Civitas Resources Inc (CIVI) 2012 Q4 法說會逐字稿

Good day, ladies and gentlemen. And welcome to the quarter four 2012 Bonanza Creek Energy Inc. earnings conference call. My name is Rachel, and I will be your Operator for 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)

I now would like to turn the call over to James Masters, Investor Relations Manager. Please proceed, sir.

Thanks, Rachel. Good morning, everyone. Welcome to Bonanza Creek's fourth-quarter and year-end 2012 earnings call and webcast. Yesterday afternoon we issued our earnings press release for fourth-quarter and full-year 2012, and filed our 10-K with the SEC this morning. You can access both on our website at www.bonanzacrk.com.

Our remarks today will include forward-looking statements. These statements are subject to many risks and uncertainties that could cause actual results to differ materially from our expectations as expressed, but are based on our current views and most reasonable expectations. These factors are described in our 10-K and our other SEC filings, which you can access through our website or the SEC's website. Also during this call, we will refer to certain non-GAAP financial measures. 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.

Finally, as you know, during the second quarter we began the divestiture process of our non-core California properties. Under GAAP, we disclosed the results from these properties as discontinued operations in our 10-K and in the Statement of Operations and balance sheet in our press release. However, all results discussed today reflect total operations, including discontinued operations. We are presenting our results this way to increase comparability with our 2011 numbers, which you are most familiar. In the future, we will focus our presentations on our continuing operations.

On today's call, Mike Starzer, our President and CEO, will begin by discussing the highlights for the quarter and end by providing comments on 2013. In between, Gary Grove, our Executive Vice President, Engineering and Planning, will report results from our operations. Other members of Management will be available during the Q&A portion at the end of the call. With that, I am happy to turn it over to Mike.

Thanks, James, and good morning, everyone. We appreciate you joining us today and look forward to reviewing what was a very positive quarter and a great year. As James mentioned, I am joined by Bonanza Creek's Management team, who will be available to answer questions at the conclusion of our prepared remarks. I owe these men and women and their respective teams my sincere gratitude for their outstanding work this year. By nearly all measures, 2012 was a terrific year, and I am proud of our performance.

I believe that we are well-positioned to continue doing the things that have made us successful. In doubling production in 2012 and preparing for continued top-tier growth, we added key members of our Management team and strengthened the personnel infrastructure to support a rapidly growing Company. We have increased our horizontal rig count to four full-time rigs in the Wattenberg Field, and are currently on schedule with our 2013 development program. We are incredibly fortunate to have a large, contiguous acreage position in the Wattenberg Field, one of the most economically attractive plays in the United States. Our horizontal well results continued to improve over the course of the year, bringing our total program 30-day IP rates from approximately 470 Boe per day to over 500 Boe per day, with very strong well head crude oil rates of over 75%. In the Niobrara B Bench, at 80-acre spacing, were our only opportunity, we would have an attractive development inventory for many years.

But as you all know, we and others are testing 40-acre downspacing and extended reach laterals in the Niobrara B Bench, as well as targeting the Niobrara C Bench and the Codell for horizontal development. These additional opportunities have the potential to significantly expand our portfolio of high-return projects. Gary will talk more about these exciting results, but suffice it to say that we are very encouraged and are eager to optimize the value of this asset.

For right now, though, let's go to the results for the fourth quarter. Revenues for the quarter were $74 million, up 100% from the fourth quarter of last year. Our sales volumes for the quarter amounted to 11,994 Boe per day, a 26% increase over the third quarter and a 107% increase over the fourth quarter of 2011. The sale of crude oil represented 7,960 barrels per day, or approximately 66% of total production. The strong quarter contributed to annual revenues of $236.6 million, and a 115% increase in sales volumes to 9,403 Boe per day.

Adjusted net income for the quarter was $15.7 million, or $0.39 per diluted share, on strong revenue and declining operating costs. For the full year, adjusted net income increased 194% to $52.2 million, or $1.31 per diluted share. Excluded from adjusted net income were unrealized gains from commodity hedges, stock compensation expense, impairment, exploration, dry hole costs, and gain on sale of oil and gas properties. Our EBITDAX for the quarter was a record $54.1 million. That is up 138% from fourth quarter 2011, and our full-year EBITDAX was a very strong $162.1 million, up 136% over the previous year. Our balance sheet remains solid, with liquidity of approximately $123 million at year end and a leverage ratio of less than one times debt to EBITDAX. As we have stated in the past, we expect to govern ourselves and our growth by staying below a two times debt to EBITDAX threshold. We think the flexibility of our balance sheet is a competitive advantage, and we plan to keep it that way.

Before I turn the call over to Gary to discuss our operations, I would like to address 2012 capital expenditures, as that is an area that did not meet expectations. Our capital expenditures were approximately $341 million in 2012, versus a budget of $298 million. Contributing to this overspend are un-budgeted expenditures of approximately $23 million, which includes participation late in the year in non-operated Niobrara B Bench horizontal wells that had a marginal impact on 2012 production, along with micro-seismic and acreage acquisitions. Approximately $15 million was due to operational modifications made, as we transitioned rapidly from a vertical to a horizontal development program in the Wattenberg during the third quarter. This includes fracture stimulation improvements on our horizontal wells and increased costs due to reduced rig efficiency caused by the transition from vertical to horizontal drilling. The remaining $5 million is associated with drilling and completion issues on 4 of our 32 horizontal wells drilled in 2012. Key learnings have been incorporated into our drilling and completion procedures, and any recurring costs associated with our experiences in 2012 are included in our 2013 capital budget.

With that, I will turn the call over to Gary to discuss the outstanding operational results we achieved in 2012.

Thanks, Mike. As you mentioned, it was a very positive quarter, and I am pleased to report on some of the exciting results we achieved on our test wells in the Wattenberg. But before I get to the quarter and year-end results and catalyst well update, let me first review our 2012 proved reserves, which showed an increase of 9.3 million Boe to a total of 53 million Boe, replacing 371% of 2012 production. Our total proved reserves grew 21%, and the PDP component grew by 47%. Proved developed reserves were 45%, up from 39% a year ago. The proved reserve mix was 57% crude oil, 6% NGLs, 25% wet gas, and 12% dry natural gas.

Our Wattenberg drilling program for 2012 resulted in net reserve additions of 12.8 million Boe. This is 95% of the Company's total net reserve additions of 13.4 million Boe, excluding the California divestiture. The Wattenberg reserve additions were primarily due to our focus on horizontal drilling in the Niobrara. Our horizontal Niobrara B proved reserves increased by 236% during the year. The California divestiture accounted for a reduction of 700,000 Boe.

Moving on to operational performance -- let's begin in the Rocky Mountain region, where we averaged production of approximately 6,549 Boe per day, or 55% of Company sales volumes during the fourth quarter; and 4,568 Boe per day, or 49% of total sales volumes, for the full year. Our production was split 75% to crude oil and 25% to rich natural gas, and during the quarter approximately 56% of our volumes came from horizontal wells. Also, I should point out that all of our oil is sold as crude oil at the well head, with no associated condensate. At mid year, the Company made a decision to augment the 2012 budget to drill some catalyst horizontal wells and also begin to transition to a horizontal development program in the Wattenberg. The result was to add 12 additional horizontal wells and remove 20 vertical wells, effectively ending our vertical development for 2012. Three of the new horizontal wells were drilled to test the Niobrara C Bench and Codell, along with a B Bench extended reach lateral test.

Overall, during 2012 we drilled 32 standard 4,000-foot horizontal Niobrara B Bench wells, for an average total well cost of $4.5 million. The average cost include additional data collection on a few of the 32 wells to increase our knowledge of the reservoir. We also experienced drilling problems on four wells, which had a negative impact on our total average. Our average 30-day production rate for all Niobrara B wells to date is 503 Boe per day at 76% crude oil, with our last 12 wells averaging approximately 537 Boe per day. Our 60-day rates also continue to improve for a total program average of 405 Boe per day, with our last eight wells averaging 476 Boe per day, as a result of recent operational improvements.

We are also very pleased with our catalyst wells that I mentioned earlier. The Niobrara C Bench achieved a 30-day IP rate of 444 Boe per day at 79% crude oil, while the Niobrara B Bench extended reach lateral produced an average of 795 Boe per day over its first 30 days at 76% crude oil. We successfully drilled the well to a total lateral length of approximately 9,600 feet, but did encounter problems running the liner and only completed approximately 8,600 feet of the lateral length. As a result of the lower lateral length completed, we believe we lost as much as 100 Boe per day of early production. As reported in January, we drilled a horizontal well in the Codell formation, achieving a 30-day average rate of 370 Boe per day at 81% crude oil.

Our average 60-day rate showed almost no decline, averaging 367 Boe per day. This was the first well where we installed gas lift early in the flowback period, and we believe that has contributed to the improved 60-day production profile. Finally, we continue an [actively seen and] acquisition program in the Wattenberg Field near our core area, and recently acquired 960 net acres for approximately $1,250 per acre. Initially, this will add additional Niobrara B locations, and is also prospective for Niobrara C Bench locations.

Moving on to the Mid-Continent region, fourth-quarter sales volumes averaged 5,402 Boe per day, a 67% increase over fourth quarter of 2011. Sales volumes for the full year averaged 4,689 Boe per day, a 90% increase over 2011. At mid year, the Company decided to drill seven additional Cotton Valley vertical wells -- three five-acre spaced wells in Dorcheat Field and four wells at McKamie-Patton. While we do not yet have 30-day results on the downspacing tests, early production results are encouraging.

In McKamie-Patton, the initial 30-day average rate for the four wells was 137 barrels of oil per day, comfortably exceeding our forecast of 71 barrels per day. In total, we drilled 42 operated vertical wells and completed 80 upper Cotton Valley pay adds during 2012. The Dorcheat plant expansion continued in the fourth quarter to include another 12.5 million cubic feet per day of capacity. The plant recently became operational in February, bringing our total capacity in the area to 40 million cubic feet per day.

Before I hand the call back over to Mike, I also want to touch briefly on operating and G&A costs for the quarter and full year. LOE for the fourth quarter was $7.81 per Boe, down from $13.20 per Boe in the fourth quarter of 2011. For 2012, LOE averaged $9.58 per Boe, 29% less than the previous year. The decrease in per-unit LOE is due primarily to increasing production volumes from the Wattenberg horizontals, which have the lowest per-unit cost in the Company. In addition, the disposition of some of our higher LOE California properties further reduced per-unit LOE costs. G&A for the fourth quarter was $8.15 per Boe and $9.13 per Boe for full-year 2012 -- a 17% improvement over 2011.

We feel good about our staffing levels at this time, as many of our added personnel were hired in 2012 to prepare for the 2013 program. As we communicated in our guidance earlier this year, we expect per-unit G&A costs to continue a moderate decline. With that, I would like to turn the call back over to Mike for a final comment.

Thanks, Gary. I wanted to conclude our call with a few thoughts about 2013 and how we view things going forward. I mentioned earlier in the call that we are well-positioned to continue the success we achieved last year, and the 2013 guidance we published in early January reflects that. Based on our 2012 sales volumes, our guidance represents a 62% increase to the midpoint of the range, or 15,250 Boe per day, again placing our growth rate in the top tier among our peer companies. In addition, the substantial oil and liquids component of our production mix affords us continued strong cash margins, particularly in this current price environment. We are running four rigs in the Wattenberg, drilling 72 horizontal wells in 2013 -- including 56 Niobrara B Bench laterals, four Niobrara C Bench wells, and four Codell wells, all standard 4,000-foot laterals.

We are also going to drill two more extended reach laterals and six wells testing the 40-acre spacing in the Niobrara B Bench. We are excited and believe that this program will lead Bonanza Creek into its next phase of growth and provide increased visibility on our development potential. We will also continue our work in Arkansas, drilling 36 Cotton Valley wells and further testing downspacing potential in the Dorcheat-Macedonia field, which has the potential to significantly increase our development inventory in Arkansas. We are looking forward to communicating these results to you as they come in throughout the year.

I want to remind everyone of our next event, our first Analyst and Investor Day on April 11 in Denver. We invite you to join us as we present our current analysis of the Company's resource potential, with an emphasis on the Wattenberg Field. We will update our potential inventory count to contemplate the impact of downspacing, the development of the Niobrara C Bench and the Codell formation, along with continued development of the Niobrara B Bench. This event will be webcast and can be viewed from our website for those not able to make the trip to Denver.

In summary, we intend to continue to execute on the plan, hit our targets, and aggressively develop our attractive asset base. We learned a lot about the Niobrara in 2012. And for 2013, I think we will learn even more about how to best develop the full resource potential of the Wattenberg Field. Thank you all for being a part of a very successful 2012 and joining us as we embark on 2013. With that, it's time to open the call for any questions.

(Operator Instructions)

David Deckelbaum, KeyBanc.

Just wanted to go back to the fourth-quarter CapEx, so I understand. There is no change, or there was no overage on an individual well-cost basis, as you went from vertical to horizontal relative to what you budgeted? Or could you highlight a little bit more the inefficiencies that led to the dollar amount associated with just going from vertical to horizontal that you hadn't budgeted?

Yes, David, this is Gary. A couple things -- we are guiding a little bit lower this year, $4.2 million from what we expect to spend -- in terms of what we spent last year, I would say on average of $4.5 million. Throughout the year, we have obviously seen some things happen that we have changed that drove that cost higher for the full-year 2012.

Some of those things are some equipment issues that we found that we have changed out, and have been progressively better through the year. Some pre-planning changes that we will do for next year. And also, quite frankly, we have seen some of our bids come in a little bit less than we had on the fracking side for 2012 into 2013.

As far as the transition from vertical to horizontal program and some of those rig inefficiencies is -- and there is also some structural things that happen too at the surface -- quite frankly, making that transition, we are looking to bring in a different rig to drill horizontally and add that extra rig versus the vertical rig that we had going at the time. By doing that, we actually drilled some of our vertical wells at the end with that larger rig, and it drove our costs up a little bit more than we had planned as we were shifting from that program -- again, vertically on those last 10 or so wells into the horizontal program.

The other side of that, though, is we had originally planned to drill more verticals, as we talked about. And we put in some facilities that would take more than one well -- as you well know, out there we don't just drill one vertical well in one particular production system. That being said, some of those costs then, therefore, needed to be spread across a smaller number of vertical wells. That led to some, just at the moment in that point in time, additional facilities that we had planned to spread the cost over additional vertical wells.

Okay, so it's fair to say that all of those factors have already been incorporated into that $394 million CapEx guidance for '13 -- (multiple speakers)

They sure have, David, along with everything else that we see going forward. We have it fully analyzed with all of those key learnings from last year, and fully incorporated into what we expect to spend for next year.

Along those same lines, I know we guided to about $8 million, and still continue to do that for the extended reach lateral. And the costs for that particular well last year came in just a little under $7.5 million, about $7.4 million. So, we do see positive events, as well.

Okay. And the last one, if I may, just on the extended reach lateral -- how do you compare what you have seen, at least on the portion of the lateral that you were able to complete, versus the four wells that Noble has been able to bring online? And how do you reconcile the 30-day rate with type curves and the incentive to go from more of a shorter lateral to a longer lateral? And then, I guess to add on to that, how quickly could you convert the program to using the extended lateral methodology more frequently?

The first question, we do compare to those four wells. We feel like we are right in line with what we see from the results to date that we can see from the public information. Based on the number of stages that we put into the lateral, is how we look to determine -- like I said, we think we might have been able to add 100 more Boe per day if we were able to get in those three to four extra stages.

That being said, overall we feel like we are tracking right in line with what we see from the four Noble wells. We also know it's early, and we also know that we and they employ a reduced flowback period early on. As we have all talked about, we hold the wells back a little bit, especially the extended reach wells. We are very optimistic for what we see going forward. However, again, it is early.

To address your second question about how nimble we are, we do have contingency plans set up internally already. If, through the first portion of the year, we decide that we want to maybe drill some further extended reach laterals into the latter half of the year, we don't currently have plans for that. But when we do, we will definitely make that announcement as we see more production coming from, not only our wells, but also from longer term on the offset Noble wells, as well.

Looking into the future, that is one of the goals from this year, is to make some further decisions on what is the best efficient use of lateral lengths to develop this large acreage position that we have out here, and quite frankly, in the different benches as well.

Great. Thanks, Gary.

Irene Haas, Wunderlich Securities.

Question on Bench B -- obviously, you guys have quite a bit of success, and it's looking more predictable as such. And you are still sticking with your 312,000 barrels a day EUR. Could we expect maybe some upward revisions?

Thanks, Irene. Yes, for now, we are sticking with our 312,000 EUR look at it. We still think, ultimately, the EUR will be depicted by more impact of what we see in years two and three, as we get more time behind us. We feel like we are still in the early stages of that curve. We don't really want to go beyond that, even though our IP rates have exceeded what we use for an IP for that curve. That being said, you will probably see us be a little slower to change our total EUR forecasts going forward. We are comfortable with where we sit today.

Great. So, similarly, when could we expect some EUR on your various benches in Codell and all that? When would you get comfortable in terms of releasing something that you feel good about?

I think we will be able to shed a little more light in our Analyst Day presentation, as we talk through that. But that being said, we now have one well in the Codell, one well in the C, and one extended reach lateral on our property. Obviously, taking into account the offset work that is being done that moves that well count higher. But I would expect we would want to see some results from our 2013 program in all of those, and then zero in on what an EUR would look like.

I would comment a couple of things. Our EURs we feel comfortable about. But again, remember, we feel like our oil split is really high, and that tends to lead us to feel that if you say we won't want to really move that up right now, it's because we are seeing such high oil percentage, and the returns are so much greater with even a lower EUR amount.

But overall on those catalyst wells, as we go through the year, we are seeing similar early day production on the C Bench well and on the Codell well as what we would have expected. The C Bench is in line with our normal B Bench wells that we have seen out there, for sure. The Codell was a little bit lower in rate. But as we mentioned, the 60-day rate was much flatter than we have seen historically, and does agree with some of the offset operator Codell wells also. We will round out a better number for you in the proceeding two to three months, I think, on EUR expectations.

Great. Thank you.

Brian Corales, Howard Weil.

Congratulations on a very good 2012.

Thanks, Brian.

On the inventory question, I know you are trying, still experimenting -- I wouldn't say experimenting, but testing some of these other zones. Is the C Bench -- is that prospective throughout your whole 32,000 acres? And what about the A, as well?

It sure is, Brian. The C, we feel, is prospective across the acreage. We have our geologic mapping that we do out there, and with the 3D seismic and the vertical well control. We felt very good about the prospectivity of the C across the entire acreage position.

The A bench is prospective across the entire acreage position, as well; although, quite frankly, we haven't looked to go ahead and drill any A Bench wells this year. I believe, as you know, and everybody knows, that Noble has a couple of A Bench tests very close to us in their Wells Ranch area in Section 24. And we are content to wait and see what the results look like there before we go ahead and embark on putting an A Bench on our property, if you will, in maybe the latter part of 2013 or 2014. That being said, we are also looking vertically through the column to see how we can drain independently between the A, B, and C Bench, and the Codell together.

Okay. And then, that was a very good extended lateral well. How much of your acreages can you drill extended laterals? Or is it -- you all have a pretty contiguous acreage block. I'm just curious, though, on -- could we see the majority of wells being drilled with a longer lateral?

We do have a very contiguous acreage block, and that is something that we feel like we could control a lot of, probably as much as maybe 50% or little -- or up to 75% of the future wells we have drilled could enter into that fully controlled extended reach lateral condition.

But that being said, I would also like to comment that even if we only owned a portion of the extended reach lateral, we feel like the neighbors that we have out there like the potential of that, as well. And so, subsequently, we may drill much less wells and maybe operate some of those extended reach laterals. Or where we have a lessened position in the acreage, we would be a non-operated partner with someone on the other side to go ahead and employ the extended reach lateral concept.

Thank you. And if I could just do one more. Just on the infrastructure side, last Summer we saw some volumes being pushed out. How does that look going into this Summer, as it -- for Bonanza Creek? Are we going to see similar type production curtailments? Or has that been already taken care of?

We fully expect to continue to see high pressures out there on the gas side through the first half of 2013, until DCP installs their next processing plant, which they expect to do in the third quarter. I think right now the latest we have heard is August. And that will increase capacity in that area by 110 million a day.

We did see some impacts of that last year, although in the 100 to 150 Boe per day range for the second and third quarter. We have put that into our guidance forecast for 2013. So, we do expect to still see that continue a little bit, probably in those same ranges for us. But we feel like we have incorporated that into our guidance for 2013.

All right, guys, thank you.

Andrew Coleman, Raymond James.

I was just looking at the 10-K here. On the costs incurred, there was $400 million spent, of which the spending for the year was $340 million. What is the delta for that? Is that phasing of activity or --?

I think it's probably best described in probably three categories, Andrew. Mike mentioned that we had about $23 million of what we would call unbudgeted piece to that. That would mainly fall in the line that we participated in non-operated wells later in the year, and so we hadn't planned on doing that. We also --

Andrew, are you talking about -- are you -- this is Ryan. Are you talking about acquisitions being involved in that $400 million number for the costs incurred?

Yes, I was just looking at because I know when I look at the income -- the cash flow statement, you have around $300 million spend. You guys talk about $340 million, and then you have $400 million on the costs incurred. So --?

I'm sorry.

I think your delta is the State Land Board acquisition.

Thank you. I'm sorry, Andrew. I misunderstood your question. Thank you, Ryan.

That is all right. I didn't see that anywhere on the balance sheet, as well. I imagine we will get some data on that next month at the analyst meeting?

As you know, we are paying that $60 million -- that is phased over five years. So, $12 million hit us in 2012, but we will obviously pay that in installments over the next four years.

Okay. All right.

But the entire $60 million, or $57 million or so, hit our cost [number] for the year in total.

Okay. Fair enough. Thinking about the reserve booking side -- with a lot of your horizontals coming on in the second half of last year, did that slow down some of the booking potential for 2012? I assume we will see an acceleration as we look at 2013 numbers here in another year.

Andrew, a couple high-point comments. And if you wanted any more detail, Lynn is with us today and she can talk to that. But I think a couple of things -- and we are going to talk a little bit more about that on our Analyst Day, as well. But a couple of high-level comments -- yes, a lot of it occurred during the end of the year, so we didn't book any offsets to, like, the Codell or the C Bench at all. All of our bookings right now are still in Niobrara B.

We also -- our extended reach lateral did not come on until January, so there were no bookings associated with that or any offsets associated with that. And then, lastly, as we started this transition to a horizontal program out in the Wattenberg, we have also started reducing and making some revisions, taking off some of our PUD locations that were vertical. And so, you will see that transition, as we move forward, have a little bit of impact on a full-year reserve add this year and maybe even into next year, as well.

Okay. Thank you for the clarity.

Mike Scialla, Stifel.

I just wanted to confirm -- I know you sell your gas -- sell wet gas at the well head in Wattenberg. Just wanted to confirm that those 30- and 60-day rates that you quoted were well-head rates; so there is no uplift in there for NGLs, is that right?

That is correct.

Okay. And based on what you have seen -- I know you don't have a lot of data yet, but maybe what you have seen between your wells and also some of the offset operators. Do you have any feel yet for what kind of vertical communication you might be seeing between the different benches, and also between the Codell and the Niobrara?

Well, we think right now the results we are seeing are consistent -- and that is the nice thing about the area that we are in, is not only the results we have, but our offset neighbors -- Noble, PDC, Bill Barrett -- we are all seeing very similar results in terms of early day rates and type curves and EURs and those types of things.

I think you have hit upon something that we feel is one of the things that we look to understand more during our 2013 campaign, as -- what is that contribution vertically in this column between the A, B, C, and the Codell? And what ultimately is the right -- for want of a better term -- stacking arrangement for the horizontal wells into the particular benches?

So, right now, we have done some microseismic work; Noble has published a lot of work they have done with their fiber optics and their microseismic. We have done some coring work. They have done some coring work obviously, and others are doing continued work out there. So, it's a little early to make any strong conclusions. But it definitely -- we feel like we do see some contribution up and down the three reservoirs in the Niobrara and the Codell.

Okay. If I heard you right, that 40-acre pilot that you are doing, that is going to be B Bench only, right? You are not going to try and stagger them in different horizons?

That is correct, yes.

Okay. Just one last one -- did you happen to run any sensitivities on your -- you provided a PV10 in your press release. I am just wondering if you ran any sensitivities in terms of maybe a higher gas price?

If you were to run it at last year's pricing, we would have added a little over $100 million in PV10 value. If you ran this year's reserves at last year's pricing -- and predominantly it is the gas movement there, Mike, you are right. So, that is the sensitivity that I could share with you today.

That is helpful. Thank you.

Ryan Oatman, SunTrust.

That Codell test has held up better than the Niobrara test. How much of that is geology versus the gas lift?

We think some decent percentage of it is the gas lift, because we are obviously augmenting it in a very favorable way with the reservoir conditions. The other thing, though, there is -- we feel like there is a geologic component to it, as well. You are exactly right, because it is a sandstone. It does have better permeability porosity characteristics than the Niobrara well, naturally. So, we think that is a combination of those two. Quite frankly, though, we are seeing uplifts in the Niobrara by installation of gas lift also. So, we know that we are contributing to that [channelling] of the decline from the operational improvements we have made.

Ryan, I might interject also that the first 30 days, we had a pretty strong controlled flowback on the well. And we want to make sure that the frac yield, this being our first Codell horizontal on our acreage. And when you look at the 60-day results, I think that was a very good decision by our technical team.

Yes, absolutely. That well has certainly held in there. To me, just from 30,000 feet, it looks like you could have a higher EUR with that than typical Niobrara B. Is that fair?

It's early. I know it's -- I don't want to sound too conservative, but we are excited about what we have seen in the first 60 days' performance. But depending on the location, depending on the cuts in terms of oil and gas from what we are seeing there, yes, we feel like it could compare very favorably to a Niobrara B Bench EUR.

Okay, thank you. What differences do you see in results across your acreage position north to south, east to west? Is there significant variability as you move one direction or the other?

We do see variability across the property. I think a lot of it has to do with the geologic positions that we see out there. You know, sometimes we will encounter some faulting, sometimes we will not as much. I think, overall, there is some very, very high-level general trends based on resistivities. So, where we obviously see a lessened resistivity out there, we would expect to see maybe a little bit less recovery, and that has probably been the major trend.

Okay. And is that on the west side? Is that on the east side? North? South? Is there any broad color there across the position where you find a gradient one direction or the other?

Probably the broadest color would be -- as we move to the northeast and directly east. I mean, really, just on the farthest east side of our properties, we see that resistivity dropping off. And that is where we would expect to see maybe some lower ultimate EURs. We also generally in that direction may see higher oil cuts, though, too. So, that is the broad color mix there.

Okay. Appreciate that. And then, one final one if I may -- there has been questions around last year and now the 2013 capital program. Looking at what you guys have proved up and accomplished in a relatively short period of time with these additional benches, how could 2014 look, given the Company's clean balance sheet? How comfortable and how fast could the Company go in 2014?

Yes, this is Ryan. Obviously, we are just going to really govern ourselves on keeping a best-in-class balance sheet, and giving ourselves ample liquidity headroom. We feel like there is still a lot to learn, as you point out, as we move through this year on just the configuration of laterals, the sequencing of laterals, and how these benches behave with one another. So, I think as we move through the year, we will have a clearer picture on that. But I think rest assured that we have a strong focus on the balance sheet and maintaining that, what we believe is a competitive advantage there.

Okay. Very good. I appreciate it.

Drew Venker, Morgan Stanley.

Do you see the opportunity for any more acreage bolt-ons in the Wattenberg and surrounding areas, or any state lease sales to pick up sizable chunks of acreage?

Drew, I think the one that we have been chasing for quite a while that we picked up in early August last year -- to see that blocky of acreage right around us is difficult. There aren't that many opportunities available. Everything that does come available, we chase. But I think what you will see more predictable will be small bolt-ons that we will continue to add, like we mentioned early on the call. There is definitely a scarcity of products of the Niobrara within the Wattenberg, because we have -- a lot of folks have been there operating for many years, and it's fairly cored up.

All right. And just unrelated, but can you offer any more color on service cost trends?

Service cost trends have been relatively flat, that we are seeing. We have secured our services on rigs and proppant. We are securing our water supply for the Wattenberg as well this year. We did see, as I mentioned earlier, some of the fracking services going down a little bit year over year, in terms of their bids. But overall, we are considering a flat scenario out there in the vendor community, not only in the Wattenberg field but also down in Arkansas, as well.

Okay, thanks.

David Tameron, Wells Fargo.

Can I get back to what you are saying about the Codell and the Niobrara and some of the gas lift? Are you guys putting on pumps? Are you talking artificial gas lift, or are you talking -- is that what you are referring to?

Yes, David, it is. We have changed -- and so, probably the best way to describe that is to tell you exactly what we do today.

Okay.

We will go ahead and drill the well -- drill the lateral length. We will go ahead and run the liner, or packer and sleeve combination. And then we will go ahead and go ahead and frac the well, and all the stages that we put in the horizontal. And then, we will go ahead and before we flow it back at all, we will go ahead and clean it out with coil tubing -- clean everything out.

The next thing we will do, we will go ahead and run in with tubing and gas lift mandrels and packer. Then we will start the flowback of the well bore, and we will do it under controlled conditions to allow the fracs to heal, to allow us to make sure that we are taking care of the near-well-bore area especially. And then, as that well continues to flow back and starts cutting oil and gas, and starts lifting itself, obviously, under natural conditions, and it will get to where it's flowing naturally.

As it starts to then not flow naturally any more, at that point in time we start to assist with that gas lift that we had -- those mandrels that we had installed initially. Initially it will be very small, just to aid it. And then, ultimately go into full-time gas lift over the first -- depending on the well and depending on where it's at in its natural strength, anywhere from 30 days to maybe 120 days to where we convert over to full gas lift. Ultimately, down the road, we may in the two- to three-year timeframe take that off and put it on rod pump or some other form of artificial lift, whatever we feel is most efficient at that time.

Okay. So, you are putting it on within the first, call it, 20, 30 days out, is when you officially put it on pump?

Yes, maybe, depending on the well and how it's flowing back, and the conditions that it has. And if we do -- and again, depending on the well, it may be just a small amount initially, obviously then increasing to where we are fully assisting it with gas lift.

Okay. Do you do anything different between the Codell and Niobrara? I'm trying to figure out why -- I guess you guys are trying to figure it out more than we are -- but why the Codell seems to be hanging in better for some operators as far as that shallower decline rate. I'm trying to figure out if it's because the wells are being choked back before they are put on, or if there is something being done different, or if you are fracking into the Niobrara? Do you guys have any comment on that? And can you tell me if you are doing anything different between the Codell and Niobrara when you complete them?

A couple of things -- no, we are not really doing much differently between the two, in terms of how we are fracture-stimulating them. I mean, some minor things, maybe some minor fluid changes, just depending on our experience out there in the area. Pumping rates are pretty similar.

But that being said, I think you have to remember too that Codell is a sandstone. It has better, again, reservoir parameters than we see in the Niobrara naturally. And that is definitely having an impact on that.

I wouldn't say so much that we are fracking up into the Niobrara or other zones would be a leading contributor at this point in time. Not saying that it couldn't be. It's just saying I don't think the information that we have right now would lead us in that direction. Overall, yes, we are encouraged by the lessened decline. I would contribute it to partially the geologic nature of the Codell, and then partially to the operational conditions that are being employed on those wells by us and our offset neighbors.

Okay. Final question -- and maybe you have covered this, I apologize if you have. But the four wells that you had issues with, can you talk about technical, geological? Can you talk about what happened, if there is any theme among the four?

Sure. As far as a theme, I think probably the biggest theme was more geological than anything else. And I think it helped us understand a little bit better the use of the seismic -- the 3D seismic that we have in hand, and all the pre-planning that we are doing. We obviously have a more rigorous pre-planning screen on everything we are doing going forward, based on the learnings that we had from last year. That is probably the two biggest -- two of the four wells had that problem, where we had to pull back in and basically redrill the lateral, because we got in a position we didn't want to be in.

We did have a standard mechanical problem on one of them. We got stuck and got unstuck, pretty normal, got drill pipe stuck on it, those things may continue to happen. Obviously, we don't want those to happen; but I can't sit here today and tell you those won't happen again, because that is the nature of our business.

Yes. All right. Thanks for all the color. I appreciate it.

Mark Lear, Credit Suisse.

Just thinking about how you guys are going to spend -- allocate capital in the Wattenberg next year. Do you guys have an idea how you are going to split activity between Codell B and C?

Yes, absolutely. We are going to drill -- of those 72 wells we have planned for next year, 56 of them, if you will, are going to be just that standard 4,000-foot lateral in the Niobrara B Bench. And then 6 we are going to use -- they are going to be 4,000-foot laterals as well in the B Bench, but we are going to use those to test 40-acre downspacing, and have already actually got a couple of those drilled to date. And then 2 more will be in the B Bench, but they will be extended reach laterals. As far as the C Bench and the Codell goes, we are going to put 4 additional horizontal wells in each of those zones in 2013, as well.

Got you. And when do you think you will have data on 40 acres?

We -- oh, on 40 acres? We are actually -- I believe the first well we completed already. I would like to tell you we would have maybe some initial information by the time of the analyst meeting on April 11, but I'm thinking we probably will not have a 30-day rate on that. We may be able to add some additional color at that time. So, probably look for something after that, if you will, really truly on the 40-acre spacing that we have seen in 2013 so far.

Okay. You talked about -- a little bit about some mechanical issues you had. Is there anything, whether it's vaulting or something else, that adds any additional mechanical risk to going to these longer laterals?

Not necessarily from a mechanical standpoint, other than it's -- I think it's more just knowing where we want to place the lateral during the drilling portion of the program. So, it's not like it's -- we are going to have a mechanical failure by going through a certain area. I think from what we have learned, we may try to avoid things or approach it differently, as you would do in any condition. But not really, nothing -- I wouldn't say that there is an additional layer of mechanical risk associated with that at this point in time.

Mark, definitely what we have learned, it's important to have 3D seismic. And that is why we have most of our acreage covered with 3D seismic, so that we can -- it resolves the faulting very clearly for us. And so, we go in to placing the well trajectory in a known area with the use of that 3D seismic.

Right. You have -- I know you have seismic on the extensional. But you have seismic on the Wattenberg?

Yes, we have seismic covering pretty substantially most of our acreage. And what we don't have, we are acquiring this year, I believe, to finish that out. And so, that is definitely a key component of our pre-planning process.

Understood. Thank you very much.

Chad Mabry, KLR Group.

Just had a question on the Mid-Continent for you, actually. I noticed that your Q4 production saw another sizable increase from Q3. Was most of that growth driven by expansions to your processing facility? And then, what are your expectations for growth from the Cotton Valley going forward this year?

Chad, I apologize. I couldn't quite hear the first part of that question. Would you mind repeating that, please?

Yes, of course. I just noticed that your Q4 production growth over Q3 was -- just curious what was driving that, if that was mostly driven by expansions to your processing facility?

No, at that time, we brought the processing -- the additional capacity on in February of this year. So, we were still working under the conditions that we had by the plant that we had in place at the time. I think we saw a nice increase because we just continued to work on our program. We saw -- we drilled some of those McKamie-Patton wells, as I talked about, in the fourth quarter, and they came online.

The other thing that we do is we do a lot of PDNP work, and we were able to go ahead and increase some of that PDNP work. It's not a lot of capital-driven, necessarily; but when we hit some of those more prolific Cotton Valley zones in the shallower part of the well bores, it can have a definite impact on our production.

Okay. Do you expect to grow that production in Arkansas?

We do. Sorry about that -- I remember the second part of your question. I would say that overall for 2013, you would expect to see a 10% growth rate down in the Arkansas area, based on the capital that we are employing down there.

Okay, great. And just one quick follow-up on that. It looks like some very encouraging results at McKamie-Patton. Any plans to increase some -- or divert some CapEx into the field this year? And maybe how much upside potential could that open up for you?

It's not quite as large as the Dorcheat-Macedonia field. And we are -- that is one of the things we are currently looking at, is what is the increased opportunity there at McKamie-Patton? It is referenced, though -- one thing I want to point out there is that we do show a lower expectation for those wells, but they are 100% crude oil. So, there is no gas associated with that rate at McKamie-Patton. So, when we are showing you that the wells made 130-plus [boe per day] in rate, that is all oil. And so, yes, we are encouraged by that.

As far as upside opportunity, we haven't put those numbers together, and haven't put them out there publicly yet. It's something that we are looking at. We may be able to share some light on that in our analyst meeting, but probably a little bit after that, as we continue to look at the out-months production out there at McKamie.

What we essentially did is we took some of the things that we were doing at Dorcheat in terms of the pinpoint fracturing, and moved it over to the McKamie-Patton field -- that sister field there. And we have had good results, as you noted today. We are excited about it.

I appreciate it. Thank you.

[Michael Hall], Heikkinen Energy Advisor.

Just trying to get a -- in the Wattenberg, just trying to get a better feel on where you are at in terms of cycle times, and how you are developing your acreage block currently? Do you expect all those wells drilled to be put on sales during 2013? And then, how much of your drilling would you say is targeting sweet spots that have been identified with the -- last year's program, versus still getting to know the acreage, if you will?

Cycle times, I would say that we drill spud to spud in the 12- to 15-day range. We have done better than that. And obviously, depending on how the well goes, maybe a little bit to the upper end of that range. But overall, I know without the concept of pad drilling, which we are doing a little bit this year, we averaged about 45 days spud to first production on the [horizontal] wells out there.

And what was the second part of your question? I apologize.

Yes, somewhat related to that -- so, if you are not doing a whole lot on real pad type development, then is it fair to say then that the wells aren't necessarily -- your wells aren't necessarily targeting identified sweet spots, as opposed to really delineating the acreage?

That is very true. And we are not so much delineating the acreage; we feel like we did that in 2012, quite frankly. But we are continuing to drill across the acreage, if you will, if that is fair? I think one of the things we are doing is we are looking to go to that pad concept more and more into the future. But at the same time, we do want to keep an eye towards our reserve growth, as well.

And by doing that, we are currently sticking with the convention -- or did at the end of this last year, with just the one offset rule. And so, by doing that, if we were to put everything in one particular section at this point in time, we'd show great reserve growth -- I mean, excuse me, production growth, but maybe not corresponding reserve growth. And we want to make sure that we are accurately portraying that, as well. Now, once we feel very comfortable about that, and we are talking about cost reduction as well, we will move to more of the pad concept in total.

And how long do you think about that transition period, if you will, running? Is that a couple-year process? A few years?

Yes, I would say -- yes, one to two years, something like that.

Okay. I think that helps. Thanks very much.

Mike Scialla, Stifel.

Just had one follow-up. Mike, in the past, you have talked about your desire to do acquisitions. Just wondering if you can talk about, from a high level, what kind of packages you might be looking at? Are they well-established plays? Or are you looking at doing something more on a grassroots level?

You bet, Mike. When you look at our history, we have been very successful at growing both through the drill bit as well as through acquisitions. And I think that is important for a Company to keep a balanced look. Now, we have looked -- we still look at a tremendous amount of opportunities, and they are -- probably the best way to describe it is it will be similar to what we acquired in August from the State Land Board. They will be very predictable. They will appeal to our strengths -- horizontal drilling, multi-stage frac -- definitely fracture technology within Bonanza Creek is a core competency. So, they will be type of opportunities that look like that.

Now, as you know, Mike, we have such a fantastic organic growth runway that just continues to expand as we do more work in Wattenberg. And so, that is where our top priority is, to make sure we fully delineate and expand and develop our Wattenberg acreage. Any transaction that we make would have to compete with that organic profile that we have.

Great. Thank you.

Ryan Oatman, SunTrust.

Just a follow-up here on the Arkansas properties. Can you walk us through the location count by field, and help us understand how that figure could move higher or lower with success? Is that five-acre downspacing? Is that McKamie-Patton? Just a little bit more color there.

Sure. At the end of the year 2012, we had booked locations, we had 120 gross, 99.9 net in the Cotton Valley in the Dorcheat-Macedonia field at 10-acre spacing. We only had two locations booked at McKamie-Patton at the end of the year. So, those are the remain -- and they are both 100% wells. Those are the current state of the affair, if you will, in both Dorcheat and McKamie-Patton.

I think what we are going to add is some color around what the potential is in the five-acre spacing at our Analyst Day presentation. So, we haven't released any of that information. And the same thing on McKamie-Patton at this point in time, although McKamie-Patton, again, as I mentioned earlier, is definitely a smaller sister field.

Okay. Thanks for that. I will stay tuned at the Analyst Day.

Nathan Churchill, Societe Generale.

Just on the learning curve side in Niobrara, wondering if you could help us appreciate how far along you think you have moved along that curve, particularly with well placement, frac stages, et cetera. And within that, if you are able to glean anything from how the non-op wells that you are participating in are being designed?

Obviously, we feel like we are pretty far up that learning curve in a lot of ways. And then, we obviously don't feel like we know everything. And so, we are always -- I think the key thing we talk about internally is -- we are never satisfied. So, looking forward, we feel pretty good about well placement. We feel pretty good about how many stages we are putting in the lateral, in terms of communication, although we are obviously always testing that process, if you will, both on our technical modeling and in practice out in the field.

As far as the information from the non-operated wells, those wells, along with all of the other wells, even though we don't have ownership in, we incorporate all of that information into our decision-making process going forward. So, we have some great neighbors. They are very smart folks. They have some great ideas, and some of those have returned great results. And we have been able to use that information to show those same good results on our property.

At the same time, some things that we have done, they will take and use as well, and apply that to their areas of ownership, as is very standard out here. So, I don't really want to try to put a number on it, how far we are up on the learning curve. Because, quite frankly, the next time we will find something else out, and then we never want to be -- like we said, we are never satisfied. But it's definitely -- we feel pretty high up along that curve in what we are doing today.

Okay. That is helpful. And on the borrowing base, when is the next revisit of that?

Yes, so we will be doing that in the next month or so.

Okay, great. That is all from me. Thank you.

Thank you. There are no further questions. Ladies and gentlemen, I would like to thank you for joining today's conference. This concludes the presentation, and you may now disconnect. Good day.

Thank you, Rachel. Good day.