, great. Thank you very much.

David Beard of IBERIA.

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

Sure. I think as we released, we are probably in the lower teens on our differentials at this point. And that's compared to the historical differential of about $8 that we've seen over the past couple of years.

What we've seen that has kind of impacted us, some short-term, some a little bit longer term, are the weather issues that we've seen over the last three or six months at this point now. Some of the macro refinery issues that popped up last fall.

Then the takeaway capacity that we are starting to see coming into the basin, rail capacity that is being augmented over time. In addition to White Cliffs increasing their capacity, Pony Express tying into the basin and taking some capacity away from there.

So our long-term, I guess as an example, we are probably in the $11.50 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 back down to $8 range, the historical range.

This is Gary. Just a little bit more color on. We just started seeing these kind of bumps up from historics right around the October timeframe of last year. We kind of crescendoed up into December, maybe being slightly more than $17 off of WTI.

The first quarter, I think, when you look at the numbers, we are right around $13.40 off of WTI -- or excuse me, for the fourth quarter of last year, on average. Then as Pat just mentioned, we are kind of in the $11 to $12 range for the first quarter of this year, and continue to move downward, we think.

That's kind of the short-term acuteness of it. Then as Pat well described, what we think is coming in the future.

Okay. As a follow-up on a different topic, one of my favorite topics is to 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?

This is Tony. What we are planning for North Park, we are planning to drill two exploratory tests up in North Park in 2014. We are planning that first one is scheduled for about May.

We will drill a pilot hole and then back up from there and drill a horizontal Niobrara well. We will then extract the data from that horizontal Niobrara well.

The key learnings 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 toward the end of the summer, somewhere in August, before the weather sets in, and get that done at that point. But they're both horizontal Niobrara tests.

Probably the most intriguing thing about it is what we are 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 can drill a horizontal in this, run a liner, but not have to frac. So we will evaluate that, and if we don't have to frac, obviously there's a great improvement to the economics.

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 room we would have.

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.

Okay, great. I appreciate it. Thank you.

Adam Michael of Miller Tabak.

If I could follow up on the North Park basin. I think the comment was there's about 20,000 net acres up there. Can you run through the current state of the leases, and do you have options to extend leases, or are there opportunities to pick up more acreage up in that area?

This is Pat. We've 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, the gas zone and the oil zone.

Some of the -- probably two of the wells that we've drilled over the last couple of years have shown the Niobrara to be deeper than what we originally anticipated. So with that in mind, we went ahead and let some of those leases expire.

Some of the mid-structure leases that we have, we've drilled 1 well, maybe 1.5 wells, maybe the best way to put it, on that part of the structure. It's given us a better picture of where maybe the oil and gas contact is, if you will.

So we've retained a number of leases on that trend. Where Tony is talking about drilling is really up almost, not quite to the top of the structure, but really within the north and south, we call them units, that yes, that we've held since 2006, I guess it is. I think we are comfortable right now with the acreage position that we have, and that substantial part of it is in the oil window of the Niobrara.

Adam, this is Gary, too. Those units that Pat referred to that have a large portion of acreage up there, they're held by production from other zones, which have been producing for quite a while. So as far as expiry there, there's no issue on that particular part of the acreage.

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

Good question. This is Tony, again. The cost, right now we're looking at about $7.5 million on those extended-reach laterals at 9,000 feet.

Okay. 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 opportunity to drive costs down even lower in 2014?

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.

I don't really want to give you any direct numbers on that. I think going forward directionally, yes. I mean, when you can combine facilities and combine infrastructure, there's going to be synergies there that will help us drive down the cost, which is part of the economic and capital efficiency piece of the equation that we are trying to improve.

Great quarter, guys. Thank you.

Andrew Coleman of Raymond James.

Let me ask Adam's question in a slightly different way. Thinking about the facilities, synergies, could you give me a rough rule of thumb, or how you think about fixed versus variable split between the cost you all are seeing out in the field right now? Sorry, go ahead.

Andrew, are you talking about on the capital side or on the lease (multiple speakers)

On the OpEx side. Are you getting improvements? I guess, some of the synergies come from the fact that we are getting new facilities going out in the field.

I recognize that you all might not be the anchor tenants on some of those facilities. Do you still get a bigger fixed costs that you can ramp up into and get your synergies there, or is everything variable?

Andrew, I think the biggest thing on the operating expense side is that we obviously are combining facilities with this pad drilling. It gives us some opportunity there to go from one location rather than multiple locations.

It actually there's some advantages there on infrastructure, as you can imagine, just on how we daily operate all of those facilities. There is some incremental advantages to that.

As far as trying to put a hard number on that and a great split between fixed and variable, you're still going to see, quite frankly, a lot of variable expense out here because that's the nature of the asset. Low-cost operating has always been a key for the D-J Basin, and I think you will continue to see it be that way going forward, with the opportunity to lower them as we do these larger and larger areas, if you will, together. Does that make sense?

Yes, yes. I guess looking at the other side, can you tell me what your (inaudible) completion and tying time are? I think last year at analyst conference you guys were talking about something like 45, 50 days.

Has that improved much over the last few months? Or do you have a view on a target as to guide you, may move toward pad drilling, what you can see in terms of total start to finish time on those wells?

Yes, we are making improvements. Our spud-to-rig-release times and spud-to-spud times, not considering when you are on pads, we had dropped down to about 11 days. Obviously when you get on pads, we can even reduce that down to spud-to-spud time to actually we've seen days at eight and seven days because of the lack of needing to move the rig.

But the trick is on, obviously as you get on pads, when you start talking about spud to first production, though of course, depending on the size of the pad, the first well you spud, if it's a five-well pad, i.e., on the super section, that well will sit and wait until the fifth well on the pad is then drilled, and then you have to come back in and complete all five wells. And then you have to, obviously, do the clean-outs on all five wells, and then the production equipment hookups on all five 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 you get into pad development, I think it's going to be more, as you've mentioned, it's going to be more along the lines of how fast can we do pads, but then they're going to have to be similar size pads.

I think we focus on, what we really focus 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 coiled tubing units on a well-by-well basis to clean the wells on and run tubing. That's where the efficiencies will be built in, and then it will all lump together in the pad development.

If you just look at it from the outside, it can be very skewed because of pads, because of that timing delay waiting for other wells to come online. That delay is on purpose. Because again, we want to maintain pressure in those well bores while we complete the other wells so that we maximize [revoluzation] of the reservoir.

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

That's probably pretty fair. I would say for going forward, I know you are trying to dig, probably get to what you can use for a model standpoint. I think sticking with that 45 days for right now is probably the best way to go.

We can start to modify that as we get more and more pads for you to compare that to. For right now, I would stick with the 45.

Okay. All right, and then the last question I had was, I still got a pretty clean balance sheet. I guess what -- with 1700 locations in inventory, what's the timeline or signpost that we might see an additional step-up in activity to accelerate the development there?

This is Bill Cassidy. We've 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 the super section.

That may affect the back half of 2014, but certainly 2015. I think really we will be absolutely focused in keeping a clean balance sheet. Our trailing last 12 months debt to EBITDAX is 1.2, and 1.2 times.

We want to keep it like that. So we will make sure we manage the operations accordingly and keep an eye on the balance sheet.

Andrew, this is Tony. Bear in mind, one of the key limiting factors to accelerating is making sure we've got the technical data. As Bill had mentioned, when the super section, as we acquire that, what we don't want to do is drill so fast and get wells out there that we regret we have drilled.

I would take you back to (inaudible) well drilling. Had we known what we could do with horizontal wells right now, we probably wished we wouldn't have drilled those vertical wells, even though they seemed -- they were a good idea at the time.

Okay, fair enough. We will wait for those super section wells, and nice quarter. Thanks.

John Malone of Mizuho Securities.

Just to go back for a moment to the upside from thinner Codell drilling. Say that you're actually able to make six feet, or even four feet work. What does that do to that 15,000 acres? How does that increase?

Again, I will direct you, if you can, back to that cross-section we had for Codell back in our Analyst Day presentation. The Codell is present across -- that 15,000 net that we talk about is really kind of centered on the western side of our acreage.

If you remember, our acreage is broken up. You have a western side and an eastern side. If we can make six-foot, four-foot, and two-foot Codell thickness work, that would extend it across our entire eastern acreage position, which would be, we've got about 35,000 net acres total these days. So that would probably expand that potential almost across that entire amount. (multiple speakers).

I'm sorry, go ahead.

I was just going to say, think of this as, obviously have this Codell sandstone and it sitting above the Carlile Shale that Tony mentioned earlier. So what we're looking at right now is we're looking as maybe a Codell/Carlile complex as it moves to the east.

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. As Tony mentioned, you'd 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.

Okay, that's helpful. Thanks. My second question is more a high-level reserve accounting question. By my readings, 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 going from vertical to horizontal.

How do you make that back? Obviously, those hydrocarbons are still in the rock. What's the [process]? Could that be added back in a year? How long would it take to bring those back onto the books?

This is Lynn Boone. I think we are taking those reserves off the books as we drill horizontal wells and plan to drill in the next year additional horizontal wells. So we are actually replacing those reserves with our horizontal adds.

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 in 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 PUD off the books. At that point we will just have PDP reserves in our verticals, and I think over the next year or so, we actually will make up the difference completely with regard to, including those reserves in the horizontal numbers.

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

That's correct.

Thank you.

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