Civitas Resources Inc (CIVI) 2011 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Bonanza Creek Energy Year End and Fourth Quarter 2011 Earnings Conference Call. My name is Derrick and I'll be your operator for today. At this time, all participants are on a listen-only mode. We will facilitate a question-and-answer session at the end of the conference.

(Operator Instructions)

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

Good morning, everyone, and welcome to our fourth quarter and full year 2011 earnings conference call and audio webcast. Joining me today are Mike Starzer, our President and CEO; Jim Casperson, our CFO; and Gary Grove, our Executive Vice President, Engineering and Planning; as well as other members of the management team.

Please be aware that our remarks today will include forward-looking statements. These statements are subject to many factors that could cause actual results to differ materially from our expectations as expressed in those forward-looking statements. These factors are described in the Company's SEC filings, and we refer you to our website or to the SEC's website to review those filings. The Company undertakes no obligation to publicly update or revise any forward-looking statements.

During this call we will make certain comparisons to 2010 operating and financial performance. We completed a corporate restructuring on December 23, 2010 with a significant investment from an unrelated party and acquired Holmes Eastern Company on that date. Any comparison to 2010 refers to the period ended December 23, 2010 for our predecessor and the effect of those transactions for the remaining eight-day period.

Also, during this call we will refer to certain non-GAAP financial measures. Reconciliations of those measures to the most directly comparable GAAP measures are contained in our fourth quarter and full year 2011 earnings release. Now I'm going to turn the call over to Mike Starzer, our President and CEO.

Thank you, James. Hello and good morning, everyone, and thank you for participating this morning and for your interest in Bonanza Creek. As this is our inaugural public conference call, I'd like to welcome you all to our new equity partners in our business. Thank you for your faith in this Company and we look forward to working together.

2011 was a terrific year for Bonanza Creek. We, along with our neighbors, including Noble, Anadarko, PDC, and others substantially derisked our Wattenberg field acreage for the development of horizontal Niobrara oil shale.

We drilled four wells with average IP rates of 788 barrels of oil equivalent per day, and our plans are to continue this development with the drilling of 24 horizontal Niobrara wells during 2012. Our proved reserves grew 33%, [SCC] PV-10 increased 72%, and production increased 90% over 2010. Our production is oil-weighted and our proved reserve base at year end is approximately 64% oil and NGLs.

Production for the year averaged 4,382 Boe per day and was comprised 71% liquids, compared to an average 2,300 Boe per day for 2012, comprised of 73% liquids. Fourth quarter of 2011 production was 5,788 Boe per day and was 70% liquids, and that compares to 2,655 Boe per day, comprised of 74% liquids for fourth quarter 2010, for an impressive year-over-year production growth for fourth quarter of 118%.

During 2011, we invested $165.5 million in drilling, gas plant construction, and leasehold acquisitions. We drilled 117 wells for the year -- 70 vertical wells, four horizontal Niobrara wells in the Rocky Mountains, 40 wells in the oily Cotton Valley formation in Southern Arkansas, and three non-operated wells in California. We again achieved 100% success in the finding of hydrocarbons. This is a testament to our team's exceptional drilling and completion expertise and the low risk nature of our assets.

At December 31, 2011, there were six wells awaiting completion. In 2011, we also completed our second gas processing facility in the Mid-Continent region, located at our Dorcheat-Macedonia Field, adding 12.5 million cubic feet per day to our field level processing capacity.

In the Rocky Mountain region, our production for the year averaged 1,722 Boe per day, with fourth quarter production averaging 2,370 Boe per day. Based on our results to date, we believe we are in the oily sweet spot and that our acreage has been substantially derisked.

We are now in full development mode in 2012 and we expect to drill 24 horizontal Niobrara wells this year. Each well that we have drilled has led to further enhancements of our procedures and techniques, increasing forecast recoveries. We've seen resulting rates above 50 Boe per day per frac stage on a typical 16-stage, 4,000-foot lateral.

At 80-acre spacing, we've engineered 215 drilling locations for 4,000-foot laterals on Bonanza Creek's acreage. However, another exciting development in the play is Noble's recent 9,100-foot lateral with 39 frac stages drilled just to the north of our Wattenberg land position. At a reported $7.5 million well cost and a projected EUR exceeding 600,000 Boe, the economics look terrific. We are encouraged that this work will work well on our acreage, and I have instructed our engineering and geoscience staff to prepare a proposal for the second half of this year.

Another exciting upside is the drilling of a horizontal in the Codell Formation, which we and others have produced vertically for many years and is just now beginning to be developed horizontally in the Wattenberg. I have also instructed our technical staff to prepare a Codell horizontal proposal for the second half of this year.

As previously mentioned, our four horizontal wells in the Niobrara, drilled in 2011, had an average IP rate of 788 Boe per day; the 30-day rate averaged 458 Boe per day and the 60-day rate averaged 389 Boe per day. We are very pleased with these results. We are currently drilling our seventh and eighth Niobrara horizontal under our two-rig horizontal program for 2012, with the first six wells in various stages of completion and flowback. The results continue to be as we expected based on our previous horizontal and vertical drilling in the area and the results of others in close proximity to our acreage.

We anticipate sharing with you test results from a number of our horizontal wells during our next operational update. We are excited by the results of our Niobrara horizontal program and will continue to develop this significant and economically rewarding asset for the Company.

Moving on to the Mid-Continent region, our production for the year averaged 2,479 Boe per day. Fourth quarter production averaged 3,242 Boe per day. We drilled 42 Cotton Valley vertical wells, 40 of these in our Dorcheat-Macedonia Field, applying the pinpoint fracturing completion process, and two in our McKamie-Patton Field.

While we are most excited about the growth opportunity in the Niobrara, the Mid-Continent region continues to produce excellent returns in 2011 as it has for many years. This development is a low risk, infill drilling program in the oil Cotton Valley sands, down to a 10-acre spacing where Bonanza Creek continues to apply the pinpoint fracturing technique with great success. In addition, this area possesses numerous recompletion options, proving the Company a stable inventory for development over the next three to four years.

As part of our 2012 capital program, we plan to invest approximately $20 million to expand our gas processing capacity in this area. Currently, we have 27.5 million cubic feet a day of natural gas processing capacity. And this expansion, which is well underway, will add an additional 12.5 million a day of capacity, taking us through full field development.

We own 100% of the gas gathering and processing infrastructure in Arkansas, and this gives us substantial control over field engineering and production growth planning, optimizes the economic net back of our economic net-back of our hydrocarbon production, and gives us a competitive advantage for considering acquisitions in the area. We have made excellent progress on our development plans to date and see tremendous potential ahead.

As of March 22, the Company has spud 35 gross wells, eight of which are horizontal Niobrara wells in the Wattenberg Field at various stages of completion and flowback. Currently, seven rigs are active -- five in the Wattenberg and two in Arkansas. We added a third vertical rig in Wattenberg to further accelerate our development program.

We are ahead of our production plan for March due to acceleration of our drilling program and individual project results, and are reaffirming our guidance of 8,700 to 10,000 Boe per day average rate for 2012. Our extensive inventory of 1,200 drilling locations -- 400, which are classified proven undeveloped -- and gross resource potential of 250 million Boe will fuel the Company's growth into the future.

I wish to congratulate the Bonanza Creek team for their hard work and dedication during 2011, returning such positive results with the funds entrusted to us. We have started very strong in 2012 and look forward to reporting the results of the first quarter in a couple of months. With that, I'll turn it over to Jim to summarize our financial results.

Thank you, Mike. As you commented in the operations overview, the Company's revenue and production grew significantly. We had an increase in revenues of 125% from the previous year due to the large 90% increase in volumes coupled with an increase in commodities prices. Volumes increased due to the effective use of our $165 million in capital expenditures.

Net income for 2011 was $12.7 million, or $0.43 per basic and diluted share. Net income for 2011 included non-cash charges for stock compensation of $4.1 million, triggered by our IPO, deferred income tax expense of $11.2 million, and an impairment charge of $4.1 million, mainly associated with our California properties. This compares to net income for 2010 of $14.6 million.

Our fourth quarter generated a loss of $177,000 due to the $4.1 million compensation charge to G&A triggered by the IPO and a very large unrealized decline in the fair value of commodity derivatives. Cash flow from operations, before adjustments for working capital changes, was $64.6 million, or $2.19 per share.

Total capital costs incurred for 2011 totaled $165.5 million. And as Mike discussed in the operations area, $138.5 million was invested in drilling and approximately $25 million in the expansion of our gas plant in Arkansas, with the remainder being spent on leasehold acquisitions.

Our balance sheet is an enviable one for growth companies of our size. At December 31, 2011, we had $6.6 million outstanding on our $300 million revolving line of credit with a $220 million borrowing base. We continue to evaluate acquisitions and this great liquidity allows us to move quickly and gives us a negotiating advantage over other companies who may have higher debt levels.

Our philosophy for hedging continues to be one of opportunity. We hedge to protect our capital and operational plans. Our current hedging position has us hedged at 46% of our 2012 forecasted oil production. With that, I'll turn it over to Gary to provide additional detail on our 2011 proved reserves.

Thanks, Jim. As Mike mentioned earlier, our reserves grew 33% year-over-year as of January 2012 to 43.7 million Boe as prepared by Cawley, Gillespie and Associates. Our trailing three-year all-in F&D costs are $9.15 per Boe. Our DD&A rate is larger as a combination of companies in 2010, was treated as a purchase for financial statement purchases.

Our current commodity mix of reserves is 56% oil, 8% NGLs, and 36% gas. All of the NGLs are from our Arkansas properties as we do not split out liquids from our high BTU Rockies gas at this time. The main area of reserve increase is in our Rocky Mountain region, where we saw 135% year-over-year increase. Primarily, reserves grew as a result of our 2011 vertical drilling in the Wattenberg Field and were enhanced by our horizontal Niobrara results.

We currently have recorded only 26 proved horizontal Niobrara drilling locations in our reserve report and have identified an additional 189 Niobrara horizontal locations on our Wattenberg acreage. As we continue to develop our Wattenberg Field acreage, we should continue to see reserve additions from our 2012 drilling program.

As an example, our 2012 program calls for drilling 92 vertical and 24 horizontal locations in the Wattenberg Field. Of those wells, 37 vertical and 27 horizontal locations are not included in our year-end reserve report. Looking forward, we'll continue the development of our assets in all regions and continually seek reserve growth by employing technical advances in the developed areas along with drilling on our large inventory of undeveloped acreage.

Lastly, we'll be continuing our delineation of the North Park Basin Niobrara opportunity later this year with three horizontal wells. With over 32,000 net acres available for Niobrara development, continued success in North Park will be another potential source of additional reserves in the coming years. With that, I'll turn the call back over to Mike for some final comments.

Thanks, Gary. We continue to reiterate our guidance for full year 2012 based on the capital budget of $250 million, excluding potential acquisitions. For the balance of 2012, we will operate two horizontal rigs, two vertical rigs in the Rocky Mountain region and two vertical rigs in the Mid-Continent region. We estimate this drilling program will drive production up approximately 100% in 2012 over the previous year, ranging between 3.2 million and 3.65 million Boe, or an average of 8,700 to 10,000 Boe per day. We will maintain our oil and liquids weighting at approximately 70% of production.

We are pleased to say that in 2011 we hit our targets. This is an employee team that believes very deeply that we do what we say we are going to do and we will continue to focus intently on exceeding expectations and growing Bonanza Creek. We look forward to getting to know you all better in the coming year. That concludes our prepared comments, and we want to thank you for participating on the call today. With that, I'll turn it back over to the operator to begin our Q&A session.

(Operator Instructions)

And our first question is coming from the line of Evan Calio from Morgan Stanley. Please proceed.

Good morning, guys.

Good morning.

Welcome. And maybe welcome back is more appropriate to the quarterly conference call circuit. And thanks for taking my call.

Thank you. You're welcome.

My first question is on the horizontal Niobrara type curves. Obviously, competitive results are generally very positive, including PDC's Niobrara increase in EURs, and your 30-day rates are impressive [for, well, I think they've been on for about] eight months now. So how many wells do you kind of envision needing or production data to establish or release a type curve of EURs that you're comfortable with on your horizontal Niobrara wells?

Hi, Evan. This is Gary. What I would say is that, like we talked about, where we have the four wells from last year that we currently drilled and we've spudded eight wells this year and will continue to see results from those coming forward. Our internal type curve, as we've kind of mentioned before, is in the 312,000 Boe range.

Yes.

And we feel like the results that we're seeing continually support that type curve today. And as we go forward, I would expect to see us probably see some minor revisions in it, moving upwards most likely.

I think the thing that we want to probably point out more than anything else is that where we sit a larger majority of the production we have is oily, and so we may tend to be conservative on an EUR standpoint as we move forward. But a higher percentage of that's in the oil region, so we're going to see better returns going forward from just the commodity mix.

That's great. That's great. On the exciting news on the longer laterals, should we expect those, the 900,000 plus foot lateral in the Codell wells in 3Q? And are those additional wells you'll be drilling or are those just in lieu of different completions of other wells [that you're in planned with]?

Right now, Evan, those would be augmentations to our budget. We're looking at our neighbors very closely that are moving ahead, particularly Nobles well that been on for a while looks very favorable. And in addition to their down spacing just to the north of us, also looking very good. So we're fast followers. We're watching very closely to see if these results continue, but right now everything looks very good.

Great. And if I could just kind of one more question, maybe Jim. Help me understand that the higher LOE and G&A versus previous guidance, are those -- those are isolated and affects your original guidance closer to $10 a Boe or how should we think about that on a go-forward basis?

On a go-forward basis, I think we've talked in the past -- horizontal wells, even on an expense basis, are front-end loaded, even for expenses. As we increase our production across the Company, you will see higher production with the, let's call it, fixed costs for expenses. So as we increase production LOE on a per unit basis will drop and will drop precipitously as we get into the third and fourth quarter.

If you look at the trend of the Company from previous years, as we displayed in the S-1, we have moved from high operating areas into lower cost areas. And then, as we've converted more of our verticals and the pinpoint fractures in Arkansas, you're seeing a lessening of LOEs.

So let's make a long story short. You will see decline in LOEs. The moderate decrease in the fourth quarter, I think, was almost planned. And as far as G&A, we took a substantial charge, non-cash charge, in the fourth quarter for the compensation expense triggered by the IPO and our G&A will still come in this year within the parameters that we've discussed. So to answer your question, G&A, a one-time charge in the fourth quarter; LOE in the future dropping as production increases.

That's great. I'll leave it there for somebody else. Again, thanks. Good quarter, guys.

Thank you.

Thanks, Evan.

Your next question is coming from the line of Brian Corales from Howard Weil. Please proceed.

Good morning, guys.

Hi, Brian.

The main question, in the Niobrara, do you think there's potential for further down-spacing with eight wells per section or is there a better chance that some of the other zones, like the Codell, would have horizontal? And if it is the Codell, what kind of EURs on a horizontal would you be expecting?

Well, the first part of that is I think as we continue to move forward we're going to see drainage in what we're seeing from spacing in terms of the horizontal wells [that are being applied] out here in the Niobrara. I think it's no secret to everybody that the Niobrara historically has not had a very large drainage radius on the vertical wells. And so as far as continued down-spacing, I think we'll see continued testing of that as well as we move forward into the future.

On the Codells, as we now convert over to the potential to drill horizontally in the Codell as well, you're dealing with a much thinner section. And so we'll probably see a little bit larger drainage from that specifically. But at the end of the day, we still expect to see EURs probably in the same range that we're seeing from the Niobrara work to date. And most of that's based on the information that we've seen, again, from our neighbors and the information that's been published to date in terms of rates, and is coming in very consistently with what we've seen from the Niobrara.

Okay. And could you all maybe provide if there's anything that's been done over the last couple of months regarding the North Park? Anything additional there?

We are currently in the process. We shot some seismic in the North Park area, and we're currently in the process of processing that and analyzing that 3-D seismic that we shot up there. Again, with plans toward the latter part of this year to drill the three horizontals that we mentioned earlier.

Right. But no one else -- no other operators have been drilling?

Not --.

Not recently?

Not in the first quarter of this year. Correct, yes.

Okay. Okay. All right, guys. Thank you.

Thanks, Brian.

Your next question is coming from the line of Mike Scialla from Stifel Nicolaus. Please proceed.

Hi, Mike.

Good morning, Mike. The two rigs you have running in the Niobrara right now, do you plan on letting one of those go at some point or you going to keep two this year?

Our program gets us through -- basically through third quarter when you do the well count and how fast we're drilling for our planned four rigs in the Wattenberg Field -- two vertical, two horizontal. We did add a third vertical rig because we had some ability to go ahead and accelerate that program, and we love to accelerate. But right now, we do plan on fulfilling that program, say, through August or September on the horizontal side and then probably talk to our board about maybe continuing the program.

Okay. So if you were to hang onto that second rig you're going to end up drilling more than the 24 wells you had planned, if things are going well at that point?

That's correct. Yes. And right now, I anticipate talking to our board about that, probably in the third quarter timeframe.

Okay. And then, I wanted to touch on the acceleration in the vertical program as well. It seems like you're getting very good results, at least early stage, from the horizontal wells and I assume the returns would be better with the horizontal wells, especially if the horizontal Codell is successful. So I'm wondering why you're thinking about accelerating or planning on accelerating the vertical, or is it just a matter of some areas are more amenable to vertical development or what's the thought process there?

Good question.

I think it's a couple of things, Mike. One is the fact that yes, there are some areas that we have that we don't necessarily have continuous acreage, and so we'd want to go ahead and drill vertically on. But I also think that it's important to note that I don't think we see this as strictly a horizontal development or strictly a vertical development. I think we see this as a combination, and we'll continue to do that moving forward.

I think our neighbors hold that same opinion, at least from some of the most recently published information as well. But we think the combination of a vertical-horizontal development out here in both Niobrara and Codell is warranted.

If I can maybe probe on that a little further, is it just a matter -- that's the best way to drain the reservoir? You wouldn't sufficiently drain it just with horizontal wells?

I think it's a little bit of that and it's also probably a little bit of just the way that the field has been developed historically as well. And so you're going to have some areas that are more consistent with drilling vertically. And then, the geology in the area is going to also kind of weigh on that as well. So we have a lot of knowledge there from a geologic standpoint in knowing how we, by drilling vertically, it helps us place horizontal wells also by getting --.

We shoot seismics, but at the same time we drill a vertical well or two or three in an area, it also gives us a little more information there to plan the horizontal correctly.

And, Mike, you know that we touched on this on our -- on our western acreage, we actually complete both the Codell and the Niobrara in our vertical wells, as Gary mentioned, and that gives us an opportunity to, of course, deplete the Codell at the same time as we are with our Niobrara development.

If we have a very outstanding Codell test and we see the continued trend of the wells that have been drilled horizontally in the Codell later this year, our engineering will probably move more towards horizontal developments.

Okay. That's what I thought. In terms of the three wells that you're in the various stages of process of completing, can you tell us where those are located in terms of the timing of -- I think, Mike, you had mentioned you plan on doing an operational update to give some rates on those probably before your first quarter release? Did I hear you right on that?

We think we will, right around that timeframe. It will probably be -- in the first quarter timeframe, it will be early May is what we're thinking. Yes, and they're all in different stages of flowback right now, Mike, and along with drilling our seventh and eighth well with the two rigs. Where they're located, from a township range, they're in 561, 761, and 1761 -- or sections five, seven, and 17 in 561.

Okay. I don't have the map in front of me. Was that the western block or is that the eastern?

East side.

It's the eastern right now. We do have plans for the western, too, this year, but these are -- we're starting off in the eastern side -- kind of mid-eastern.

Okay. Anything planned this year to test kind of the northeastern extent of the acreage?

We do. We do. We have locations there. As we get closer to the [Krieger] area of PDC, we'll be south of that on our -- and that section five well is actually kind of in the northeastern of our acreage.

Yes.

Okay, great. I'll get back in the queue. I've got a couple more, but I'll hop back in the queue at this point. Thanks.

Super. Thank you.

Your next question is coming from the line of Andrew Coleman from Raymond James. Please proceed.

Thanks a lot. Good morning, folks.

Good morning, Andrew.

I had a question on -- can you give us -- is there much of an update on the California process at this point, for those assets?

Yes. We've had a number of inquiries in California by operator that are interested in the position. We're evaluating that right now [in Pat's] group, in our corporate development side. We still are planning to talk with our board and have a market test of what those assets may be worth and talk about it mid-year. And, Andrew, you know previously we've been talking that we're looking at a potential monetization of our California assets.

Okay.

That's still on track for mid-year.

Perfect. And then, kind of -- we've heard -- I guess I'd like to get some of your view on the overall DJ Basin sort of [leasing kind of heat], if you will. There have been some other operators that have looked at -- I believe are looking at some deeper zones. Are those kind of in your long-term horizon or could you test any of those more Mid-Continent plays that folks are saying could extend way up into the Rockies there?

We had a few horizons that are being touched on this year, actually by a number of operators. The Greenhorn -- Pat, correct me -- and some of these are looked at --.

The Greenhorn's a potential --. You made the comment as far as the Mid-Continent horizons that are coming into the DJ.

Yes.

I don't think they -- yes, if you're talking about the Cherokee and some of those, I don't believe those come all the way up into our acreage. But we do have, as Mike mentioned, the Greenhorn. There is some [Lions] potential, so there are some deeper horizons in there.

Okay. And is that something --.

Andrew, I guess I'd just add to that, is most of the leases that we have, if not all of them, in the DJ Basin are pretty much all depth leases as well.

Okay. Would you have the ability to go back and speak to some landowners, if you thought there was prospectivity, to add those deeper zones? Or would this be a -- if you decided to look at those plays, be a potential target for some new leasing in the future?

We could expand our leasing [aerially], but we have, for virtually all our acreage, Andrew, we have all depths, so we wouldn't need to lease new acreage. If there's a discovery, a deep discovery found, we already have the land position on our current acreage.

Okay. So last question then, as you think about perhaps extending the program later in the third or fourth quarter, it's possible that we could see some of that coming into the program as well?

We could. Our neighbors are -- there has been a lot of talk about it, but we haven't seen a lot of activity going down deeper below the lines.

Yes. Not at this point. Yes. Nothing below the lines to this point.

Okay. Thank you.

Thanks, Andrew.

Your next question is coming from the line of David Deckelbaum from KeyBanc. Please proceed.

Good morning, guys. Thanks for taking my call.

Good morning, David.

Good morning, David.

Just about the type curves a little bit and touching on some of the other analysts' questions today, I guess as we think about some of the encouraging things that you've seen, particularly out of the 60-day rates, it looks like the curve's come up and originally you all had revised the type curve up to 312,000 equivalent.

And I guess as we think of the North Platte curves being a bit higher than that, as you -- I guess if I'm looking at sort of the curve in more of the eastern block when your State Whitetail, State Antelope well's getting a little bit higher, as we're ahead of plan here, my impression was that this guidance had been predicated on sort of a lower type curve. And now, we're using a higher curve and we're reiterating and we're ahead of plan, I guess. Is there -- do you feel like there's a little bit too much conservatism in guidance right now, or are we risking around timing of completions? And how should I think about that in regards to the curve and the guidance now?

Currently, the results that are coming in give us no cause for pause on our guidance at all. We're ahead on our drilling plan, as I mentioned earlier. And the individual project results are coming in nicely, so we're just reaffirming our guidance at this time.

Yes. We think the range is sufficient that we have in store right now. But as we move forward through the year, we'll continue to update that range for you. It's real early in the year right now. We haven't seen all the results from the wells we've currently drilled. And as we move forward, we'll continue to narrow that range for you moving forward.

All right. I'm sorry if you touched on this a little bit earlier, but with the 24 horizontal plan this year, how do we think about the mix? I know that a lot of the wells currently completing right now are more in the eastern block, but how is the mix play out for the rest of the year in terms of eastern, western, and Niobrara, or in the Wattenberg specifically?

I think you'll see -- overall, I think you'll see about -- of those 25, about, I'm going to say, 15 on average are going to be more towards the eastern side and the ten will be more towards the west. Was that your question, David, about where [are they going to fall]?

Yes.

But, quite frankly, this year we're going to push those wells across our acreage. I think the key point is when I talk about we're going to drill 24 wells this year, but only three of those are in our proved reserve ledger at this point in time. I think we're continuing to drill across the acreage to where we can see all of it, if you will. Even though we feel like it's all been substantially derisked, we're going to make sure that we've got wells in a lot of the acreage going across our position.

Yes. And some of it's, David, driven a little bit -- we have just a few wells we need to make sure we drill to hold acreage, and we're ahead of the curve on that. So effectively, at the end of this year we'll have all but a little bit of our acreage held by production. Isn't that right, Pat?

About 90%.

About 90%.

And if I may, just on North Park, I know that you all sort of put out where your plan is and what your expectation is there. What are you seeing in terms of other operator activity? I know that you have few peers in that area, but do you feel like the mood has softened? Has enthusiasm picked up at all or is it more status quo since three months ago?

I'd go with the latter. I'd say it's status quo from where we've been over the last few months. There's been activity up in that area; I think we've talked about that in the past and that's what we've used to kind of predicate what we think we're going to see up there and then we'll continue with our program towards the end of this year. And, as I mentioned earlier, I think we haven't seen any operator drill in 2012 to date in the North Park area.

And one reason there, David, is because we don't have the gas takeaway infrastructure there. We've mentioned that; we get asked this quite frequently while we're on the road, is the North Park area, there's a little more lead time in being able to get gas takeaway capacity and running that line, region line, up to Wyoming. It's not insurmountable, but it is a little bit of delay.

The beauty of the Wattenberg is you drill a well and you put it on immediately. You've got a very advanced infrastructure there with compression and gas processing capability. That will come in North Park, we believe, so that's probably the reason that you don't see as much activity.

I appreciate the color on that, and good luck with the rest of the year, guys.

Thank you.

Your next question is coming from the line of AJ Strasser from Cooper Creek Partners. Please proceed.

Hi, guys. Good morning.

Good morning, AJ

Hey, how are you? At the risk of probably sounding like a broken record, I guess everybody wants to see if it's possible for you guys to take up your type curves in the Wattenberg.

Let me ask you just a different way. Based on the IP rates that you're seeing today, is there anything that's kind of significantly different, maybe geographically speaking or something else, that would cause us to differentiate your potential type curves from that of PDC and Anadarko? Is it possible that we could start to eventually get into that sort of kind of 450 barrels to 500,000 barrels range?

That's potential, AJ I think right now we feel very comfortable where we're at. But as we continue -- and a year ago when we were looking at the horizontal Niobrara program, our neighbors as well as us, the EURs just continued to move up and as we find additional procedures and techniques that are unlocking this vast resource. So it is likely to expect it to move up. But as of everything we've seen so far in our drilling of our current wells as well as the performance of our wells last year and our neighbors, we feel very comfortable with our EUR forecast.

Okay. But there's nothing sort of significantly different that you can think of that might -- that may completely separate you guys from what we're hearing from Anadarko and PDC? I guess that's my --.

Not at all.

(inaudible - multiple speakers)

Geologically, there's really not a lot of difference there. As you do know, as you move to the northeast you'll see more oil coming in terms of production, you'll see a bigger blend of oil in that area. But that's probably the only difference that I could recommend at this time that we have seen from all the data that we've analyzed.

Okay, thank you. And then maybe moving on to the -- on your midstream assets, can you possibly give us a sense of how much EBITDA you expect to generate from those assets this year? And maybe share with us your potential plans. There's obviously been -- a lot of your peers have been talking on different ways to modify the midstream assets, and I'm just maybe curious to get kind of your high level thoughts on that.

I think, AJ, a very good question. One, let's start that we own all of the gathering and all of the gas processing facilities in that area. And people look at those and sometimes we feel that they get neglected when they're evaluating the Company. If you look at the guidance that we've given, and let's assume $100 a barrel, if you look at what we're giving out for G&A and LOE, there can be a wedge approximately of $75 to $80 per barrel produced in Arkansas.

If you look at the production that we have given for our Mid-Continent area, our fourth quarter production was about 3,200 barrels a day. And as we continued to do recompletions and continued to do the drilling, you will see that obviously the production would rise. And if you just multiplied the $80 times the barrels per day there, you could obviously get to a very large number.

We have not specifically given EBITDA or a cash flow in those fields. All I can do is direct you to how to connect the points. If you look at the fact that we are adding 50% to our processing capabilities, approximately, from what we have today -- effective processing, let's call it 40% -- you would assume that we would expect our production to increase 40% to 50% as well.

Okay. Thank you. That's helpful color. And then if you'd just let me ask a couple of quick questions here on -- is there anything within your CapEx guidance that is being used for kind of new ventures? How should we think about different areas that you guys might branch out to at some point?

I talked about it briefly when we were looking at a very significant liquidity position for a Company of this size. In our budget of $250 million, it's all identified with a very nominal amount -- when I say nominal, 1% to 2% for, let's say, acreage acquisitions in the areas that we currently operate.

If there is to be acquisitions other than that, those would be add-ons to what we've already quoted. As you know, we continually look at acquisitions, but obviously those would be things that would be predictable for a Company like us to make. They would be accretive to the shareholders and obviously would have to beat the returns that we've received in the past.

Okay. And lastly -- last question here, and I know it's probably way too early to tell, but just curious to get your thoughts. There's been, obviously, a lot of thought here given to Southwestern Brown Dense/Lower Smackover. Just as we hear more about that play, how should we be thinking about you guys as a kind of beneficiary for that? How close are you to the wells that they're drilling? Any type of thoughts, because obviously it could be substantial to you guys, would be very helpful.

Yes. AJ, I might just mention real quick that we had been contacted by Southwestern and others because of our gas processing infrastructure, but I'll turn it over to Gary, who's actually been involved with his staff in some of those conversations.

What I would say -- how close are we? The well they drilled is in the Atlanta Field; we have property in the Atlanta as well. It's real close to Dorcheat; you're talking five miles distance, something like that, from where their wells are located in the Brown Dense today.

There's been other Brown Dense wells drilled in and around our acreage in that position as well, and we've analyzed that with the information that we have on our own property and along with any information that's coming from Southwestern and the subsequent wells that we'll see from Cabot and Exxon and others in that area.

So we'll continue to analyze it, looking forward. I think how you should look at us on that is two-fold. One, Mike mentioned the fact that we do have processing capabilities in the area and we would see that, again, as a competitive advantage, that we could take the gas directly into that facility and be ready to go.

Two is the fact that we hold all of our acreage there by production and we don't have any issues there in terms of expiree issues on acreage. And we would continue to wait to see the application of the horizontals here that Southwestern has drilled and continue to get that information from then and then make our plans on that. And to use Mike's term from earlier, expect us to be fast followers in the Brown Dense.

Okay. That's very helpful. Thank you for taking all my questions.

Thanks, AJ.

You have a follow-up question coming from the line of Mike Scialla from Stifel Nicolaus. Please proceed.

Yes. One to see -- where are your current well costs on the horizontal Niobrara?

Of the 35 wells, we've spud to date, and everything's looking good, Mike, we're within 1% or so of [AFE] right now, based on the last report I received from operations.

So that puts the cost in the horizontal wells, Mike, about $4 million -- $4 million to $4.1 million.

Great. Okay. And in terms of what you're planning on doing there this year, it sounds like you're really just focused on delineating the acreage and I would assume you don't have any plans to test spacing, or is that something you're thinking about already?

That's correct, Mike. We don't have any plans to test spacing. As I like to affectionately call, our R&D groups are busy doing that, so our neighbors are busy doing some of that work as well. And so, again, we love the fact that they're very active and we have good neighbors and we like to be good neighbors as well. But in this case, we're going to see some tight spacing results coming -- tighter spacing results coming out shortly from them. And we'll continue on with our plan and then make changes as necessary going forward to down-space where we feel it's appropriate.

And, Mike, I might add to that. You know that volumetrically, even at 80-acre spacing, we're not going to -- forecasting an EURs [per section] that's very high at all for that much resource in place. And I think there's definitely -- from a volumetric standpoint, there's room that the numbers could move up.

I might also -- Gary and the team, we've talked about -- down in Arkansas, we're developing on ten-acre spacing. But since you brought up down-spacing, we are looking at going to potential five acres on that. So we'll be looking at that this year and we mentioned it at a couple of conferences.

Would the five-acre spacing, if that is successful in the Mid-Continent, would that have some reserve implications as well or just acceleration?

It would have some reserve implications, absolutely. And again, mainly because of the lenticular nature there of these sands in the Cotton Valley, a lot of it becomes to access to the reservoir that's available to us at a spacing.

Okay. And then just last one from me. In Wattenberg, Mike, you had mentioned you'd benefit from the advanced infrastructure there. Any potential constraints you see in terms of getting wells drilled, completed, or put online?

We haven't so far, Mike. Because you have very strong midstream players out there in DCP and Anadarko and multiple sale -- buyers of our product, it's been pretty aggressive. Having said that, you will have -- time to time, you'll have a disruption due to equipment going down or something like that, but they jump on it very quickly. So we don't actually forecast any problems in capacity or certainly regional takeaway because of the expansions --.

Or in services.

Or in services, good point. Yes.

Great. Thank you very much.

Thanks, Mike.

At this time, I'm showing we have no further questions in queue. Bonanza Creek Energy would like to thank you for participating in today's conference call. You may now disconnect and have a great day.

Thanks, everyone. Enjoy your weekend.