Civitas Resources Inc (CIVI) 2012 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the First Quarter 2012 Bonanza Creek Energy Inc. Earnings Conference Call. My name is Jeff, and I'll be your coordinator for today.

(Operator Instructions)

I would now like to turn the conference over to your host for today, Mr. James Masters, Investor Relations Manager. You have the floor, sir.

Thanks, Jeff.

Good morning, everyone, and welcome to Bonanza Creek's First Quarter 2012 Earnings Call and Webcast. Joining me today are Mike Starzer, our President and Chief Executive Officer; Jim Casperson, our Chief Financial Officer; Gary Grove, our Executive Vice President Engineering and Planning; and other members of our Management team.

Yesterday, we filed our 10Q with the SEC, and we issued our earnings press release for the first quarter. Both are available on our Website.

The agenda for today will begin with Mike discussing the highlights for the quarter. Gary will provide an operations update. Jim will summarize our current financial condition. Mike will provide closing comments.

We will leave time for Q&A at the end.

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. These factors are described in our SEC filings and we refer you to our Website or to the SEC's Website to review those filings. We undertake no obligation to publicly update or revise any forward-looking statements.

Also, during this call, we will refer to certain non-GAAP financial measures. We use these measures because we believe they are good metrics to use in evaluating performance. Reconciliations of these measures to the most directly comparable GAAP measures are contained in our earnings release.

With that, let me turn over the call to Mike Starzer, our President and CEO.

Thank you, James.

Good morning, everyone, and thank you for your interest in support of Bonanza Creek.

It is my pleasure to report to you our significant accomplishments for the first quarter of 2012. As you can see from our press release, issued yesterday, this was a strong quarter for Bonanza Creek, matching expectations and keeping us on track to meet 2012 guidance, which we forecast to effectively double the production achieved in 2011.

Throughout much of our history as a private company, Bonanza Creek's growth was limited by access to capital. Entering the public market allowed us the financial flexibility to pursue the dramatic growth we knew we could achieve.

I am pleased to report that the first quarter confirmed the potential of our assets. We invested $60.9 million in the first quarter to drill and complete 16 wells, with an additional 26 wells waiting on completion at the end of the quarter.

In the Wattenberg Field, we drilled and completed five horizontal and four vertical wells. In the Mid-Continent Region, we drilled and completed seven wells and performed 31 Cotton Valley pay additions, with an additional five wells waiting on completion at the end of the quarter.

This activity helped produce record sale volumes of 646,000 barrels of oil equivalent, or an average of 7,100 barrels of oil equivalent per day for the quarter, a 96% increase over the first quarter of last year and a 21% increase over the previous quarter.

In addition, we produced an average of 7,900 barrels of oil equivalent for March, a 126% increase over March of last year. This production growth translates to EBIDAX for the quarter of $31.5 million, or $0.80 per diluted share, a 132% increase over the first quarter of last year.

Our adjusted net income for the quarter was $11 million, or $0.28 per diluted share. This is an increase of 193%, compared to the first quarter of last year. Adjustments included unrealized commodity derivative losses due to the strong oil prices and a non-cash stock-compensation charge.

GAAP net income was $8.5 million, or $0.22 per diluted share, on net revenues of $49.5 million, which represents a 123% increase over net revenues from the first quarter of last year. Meanwhile, crude oil and liquids represented 76% of total production for the quarter and contributed approximately 93% of our revenue.

We are very pleased to show such strong year-over-year financial results. Thank you goes to our Operations team for these tremendous accomplishments.

With that, I'll turn the call over to Gary Grove for the update.

Thanks, Mike.

During the first quarter 2012, we drilled a total of 42 gross, or 36.5 net wells; completed 16 gross, or 13.7 net wells; and performed 33 recompletions. This was an acceleration of our drilling plan, which is anticipated to have a significant impact on production in the second and third quarters of 2012.

In the Wattenberg Field, we drilled 30 wells and completed five horizontal and four vertical wells. In the Mid-Continent, we drilled 12 vertical wells and completed seven wells. A total of 31 Upper Cotton Valley recompletions were also performed.

At March 31, 2012, we were in the process of completing three horizontal and 18 vertical wells in the Wattenberg Field and five vertical wells in Southern Arkansas. At May 1, 2012, we had two horizontal and two vertical rigs operating in the Wattenberg Field and two vertical rigs active in Southern Arkansas.

Our horizontal Niobrara well costs in the Wattenberg Field continue to be flat at $4 million. While we internally modeled a 3% per-year increase in service costs, we haven't seen any cost inflation to date. We have our two horizontal rigs under contract, have not had any problems securing water or frac sand, and we have a dedicated frac crew from Halliburton.

In Wattenberg, production continues to rapidly increase into second quarter due to our development program. We completed five horizontal wells in the first quarter, two of which have produced for longer than 30 days to date. These two wells had an average 30-producing-day rate of 541 barrels of oil equivalent per day. Together with the first four wells completed in 2011, our average 30-day producing rate for all horizontal Niobrara wells to date is 486 barrels of oil equivalent per day, at 72% crude oil.

I am pleased to report that during the second quarter, we achieved our highest 24-hour initial production rate in our 4,000 foot horizontal Niobrara program, with the completion of State Antelope 31-11, which came on at 915 barrels of oil equivalent per day, producing 63% crude oil.

We continue to apply operational enhancements to our horizontal development program to increase recovery and reduce cost. For example, we have recently increased the number of stages from 16 in our previous wells to 18 in the same approximate 4,000-foot lateral in our most recent completions.

Our horizontal Niobrara well results continues to substantiate a 312,000 barrels of oil equivalent tight curve forecast, which assumes a well-head commodity mix of 65% crude oil and 35% associated rich gas. The rich gas at the well head averages between 1,330 to 1,370 MMBTU per cubic feet, calculating volumes on a combination of oil, liquids and dry-gas yields and an estimate ultimate recovery of 356,000 barrels of oil equivalent and a resulting commodity mix of 57% oil, 19% NBLs and 24% dry gas.

We have previously disclosed in corporate presentations 215 future Niobrara horizontal-drilling locations spaced at 80 acres. This included only acreage where we hold a majority interest control. When we include acreage in which we have less than 50% working interest, as of March 31, 2012, our location count increases to approximately 290 wells -- again, spaced at 80 acres.

New opportunities continue to emerge in the Wattenberg Field. For example, we plan to partner with an offset operator on a 9,000-foot extended-reach lateral during 2012. Participating in this well will provide us valuable information that we will use in drilling our own extended-reach lateral planned for the second half of this year.

Noble Energy drilled an extended-reach lateral in 2011 and has seen dramatic improvement in returns and recoveries over the standard 4,000-foot lateral well. Expected reserves of over 750,000 barrels of oil equivalent per well at a well cost of between 7 million to 8 million results in economics that are competitive with any shale play in the country.

We and our neighbors are primarily targeting the Niobrara B Bench for horizontal development using 4,000-foot laterals at 80-acre spacing. However, offset operators are currently testing extended-reach laterals and downs-pacing to 40 acres. These operators are also testing the horizontal potential of the lower C bench of the Niobrara and the Codell formation. To date, results from extended-reach laterals and the additional horizons have been encouraging, while data on down-spacing is still forthcoming.

Turning now to our Mid-Continent region, during the first quarter of 2012, we completed seven wells in the oily sands of the Cotton Valley. We continue to have success using the pinpoint fracturing completion technique to develop new wells. Our new-well program and active recompletion efforts continue to significantly increase production from the region, which has grown from approximately 900 barrels of oil equivalent per day in 2008 to an average rate of 4,334 barrels of oil equivalent per day in the first quarter of 2012.

The entire Dorcheat Macedonia field has been engineered into our proved reserves by Cawley, Gillespie and Associates at 10-acre spacing. As of March 31, 2012, we had 147 gross locations remaining, including 10 new proved locations acquired during our ongoing leasing program.

We are encouraged by the potential to further down-space the area based on the lenticular nature of the [stacked] sand and shale sequences in the Cotton Valley formation. We plan to test this potential during the second half of this year. Our goal is to expand our development inventory and increase our recovery factor of oil in place.

In 2012, we are expanding our Dorcheat gas-processing facility, effectively doubling capacity to 25 million cubic feet per day in the Dorcheat field. We remain on track to be on line in the first quarter of 2013. This will bring total processing capacity for the Mid-Continent region to 40 million cubic feet per day and facilitate our increased oil production from the field.

While we process a nominal amount of third-party gas, we primarily own and operate these facilities for our own current and future development. We are confident both in our plan and our ability to meet our production targets for 2012.

With that, I'll turn the call over to Jim to summarize our financial results.

Thanks, Gary.

As Mike mentioned earlier, we reported record numbers in sales volumes, revenues, earnings and cash flow for the quarter. Our balance sheet continues to be very strong, with only $21.6 million outstanding on our revolving credit facility at the end of the quarter. On May 8, we closed on our amended $600 million credit agreement, ensuring us added capital flexibility into the future. The borrowing base was increased to $245 million.

Regarding expenses for the quarter, we continue to bring down our per-unit lease-operating expense, although it is not yet where we anticipated, while averaged for the year. Our LOE for the quarter was $12.03 per barrels of oil equivalent, as compared to $13.99 for the first quarter of last year. LOE is higher initially as we complete and produce our horizontal wells. The costs should subside after a few months of production. We will also continue our recompletion programs in both regions, bringing on additional volumes without incurring additional lease-operating expense.

We reported cash and general-and-administrative expense of $5.3 million, or $8.19 per barrels of oil equivalent, which is on track to meet our guidance for the year. We have added approximately 30 administrative employees to our staff since September 30, 2011. Most of these are accounting, information technology and finance personnel, as we have migrated accounting and I.T. from third-party providers.

I am very pleased with the personnel we have added and believe strongly that our success is predicated on hiring and retaining the best people.

I'll turn the call back over the Mike for closing comments.

Great. Thanks, Jim.

As we did in our last call, we reiterate our guidance for full-year 2012 based on a capital budget of $250 million, and excluding potential acquisitions. We will operate two horizontal rigs and two vertical rigs in the Rocky Mountain region and two vertical rigs in the Mid-Continent region. We expect our drilling program will conclude sometime in the third quarter.

We estimate this drilling program will drive production to double that of the previous year, averaging between 8,700 to 10,000 barrels of oil equivalent per day.

We are thrilled by the results shown to date in the Wattenberg Field, giving us high confidence to aggressively develop this asset over the next several years. Our goal and message for 2012 has been hitting our targets, and I'm pleased that we have accomplished this in the first quarter.

We are excited about the future as we proceed with investing in our attractive development inventory. We have communicated at every opportunity that this is a team that believes very strongly in doing what we say we are going to do. We value your trust in Bonanza Creek and we'll work hard to meet and, hopefully, exceed your expectations.

That concludes our prepared comments. We want to thank you for participating on the call today.

With that, I'll turn it back over to the operator for any Q&A; so, back to you, Jeff.

(Operator Instructions). Brian Corales, Howard Weil Incorporated.

Good quarter.

I have a question on the down-spacing of the Niobrara. From the work you've done and maybe some of your analysis of what others have done, where's your confidence level on where spacing should be, whether it's 40s or 80s, or wider?

Brian, I would say that right now we have a lot of confidence in the 80-acre spacing that we've seen from not only ourselves, but our offset operators. I think the initial results from what we've heard on the 40-acre spacing test -- again, like we said -- are encouraging. The rates are within what we expect to see from wells spaced at 80 acres. I think a little more time is prudent here, again, to see what we will see from a 40-acre-space test as we move forward.

But ultimately, if you look at recoveries from the Niobrara from the vertical wells, we all know the drainage areas around those wells are relatively small. So going to that 40-acre spacing is a very logical next step.

Have you all seen both Niobrara benches and Codell on all your acreage with the vertical drilling in what you all have drilled so far?

On all of our acreage, we see all three benches in the Niobrara. We do see the Codell and we do see the Greenhorn shale as well. But as you move to the east, across our acreage, approximately halfway, the Codell becomes relatively thin in that direction. So we would not currently look to drill any Codell wells on the more eastern part of our acreage.

Mark Lear, Credit Suisse.

In terms of the number of horizontal Wattenberg completions in the quarter -- I just wanted to get a sense of how that's going to ramp during the year, to hit that guidance range.

We drilled eight wells in the quarter. We completed five of them, but only three of them were on line at the end of the quarter and contributed any volumes at all to the quarter.

We continue to go forward with our two-rig program out there. As we move forward, it'll be pretty much -- 14 days is what we're seeing on average from spud to rig release. Then we'll follow in quickly after that with our fracture stimulation program on each of those wells.

I think currently right now, our spud to first production is averaging 44 days on the wells we've drilled to date for this year. So if you look at our schedule moving forward -- and using those time parameters -- that's what I would use programming out for the remainder of the year.

For the year, to hit the guidance, what was the actual number of Wattenberg completions you guys were --?

We had 24 wells that we're going to drill and complete during the year in the Wattenberg horizontal program.

Right now, with that schedule, we'll be completed with the 24 wells about July.

Yes.

There's not going to be any drilling in the back half of the year or in the 4Q?

We are discussing that with our Board. And with the early results, we'll probably have further discussions with them. But right now the $250 million budget includes just $146 million allocated to the Rockies, which reflects that 24-well program.

Thinking about going out to 2013, would it be a similar program or would you look to accelerate it a little bit further?

Based on what we see to date and market conditions, if they remain stable, we will probably accelerate -- is what we would recommend to our Board.

Andrew Coleman, Raymond James.

Looking at the additional locations from the lower working-interest wells, will any of those make it into the program this year, or should we just leave those in the tail of our net-asset value?

I would say, for structuring purposes, I'd probably leave them in the tail end. That makes the most sense. However, as you can imagine, we will see some of those wells scattered in throughout.

As an example, we have an offset operator, as I mentioned earlier, that we are going to participate with this year, and that will be a well that we own less than 50% interest in. And that will come inside of our $250 million for this year, as currently planned.

Also thinking about those wells, would you say the majority of those are ultimately going to be horizontal locations as you look at them? Or will they be a lot of verticals?

Absolutely every single one of those are all horizontal locations, spaced at 80 acres. And, again, I guess I should reiterate -- only for the B bench.

Looking at what other operators are doing and kind of starting to test the C bench, I believe -- is there any risk in terms of your ability to frac down into the C bench or you have a pretty good barrier in between those two?

I would guess on that is that, again, based on a lot of the information that we see from vertical wells -- which, again, if you think like -- fracking on an individual stage in the horizontal wells is very similar to what we would have done vertically. We know we see some height growth, but that is something that we would plan for in terms of getting good vertical coverage.

I think what you see from us extending out on the horizontal plane here that allows us to get excellent aerial coverage. And the thing that we want to do in the entire Niobrara interval is now concentrated on getting very good vertical coverage across all three of the benches. And so that's where you see us move up and down. And you do have more barriers there that would allow us to do that between the B and the C.

Andrew, I might add to that I think there's been about a dozen C-bench horizontal completions. The reason they're doing that is because when we focus on the B bench -- and our micro-seismic does show that we are fracking and the A-bench could be a significant contributor. But we don't see that on the C.

So to access the C reserves, the conventional wisdom right now is that we need to go ahead and put our lateral within the C bench.

You drilled eight in the quarter. You completed five. You have three that you brought on line. Your plan is set to have all the wells drilled by the late summertime. How much of a backlog are you comfortable carrying before you'd consider picking up an additional frac crew?

Horizontally wise, we're comfortable with where we are right now. At the end of the quarter, we had three waiting on completion, but would have happened in the next week, essentially.

Our backlog is not substantial here, on the horizontal wells. Again, we're going from 44 days -- and that's from spud to first production. That is well within our timeframe of bringing these wells on line.

Vertically, we've actually been drilling wells out there in pads. That's why you see a bulk of the wells that were drilled and weren't completed in the first quarter were the vertical wells in the DJ Basin, but you'll see us quickly take care of that inventory as well because we'll frac them in batches also. We actually have recently added a second frac crew for the vertical wells.

Mike Scialla, Stifel Nicolaus.

Gary, in your comments you had mentioned the rates on the producing days. Can you talk about -- how many days are these wells typically offline during that first month or two that they're on production? Is it significant?

What I would say is that early on, the first few wells we drilled, we probably had more non-producing days than we do on the most recent wells. A couple of those were from -- we were doing some different completion techniques in terms of flowing the wells back when we had started artificial lift when we clean the wells out, as we did the first couple wells on our property.

I would say, today, that number of zero days in the first month is very limited. And really the only zero days we would have is when we would install artificial lift at that point going forward.

Right now, we're installing artificial lift anywhere between the 30th day to the 60th day on the wells that we have currently in place.

How long does it typically take these wells to clean up before you see a peak 24-hour rate?

We've been using a little bit more controlled flow-back here in the last few wells also. So I would say that anywhere within the first three days we're seeing probably our peak 24-hour rate. That can vary a little bit, but that's probably a good average.

That's when we start cutting oil. We probably get our peak within the first week. Just when we initial flow-back, it's a couple weeks -- isn't it Pat?

It's about three weeks when we see our peak rates -- the first of the flow-back.

Three weeks.

So the first few wells have been -- quite a bit of downtime, and then what you're reporting as an I.P. rate. Then your peak 30-day rate -- you're quite a ways into -- you're several weeks into before you really start that process?

I'm looking at state data. It's not going to tie very well with -- at least especially some of the early wells -- what you're reporting on those wells. But over time, I would assume those are going to probably come together.

Very true. In fact, we've already improved, as Gary mentioned -- our zero-producing days is less than it was in our first few wells.

You've got some good rates on those two new Niobrara wells that you had on for more than 30 days. Have you seen enough data yet to even report an I.P. rate on the other three wells that you completed during the quarter?

Because of the controlled flow-back -- the I.P. rates are 24-hour, I should say. I.P. rates are coming in just as expected, but we haven't been reporting those. We think it's much more meaningful to the market that we share our 30-day rates once the wells are producing and lined out.

On the four that were completed last year -- do you have any longer-term rates on those? You gave us a 60-day rate last quarter on those. Do you have anything longer-term?

We don't currently. Those four wells are just crossing the 60-day point, collectively. They're within our expectations.

You've drilled across the eastern portion of your acreage -- anything from a geologic standpoint that you see here that you've learned in terms of the variability within the Niobrara? Has it been difficult to keep the lateral within the targeted zone? Has faulting been an issue; the rock quality changed at all?

As far as the geology on the east side, we haven't really seen anything surprising. We have seismic over almost all of that acreage out there, so we were able to identify the faults and any drilling issues that we were going to observe; and no surprises there.

On the positive side, we've had a couple wells that have come in a little bit higher on the gas side than we expected on the east side. But from a geologic standpoint -- no, we haven't seen any surprises.

I think the other part of your question, as far as, steering and staying within the B bench -- we haven't seen any issues over there at all. We have a [porpoise sitting] of the wells. They've really been staying right in line with where we wanted them to be.

I think a lot of that is because they drilled -- Noble has drilled, I think, about 170 horizontal wells. There has been over 250 drilled in the Wattenberg Field. So we're using the exact same crew as -- many of the same team. Then we've got our technical folks on the wells. I think there's a very high experience level here.

You had mentioned you were going to try drilling a lateral in the C bench, thinking that the laterals you drilled in the B may be tapping you into the A bench, but not the C. Is the thought process that fracking in the C bench would get everything in all three benches?

No. I think at this stage we believe that the C bench has potential, but we wouldn't be able to capture B and A from the C bench lateral. What you may see are two wells -- on in the B that we're currently doing and then another one in the same area, in the C, to capture all the Niobrara.

Evan Calio, Morgan Stanley.

It's [Todd Firestone], standing in for Evan this morning. Congrats. You actually decreased gas production by 8 million cubic feet, which is quite a feat, and that's commendable.

Strategically in the Mid-Con, in trying to figure out what's the more economic well, with your gas midstream assets there -- your differentials must be better there than in the Wattenberg -- your Rockies gas. That well is probably more economical. Have you thought about potentially increasing the development program in the Mid-Con and maybe acquiring more acreage?

Are you seeing leasing pressure in that play now? Maybe you could shed some light on, strategically, what you might consider doing in the Mid-Con.

I would say that we're always looking to expand our position there from a leasing standpoint or from a nearby-acquisition standpoint as well. That's always up-front for us as far as moving forward. As I mentioned earlier, we did actually basically add 10 wells to our proven-development inventory there during the quarter, acquiring some acreage.

As far as future development there in the Mid-Continent area -- we do process the associated gas there. We are highly oil sands there -- the Cotton Valley sands -- so we do process that gas to produce that oil. But at the same time, we also are putting in a new additional facility to allow us to continue that development.

At a certain point, we become -- I don't want to say limited -- but the amount of gas that we can process at this time would kind of keep us from accelerating that development into 2012 pretty much any further than what we currently have planned for the year.

Fortunately for us, we have seen results to date from this year be more oily down there than gas. So that's been a very positive event and it's allowed us to do some other things sooner than we had originally planned as well. So, again, talking about acceleration -- we're accelerating as quickly as possible there, within our processing capabilities at this point. Once we bring that facility on in the first quarter of 2013 that would allow us to continue that development at a faster pace.

You did add those new locations in the Mid-Con. I think I remember you basically have no unproved locations left in the Mid-Con. Is that right?

We have a handful, I would say, right now. There are 10 to 15 that are classified as unproven around the edges of the reservoir at this point in time.

On the CapEx, it looks like you guys -- I guess slightly below. Are you seeing any CapEx reductions for either the -- probably not in the vertical one (inaudible) horizontal? More generally, could you expect a reduced guided CapEx for 2012?

I think we're dead-on for the $250 million. We haven't seen any significant price increases or decreases because we have gotten experienced in the horizontal drilling out there. I think anything you say -- may see as a lessening in cost as we become more experienced. The $250 million -- we are dead-solid perfect on it.

Congrats, again.

David Deckelbaum, KeyBanc.

Have you guys lined up your Codell proposal for the second half of the year at this point, or is that still something that's in process?

It's in process. Our Engineering team is putting it together, and we expect to get an AFE in the next -- Pat, what do you think? A month or so?

Yes, easily.

And then we'll talk to our Board about it.

I guess you've seen enough competitor activity at this point to come up with an idea of how enthusiastic you are or aren't about that horizon.

Very true. So far, everything we've seen to date, from Anadarko and Noble has been positive.

In Mid-Continent and in the Dorcheat field we saw good uplift this quarter. Certainly there's some good reasons why. Should we think about that being as pretty lumpy given the rate of completions and re-completion activity in the first quarter relative to what you have planned for the rest of the year?

I wouldn't necessarily so lumpy. I think as we move forward we'll continue the same process we had in the first quarter, which may be slightly less recompletions. We had an opportunity to go out there and add zone -- we're not losing the existing zone -- but add zone in the existing wells in the first quarter as we were able to ramp up and fill the capacity of our gas-processing facilities.

We'll look to just continue our program of drilling with the two-rig program there -- pretty smooth throughout the rest of the year. So I would forecast that to be a relatively smooth increase in production towards year end.

The improvement in the 30-day rates that you've seen -- we don't want to extrapolate a ton -- could you share any learnings on incremental improvements that you had on the completion side? This was relatively in line or slightly above your expectations for a curve, particularly on the eastern portion of the play here, in the Wattenberg. Is there anything that would have driven those rates to be better than previous vintage?

Our teams -- we continue to push the phrase continuous improvement. We started up high on the learning curve with our neighbors in our expertise in horizontal drilling and fracture stimulation.

Pat, you've seen some recent improvements from the tweakings.

We have. We really haven't made any major adjustments to our well designs or stimulation designs. Some of it is we're just getting more data points now. We're blanketing our acreage position now with the number of wells. Some of them have -- I honestly can't say we've seen many negative surprises, but we have seen some positive surprises, particularly on the gas side. We've seen some wells come in a little bit higher than what we expected them to do from the gas component.

As far as the overall designs, we've made some tweaks, but we haven't made any major adjustments on the drilling or the completion of these wells.

One you mentioned -- the two extra stages you're putting in your wells now.

We've done that recently, but that isn't reflected necessarily on any of the wells that we've got on production so far. But, yes, we have -- in a 4,000-foot lateral we were putting 16 stages in, about 4 million pounds -- 250,000 pounds per stage. We've jammed a couple more in that same 4,000-foot lateral -- got two more stages in there. Those are on the most recent four wells that we have on line -- in the mix, not necessarily on line.

Is it fair to say that in that 4,000-foot lateral that the 18 stages would be as tight as you could space those stages, or you think we're still exploring the forefront of that potential?

I think it's still being explored. We've run a little bit of micro-seismic out here. Even with the 16 stages, we saw some pretty good overlap between the individual stages themselves. Some of this is relying on what our neighbors are seeing. They're bumping their stages up. They've got a lot more of -- obviously, a lot more wells they've drilled; a lot more data to base that off of. So we're kind of following along and seeing what kind of results we see.

John Labanowski; Brenham Capital.

Congrats on the quarter.

In the Wattenberg Field, is there potential to do any kind of bolt-on type acquisitions? Or at this point is everything basically spoken for?

We are acquisition-oriented in our growth, making over 30 in the past 10 years. We continue to seek out. But we're known for not over-paying. A lot of our acquisitions are sole-source-negotiated transactions that we come in and see additional upside in the property.

It is a very competitive market in the Wattenberg Field right now; just an indication from lease prices -- they've gone up considerably. So it is a lot more competitive than it was four or five years ago, when we built the bulk of our position out there.

In our core areas there, we look for assets that we can pick up that will mold right into our existing infrastructure; and we can apply our horizontal drilling and fracture-stimulation expertise.

On the North Park Basin -- did you guys get timing as far as when to expect your first wells to be drilled and (inaudible) date released on those?

We have $18 million budgeted in North Park for this year. That includes the seismic program that we just completed. We're evaluating the seismic work. Then we have three potential horizontal wells.

Because we're early in the evaluation stage, we'll be talking with our Board about those three projects and optimizing what we think would be a good test for North Park. Our plan is still to do that second half of this year.

Congrats on the quarter.

Phillip Jungwirth; BMO Capital Markets.

What is the reason for the reduced dry-gas production in the quarter? Should we see the gas-to-oil ratio increase from the first quarter throughout the year, because I think you had previously guided to about a 30% dry-gas-production mix, which was in line with last year.

I would say that we've seen the production coming from the Mid-Continent be more towards the oily side, from the recompletion program that we've put in place in the upper part of the Cotton Valley. Also, some of the wells we've drilled this year have been more oily there as well. That's driven a little bit more of that overall mix of the Company on the oil side in the first quarter, for sure.

As we move to the DJ Basin, we're seeing very similar things -- a little more oily from some of the wells we're drilling across our Niobrara acreage as well. The bulk of that move is more in the Mid-Continent side.

As we look forward, I would say the same thing. As we continue to develop out there, we probably would be probably in between that 70% and that 75% that we showed in the first quarter, moving forward.

Can you give us the average working interest on the additional horizontal Niobrara wells that you talked about in which you aren't the operator?

The extended-reach lateral that --

The one we're going to participate in with our offset operator?

No. I think the previous location count was 215. And then you mentioned that you have 290 locations, including units, in which you aren't the operator.

Yes. I would say that our average working interest is less than 50% on that. But those 290 locations are basically a net-well count to us, if that's what you're asking.

Any reason for increasing the commitment level under the revolver to $600 million?

I'll address that. $300 million is an awkward number. And I say that in that this Company has, in the past, always made acquisitions in the $100 million to $200 million range -- the important ones. Those don't happen anymore. We obviously had room (technical difficulty) into our acquisitions. But where we really enjoy growth in the Wattenberg have become expensive.

The Management team wanted to make sure that we had plenty of flexibility and plenty of room to move. One of the things that happens, as we all know, in this industry -- sometimes the best deal is made and give to the person that can guarantee delivery of cash in a very short period of time. So anybody we're negotiating with knows subject to the component of their properties that they're trying to sell that we can write a check almost simultaneous to making our offer.

Great work, guys.

A.J. Strasser, Cooper Creek.

Great quarter -- really solid results.

Can you elaborate on the timing around the 24 Wattenberg wells? You said that you expect it to be by July. What was your initial timing for those 24 wells, just so we can gauge how much ahead of your production schedule you're running?

Right now, we expect to finish drilling that in July. We're probably 45 days ahead of that schedule overall what our original plans were. We're probably about 45 days -- move the entire program 45 days forward.

Could you just share with us when you're going to be giving us an update on the Codell and the North Park region -- when you expect to have any test results specifically around the North Park.

Can you update us on what kind of data you have in the North Park historically, and how you're thinking about it in the near term versus the potential that we're seeing in the Wattenberg?

North Park, we entered into in 2006. We've been operating up there since then in the [McCollum] Field. We always knew the Niobrara was productive there. There is a lot of vertical Niobrara production that dates back 20, 30 years.

EOG went in there and drilled seven horizontal wells since 2007 forward. And they moved it up into what is now the 4,000-foot plain-vanilla lateral 4-million-pound frac on the last couple wells. We've watched that very closely as we were picking up additional acreage on our side of the Spring Creek Fall.

The things we needed to do were to make sure that we understood the geology very well. So Pat went out there this year and completed a seismic program over where we plan to drill at least one of our horizontals this year.

As for results coming out of North Park after those horizontals -- we don't expect to probably have any data until the end of the year, maybe first quarter next year, that we can feel real comfortable about how these wells will perform. That's probably about the same for our Codell and the Wattenberg Field, too. Although with the operators, we feel more confident with our Codell potential. So we may accelerate that depending on our discussions with the Board.

I wouldn't factor that you'd see anything significant this year until late fourth quarter.

Great quarter, again.

[Robert Lee], [Waterfront].

Congratulations on the quarter.

I had a question regarding your locations for the Niobrara horizontal -- which benches does that include?

That's strictly the B bench at this point in time.

If you were able to include the A bench and the C bench, does that theoretically mean you double your amount of inventory?

The way to look at that, Robert, is to -- right now, the B bench is probably draining the A bench, too -- based on the micro-seismic and our volumetric calculations for the Niobrara. But we feel pretty confidence, and so do our neighbors, that we're not depleting the C bench, which has a lot of additional potential there.

We will have to go factor that in. I wouldn't say it'd be a doubling of our well count, but it'd be a significant increase once we test the C bench and it shows as productive as we've seen in the B and A.

I just want to clarify on a previous comment you made regarding ramping up in 2013. Currently this year you guys are doing 24 Niobrara horizontals, is that right?

Correct.

Could you quantify how many gross wells you could drill in 2013? Would that be double the amount this year -- 50 wells? Can you help me understand how many wells you could drill in 2013?

We've had preliminary discussions with our Board. These results continue. We think we'll be increasing and asking our Board to increase the number of wells that we drill horizontally next year. The short of it is we have lots of capital capacity to increase that program. It's probably premature. These discussions with our Board -- it'll be probably third quarter that we'll sit down and put together a budget for next year.

Mike Scialla, Stifel Nicolaus.

On your NGL price for the quarter -- I noticed one of your nearby competitors was really hurt by some ethane prices at Conway. It looks like you've got a higher realized NGL price. Can you just talk about how those liquids are priced? Was ethane extracted or rejected during the quarter? Is that something you can control?

Right now, the way we're showing the NGLs -- those NGLs broken out in our financials are only for the Mid-Continent region. So we don't break out NGLs currently right now in the D.J. Basin. Down in the Mid-Continent region, we sell to [Mont Bellevue] and we also do not sell ethane into that blend. The ethane is re-vaporized into the gas stream at exiting the plant. And so our NGL product there is propanes plus. So when you look at that realization for NGLs, that's what you're looking at. It's strictly from the Mid-Continent.

I will comment on the NGLs in the D.J. Basin as well. We do sell into [Conway] and we do see a lowered price there for the NGL component because ethane is included in that stream as well.

Do you have an average NGL price for the D.J. that you could share for the quarter?

If you take into account our percent-of-proceeds contracts -- you take the contract rate into account as well. If we looked at the breakout -- if we were to breakout the liquids -- we would average about 35% of WTI for the entire liquid stream in the D.J. Basin with an associated dry-residue gas on top of that.

Ladies and gentlemen, since there are no further questions. That concludes today's conference. Thank you for your participation. You may now disconnect and have a wonderful day.