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Executives

Bud Brigham - CEO

Gene Shepherd - CFO

Lance Langford - EVP, Operations

Jeff Larson - EVP, Exploration

Analysts

Subash Chandra - Jefferies & Co

Ron Mills - Johnson Rice

Steve Berman - Pritchard Capital Partners

Derrick Whitfield - Canaccord Adams

Dan Guffey - Thomas Weisel Partners

Robert Calsen - Janney Montgomery Scott

David Snow - Energy Equities Inc

Brigham Exploration Co (BEXP) Q3 2009 Earnings Call November 6, 2009 10:00 AM ET

Operator

Welcome to the third quarter 2009 Brigham Exploration Company Earnings Call. (Operator Instructions)

I will now turn the presentation over to your host for today, Bud Brigham, Chairman, President and CEO.

Bud Brigham

Thanks to each of you for participating in Brigham Exploration Company's third quarter 2009 conference call. With me today we have Gene Shepherd, our Chief Financial Officer and Executive Vice President, Lance Langford, Executive Vice President of Operations, Jeff Larson, our Executive Vice President of Exploration, and Rob Roosa, our Finance Manager.

Importantly, before we get started, I'd like to encourage you to be prepared. During the course of this call you can view our conference call presentation, which can be accessed via our website at www.bexp3d.com. It includes very helpful information regarding our Q3 2009 results, as well as our plans for the remainder of the year. We'll be referring to the slides in the presentation during our discussion.

During the call, we're going to make some forward-looking statements to help you understand our company's results in our company's SEC filings and the press releases that were issued. There are some risk factors that should be noted that might cause our actual results to differ from what we talk about today or from our projections. I encourage you to review our filings with the SEC.

In addition, in this call we may use the terms probable and possible reserves and locations, which are unproved reserves that we do not include in our SEC filings. Please refer to page two of our corporate presentation for a cautionary note to US investors regarding the use of the terms probable and possible reserves and locations.

Finally, a copy of our company's press releases, as well as other financial and statistical information about the periods being presented in the conference call will be available on the company's website, under the section entitled Investor Relations at www.bexp3d.com.

So let's get started. First, we want to thank all of our existing investors who stepped up and participated in our recent offering. We also would like to welcome and thank all of our new investors for joining us during this very exciting period for our company.

If you'll go to slide five, you can see our outline for the call today. We're involved today in an exciting and accelerating transformation. We're quickly becoming a pure, long reserve life oil resource player, with a remarkably deep inventory of projects for a decade plus of net asset value growth.

During the course of the call, we'll talk about this transformation, and as a part of that, we'll also update our operations, particularly in our 100,000 net acre Williams and McKenzie County, North Dakota area, where we believe we've largely derisked with our recent successful Bakken wells.

Slide number six summarizes our achievements since May, which I won't go through item by item. I will say that we're blessed to be involved in the Bakken and Three Forks play. We frequently said that it's a gift that keeps on giving, at least Mother Nature does in this case, as the play just gets better and better, which is part of what makes it so exciting.

Of course, the recent transaction positions us to meaningfully accelerate our net asset value growth in the play. We believe it will prove to be very accretive and rewarding for all of our shareholders.

Skipping ahead to slide eight, you can see that the oil commodity advantage that's persisted for the last several years is continuing. We expect oil to be the favorite commodity, domestically, for the next several years. As you can see on slide nine, we're ideally positioned to capitalize on this advantage, given our huge position centered in the core of the only large high quality oil resource play domestically.

We're benefiting from a very well-supplied natural gas environment, which has driven our costs down, providing very attractive margins and returns on our huge inventory of Bakken and Three Forks oil drilling projects.

Slide 11 is an important slide. It illustrates the growth in our Bakken and Three Forks oil production. Obviously, this is what you want to see for a resource play, predictable additions to production and reserves. In this case, with results improving significantly over time.

At the upper right yellow box, you can see that we're just getting started here. If you look at our core areas alone, being Mountrail County and our Rough Rider area west of the Nesson, and Williams and McKenzie Counties, we've only drilled 22 of 700 net wells we think we'll have the opportunity to drill here. That's about 3% of the inventory in our roughly 147,000 net acres that we consider to be core today. In addition, we have another 150,000 net acres that could also become core.

Although we drilled the initial 3% of our core inventory, with predominantly earlier technology and thus, have lesser well performance than we're achieving today, it's already grown our production here to over 2,000 barrels of oil equivalent per day.

Gene will discuss our guidance in a minute, but given our 2010 capital plan, we expect to more than double our Williston Basin oil production as we exit 2010.

Looking further at slide 11, you can see that we were hibernating during the first half of this year. As we resumed completing and drilling wells at mid-year, particularly given the dramatic improvement we've delivered in well performance, the production response has been stronger than that of our earlier wells.

I should also point out that the production chart on slide 11 runs through September. So our recent Brad Olson and BCD Farms completions, which produced at early peak rates of 2,112 and 1,776 barrels of oil equivalent per day, are not on this chart.

Slide 12 shows our Bakken completion since mid-year, have impacted our oil production in the third quarter. We've had six consecutive 18 plus frac stage wells, with average initial peak rates of roughly 1,900 barrels of oil equivalent per day, certainly outperforming our expectations and our guidance.

Slide 13 illustrates our company's total oil production volumes with the green line, and of course the growth is driven by our Bakken and Three Forks drilling.

Again, we've achieved meaningful growth thus far. Our third quarter oil volumes were up 84% relative to the third quarter of 2008. The orange bars illustrate just our Bakken and Three Forks net wells completed, and currently expected to complete by quarter. Of course, we were hibernating during the first half of 2009, and as we resumed completing and drilling wells at mid-year, particularly given the dramatic improvement we've delivered in well performance, the production response has been stronger.

For example, the 2.8 net Bakken and Three Forks wells we completed in the third quarter, drove our company's total oil volumes up 43% sequentially, relative to the second quarter.

Staying on slide 13, you can see that although we now have three rigs running, our net well count is down somewhat in the fourth quarter, and even Q1 2010, relative to what it would otherwise be due to our joint venture drilling with US energy.

The joint venture diluted our interest in much of our near term Rough Rider drilling. As a reminder, we back in for 35% of the participants' interest after payout, so our net interest in those wells will increase over time.

Our joint venture drilling should finish up early in 2010. That, combined with the fact that we're picking up a fourth rig around mid-year 2010, will lead to a significant acceleration in our drilling and, therefore, our production and reserve additions.

Jeff will briefly walk you through our acceleration schedule in more detail in a minute, but I think you can see from this graph, while we're confident that we'll more than double our oil production by the time we exit 2010.

One last thing. We believe this is a conservative capital plan for us. And if our wells continue to outperform, and provided commodity prices hold up, we could be in a position to accelerate beyond this early next year.

Moving to slide 14. You can see our six to one equivalent production volumes and that we're becoming oilier pretty quickly.

Given that we continue to hibernate with our gas projects and also given that our best gas projects are held by production, we can continue to keep those in inventory as we continue replacing our shorter reserve life gas reserves with 30-year economic life, higher value oil reserves.

As shown on slide 15, oil continues to trade at a substantial premium to natural gas, recently at a 15 to 20 equivalency. In the third quarter, our six to one equivalent oil volumes generated almost three times the revenue of our gas volumes.

On slide 16, you can see our realized equivalency by quarter, based on the actual prices we received. Although our activity has been relatively modest in 2009, you can see we've substantially grown our realized equivalent production volumes. Given our acceleration, we expect substantial growth in 2010.

Now, let's briefly discuss the advancements in completion technology, which are driving improved well performance. On slide 18, you can see the dramatic improvement that our operational team has delivered in well performance. The chart illustrates the elevated production performance as we've increased the number of frac stages.

You can see that we now have meaningful history on our 24 frac stage Anderson well. This well is still producing roughly 500 barrels of oil per day, after making about 65,000 barrels, and is on pace to pay out about a year after completion. That's pretty remarkable when you consider that we expect these wells to have a 30-year economic life. Obviously, the rate of return on that well should be more than a 100%. As shown on the yellow inset table, it's not just higher rates; it's higher EURs and lower finding costs. Today, we think our drilling dollar finding costs are $10 to $15 per barrel.

Slide 19 illustrates schematically the evolution to-date in our well designs. Expect more to come here, not just by us, but from other operators as well. Right now, we've got more work to do delineating how much improvement we can generate from more frac stages.

Given that we are not increasing the cumulative size of our fracs to this point, the incremental cost per frac stage is only about $20,000. Our results going from 715-foot frac spacing down to 400-foot frac spacing appear to indicate we are adding about 35,000 barrels in reserves per stage, which implies a cost for those reserves of $0.60 per barrel. We are going to monitor the results of our 28 frac stage wells, but don't be surprised to see us increase the number of stages further.

On slide 20, you can see looking beyond the initial peak rate for frac space that the same relationship is illustrated looking at the 30-day average production. As shown, there is a pretty good linear fit to those points. Clearly, adding frac stages, although incrementally relatively inexpensive, is having a material impact on well performance to this point.

Looking at slide 21, you can see another way to look at the impact the increased number of frac stages is having on performance by looking at the number of days to produce 40,000 barrels of oil. Of course, it's all about return of capital. And you can see that our Anderson well produced 40,000 barrels in only 37 days and it's continued to perform strongly.

Moving to slide 22 to finish up on operations and economics. You can see that we are modeling $6.25 million per completed well. However, our operations team has done a good job to this point and that we are currently coming in at just under $6 million. We are continuing to make an effort to drop down costs further and to lock in low costs in areas where we expect to see costs creep over time. Ramping up to four rigs has provided us the opportunity to do just that and we have managed to lock in roughly 50% of our costs for our 2010 plan.

Now, let's move on and provide you an update on our accelerated drilling program. Slide 24 summarizes our inventory. Inside the green box, you can see the portion of our Williston Basin acreage that we believe is Tier 1 core to this point. We have almost a 150,000 net acres in Mountrail County and in Williams and McKenzie counties where we recently drilled six consecutive 18 plus frac stage wells, with initial peak rates averaging about 1900 barrels of oil equivalent per day.

All these wells were in Rough Rider west of the Nesson and two were in our Ross area of Mountrail County. We believe we will drill about 120 initial wells in each production unit to hold these areas and that we will likely drill an estimated 700 wells per full development. In areas where the Bakken and Three Forks both work, we expect to drill three wells per each objective across each unit for full development.

Also on slide 24, you can see that we have 83,000 net acres in Montana, which we believe could be de-risked to some degree over the next six months. We have two private operators drilling one well already with another well planned. In addition, ELG is apparently planning to commence a well immediately to the east of our 83,000 net acres there. We really like this area and believe it's got an excellent shot at becoming core for us.

We are currently planning on commencing our first horizontal Bakken well in this area late during the first half of 2010. There is activity around our other areas north and south of Mountrail County which could be again de-risking those areas as well, though at this point we consider them to be generally higher risk than Montana. Though time will tell.

Slide 25 summarizes our progress in these areas and lists our six recent wells which our operations group has delivered strong early well performance.

Slide 26 is a map that shows our acreage in the basin in red. Again, we view the Ross, Parshall areas of Mountrail County and the Rough Rider area of west of the Nesson as core and largely de-risked at this point. You can see it illustrated on the map the area of activity around our 83,000 net acres in Montana, which could begin de-risking that area near term.

Now moving to slide 27 to discuss Rough Rider specifically. We have labeled here our completions thus far. The Mrachek was our first well, a short ladder with seven frac stages which by the way has outperformed our seven frac stage wells in the Ross area. We have since drilled four 18 plus frac stage well in this year which have produced at initial rates of between 1,433 to 2,112 barrels of oil equivalent per day.

We believe that the market should appreciate that our BCD Farms was 13 miles Northwest of our Olson wells and about 30 miles Northwest of our Mrachek and Figaro wells. In our view, these confirm our belief, based on the significant number of vertical well control points, the four single frac stage wells and our other technical data, that this is one continuous reservoir across our acreage. It's simply been a matter of technological improvements allowing us to be more efficient in recovering the substantial amount of oil in place to get it out of the ground.

We have a sequence of slides to illustrate this. Slide 28 shows the early single frac stage wells relative to our seven frac stage well Mrachek well. Going to seven stages roughly doubles the reserves expected to be recovered.

Now if you move to slide 29, you can see the much stronger performance demonstrated by our 20 frac stage Olson well which we believe likely doubled the EUR once again relative to the Mrachek.

On slide 30, you can see that our 19 interval Figaro well is performing roughly comparable to the Olson well. By the way, the star is placed where the well was put on pump.

Slide 31 shows the Brad Olson, which has been a strong producer thus far and the early performance of the BCD Farms, which we drilled on the far Northwest portion of our roughly 100,000 net acre position.

Moving back to the map. Slide 32 shows our two wells currently completing. The Lee, which is a little south of the BCD Farms, is currently being frac with 28 stages. And due east of the Lee, the strand will commence fracking in the next couple of weeks. These are joint venture wells with US Energy as our participant.

Slide 33 shows our State 36-1 and Williston 25-26, which are both drilling in the Eastern portion of our acreage. To the south of our Olson and Brad Olson wells, our Jackson 35-34 is planned to spud early next week. We are also participating with an eighth interest in the Bobcat 25 well to the Northeast of our acreage. So with three rigs running, we are going to have quite a bit more data in this area by year end.

In addition, Newfield is currently completing their [Channel] well, offsetting quite a bit of our acreage on the east side and on the west side ELG is apparently completing their round prairie 1-17H well. So there's a flurry of Bakken activity by us and other operators in this area. The results have been some encouraging Three Forks producers drilled to the Southeast of our acreage.

As some of you know, we drilled a hole core through the Three Forks with our Olson well, which indicated oil saturated pay. We believe it's likely we'll drill our first Three Forks well in this area early in 2010.

Finishing up, slide 34 and 35 show our current 2010 capital plan. It's important to note that our budget in 2008 was comparable to our 2010 plan. So we're very well staffed to execute on this program and even increase it if that makes sense. You can also see on this slide that we completed 7.2 net Bakken and Three Forks wells during 2009, which generated very strong growth in our oil volumes. We are therefore very confident in our expectation to more than double our Williston oil production by the fourth quarter 2010.

Now briefly before we hand off the call to Gene, Jeff's going to provide you a few more specifics regarding our accelerated plan.

Jeff Larson

Thanks, Bud. As Bud mentioned earlier, we have three rigs currently running in the Williston Basin, with plans to keep those three rigs running throughout 2010. At this point, all three rigs are in the Williston county portion of our Rough Rider project. I plan to spend a few minutes detailing each of our rig lines this morning and would point out we are also aggressively preparing locations in both Easy Rider and Rough Rider to potentially add a fourth rig line some time in the first half of 2010.

As noted earlier, our neighbor's 52 rig is currently finishing the curve section on the Williston 25-36 well. This rig will then go across the Anticline and drill a high working interest, three-well package, in our Easy Rider project area.

The first location, the 67% working interest lift rig, will be a Three Forks well on the west side of our Ross block. The second location, the 50% working interest (inaudible) Anderson, will also be a Three Forks well, located just two miles north of or excellent Strobeck, Three Forks producer.

The third location, our 42% asset location is located near our Johnson well in Northern Ross area. This will be a Bakken test.

On the neighbors 49 rig line, we are currently at kickoff point on our state well in the Rough Rider area. This rig is currently scheduled to stay in Rough Rider throughout much of 2010. We'll next drill our 53% working interest Owen nearing Bakken location approximately five miles Southwest of our Brad Olson well. We will then move this rig south of the river to McKenzie County and drill our Pompano trust location which is just two miles west of our Mrachek well.

On the third rig line, we are currently rigging up our 54% working interest Jackson location. This is just two miles south of our current Olson producer. This rig will also stay in Rough Rider much of the near term throughout much of 2010.

We're also preparing to drill, as Bud mentioned, a Ghost Rider Bakken location in Roosevelt County, Montana, sometime in Earl 2010, with plans being to core the Bakken and Three Forks formations and then kick off and drill a Bakken test. We're very excited about this location. Control points in the area show us that the Bakken has excellent middle Bakken ferocity, and also the Bakken shales in this area are very mature. We're also looking forward to testing the Three Forks in our Rough Rider area sometime in 2010.

Lastly, in early 2010, as we transfer from drilling JV wells to non-JV wells, our net interest and therefore our net oil volumes should increase significantly.

With that, I'll turn the call back to Bud.

Bud Brigham

Thanks, Jeff. We're going to go ahead and pass the call over to Gene to discuss our financial progress, after which we'll be happy to answer any questions.

Gene Shepherd

Thanks, Bud. Before we review our financial results for the third quarter, I thought I would update you on the liquidity enhancing initiatives that we've implemented since the beginning of the third quarter.

These initiatives have positioned the company to accelerate drilling in 2009 and 2010, and thereby, take advantage of our significant Williston Basin acreage position and inventory of horizontal Bakken and Three Forks drilling locations, the current favorable macroenvironment for drilling wells in the Williston Basin, and lastly, our superior operational capabilities, which have evolved to a point where we are generating outstanding production rates, EURs and returns from our horizontal Williston Basin wells.

Slide 37 lists our recent liquidity enhancing initiatives.

First, our five recent horizontal completions in the Williston Basin, with IP rates averaging 1,992 barrels of oil equivalent per day, have outperformed our risk forecast and have allowed the company to fund our third quarter drilling and completion activities out of internally-generated cash flow. As a consequence, our cash, cash equivalent and investment balance has increased from $72 million after our May equity offering, to $75 million at the end of the third quarter.

Second, in July, we extended the maturity of our senior credit facility to July 2012, and increased the number of banks participating in the facility from five to six.

Third, in order to protect the very attractive drilling margins that exist for Brigham in the Williston Basin, we continue to hedge our oil volumes and expect to continue to do so for the foreseeable future. Since our May equity offering we have added approximately 650,000 barrels of crude costless collars, with a floor of approximately $60.77 per barrel and a cap of $87.87.

Clearly, these wide collars are attractive, given that we can earn solid returns at $60, while at the same time retaining plenty of headroom to benefit from potentially higher commodity prices.

Furthermore we've also taken steps to lock in service costs where we can, given our acceleration in drilling activity which is under way. At the present time we have signed, or expect to sign in the near future, contracts that lock in the costs associated with roughly 50% of our currently planned 2010 CapEx budget.

Fourth, in August we entered into a drilling participation agreement in our Rough Rider project area, allowing us to preserve the state leases and accelerate our drilling activity in our Rough Rider project area before yearend, further delineating the value of our approximately 100,000 net acres west of Nesson Anticline.

Finally, in late October, we priced a 16 million-share common stock offering, raising net proceeds of roughly $160 million. The offering will fund an accelerated level of Williston Basin drilling activity in 2010, initially consisting of 24 net horizontal Bakken and Three Forks wells, up from seven net wells in 2009.

This week the underwriters of the offering indicated that they intended to exercise a portion of the green shoe, which should close next week and result in an additional 838,000 shares being issued, generating additional $8.4 million in net proceeds.

The 24 net Williston Basin wells represent the bulk of our currently planned 2010 CapEx budget, totaling $176 million. Pending investing the offering proceeds in 2010, we used a portion of the net proceeds to retire the $110 million outstanding under our senior credit facility.

Combined with our pre-offering cash balance, post-offering, the company is left with $133 million of cash on the balance sheet, and an undrawn credit facility, giving the company total liquidity of $243 million pro forma for the exercise of the green shoe.

We are in the process of having our borrowing base re-determined and expect it to have it reaffirmed at $110 million within the next several weeks.

Based on our initial 2010 budget, we expect to use our cash position and our internally generated cash flow to fund the bulk of our activities during 2010 and would not expect to draw down under the senior credit facility until late in the fourth quarter 2010.

In conclusion, we believe that our recent equity offering has addressed the company's capital needs, not only for 2010, but for a major portion of 2011 as well. This leaves the conventional asset sale that we discussed in the past as an alternative for funding the remaining portion of our 2011 capital needs.

As a final point around our 2010 spending plans, to the extent our Williston Basin completions continue to outperform our risk forecasts, as we have seen with our five completions since May, we should be in a position to announce a further level of acceleration in our Williston Basin drilling activities at some point in the first half of 2010.

Moving to a brief discussion of our financial results for the third quarter, our daily production volumes averaged 5,200 barrels of oil equivalent per day, above the high end of the production guidance that we previously issued for the third quarter of 2009.

Further, our Q3 production volumes increased 15% sequentially from those in the second quarter 2009 and 13% from those in the prior year's third quarter. The sequential increase in our Q3 production volumes was primarily attributable to our three recent Williston Basin completions, which resulted in a 68% increase in our Williston Basin oil volumes and a 43% increase in our overall oil volumes, relative to those in Q2 2009.

Importantly, our oil volumes in the third quarter represented 50% of our total volumes on a six-to-one equivalent basis, however, generated 75% of our total revenues before hedge settlements. Reflecting both the continuing transformation to an oil-based resource play focused company, and the superior returns that our shareholders are realizing from such transformation.

As far as the income statement is concerned, our increased production volumes and increased hedge settlement gains only partially offset the impact from lower commodity prices during the third quarter, resulting in a 36% decrease in revenues, including hedge settlements to $19 million.

Third quarter 2009 revenues were positively impacted by $8.8 million due to the aforementioned increase in production volumes and $2.4 million due to the increase in cash hedge settlement gains. These increases were offset by $21.8 million decline in revenues due a 48% decline in pre-hedge commodity prices.

On a per unit basis, lease operating expense decreased 6% to $7.01 per BOE in the third quarter 2009, from $7.45 per BOE in the third quarter of 2008. Higher production volumes and a 3% decrease in the dollar amount of our operating and maintenance expense accounted for the decrease and were partially offset by an increase in workover expense.

The decrease in O&M expense was driven by lower well service and repair, compressor rental and maintenance and saltwater disposal expense. On a per unit basis, production taxes were $3.31 per BOE, relatively flat with those in the third quarter 2008.

General and administrative expense of $2.1 million for the third quarter 2009 reflects a 17% decrease versus that in the third quarter 2008. The decrease in employee payroll expense associated with our previously announced cost cutting initiatives accounted for the majority of the decrease in G&A expense.

However, with the rebound in oil prices from the beginning of the year, and the restart of our Williston Basin drilling program, we would expect that our G&A expense should return to 2008 levels. Higher production volumes partially offset the impact of lower commodity prices resulting in a 43% decrease in EBITDA during the third quarter 2009, relative to that in the third quarter 2008, to $13.2 million.

Moving on to the balance sheet; at the end of the third quarter, we had a $110 million outstanding under our senior credit facility, which we have subsequently repaid with the proceeds from our October equity offering, and we had a $160 million of senior notes.

Recapping capital spending activity for the third quarter, exploration and development capital expenditures totaled $13.6 million, of which $11.1 million went to drilling expenditures and $2.5 million went to land and G&G expenditures.

For the full year 2009, we currently expect that our exploration and development capital expenditures were totaled $51.5 million. As I've stated with our drilling acceleration that we planned for 2010 in the Williston Basin, we currently expect that our 2010 exploration and development capital expenditures will total $176 million, with $169.4 million consisting of drilling expenditures and $6.4 million consisting of land and G&G expenditures.

In our operations release that we put out this morning, we updated our production guidance for the fourth quarter 2009. In terms of our expectations for the fourth quarter, we are forecasting production volumes to average between 4700 and 5200 barrels of oil equivalent per day. Of this, we expect oil volumes to make up roughly 54% of our fourth quarter volumes.

This would equate to fourth quarter oil production of approximately 2,673 barrels per day, which should be a real positive for our current quarter revenues, given the superior economics associated with oil versus natural gas. Further, during 2010, we would expect that our Williston Basin oil volumes should more than double from the fourth 2009 to the fourth quarter 2010.

Lastly, we would expect that our total 2010 production volumes should grow by a minimum of 25% over those for 2009, with the bulk of this growth coming in the form of our growth in our Williston Basin oil volumes.

That concludes my remarks. I'll now turn the call back over to Bud.

Bud Brigham

Thanks, Gene. That concludes our prepared comments. I would like to thank everybody for their participation and we would certainly be very happy to answer any questions you might have.

Question-and-Answer Session

Operator

(Operator Instructions). Our first question comes from the line of Subash Chandra with Jefferies. You may proceed.

Subash Chandra - Jefferies & Co

A few questions here. First, I guess, just on the financial side. The Q4 CapEx, just between the capital items, I'm getting a little bit lost. Could I get the Q4 capital number between drilling, land and then the capitalized items?

Gene Shepherd

The total budget for Q4, we've got $14.8 million for drilling, and then $1.4 million for non-drilling, then the capitalized items represent the remainder. So if you take the $51 million and subtract out the first three quarters, that will give you the fourth quarter number.

Subash Chandra - Jefferies & Co

So the 51 was with the capitalized items. Got you. Further acceleration, what would be the decision matrix to get there? Is there some balancing of how much you want to spend beyond cash flows, some sort of growth rate you want to achieve or how do you make the decision to go to a fifth rig, maybe even more?

Bud Brigham

This is Bud. I think the plan that we've laid out is pretty conservative, given the capital that we have on hand and current prices, and, in particular, we're certainly not modeling the well performance that we've achieved with our last five or six wells. So I think if we continue to see that kind of well performance and prices holding up, just based on the modeling, I think we'll be in excellent position to accelerate early next year.

Gene, do you want to say anything else about the plan?

Gene Shepherd

We have got pretty conservative budget. We haven't really made any big changes to our forecasting since the May equity offering, despite the performance of these recent wells. So I think that should, if the results going forward continue to mirror the recent completions, give us an enhanced level of liquidity as we enter 2010.

Subash Chandra - Jefferies & Co

You have far more precise production model I would imagine, just knowing when wells come on and that sort of stuff. The 25% type growth number for next year, and how you are sort of looking at the latest well, I guess what type of conservatism do you think is built into that number?

Bud Brigham

One thing, Subash and these guys they want to add to what I said, this to Bud. But it's pretty much a back-end loaded program. You can see it on that net well chart relative to the production growth we've you achieved that it's really going to begin to ramp up in the first quarter, but significantly as you get into the second and the third quarter, as the joint venture rolls off, our equity increases in the wells.

And then further when we add the fourth rig, it's a significant ramp-up. So that's why our oil production we expect to more than double in the fourth quarter of 2010 relative to '09. So our exit is going to be much stronger than that 25% overall production growth for the year. I don't know if that helps.

Subash Chandra - Jefferies & Co

Yes. That does. That puts it in perspective. One final one for me. These BCD Farms and how big a step out that was relative to prior wells. Looking at I guess the next few wells, they are sort of in the neighborhood. I didn't see it in the presentation, when do you propose your next big step out or delineation well on the Rough Rider side?

Bud Brigham

Maybe I'll make this initial comment and then Jeff can certainly be more precise. The current wells we're completing are south of the BCD Farms on the west side, but we are currently drilling on the east side of the Rough Rider acreage. So, we should have results on those later in the year. Then also we've got the Three Forks that I think some time hopefully in the first half of 2010, we'll drill our initial Three Forks well.

In our view, the Bakken should be largely de-risked in Rough Rider to the market. We don't think that's reflecting our stock price, we think that the well's performance has demonstrated that. So the Three Forks should be a big catalyst early next year and then beyond that of course Ghost Rider. We have got EOG and private operators, two private operators with four wells between them in and around our Ghost Rider area over the next six months, and so those could significantly de-risk the Ghost Rider area, then we get out and drill our well.

Subash Chandra - Jefferies & Co

So the little splotch there I guess on the east side, it looks like somewhere between the Figaro, west of Figaro and south of Round Prairie. Is that even an area that's necessary to test here in the near term?

Bud Brigham

Not in our view in terms of derisking. Some of that's in the joint venture, some state acreage that we're preserving. In our view, the entire acreage position is largely derisked. I think it will probably help market those well from east (inaudible). State well and the Williston well will probably help the market give us more credit for our 100,000 acres in the area, since those will be wells over to the east portion of our block.

Jeff Larson

We've also got excellent sub-service control from start data points across the block, which shows really continuous well development on the Bakken (inaudible) confidence.

Bud Brigham

Well over there on the east side that performed comparably to the single frac stage wells in the center and on the west side, fully performed identically.

Gene Shepherd

Subash, just a correction. The $51.5 million of CapEx that I referenced earlier, that's without the capitalized cost. So you have to add the capitalized cost for the full year to get back to the total budget. What we're trying to do is give you some sense as to the CapEx, without the capitalized cost, so that you can compare that to the discretionary cash flow, which obviously captures cash expenses, so that there's not a double accounting going on.

Operator

Our next question comes from the line of Ron Mills with Johnson Rice.

Ron Mills - Johnson Rice

As you look at your 24 wells next year, it looks like half of them are expected to be in Ross, half of them near Rough Rider area, plus the one I guess in Ghost Rider, but what do you think of the Bakken versus Three Forks distribution in both Ross and Rough Rider?

Lance Langford

We've had excellent success already in Ross with our Three Forks, with our Strobeck well and I think we'll look at the mix, Ron, and see how the wells layout for us. We're very excited about testing the Three Forks and Rough Rider. With the recent activity with the Williston County well, (inaudible) 500 barrels a day, east part of the Nesson Three Forks and Rough Rider has given us very good encouragement, and also our core obviously, so we would like to test the Three Forks well earlier as opposed to later in Rough Rider in 2010 to set us up for Three Forks development there as well.

Bud Brigham

But I think at this point on the Ross area we probably anticipate that half of the wells in the Ross area will be Three Forks and maybe half will be Bakken.

Ron Mills - Johnson Rice

In Rough Rider you'd have at least that one Three Forks, but maybe if that works, would you do maybe three or four Three Forks there?

Bud Brigham

Yes, in the second half of the year, that's right. You could kind of see of course what happened in Ross is we both have proven up with very attractive economics and if we get initial success and other operators continue to have success in Three Forks you could see us go 50-50 maybe in the Bakken Three Forks in the Rough Rider area as well.

Lance Langford

I think you're aware of the way the NDIC works. Your spacing units in the way you permit, you can make basically election when you spud it, it can be a Three Forks or Bakken wells, that gives us a lot of flexibility.

Ron Mills - Johnson Rice

Under the JV or the participation agreement with USEG, as I recall the payout before you start backing in is on the first six wells combined. What is your expectations based on your production estimates as to when that payout would be received and you'd start to back into that incremental acreage or interest?

Bud Brigham

Well, Ron, this is Bud. I mean, generally our modeling, if you use the 600,000-barrel well case and recent prices and well costs, it looks like it's about averaging maybe a year and-a-half payout on these wells. Of course, the Anderson, the first 24-frac stage well with a lot of history looks like it's going to be about 12-month payout. So combining those six wells you might look at a year-and-a-half or so out from the six wells being completed.

Ron Mills - Johnson Rice

In addition to your 25% production growth that you have, then as you look to 2011 you should have a real nice at least head start to the year, just from backing into that incremental?

Bud Brigham

Yes, that's right, Ron. Certainly our exit to 2010 is going to be, as we mentioned, we expect our oil volumes to more than double, so the exit is going to be much stronger than that full year average of over 25%.

Gene Shepherd

The one and-a-half year payback was based on risk volumes, so conceivably if our wells continue to outperform you could see something shorter than that.

Ron Mills - Johnson Rice

Gene, I think you mentioned your cash flow plus the cash on the balance sheet should fund you through most of 2010, I think on my model I get you all the way through. What's kind of your financial strategy as it relates to funding incremental CapEx on your revolver, and to what extend would you do that?

Gene Shepherd

First off, we're currently modeling risk volumes and our recent wells have outperformed those, what we have in our models, both from the standpoint of production performance and also we're running at $6.25 million, then we've got a 10% overage built in, so that's like $6.9 million per well and our recent wells are actually coming in below $6 million. So if the trend continues into the future, both from a CapEx standpoint and production standpoint, you would expect that trend to positively impact liquidity next year.

Our modeling work based on the equity offering and based on the 24 net wells next year, we don't really touch the credit facility until the very end of next year. At the same time, we're growing borrowing base next year. So we certainly expect that that $110 million borrowing base will grow as we move through the year and certainly you could argue that we believe we've already derisked 150,000 acres. We're going to be focusing our activities, but as you get to even more into a development drilling mode you can argue that certainly it's reasonable to use some degree of leverage.

Certainly, we would intend to use a portion of the availability under the credit facility, but we won't have a need to use that availability until really 2011. So it will be in 2011, a combination of cash flow, availability under the credit facility or some form of leverage and we've also talked about our desire to monetize a portion of our conventional assets and that's another option that we'll be exploring next year.

Ron Mills - Johnson Rice

Just on your service cost, you talked about locking in 50% of next year's. How are you doing that? Is that rigs, is that completion services, is it profit, what are you doing to lock in those service costs?

Lance Langford

This is Lance. It's on a multitude of services and what we did basically is take the larger services or most expensive services that we have in an AFE and started locking those in, so those are rigs, they are proppants, they are stimulation jobs, it's our swell packers, our perf-and-plug, it's our casing. So we started with the bigger ones and we're working our way down. We expect to tie in more of those costs as we go along, but there will be some part of it's that's always going to be variable. Then even some of the costs that we are locking in will have some adjustments quarterly or yearly.

Operator

Our next question comes from the line of Steve Berman with Pritchard Capital Partners.

Steve Berman - Pritchard Capital Partners

Getting back to Ron's DPA question, beyond these first six wells, I believe US Energy has an option on nine more. Are you assuming anything in 2010 for that?

Bud Brigham

On their election, we have the opportunity to participate for them to have 50% down to 15% and we're clearly going to elect to retain more equity so they'll have 15% equity in those wells.

Steve Berman - Pritchard Capital Partners

So you're assuming they will exercise their option?

Bud Brigham

I'm very certain, Steve, that they will.

Lance Langford

So we get the opportunity next year to keep up to 50% and we have the option to go as low as 15%. So going forward just based on the financing we've done, we would expect that of that original working interest that we had in those wells that we expect to keep 50% and that leaves them with the other 50% so long as they elect to participate.

Gene Shepherd

With the recent outstanding success of the JV, it's our expectation they'll participate.

Lance Langford

They will. So it will be a 50:50 split is what we're modeling.

Steve Berman - Pritchard Capital Partners

Isn't it your option as to which wells those nine are?

Lance Langford

That's correct.

Steve Berman - Pritchard Capital Partners

So you could drill a particular well in Rough Rider, and say, no, you're not in this one, but you can be in that one?

Bud Brigham

Yes, we can.

Steve Berman - Pritchard Capital Partners

Then just one other question. Gene, what's the current share count including the overallotment exercise you mentioned earlier?

Gene Shepherd

Yes. 99.8, that includes the green shoe.

Steve Berman - Pritchard Capital Partners

Okay. All right. That's it from me. Thanks, guys.

Bud Brigham

You're welcome. Just one general comment. U.S. Energy is a great partner and it's been great relationship, and so we're clearly going to be real fair and we've got a lot of good locations to drill with those guys.

Operator

Our next question comes from the line of Derrick Whitfield with Canaccord Adams. You may proceed.

Derrick Whitfield - Canaccord Adams

So based on the early read you have on Brad Olsen and BCD results, do you have any inclination to increase fracture stimulation for your next few wells?

Lance Langford

This is Lance speaking, Derrick. You'll probably see some 32 stage but the majority I think are going to stay in the 28 stage range. Until we get more production data to analyze to determine what benefit we're really getting with more stages. So I suspect most of them are going to be 28 stages, but I would see maybe one or two 32 stages in there until we get more data, majority will stay 28 stages.

Derrick Whitfield - Canaccord Adams

Then other than location, were there any subtle differences between the Brad Olson and BCD Farms?

Lance Langford

There's slight differences in the way the well treated. Across the area, it's very similar, but there are small changes in the lithology and the way the rock is made up and the way the wells treat and flow back. But I'd say they're very small differences at this point.

Derrick Whitfield - Canaccord Adams

Then lastly, on that Newfield well, that's in your Rough Rider area, is that a Three Forks, Sanish or Bakken well?

Lance Langford

It's a Bakken well.

Bud Brigham

It's a single section short lateral.

Operator

Our next question comes from the line of (inaudible).

Unidentified Analyst

As you think about well count next year and the 26, I guess, net wells, just wanted to kind of walk through kind of a gross and then net quarter in, quarter out as you go through the US EG wells and just kind of stagger that into the model. Can you go through that for me?

Bud Brigham

Yes, David. I think Rob can probably answer that question the best with Jeff's help.

Rob Roosa

So I think, David, in fourth quarter, all four of the wells that we're going to bring online, they're all encompassed within the joint venture, the Brad Olson, the BCD Farms, the Lee and the Strand and including the non-activity that we expect to bring online, that should probably be about the 1.8 net wells, fourth quarter of 2009.

So you can see the difference there. We brought online the three high working interest wells in the third quarter, the Strobeck, the Anderson and the Figaro, so we're at 2.8. The increase in JV activity reduced that to 1.8 and in the first quarter of 2010, you'll see the significant ramp-up in the activity and that's driven by, one, adding that third operated rig that we talked about. Also, basically the impact that Steve Berman talked about, our ability to selectively indicate which wells we're going to participate in the JV or outside of the JV.

Gene Shepherd

Then also, in Easy Rider remember there is no JV. We have got a package of three wells early on, basically 2009, 2010 which are real high interest.

Rob Roosa

So in the first quarter you'll see one rig in our Easy Rider area, and that's drilling of the rig and the drilling of the Anderson wells that Jeff talked about. Then on the west side, you see us drilling, have the two rigs. They will be wrapping up the state in the Williston wells that we talked about and then after that they'll be drilling a couple of non-JV related wells, our [Owen] nearing location and then the Jackson location. So both of those will be outside the JV. Then remaining wells in the first quarter of 2010 will be within the JV.

So all told, those wells ramp up to about the 3.6 net well and then after that, in the second quarter we are modeling increased wells that DEXT participates only in and then really in the third and fourth quarter, you can see going up to the seven wells. It's largely driven by the fact that we are adding that fourth operated rig in that time frame.

So that's really when you see the significant ramp-up activity and that's what Bud alluded to, the ramp-up in the 2010 exit rate because of adding that fourth rig. So it's the production growth, you're really going to see it in the third and fourth quarter of 2010.

Unidentified Analyst

That was perfect.

Gene Shepherd

Obviously, this is a forecast and there's lots of variables that we're dealing with on a daily basis. At the present time, it's 24 wells next year and exactly pinpointing how many net wells on a quarterly basis is somewhat difficult to do, but what's reflected on the slide is where our thoughts are at the present time.

Unidentified Analyst

Then as you think about EOG on the call that they talked about 640 wells that cost $4.4 million recovered 300 MBOE and all Bakken and Bakken light or equivalent. You're doing 1280, more expensive and twice that EUR. As you go through this technical process, how do you guys think about ever testing 640s again, or do you expect offset operators to move towards 1280s or where does the industry kind of come together or does it ever on the decision of the best way to develop the Bakken and Three Forks?

Bud Brigham

I might just have a couple general points on that, then Lance may have more specifics. Three factors that come into play. One is that by drilling of course a long lateral, we're holding 1280 acres and we have 120 wells to drill to HBP, the initial 150,000 acres that we consider core and largely de-risked now. So, that's a positive for the long laterals. But also simplistically the incremental cost for long lateral versus the EUR. Lance, you want to get into that?

Lance Langford

I just think that for one, we're drilling the long laterals not to hold acreage. We are doing it because we think the economics are much better to drill the 1280 space and we think the industry as a whole, I think if you look at a whole, the industry is already moving that way. EOG, right now they're drilling some 640s. I suspect that they're going to start moving toward the 1280s and it's because of economic reasons.

Jeff Larson

One comment on that. I think one thing that you are hearing and that you will continue to see and albeit more defined over time is there is going to be a little bit different recipes in different areas and the recipes in different elements of how we drill and complete the wells. So in some areas, in the Parshall, maybe high string profanes not as important, but you get in the tighter area.

Lance and the guys have proven that higher string profanes are critical and then more frac stages are more beneficial in some of the tighter areas. In some areas, you might maximize the number of frac stages at a lower number that are optimal. So you're going to see a little bit different recipes in different areas.

Unidentified Analyst

As you think about going in and holding acreage, I guess, the one other thing that seems like a way to de-risk acreage is the multiple layers of, you'll either find Bakken, you'll find Three Forks, Sanish, or you could find both. Do you think about the play that way where acreage really is being de-risked by the multiple layers that are being drilled as well?

Bud Brigham

You're exactly right. We do need to get a Three Forks well drilled in Rough Rider. We think it's going to work. We could be wrong, but we think it's going to work there. It's certainly working just to the Southeast of us. We really like the rock we saw in the [Holco] and the Olson and the Three Folks. So all saturated play. So, yes, we do think about it in layers. So it's really de-risking it for those different levels for our plans and so that we can optimize the development on a go forward basis, but also so that the market will give us more credit for the value that we've delineated there over time.

The great thing is, whether we drill the Bakken or the Three Forks or maybe we develop another resource play, the first well in there is going to hold all the acreage and so we'll be able to develop each of the objectives optimally based on the economic, what's optimal for us.

Operator

Our next question comes from the line of Dan Guffey with Thomas Weisel Partners. You may proceed.

Dan Guffey - Thomas Weisel Partners

I was wondering the total cost on the BCD Farms and Brad Olson, and then also, if you could provide how much the drilling portion, how much the completion portion of each well came in at?

Lance Langford

This is Lance, Stan. Our AFEs are $6.25 million. In the last several wells we've been in or right under $6 million, right in that range. So that's where we are on the last wells and we're locking in cost, trying to hold these costs as low as we can. You might see some of the costs go up a little over time, you do expect that.

Dan Guffey - Thomas Weisel Partners

So you expect that $6..25 million for the Lee and the Strand also?

Lance Langford

Yes.

Dan Guffey - Thomas Weisel Partners

Can you break out how much of that is drilling and how much is completion?

Bud Brigham

It's 65% or so completion.

Dan Guffey - Thomas Weisel Partners

Then I was just wondering your thoughts on what oil differentials are going to do over about the next six months or so?

Gene Shepherd

I think in our models, we're modeling $9.50 or $9 something in our models for differentials. I really think that in first quarter with all the capacity coming on, everything, I think it's going to be in the historical average is $6 to $6.50 up to $9 and what they're running right now and I think that you're going to see that thing reduce from $9 to closer to the historical averages.

Here in the short-term, until all the new capacity comes on, we've already got contracts for November, but you could have contracts tighten up a little bit in December, January possibly and differentials spread. We have no indication of that happening right now.

Bud Brigham

By the way, you probably saw it, but slide 42 in the appendix of the corporate presentation shows the production today relative to the capacity expansions that are under way. That's why you can see there's a lot of capacity coming online relative to the growing production out there. Slide 43 by the way shows our volume related oil differentials.

Dan Guffey - Thomas Weisel Partners

Can you also give an update on gas processing in the Bakken and when you guys think you might take advantage of that benefit?

Lance Langford

Well, if you look in McKenzie Williams County, we've got a long-term gas contracts with (inaudible), I think it's a 10-year contract. We've been selling and they're processing, a share of proceeds, so we get a share of the processing proceeds as well as a share of the residue gas.

On the Mountrail side, we just started selling the majority of our gas in the last 30 days going to the Whiting plant. So we're also getting a share of proceeds contract in place with them.

Operator

Our next question comes from the line of [Robert Calsen] with Janney Montgomery Scott.

Robert Calsen - Janney Montgomery Scott

Your average realized price for oil is $57. Seems like that's a low number. What would that might be today?

Gene Shepherd

Are you looking at it on an Mcf equivalent basis? For $57.45, you've got a $2 hedging loss. $2.29 hedging loss, and then it looks like for the quarter we've got $68.30, which is our weighted average oil price and then looks like an $8.56 differential to NYMEX is what we average for the quarter. $68.30 less the $8.56, less $2.29 hedging loss so that's the cash, that's the cash settled loss.

Robert Calsen - Janney Montgomery Scott

Is there a ballpark way of saying what that might be, instantaneously?

Gene Shepherd

What was that again?

Robert Calsen - Janney Montgomery Scott

What you might be selling oil for today?

Gene Shepherd

We've got to check. I don't know off the top of my head, what we are.

Robert Calsen - Janney Montgomery Scott

It's going to be considerably over that number; right?

Bud Brigham

Oil's at $78 then the differential's at $8 or $9. So $69.

Gene Shepherd

I mean, we're talking about the third quarter, and if you go back to early August, the prompt month was at $68 and then prices sort of fluctuated. They ran up late in the month and then in late September we were back to $66 again. So a lot of fluctuations in prices, obviously prices have elevated quite a bit since the end of the quarter, so we should see on average higher pricing in the fourth quarter.

Operator

Our next question comes from the line of David Snow with Energy Equities Inc,

David Snow - Energy Equities Inc

I'm wondering in the new reserve regulations, how many offsets in the Bakken might you show for every one that's been put on, compared what the experience was last year?

Lance Langford

David, this is lance. Well last year's rules were you could only book two offset PUDs to every PDP. The rules are more broad this year that you could actually book as many as eight. I think the guidance that we're getting, it depends, you have to look out on a well by well basis, but I think it's going to be two to four wells PUDs per PDP.

David Snow - Energy Equities Inc

If I took the midpoint a 50% increase, then that would be improved reserves?

Bud Brigham

You probably can't simplify it that much because you really need to look at the Bakken reserves and the Bakken, we were booking two offsets. It sounded like we'll be able to book four offsets and also at yearend you had $45 oil prices and with the old booking methodology at use, the offsetting technology, even if it was not the technology you're using today. For example, single fracs versus multi-stage and today we can use the multi-stage. So there's a lot more complexities, but clearly we're going to get a lot more credit for reserves that we believe we've proven up around our discoveries.

David Snow - Energy Equities Inc

That will be for the 1P reserves.

Bud Brigham

Yes.

David Snow - Energy Equities Inc

What will be the difference in 2P?

Lance Langford

Well, we didn't report 2P last year, so there is no reported 2P. I also want to mention on the 1P reserves, we had had very little Bakken booked in last yearend's reserve report. So you can't just increase it 50%.

So the 2P, we don't have a number. We're working on that. We haven't even made the decision that we're going to report 2P, but we are trying to work the numbers, so we'll have it in case we decide to report it.

David Snow - Energy Equities Inc

Then on your 1280 spacing concept, what acres does that not apply to? I suppose it would by default apply to everything else.

Bud Brigham

Most of our acreage will likely be developed on the 1280s. The exception is largely, correct me if I am wrong Jeff. That was largely locations that have already been permitted and set up to drill on 640. So they might be stranded at some others.

Lance Langford

There's a few stranded sections that are some 640s which we're trying to actually rectify and respace. And then our non-operated Parshall/Austin acreage that EOG is developing.

David Snow - Energy Equities Inc

I guess overall do you feel you're getting optimal, not just economics, but reserves per 640s with the three per 1280 layout, or do you think you may go more densely as you go through time?

Bud Brigham

Our gut feel is that we're going to be able to drill and Lance may add to this, three wells across each production unit. Some think maybe even four, but we think three is very reasonable. If you look at it, it's already many of the tracks already have three wells across each unit and there's better permeability over there. So we think that's pretty safe projection. Of course in the booking right now, we're only going to be booking one well per unit and then whatever they'll give us on PUDs, maybe four offsets per well, per unit. So there's obviously going to be different levels of incremental reserves adds in booking as we book infill locations. Lance do you want to add anything to that?

Lance Langford

That will come over time. In our areas, where the guts of our acreage is we don't have any examples of where you've got two wells in the same unit. So over time, that will occur and so you'll take a big reserve growth at some point when you go from one well per unit to two wells per unit, then further down the road it will give again, it just keeps on giving. You'll get a third well and you'll prove that up and then you'll prove in a large area, you will go from two wells to three wells per unit.

Bud Brigham

It's an example of the substantial value that is intrinsic in our reserves, if not necessarily reflected in the proved reserve report.

David Snow - Energy Equities Inc

Is there any possibility that simul frac method that's been successful in the Barnett might be applicable here where you lay two simul frac method that's been successful in the Barnett might be applicable here where you lay two pretty close to each other and frac them in stag or simultaneous fashion.

Lance Langford

I really think there is an opportunity for the simul frac to work. Just the problem that we have right now, because of our large acreage position, that we're drilling units to protect them and so it's hard to drill them right beside each other at the same time, at least at this time.

Bud Brigham

At some point, I think that is one of the opportunities down the road, as we get further along and more development mode to optimize and get more efficient, that's just one example. Another example is and other operators are apparently getting ready to utilize it is back laterals, one vertical wellbore with two horizontals for the Bakken and the Three Forks and Lance and the guys were concerned about operation making that happen without too much risk and difficulty, complexity.

But it's looking more and more like it. We've always known it's a matter of time before they can make that happen and it could be some other operators are apparently going to be trying that here over the next several months.

Lance Langford

The stack laterals have been done in the Bakken, but the problem is you can't do the multi-stage completions on both laterals. So, there's some new technology out there that some of the other operators are going to try and do that are going to have multi-stage completion in the stack laterals and one vertical wellbore. So hopefully, they'll be successful. Over time, they will out how to get it done successfully, but hopefully the first operator will be successful.

David Snow - Energy Equities Inc

Has there been any micro-seismic done to determine what your frac reach is in the patterns that pursuing recently?

Lance Langford

We were in a consortium. I don't know if you heard of it. There were quite of few of us with Schlumberger using their technology, but we did a bunch of mapping using micro-seismic and we've determined that frac wings are being grown, probably in the three to 1,000-foot length. But that does not mean that it's across that entire length. It's probably a portion of that. So really I think it's three to 600-foot frac wings.

David Snow - Energy Equities Inc

So does that imply that you have more than three per 1280 spacing opportunity in the future, or is that geometrically work out to about three per 1280?

Lance Langford

I think that just looking at it from a common sense, like Bud said, you look and [M. Cooley], they have three and many of the units there. It's clearly high permeability over there. So we can clearly have three. Our Chief Reservoir Engineer thinks there's going to be a need for four. But right now, we're planning on the design to develop for three.

Operator

Our next question comes from the line of [Joel Musante]. You may proceed.

Unidentified Analyst

I just had a couple questions. What are you modeling for your decline rates on your existing production?

Lance Langford

I don't think we've ever reported that, but it varies by region and I think a 20 to 25% base decline rate on the base production is probably a good decline rate to use.

Jeff Larson

That's obviously a pretty easy forecast to make, given that we've got a lot of production history.

Unidentified Analyst

Okay.

Jeff Larson

Very little risk in us not being able to accurately forecast that production.

Unidentified Analyst

For the wells going forward, is there like a type well that you're using, and, if so, what kind of IP rate is reflected in that type curve, first 30-day IP rate?

Jeff Larson

Well, in our models I think that of course we've been outperforming our models. I think it's about 1,000 barrels a day, first 30 days is 651 BOE per day, but I think its initial rate is about 1,000 barrels a day, and it's pretty steep decline, hyperbolic decline of course. But over the first year we've kind of looked at some side boards and we think it's going to produce 100 to 140 MBOE in that first year.

Unidentified Analyst

Just going back to your previous conversation about well completion recipes in different areas, I saw one firm that reported well costs of about $3.1 million for an 18 stage frac in southern Mountrail County. They were getting pretty good rates. I was just wondering if it made sense maybe to use a different completion in your Ross area?

Lance Langford

Of course, we think that we're using the best completions in each of the areas that we're operating. We of course are always open and looking. I saw that same release and that was a non-operator releasing a cost estimated on somebody else's operated well.

I have a hard time seeing that number. I actually went and looked and I looked at the operators. In fact, I looked at that operator that we got AFEs for similar type completions and they were much higher than that. I'm not sure where that number comes from, but 18 stage if you're using any kind of profane and actually using swell packers and all that stuff would be pretty difficult to do for that kind of dollars.

Unidentified Analyst

Even using a frac sleeve method where you have everything kind of set?

Lance Langford

We use perf-and-plug. I think you can look at some of our poorer wells in multi-stage is using those frac sleeves. We really think perf-and-plug is a way to go.

Bud Brigham

But the price wouldn't save you that much to make that 3.1.

Lance Langford

No, he wouldn't make that difference, but it is cheaper. It can be cheaper. But you really lose I think on productivity and EURs.

Bud Brigham

We have specific examples of that wells proximal to our wells that use the frac sleeves relative to our perf-and-plug that significantly underperformed.

Lance Langford

We used early. Our first well we used it and they're forced wells.

Unidentified Analyst

The underperformance was mainly because of your using more profane that opened the fractures or stronger propane that can hold?

Lance Langford

No, the amount of propane we used was the same. The major difference in those early time wells we used those frac sleeves versus perf-and-plug.

Bud Brigham

Maybe you might talk about briefly why you think the perf-and-plug is superior.

Lance Langford

Basically what happens from the micro-seismic that we shot, everywhere perforated, we can see that we were initiating a frac wing and growing a frac wing and what we've seen over time is like using even a pre-perforated liner or frac sleeve, you go and you try frac zone and you can't get it to take any propane and so you run in there and perforate in an interval.

As soon as you perforate it, it takes frac job and grow the frac wing and you get a good completion. So we are perforating four intervals between swell packers for each stage. We feel like we could be recreating four times as many frac wings as you create using the frac sleeve method. We think we see that in performance.

Operator

This concludes our question-and-answer session for today. I will now turn the call back to any closing remarks.

Bud Brigham

Well, thank you. Again, this is Bud Brigham. We want to thank everybody for participating in our call and we look forward to reporting what should be a very exciting finish to 2009. Thank you.

Operator

This concludes today's presentation. You may now disconnect. Good day.

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Source: Brigham Exploration Co Q3 2008 Earnings Call Transcript
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