Civitas Resources Inc (CIVI) 2012 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Second Quarter 2012 Bonanza Creek Energy Incorporated Earnings Conference Call. My name is Erin and I'll be your coordinator for today. At this time all participants are in a listen-only mode. We will be facilitating a question-and-answer session toward the end of today's conference.

(Operator Instructions)

I will now turn the presentation over to your host for today's conference, Mr. James Masters, Investor Relations Manager. Please proceed, sir.

Thank you, Erin. Good morning, everyone. Welcome to Bonanza Creek's Second Quarter 2012 Earnings Call and webcast. We are glad you could join us today. As you know yesterday we issued our earning release for the second quarter and filed our 10-Q with the SEC. You can access both on our website at www.bonanzacrk.com

Before we get started, please be aware that 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.

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 EBITDAX adjusted net income and other non-GAAP financial measures. We use these measures because we believe they are good metrics to use in evaluating performance. Reconciliations of these measures, most directly comparable GAAP measures are contained in our earnings release.

Finally, during he second quarter we began a divestiture process of our California properties. Under GAAP we disclosed the results from these properties as discontinued operations in our 10-Q and the statement of operations and balance sheet in our press release. All results discussed today reflect total operations including discontinued operations.

On today's call I'm joined by Mike Starzer, our President and Chief Executive Officer; Gary Grove, our Executive Vice President, Engineering and Planning and Wade Jaques, our Chief Accounting Officer and Controller.

Mike will begin by discussing the highlights for the quarter. Gary will provide an operations update, and Wade will summarize our current financial condition. We are also joined by the members of our management team who will be available to answer questions during the Q&A portion at the end of the call.

With that, I'd now like to turn the call over to Mike.

Thank you, James. And thanks to all of you for joining us for our second quarter conference call. I'm joined here in Denver by members of our management team who are looking forward to answering your questions later in the call. Jim Casperson, our CFO, could not join us this morning, but we are in the very capable hands of our Chief Accounting Officer and Controller, Wade Jaques.

As I have mentioned in each of our previous conference calls, we take great pride in doing what we say we are going to do, and I'm pleased to report that for the second quarter we did just that. I know most of you have already read yesterday press release, but for those of you that have not had the opportunity, let's start by recapping the highlights.

In the second quarter of 2012, as compared to the second quarter of 2011 Bonanza Creek generated a 144% increase in production to 8,944 barrels of oil equivalent per day. We increased revenues to 106% to $53.5 million and grew net income by 179% to $21.5 million. We further expanded adjusted net income by 149% to $12.5 million or $0.32 per diluted share, and generated a 127% increase in EBITDAX to $36.9 million.

In addition, we leased 5,639 net acres in our core operating area of the Wattenberg Field, and increased our 2012 CapEx budget by approximately $48 million to continue our horizontal Niobrara drilling and test additional drilling inventory potential.

As the year-over-year metrics illustrate, Bonanza Creek is truly a different company today than it was a year ago. We head into the second half of 2012 having made a strategic acreage acquisition in the heart of our Wattenberg asset, and are expanding the capital budget to take advantage of a number of exciting opportunities. I would first like to talk about our performance and accomplishments during this quarter, and then I will discuss our expectations heading into the second half of the year.

Our solid performance was accomplished in the quarter that was challenging both from a macro perspective as well as operationally. Softening commodity prices negatively impacted price realizations by 14% over the previous quarter, yet we still delivered a strong 69% cash margin, thanks to the low-cost nature of our operations and the oil weighting of our production stream.

Further, we had a strong quarter despite June being affected by high line pressures in the Wattenberg Field and mechanical issues in our Dorcheat gas processing facility in Arkansas. Our horizontal Niobrara Program continues to confirm our expectations. It is remarkable to think that just 1 year ago we drilled our first horizontal well in the Wattenberg Field. Since then we have increased our tight curve from 285,000 to 312,000 BOE.

We have decreased our spacing assumptions from 160 acres to 80 acres, and we are seeing our neighbors testing horizontal wells on 40-acre spacing. One year ago our focus was on developing the Niobrara B bench, but now we are evaluating a potential for horizontal development of the remaining Niobrara benches and the Codell formation.

Further downspacing and expanding our horizontal development into these intervals has a potential to greatly increase our drilling inventory. Our understanding of the ultimate potential of this area has grown considerably and in just the last year. We recently leased an additional 5,639 net acres, with multi horizon potential in the core of our Wattenberg position. This acquisition adds approximately 70 net Niobrara B bench drilling locations on 80-acre spacing, a 24% increase to our beginning inventory of 290 locations.

The lease terms include an approximate $11.9 million payment per year for 5 years, and a 20% royalty to the Colorado State Land Board. This acquisition is further bolstered by the potential for downspacing to 40 acres in the Niobrara B bench, and horizontally developing the additional Niobrara benches and the Codell formation.

Finally, because Bonanza Creek operates on adjacent lands with infrastructure and access agreements already in place, we are well ahead on the logistics of development. This acquisition is a perfect match for our core competencies.

Moving to the capital budget for 2012 Bonanza Creek's Board of Directors recently approved an additional investment of approximately $48 million to continue the horizontal development of the Wattenberg Field and test downspacing potential in Arkansas.

A couple things are important to note. First, to-date the total projected capital cost has not differed materially from budget, and second, while the additional capital has a production impact on 2012, it will primarily affect the first quarter of 2013. We expect to spend $37 million of the budget increase in the Wattenberg Field where we plan to drill five additional 4,000-foot lateral Niobrara B bench wells, an extended reach lateral in the Niobrara B bench, and one horizontal well in both the Niobrara C bench and the Codell formation.

In Arkansas we expect to spend $11 million to drill a 3-well pilot to test further downspacing potential in the Dorcheat-Macedonia field, and four wells utilizing the successful pinpoint fracturing technology in our McKamie-Patton field.

Although these projects will contribute to an increase in production, Bonanza Creek is already expected to achieve greater than 100% year-over-year production growth in 2012 from its original program. Therefore, the rationale for these projects is also to evaluate a number of potential inventory catalysts that exist in our asset portfolio.

As the horizontal Niobrara B bench transformed Bonanza Creek 1 year ago, the Codell and the other Niobrara benches have the potential to bring the Company to its next level of growth. We believe we are building momentum for production growth in the quarters ahead. Although we experience some challenges during the second quarter our drilling results today give us confidence to increase our full-year production guidance to between 9,100 to 10,100 BOE per day, up from 8,700 to 10,000 BOE per day

We are also increasing our cost guidance for lease operating expense and G&A. We are estimating a combined increase in LOE and G&A of approximately 1.55 per BOE for 2012. Gary will go into more detail on LOE, but we have experienced higher than expected operating costs on our horizontal wells in the first 2 producing months, and have battled high line pressures in the Wattenberg Field, increasing our operating cost beyond what we had originally forecast.

While per unit LOE continues to decline, we don't believe it will average within our original guidance range for the year. On G&A, we expect to modestly exceed the top end of our original guidance due to accelerated hiring of staff to keep pace with our expected growth.

I look forward to taking your questions at the end of the call, and now I'll turn the call over to Gary.

Thanks, Mike. This morning I'm going to address production, operating and capital cost trends, and our expected drilling program for the remainder of 2012, taking into consideration our increased capital budget.

Our production for the year, as of June 30th, averaged 8,022 BOE per day, our second quarter production averaged 8,944 BOE per day, and June production averaged 9,137 BOE per day, a 131% increase over June of last year.

Production for the second quarter was negatively impacted by unscheduled gas processing facility maintenance at our Dorcheat-Macedonia field in Arkansas. During the second quarter this facility was operating for some time at constrained efficiencies, and was fully shut down for 10 days.

In the Wattenberg Field, you've heard that -- you have heard a number of our neighbors comment on high line pressures throughout the system causing production interruptions. These pressures, which were not a material issue for us in the first quarter, did impact our production in the second quarter.

A more significant impact we felt on our lease operating expense. We have experienced these high line pressures to be a localized gathering issue, not a regional takeaway problem. We believe that installing compression in the appropriate areas and further transitioning from vertical wells to horizontal wells, will allow us to mitigate the impact of this issue.

The combined production impact of the gas plant downtime and the high line pressures was approximately 200 BOE per day for the quarter. Our increase midpoint production guidance for the year to approximately 3.5 million BOE takes into account the impact of these issues and the production uplift from the incremental capital program.

Activity levels across the Wattenberg will likely remain elevated, as the midstream operators are actively keeping up with processing capacity needs. DCP, for example, just announced that it will double the size of the DJ Basin gathering and processing system by 2014. On the oil side, or DJ Basin differential remains at a flat $8 deducted WTI, which is an all-in fee incorporating transportation cost.

In the second quarter, per unit lease operating expense continued to decline to $9.45 per BOE, down from $12.03 per BOE in the first quarter. This is a significant improvement, but is still above our original estimates. The biggest contributor of our higher LOE expense has been the increased cost of our operating horizontal wells in the initial months of production which have required, in most cases, 24-hour supervision and equipment rentals as permanent infrastructure is installed.

Our annual guidance was based on limited historical data for the horizontal wells, and the initial operating cost were the most difficult to predict. As the horizontal wells produce in the later months, their monthly cost to operate comes more closely in line with our original estimates.

In addition, our lease operating expense was negatively impacted by the high line pressures, which knocked some vertical wells offline and required insulation of compression to push gas into the gathering system, in addition to the cost of reestablishing production.

Going forward, we are revising our full-year lease operating expense guidance to be in the range of $8.50 to $9.50 per BOE, an increase of $1.30 per barrel. The last topic I'd like to discuss is our drilling plan and capital budget for the remainder of the year inclusive of a significant increase in capital.

Our development capital budget now stands at $298 million with the addition of 5 horizontal Niobrara B bench wells, and different inventory catalyst in the Wattenberg and Arkansas. In addition, we continue to transition our Niobrara Development Program away from vertical wells to a horizontal development program. In the second half of this year, we plan to reallocate capital away from 20 vertical wells and instead drill -- and instead, drill 4 more horizontal Niobrara wells.

All combined, in 2012 we expect to drill 35 horizontal Niobrara wells and the one horizontal Codell well. Our increasing focus on the horizontal Niobrara Program is due to the positive results achieved today. Since we began our development program in July 2011, we have spud 22 wells and completed 20 wells.

Our 30-day average production rate on 16 of those wells is 470 BOE per day at 74% oil; and our 60-day average production rate on 11 wells is 373 BOE per day at 72% oil. Both of these rates are in line with our projections.

We continue to experience a flattening of vendor cost in the Rocky Mountain and Mid-Continent regions. Vendor services including drilling rigs and stimulation crews have been adequate to meet our development schedule, and we do not predict this to change. Although we have not experienced water limitations we are in discussions with various water providers to ensure supplies are available in the future.

With that, I'd like now to turn the call over to Wade to summarize our financial performance.

Thanks, Gary. It is my pleasure to report that Bonanza Creek enjoyed strong financial performance for the second quarter. We noted earlier that during the quarter the Company began a divestiture process for its California properties. Under GAAP these properties have been disclosed as discontinued operations and are reflected as such in our 10-Q and the Statement of Operations and balance sheet in the earnings release.

For the purposes of reporting actual performance for the quarter, all financial results discussed to date include California as part of our continuing operations.

Our balance sheet continues to be very strong with only a 10% long-term debt to capital ratio at June 30th. We ended the quarter with 62 -- $62.6 million outstanding on a borrowing base of $245 million. However, on August 1, 2012, the Company's availability was reduced to $197 million, due to a $48 million letter of credit required to facilitate the Company's leasehold acquisition in the Wattenberg Field.

Finally, as Mike mentioned earlier, we reported record sales volumes, revenues earnings and EBITDAX for the quarter.

Regarding expenses for the quarter, as Gary explained, we continue to bring down per unit lease operating expense, having improved this metric over each of the previous 2 quarters. Our LOE for the second quarter was $9.45 per BOE, as compared to $12.03 and $13.20 per BOE respectively.

We should continue to see our per unit cost decline as production increases and the cost for new horizontal wells decline and stabilize in the outer months. Cash, general administrative expense for the quarter was $6.3 million or $7.74 per BOE. Our increased G&A reflects the realities of running a small, high growth public company.

We hired 20 people in both technical and administrative function in the second quarter to support our dramatic growth. We are revising our full year cash G&A guidance to be in the range of $6.00 to $6.50 per BOE, a marginal increase of $0.25 per BOE.

Bonanza Creek continues to maintain an active oil hedging program, with approximately 60% of our current production hedged at $90 per barrel or higher. We hedge to protect our cash flows to ensure that we can execute on our attractive capital program. A key component to our growth strategy is the reinvestment of our high margin cash flows and to high rate of return on projects.

As Mike mentioned earlier, due to the softening commodity prices, our un-hedged realized price declined by 14% from last quarter to $65.69 per BOE, but we still maintained a strong 69% cash margin.

Our cash flow and profits continue to be significantly tied to the price of oil, which comprise 63% of total volumes and 86% of our revenues for the quarter. When combining our oil and NGL revenues, liquids represented 92% of our revenue in the second quarter.

Oil price realizations in the second quarter, excluding the effects of derivatives, were $89.82 per barred of oil, a 10% decline from $99.71 realized in the first quarter. Gas price realizations in the second quarter, excluding the effects of derivatives, were $3.05 per Mcf, a 12% decline from $3.46 realized in the previous period. NGL price realizations for the second quarter, which contributed 6% to our revenue for the quarter, were impacted by the decline in liquids pricing from the Mont Belvieu hub, declining $0.27 -- or 27% to $47.04 per barrel, from $64.04 per barrel in the first quarter.

At this time, we'd like to turn the call over to our moderator who will take your questions.

(Operator Instructions)

Your first question comes from the line of Irene Haas from Wunderlich. Please proceed.

Yes, hello. I would like you to talk a little bit about these extended laterals and it seems like Bonanza Creek has the ideal sort of acreage to be able to fit these 9,000-footer in. Could we have a little color on your expectations and cost of such things?

Yes, hi, Irene. Yes, I think because our acreage there in Wattenberg is pretty much contiguous throughout, we've got a lot of adjacent 640 sections, we do have the capability of drilling a number of our extended reach laterals on 1280-acre spacing and we're excited about that. And Irene, just to the north of us Noble has probably one of the longest-producing extended reach laterals in the Niobrara B bench and we've been watching them very closely. We think that's a perfect analog to apply to our acreage.

Pat, do you want to add a little more on the extended reach lateral potential?

No, as Mike said, our acreage is very nicely situated to develop the Niobrara and potentially the other benches, but at least the Niobrara B at this point, with the extended reach laterals. We started to get some data in, the data looks very encouraging as far as what we see early time production rates are. And we will just continue to monitor the longer term production and make sure it fits in line with what the EUR projections are.

And what's your cost expectation to drill and complete one of these wells in the early stage?

We're looking at $7.5 million to maybe $8 million. It's not quite what two -- 4,000 foot wells would be, but a little bit under that.

Great, thank you.

And your next question comes from the line of Michael Scialla from Stifel Nicolaus. Please proceed.

Good morning, guys.

Hi, Mike.

Good morning.

Any way to quantify how much the pipeline pressure has curtailed your production in the second quarter?

It's a good question. It mostly affects our vertical wells, Mike. And so, it didn't impact a whole lot of our horizontal production results coming on, but the wells produce is so strong.

But, Pat, from a vertical standpoint, do you have an estimate of--

We were figuring about 100 barrels a day for the quarter, like Mike said, mainly in the vertical wells. The horizontal wells come on strongly with enough flowing pressure to overcome even the high line pressures, plus they go on ride pump after about 30 days. So you've got a positive displacement pump that's overcoming the line pressures also.

So it sounds like pretty minor -- many continued risk as you look forward for the rest of the year?

No. What we are hearing is a lot of our productions going into the DCP system, they are -- again what we are hearing is they should have additional compression and some plant workout by the end of the year, which should lower the line pressures on a good portion of our acreage by December or January of next year.

And to add to that, Mike, we've -- for our second-half guidance, if you will, we kind of included any potential risk we see there in the [volumetric] estimate.

Got it. Okay. And you talked about deferring, or I guess redirecting capital away from vertical wells to the horizontal. As you look into 2013 -- realize you haven't set your plans yet, but I would -- should we anticipate fewer vertical wells next year than you drilled this year, or how do you thing about that?

I think everybody is shaking their head, yes, here. So --.

I think you wouldn't be surprised by that, Mike.

Would it be -- I mean, would you drill any vertical wells next year?

We might drill a few mainly for geologic purposes or smaller pieces of acreage, but it will be minor for next year.

Okay, great. I'll jump back in the queue. Thanks.

Thanks, Mike.

And your next question comes from the line of Andrew Coleman. Please proceed.

Hi, good morning. Thanks for taking my questions. The question I had was on the acreage you guys picked up in the core Wattenberg. I guess how did you come across that? And are there other opportunities to kind of do more that in the future?

You bet, Andrew, and I'll go ahead and kind of lead in and turn it over to Pat, who handled that transaction. We -- for the state historically have -- has leased out acreages and it would be an auction process. They did something a little different this time which we are seeing in a trend towards, where they did a sealed bid process and they brought in a lot of acreage together that had been un-leased.

This is acreage that on the surface is -- referred to as the National Hog Farm acreage of which we have existing relationship on some of the hog farm acreage that we currently own. We are focused on this area being right next door to our existing acreage and so this -- it was a very nice pick up for us and we have seismic over a good portion of the acreage. It has both -- all the Niobrara 3 benches as well as Codell.

Pat, any additional analysis that you have on it--?

I think you had most of the high points. This acreage kind of trends into what we've described as our western acreage. Most of it occurs in that side of our position, which brings in lot of the Codell formation -- all the 3 benches of the Niobrara are present, as Mike mentioned, between seismic and well-control. We've got a really good geologic picture over the acreage.

Yes, and I would say, Andrew, the -- our most recent presentation that's on our website would show you a map where that acreage is located, and you can see, again as Pat has described it, it's a truly adjacent to existing acreage. And it fills out kind of on the earlier question about the 1280s -- allows us to control the entire length of those laterals as well in that area.

Okay, thank you. Then, if I could -- throw one more in before I get back in the queue. It's -- with the additional targets that you have between, I guess, the C bench and the Codell and other zones for Niobrara and Wattenberg, will that slip or put more activity in this area ahead of our North Park Basin, or do you still have plans to drill some wells in the North Park Basin this year?

Yes, we're still in the evaluation phase on North Park. Pat shot the seismic, he has evaluated it with his team and we're doing some work out there on the vertical wells currently. So at the North Park, we're still very excited, looking forward to moving ahead with that, but Wattenberg is turning into for us, Andrew, it's pretty much just blocking and tackling. It's in full development mode, and I think that's where you're going to see most of our capital and most of our attention increasing our production in proved reserves.

Pat, add on that on the North Park?

We shot roughly 23 square miles of seismic earlier this year; it's all been processed and interpreted. We are doing some work on a couple of vertical wells, which will help us validate the geologic picture that we have on the Niobrara and other horizons up there, but more specifically, the Niobrara.

We're currently testing one, we plan on entering the second well probably later on this month, maybe early September, and do some additional testing.

Okay. So, we'll look perhaps on the next call to get some -- I guess updates on how those are performing?

Yes.

Okay, great. Thank you very much.

Thanks, Andrew.

And your next question comes from the line Mark Lear from Credit Suisse. Please proceed.

Good morning.

Morning, Mark.

With the 5-acre pilot at the Dorcheat, I'm just curious what the potential inventory added there with the successful pilot?

Well, what I would say Mark is that in -- we're currently spaced at 10 acres there and looking across our acreage position we're talking about if we were to go and continue down the 5-acre positioning there, we could see -- and again this is full across the field, we could see an additional 150 to 250 locations at that spacing, on the acreage that we contain to-date. So, that's kind of in line with our earlier 10-acre downspacing opportunity that we saw there, just multiplying that, if you will, down to 5.

Got you. Then moving to Wattenberg, looks like you've drilled some additional horizontals as you move further east, even one outside of -- or further east of where you have seismic. I was just curious how well performance there is stacked up versus the type curve?

The furthest east well that you mentioned out in section 12, so it's the furthest east that we have -- it is right outside of our seismic, we did have a little bit of well control out there, so we weren't really concerned as far as the geologic picture that we have. We did have some mechanical issues on that well. We had a liner [flap] let go during the frac. So that well has been repaired, it has been completed. It is fairly early in the flowback in production.

Typically, what we are looking at is the reservoir pressures, flowback pressures and all that. Pressures seem in line with everything that we have seen previously, rates are little bit lower, but that could just be because, one, it's early on, and two, the mechanical issues that we have with that well.

The other is eastern wells, we have seen certain really good performance out there. We drilled a well on section-17, which is one of our highest IP wells. 30 day rates are looking good on that one. So for the most part, the eastern side is performing as expected.

Great. And then just, lastly, can you maybe give some timeline, or color on the timeline of when we should expect Codell and C bench results from you guys?

Yes. They are planned right now. They are permitted. The Codell is probably the first one that we are going to do out of the 3 [adds] that we are putting on the C bench in the extended reach. It's permitted, ready to go, probably will be drilled late August into September. So results best-case would be October, November, that timeframe -- probably more in the November timeframe.

Great. Thanks, guys.

Thank you.

And your next question comes from the line of Adam Margulies from Miller Tabak. Please proceed.

Hi, guys. I think most of my questions have been answered, but I do have a follow-up on the Codell. When we are modeling this going forward and I realized that you have limited data there, but it sounds like the type curves are looking similar to the Niobrara, should we expect a similar commodity mix between NGLs, oil and gas?

I would say overall the commodity mix might be a little bit on the higher side, because most of Codell is on the western side of our acreage. So you're probably looking at the -- I'm sorry, I may have said that wrong -- you're probably looking at a - no, I did say that right, we are looking at a higher gas component probably on that -- on the Codell than we've seen on an overall basis on the Niobrara.

Yes, I think we are -- Adam, I think our Codell is looking actually -- we're following the lead from our neighbors, and where they have produced historically, vertically, from both the Niobrara and the Codell. Our Codell produces very nice vertically, so when we bring in that analog and apply it to horizontal, we're expecting to have some good performance from Codell where we have it in our acreage.

And, Pat, you think it maybe a little more gassy based on where our vertical performance has been.

Well, I say that just because I think we're, for the most part reporting our overall Niobrara results. If we're looking at our western side -- the feeling is, based on the results that we're seeing -- based on our internal model that we've generated I'd say the gas is going to be a little bit -- it's going to be little bit gassier similar below what we see in the Niobrara B for our western acreage.

Okay. And then I know this is still early stage, but do you think the downspacing potential also just in the Codell to maybe work down to 80 acre even or possibly a tighter spacing there?

Yes, it's a good question. We've debated that, discussed that ourselves. The Codell is a little bit thinner at interval overall, a little bit better [processing] permeability, though, so depletion could be a little bit more aerial than what the Niobrara is. So, can we get down to 80 acres? I think there is a good chance of it. 40 acres might be still on the bubble at this point.

Okay. And then, one last question on the Niobrara. Have you had a chance to look at microseismic data that shows the potential communication between the C and the B bench, or is most of the communication between the B and the A bench.

We were on microseismic on 3 wells so far. The thing to keep in mind on microseismic, it really just shows events. It doesn't necessarily show that there is conductive fracture that's been created between the B and the A, or the B and the C, but we do see events occurring in the C bench and even up into the A bench, which I think if you look at how most operators are looking at developing the B and the C and even the A if you want to throw them in there, is kind of in a staggered position.

So you would necessarily put a C bench completion on a vertical plain right under our B bench, they may be offset to some degree.

Okay. Great quarter, guys. Thank you.

Thanks, Adam, and welcome to Bonanza Creek.

And your next question comes from the line of Robert Johnson from Johnson Investments. Please proceed.

Gentlemen, I'm somewhat confused by some statistics in your [current] investor presentation and so please forgive my ignorance. You have the NPV-10 statistic at both $80 a barrel of oil and $100 a barrel. Let's just talk about $80. For Dorcheat-Macedonia you show a cost per well of $1.7 million and the NPV-10 even at $80 a barrel is $1.9 million, a positive figure compared to $1.7 million.

However, when you look at the North Park Basin, Niobrara, the cost per well is listed as $5.1 million and the NPV-10 at $80 a barrel is $2.1 million -- is a fraction of $5.1 million. Less bad than that is the cost per well in the Wattenberg Horizontal Niobrara, which is a cost per well of $4 million and NPV-10 at $80 or $4.1 million, which is still a figure in excess of $4 million.

But the North Park Basin, please explain why -- again, I know NPV-10 is not necessarily the best metric, but you are showing $2.1 million NPV-10 at $80 a barrel versus $5.1 million cost per well in North Park.

Yes, Robert, basically what you see there is you are seeing the net present value associated with an $80 and $100 price, but that would already include recouping the -- in the case of North Park Basin, recouping the $5.1 million. So basically, you are looking at a cash flow that already takes into account, you've recouped that $5.1 million and your incremental value over and above that $5.1 million on a discounted basis is equal to the NPV shown there for both $80 and $100 pricing.

But even - well, I appreciate you correcting me on that, or informing me, but even so the North Park Basin $2.1 million NPV-10 compared to $5.1 million cost per well is still -- it seems significantly less profitable than the $1.9 million NPV-10 in Dorcheat-Macedonia compared to the $1.7 million cost of a well.

You are correct. I mean, we have a greater return on our Dorcheat-Macedonia well at this point in time than we do in North Park. Again, we are very early in our North Park development and those are kind of the economics that we see there that makes it attractive for us going forward.

There is a large opportunity from an acreage standpoint that's completely un-drilled at this time and un-produced at all from the Niobrara, so it's an excellent opportunity for us going forward much like what we did in the Wattenberg area when we entered into the Niobrara there as well and we are seeing good results.

But you are correct, we see a better return on a well in Dorcheat-Macedonia than we would project to see, with the information we have to-date right now in North Park, however, they are both highly economic.

Final question. Obviously, there is a great deal of emphasis on Wattenberg, is there any acreage available that's not yet exploited in the Dorcheat-Macedonia area because that seems to be so very, very profitable?

Kind of going back to what we talked about earlier, one of the things we are doing is we are going to go ahead and test some additional downspacing there at Dorcheat. Again the sands there, our Cotton Valley sands and our oily Cotton Valley sands, but they are very lenticular in nature, which means that they are [podular], if you will, and they come and go quite frequently.

And so, one way to continue to see an uplift there is to test further downspacing. We've been very successful downspacing the 10 acres to-date. We see that as an additional opportunity going forward there to recreate some of these excellent economics that you are talking about.

So, that is the next phase that we are doing here with these 3 wells we are going to drill in Dorcheat. And on top of that we are also expanding some of the technology that we have done at Dorcheat-Macedonia over to a nearby field called McKamie-Patton, which has again oily Cotton Valley sands in it as well. Applying that technology over there and a couple of wells we drilled to-date have been -- we've seen very good results, so, we are expanding that and drilling 4 more by the end of the year to continue down that path as well.

Thank you very much.

Robert, I might interject there also, our land department has an active leasing program in both the areas, Mid-Continent as well as in the Rocky Mountains and we're picking up acreage. In fact, we just picked up 280-acreage sections in the Dorcheat field. So we continue to look for opportunities where we can pick up attractive acreage that fits in with our development model. And, of course, we buy right, we don't want -- because a lot of times these areas are either adjacent or right within the field where we have all the economics to support.

Thank you, again.

You bet. Thank you, Robert.

(Operator Instructions)

Your next question is a follow-up from the line of Irene Haas from Wunderlich. Please proceed.

Yes, and just a little clarification, in your PowerPoint you listed 360 net horizontal locations, are those 80 spacing single zone, Niobrara, assuming sort of standard lateral? And then, really, what could be the multiplier effect when you crank in a closer spacing and sort of a more horizons as such?

Good question, Irene. Yes, we are looking at that right now but, yes, your -- the answer is, of 360 net locations that's all B bench 80-acre 4,000 foot laterals. And I think with the -- Pat, go ahead and chime in -- Gary.

On the extended reach lateral, you would see probably that total count, of course, reduced as we're developing with -- on 1,280 spacing, but we would still probably be developing a lot of the acreage on 4,000 footers because of just of the nature of our acreage.

I would say just on the total well count, Irene, if you look at our neighbors, and again, we have good neighbors as we like to say. If you talk about going to 40-acre spacing that math is pretty easy to do.

You know, going from 360 at 80-acre spacing down to 40-acre spacing in the B, and obviously we've now started drilling C bench laterals at 80 acre spacing, the acreage obviously would -- the math again there is pretty straightforward, and the potential to downspacing the C, and then subsequently drilling the A bench wells and downspacing the A, I think that you can start to see how this -- the inventories grow pretty dramatically with those type of opportunities.

And then, lastly, we talked about the Codell and had some discussion about that already, but the Codell does only cover about half of our acreage out there at this point in time, about 14,000 acres. So, we would need to reduce the amount of Codell acreage correspondingly.

But, again, all in, when we start talking about developing all 3 benches and the positive results we're seeing, from the 40-acre test to the north of us, from Noble as they just recently presented, bodes extremely well for us going forward on an inventory standpoint.

Yes, so even if you were to drill some longer lateral more than likely there would be some upward revision to this 360 location at some point in time?

I think so, we see, not only both vertically with the multiple horizons, but we also see aerially increased downspacing, and the extended reach lateral that Noble drilled to the north of us is performing so well. They've come out and said that are going to recover over 750,000 barrels as you know, Irene, for $7.5 million well cost. That really enhances the economic. So everywhere that we can place an extended reach lateral well, we're looking at doing that and maybe retooling our Wattenberg inventory and increasing the run rate.

Great, thank you.

You're welcome.

And your next question comes from the line of Mike Scialla from Stifel Nicolaus. Please proceed.

I was just wondering are you guys planning on doing any work on testing spacing later this year, or is that going to be down the road?

In the Wattenberg, Mike?

In Wattenberg, sorry, yes.

We are watching our neighbors that have drilled on 40-acres spacing, and I think what we will do -- guys?

I don't know if we have any plans for the remainder of this year to test going down the 40-acres spacing, they will definitely be in the plan for 2013.

Okay. And I just one question on the well performance, you talked about going to 18 stages from I think your first wells in the horizontal Niobrara were 16 stages. Have you seen any difference in the performance from those first few wells to the most recent wells and how the cost compares as well?

Costs are actually minimal, little bit of [wood] and sand. The largest component of the frac treatment -- a large portion is the equipment [now] and it's already there, so, you are not adding any more equipment. A little bit of time, but it's really insignificant in the overall cost. I think we've figured it's like $100,000 to do 2 additional stages in the overall well cost.

As far as the results, we have actually just -- we started going from 16 stages to 18 stages about half-way or so through the program. We are actually just getting to those wells and getting those frac, and completed, so we don't really have any results yet off the wells that we have gone to the 18 stages.

How about - go, ahead.

I might mention, Mike, that even though we are at the $100,000 increase, we are still [ASVing] our wells with the 18 stages at $4 million each.

Okay, great. And I realize you may not have the data from the recent 18-stage wells but, say, some of the wells that you've had 30-plus or maybe some 60-day rates on, how do those compared to like the first wells you drilled last year where you've got some extended production history?

Yes, I think we're seeing results that are little bit better on an overall basis. We've tweaked our flow backs. We've, I think, gotten a little bit better at conversion to artificial lift, so our results are looking a little bit better as we move forward.

Okay, great, thank you.

Thanks. Mike.

And there are no further questions at this time.

Thank you very much, Erin. And thanks, everybody, I appreciate you participating in our second quarter call.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.

Good day.