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Executives

Bud Brigham - President, Chairman and CEO

Gene Shepherd - CFO and EVP

Lance Langford - EVP of Operations

Jeff Larson - EVP of Exploration

Rob Roosa - Finance Manager

Analysts

Scott Hanold - RBC Capital Markets

Nick Pope - JP Morgan

Ron Mills - Johnson Rice

Marshall Carver - Tudor Pickering

Jack Aydin - KeyBanc Capital Markets

Presentation

Brigham Exploration Company (BEXP) Q3 2007 Earnings Call November 7, 2007 10:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter 2007 Brigham Exploration Company Earnings Call. My name is Stacey and I will be your moderator for today. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today, Mr. Bud Brigham, President, Chairman and CEO. Please proceed.

Bud Brigham

Thank you, Stacey. Thanks to each of you for participating in Brigham Exploration Company's third quarter 2007 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.

Briefly, during this call we are going to make forward-looking statements to help you understand our company's results. In our company's SEC filings and the press releases that were issued yesterday, there were 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, a copy of our company's press releases, as well as other financial and statistical information about the periods to be presented in the conference call, will be available on the company's website under the section entitled Investor Relations at www.bexp3d.com.

We've also updated and will continue to update our corporate presentation, which can be accessed via our website. It includes both our third quarter 2007 results, as well as our plans for the remainder of the year.

Also in the venture following the Mountrail County, North Dakota Bakken Play, there is a map in the presentation that would be very helpful to view, as we describe the exhilarating development of that very active play.

To get started, I would like to summarize the highlights of our progress thus far in 2007, much of which we will discuss in more detail, later in the call. First, our drilling successes have generated a strong year of production growth. Through the first nine months of 2007, our production was approximately 43.6 million cubic feet equivalent per day, up roughly 21% relative to that of the first nine months of 2006. This growth was driven in large part by our continuous Vicksburg drilling program, as well as our success in Southern Louisiana. As a result of our strong production growth, we are on track for record levels of annual production, annual revenues and annual EBITDA.

However, as discussed in our last two operations press releases, we've taken a breather in our Vicksburg drilling program, in order to integrate our new reprocessing with our recent Vicksburg drilling successes. Although our continuous Vicksburg drilling program will resume, this breather is the single biggest factor contributing to the forecasted sequential decline in our Q4 production volumes as the fourth quarter will not get the benefit of our typical flush, high rate, but high-early decline, hyperbolic Vicksburg production.

Other factors include the fact that we aren't forecasting any of our other significant wells to come online in time to materially impact the quarter, the natural decline of our other production, and of course, our recent asset divestiture. All of this creates a pause in our production growth.

However, we have 11 significant wells drilling or soon to be drilling to impact the first quarter. These include the resumption of our Vicksburg rig line later this quarter, our Southern Louisiana wells, and Texas GulfCoast and Williston Red River currently underway, as well as three wells we're currently drilling in Mountrail County, North Dakota, an area that has seen quite a number of high-rate Bakken drilling successes.

We, therefore, expect our production to resume its upward momentum in the first quarter of 2008. And of course, we expect another solid year for production growth in 2008. The second thing I want to summarize is the most important area currently where we need to spend some time updating you on our activity in the Mountrail County, North Dakota.

In this area, we just commenced our first high working interest operated Bakken well, with two more operated wells spudding in the next two weeks. Of course, this is an area where other operators are also accelerating their drilling due to very strong recent results. We will cover some details about this play and how it's developing later.

But in summary, I think you'll see that if you like this play, you should take a look at Brigham Exploration. Our acreage position in this play is currently about 42,600 net acres, and we expect it to grow to about 60,000 net acres by year end. This position, relative to our size, is potentially the most impactful position of any public company in the play, and it exposes us to a unrisked net reserve potential estimated at 27 million to 56 million barrels of oil.

Further, as we refine the new drilling and completion techniques that are working so well in the Mountrail County area, we have another roughly 100,000 net acres west of the Nesson Anticline, providing very substantial additional option value for our shareholders.

With that, I'll turn the call over to Gene to review our financial progress, after which I'll briefly provide more specifics on our performance and our operational plans for the remainder of 2007. Gene?

Gene Shepherd

Thanks, Bud. Starting with the income statement, daily production volumes for the third quarter averaged 43.4 million cubic feet of equivalents per day, a 20% increase in production from that in the third quarter 2006. Despite the September 1, 2007, effective date for the sale of our Anadarko Basin Granite Wash assets, we were still able to generate third quarter volumes that were essentially at the midpoint of our production guidance that we issued in August.

For the month of August, the Granite Wash assets averaged 1.8 million cubic feet of equivalents per day.

Our revenues, net of hedging settlements, but excluding mark-to-market gains on our derivative portfolio, were up 22% to $31.5 million, relative to that in the third quarter 2006. The 20% increase in production volumes positively impacted third quarter 2007 revenues by $4 million. Increased oil and natural gas prices increased revenue by an additional $1 million. Including our hedging settlements, but excluding our unrealized hedging gains and losses, average realized prices for natural gas in the third quarter 2007 increased by 5% to $7.31 per Mcfe, and average realized prices for oil increased by 2% to $73.43 per barrel compared to that in the third quarter last year.

On a per-unit basis, lease operating expense decreased 20% to $0.66 per Mcfe in the third quarter 2007 from $0.82 per Mcfe in the third quarter 2006. A decline in operating and maintenance expense associated with a decline in saltwater disposal, chemical treating, equipment rental and compressor rental expense accounted for the majority of the decrease and was partially offset by higher per-unit expense workovers.

On a per-unit basis, production taxes decreased 38% to $0.24 per Mcfe in the third quarter 2007 from $0.39 in the third quarter 2006. The decrease was due to a $246,000 increase in tax credits associated with high-cost gas production tax abatements. The increase in tax credits is partially attributable to the fact that we're recording credits immediately upon commencing production from our Vicksburg and Mills Ranch wells, given our 100% success rate in applying for credits.

We book credits immediately now, rather than deferring recognition until receiving approval from the relevant government authority. Our per unit general and administrative expense increased 5% to $0.64 per Mcfe in the third quarter 2007 from that in the third quarter 2006 as higher production volumes helped to offset increases in employee compensation and travel expense. Roughly 87% of the increase in compensation expense was attributable to an increase in non-cash share-based compensation expense under FAS 123R.

Our per unit depletion expense increased by 3% to $3.78 in the third quarter 2007 from $3.67 in the third quarter 2006. The higher depletion rate was due to an increase in finding and development costs, incurred in the first nine months of 2007 relative to that in prior periods.

Our higher production volumes and higher realized prices contributed to a 26% increase in the EBITDA during the third quarter 2007 to $26.4 million.

You'll notice on our income statement that interest expense increased in the quarter. Our higher level of debt outstanding and a higher weighted average cost of debt attributable to our April 2007 $35 million add-on to our existing senior notes resulted in a $1.3 million increase in interest expense in the current quarter to $4 million.

And finally, third quarter 2007 adjusted after-tax earnings, a non-GAAP financial measure, which excludes the after-tax impact of non-cash hedging losses, was $4.4 million or $0.10 per diluted share. Third quarter 2006 adjusted after-tax earnings, which excludes the impact of both non-cash hedging gains and non-cash gains on the ineffective portion of our cash flow hedges, was $3.7 million or $0.08 per diluted share.

Please see the financial tables included within yesterday's earnings release for the reconciliation of GAAP net income to adjusted after-tax earnings. Moving to the balance sheet, in September, we closed the sale of our Granite Wash assets, consisting of roughly 5,000 net acres and 47 active wells, all located in Hemphill and Roberts Counties in the Texas Panhandle.

The net proceeds of $35.4 million allowed us to repay our senior credit facility in its entirety and place the remaining funds on deposit. Overall, this transaction provides significant incremental liquidity as we begin to lay out our 2008 drilling plans.

In terms of our leverage statistics, benefiting from the proceeds from the asset sale, we ended the third quarter with a total debt-to-book capitalization ratio of 38% and a total debt-to-latest 12-month EBITDA ratio of 1.65 to 1. At the present time, we have roughly $3 million outstanding under our senior credit facility that has a borrowing base of $101 million, which is limited by the covenants under our senior notes to roughly $90 million.

Covenants under the senior notes require us to use year-end 2006 SEC pricing to determine the credit facility availability for the entirety of 2007. To the extent that natural gas and oil prices exceed year end 2006 prices of $5.48 per Mcf and $61.06 per barrel at the end of 2007, our access to the borrowing base could be enhanced.

In the third quarter, oil and gas capital expenditures totaled $26.4 million, of which $18.8 million went to drilling, $4.5 million went to land and G&G activities, and $2.9 million for capitalized interest and overhead expenses. Excluding the proceeds from the asset sale in the third quarter, we funded close to 100% of our oil and gas capital expenditures out of operating cash flow.

In our earnings release yesterday, we provided production guidance for the fourth quarter. In terms of our expectations for the quarter, we're forecasting production volumes to average between 33 million and 37 million cubic feet of equivalents per day. As Bud stated, this guidance reflects the fact that we think it's unlikely that any significant wells will come online in time during the fourth quarter to materially impact production.

As a result, our forecasted production is a byproduct of the decline in flush production from recently completed Vicksburg wells, decline in our Southern Louisiana production and of course, the asset divestiture.

Given that our Vicksburg program is resuming later this quarter, and given that our current drilling in Southern Louisiana, as well as the accelerating early drilling in our very exciting horizontal Bakken play, we expect our production to resume it’s upward momentum in the first quarter.

In conclusion, we're pleased with our ability to control our operating and G&A costs over the last several quarters. Further, over the last two quarters, we've largely funded the company's oil and gas capital expenditures out of operating cash flow.

Lastly, with the sale of our Granite Wash assets completed for a very attractive price, we have paid off our credit facility and in effect have pre-funded a meaningful portion of our 2008 drilling CapEx. At the present time, we're formulating our 2008 CapEx budget, but expect that our 2008 drilling CapEx, subject to commodity prices, will likely increase relative to our 2007 drilling CapEx.

As has been the case over the last several years, the continuation of what is largely development drilling in the Vicksburg will constitute a significant portion of the 2008 plan, as will the continuation of our drilling program in the Mountrail Bakken. This comes on the heels of our drilling three 2007 fourth quarter Mountrail wells, one of which has recently spud, with the other two expected to spud before the end of the month.

Other focus areas that are expected to constitute a meaningful portion of the 2008 drilling budget are conventional plays in the Gulf Coast and the Anadarko Basin and potentially our Mowry shale play.

As has been the case for our 2007 plan, the 2008 plan will be funded out of cash flow; the availability under our senior credit facility, which at the present time has approximately $87 million of availability; and non-strategic asset sales such as the recently completed Granite Wash sale.

That concludes my remarks, and I will now turn the call back over to Bud.

Bud Brigham

Thanks, Gene. I'm going to be brief in covering our conventional plays, in which most of you who have followed us are very familiar, so that I can spend a little more time discussing the significant amount of activity in the Bakken play.

I'll start in the GulfCoast with the Vicksburg, where we've taken a break from our continuous drilling program since August, but where we plan to resume continuous drilling in December. We have already proposed two additional wells here, and we will be proposing two more in the next several weeks. So, we are about to get very busy in the Vicksburg again.

We're continuing to interpret our recently reprocessed 3D data volume and to integrate this with our recent well results, which have changed our picture somewhat in this area. As a result, we've generated some exciting new ideas here, which we believe provides us with some real upside in 2008. We are also continuing to look outside our existing fields for other growth opportunities in the Vicksburg.

We plan to resume our Vicksburg drilling in December with the commencement of the Sullivan C-38. This well will be drilled to develop the north end of the Floyd Fault Block. The Floyd Fault Block has been the most prolific of the three fault blocks we're developing. In fact, of the 43 Vicksburg wells we've completed in the area, the three most prolific are in the Floyd Fault Block.

Our most recent Floyd Fault Block well, the Sullivan C-33, which was drilled very late in 2006, produced at an early rate of over 10 million cubic feet equivalent per day and has an estimated ultimate recovery of about 10.7 Bcfe. So we're pleased to be resuming our Vicksburg drilling and the Sullivan C-38 should get us off to a strong start as we enter 2008.

Now, I'll move up the GulfCoast briefly to the Frio in Brazoria County, Texas, where we have begun drilling the Randall Unit #2. This well is proximal to excellent Frio production and it has a reserve potential of 15 billion cubic feet equivalent or about 11 Bcfe net to our 94% working interest. This is in an area where we've drilled some of our strongest Frio wells, so it provides us some relatively low-risk, but good reserve and production exposure prior to year end.

Moving further east to Southern Louisiana, as announced a while ago, we unfortunately drilled a dry hole with our Cotten Land #2S2 well. Prior to drilling this well, we believed the risk was not finding reservoir quality sands, but instead, we found plenty of sands -- we thought the risk was not finding reservoir-quality sands, but instead we found plenty of sand and a structurally high, but apparently oscillated fault block that was wet.

Fortunately, the three previous wells we drilled continue to outperform, exceeding the production and reserves reflected in our reserve report substantially. These three wells are currently making roughly 46 million cubic feet equivalent per day or about 10 million cubic feet equivalent per day net to our interest.

We're currently assessing the viability of an additional location in the field. We're nearing total depth on the first of two wells we are drilling in Southern Louisiana with PetroQuest. The Blue Heron #1 should be down soon. It's an exploratory well in the Lake Arthur area, which has generated prolific production. In the same area, we will immediately follow the Blue Heron #1 with the (inaudible), which tests an adjacent fault block.

We hope to get this well down around year end, and on a combined basis, both wells expose us to between 7 billion and 9 billion cubic feet equivalent in net reserve potential. We also have the option to participate in a third prospect following the (inaudible) well.

Moving to the Anadarko Basin Hunton play, we are continuing our interpretation of our process in pre-stack migrated 180 square mile proprietary high-resolution Laker project 3D seismic data. We're very pleased with the early indications. We have an excellent acreage position and expect to drill several of these opportunities in 2008.

Lastly, for the Anadarko Basin, we divested our Granite Wash reserves and acreage, generating net proceeds of $35.4 million. We were very pleased with this transaction. While the project provided a significant inventory of low-risk drilling locations, they were not competitive relative to the rest of our drilling inventory. We will use this capital to supplement our cash flow as we enter 2008.

Lastly, I want to finish up by updating you on our unconventional plays, the Bakken of the WillistonBasin and the Mowry of the Powder River Basin. I will start with the Williston Basin, Bakken. We continue to grow our acreage positions to the east of the Nesson Anticline, primarily in Mountrail County, North Dakota. This area has enjoyed a steady flow of positive well results, including recent strong horizontal drilling successes by EOG, Whiting and several private operators.

I encourage you to view the map of the Mountrail County area in our updated corporate presentation, as we have the key wells spotted, and we have outlines of the general areas to help you delineate our acreage position relative to the accelerating drilling activity. Today, we have been participating with very small working interests as a non-operator, and that has given us the opportunity to see firsthand how the operators are drilling and completing wells in this trend.

As far as our near-term drilling is concerned, we're planning to drill and complete our wells using swell packer technology, single-section laterals and other operational techniques that have generated EOG's strong recent completions in the area. Given what we have learned and the positive results of late in the area, we're very excited to be drilling our first operated Mountrail County Bakken well, the Bergstrom Family Trust. This well is in a good area, roughly 6.5 miles northeast of the Parshall Field and about six miles southeast of EOG's most recent announced discoveries, the Austin #1-02H and the Austin #2-03H wells.

As many of you know, EOG announced that the Austin #1-02H tested at 2000 barrels of oil per day and that they expected the Austin #2 to produce comparably. EOG is drilling a third Austin well near the first two discoveries. We have approximately 170 net acres directly offsetting these wells, so about 27% of the net well. So this acreage is becoming proven and it's likely we will be participating in additional wells offsetting the EOG Austin discovery soon.

In addition, EOG recently permitted another well between the Austin discoveries in the Parshall Field due west of our Bergstrom well. The EOG Austin #8-26H is located about 4 miles south of the two recent Austin discoveries and about 3 miles north of the northernmost Parshall Field discovery drilled to date. We have a minor amount of acreage directly offsetting this well, and our Bergstrom well is roughly 4 miles due east. So activity is accelerating in this area, and if we have the success we expect to have, we will be prepared with additional locations ready so that we can drill another well subsequent to finishing the Bergstrom.

In the next two weeks, we expect to spud two additional operated wells to the west of this area, again, as shown in the map in our corporate presentation. The Bakken 23 #1H is located about 12 miles west-northwest of the EOG's recent Austin completions. The Bakken location is also about 13 miles north of Whiting's accelerating drilling activity. Our third operated well, which will also spud in the next two weeks, is the Hynek 2 #1H, which is located roughly 6 miles northwest of the Bakken.

As shown on our map, EOG has permitted two wells about 4 miles to the north-northeast of the Hynek, and we have acreage directly offsetting these EOG permitted locations as well. We're very excited about both of these locations. We believe that they have similar geologic characteristics to the Parshall Field area. So, it will be a very busy fourth quarter for us drilling in Mountrail County, and we expect to have results for all three wells during the first quarter of 2008. As discussed in our press release, our acreage position continues to grow. Currently, we control about 42,600 net acres in Mountrail County and the surrounding area.

And we expect that by year end, based primarily on pending acquisitions, we will control around 60,000 net acres. Approximately, 28,600 net acres are located in Mountrail County while, roughly 14,000 acres are located in extensional areas where horizontal Bakken wells have yet to be drilled. Our Mountrail County area map in our corporate presentation helps delineate our acreage position and the current activity.

Of our 28,600 acres in MountrailCounty, about 4600 acres are located in eastern Mountrail County in the general area where the Parshall Field and EOG's recent Austin discoveries are located, and this area is outlined on our map in yellow. Although it's early, based on the production performance to date from these wells, we estimate the average gross reserves recovered by these wells will be somewhere between 700,000 and 950,000 barrels of oil.

Assuming 800,000 barrels of oil per well at an 80% average net revenue interest, although in reality the average is probably quite a bit better, provides about 640,000 barrels of oil per net well. If you assume a $5.2 million completed well cost, the drilling in this area appears to generate a potential finding cost of roughly $8.13 per barrel, or converted on a six-to-one equivalent basis, roughly $1.35 per proved developed Mcfe. Given the current value of a barrel of oil, these wells are providing better than an eight-to-one undiscounted coverage, and as EOG has stated, they could be generating rates of return around or even over 100%.

At this point, the economics of this area look outstanding. As discussed in the press release, we control about 4,600 net acres in this area proximal to the Parshall Field and EOG's Austin wells, which provides us with seven to 14 net locations, assuming 640 acre and 320 acre spacing, respectively. So in this area, it appears that we are exposed to unrisked net potential reserves of 4.5 million to 9 million barrels of oil, again, depending on the spacing.

Our remaining 24,000 net acres in MountrailCounty are generally to the west of this area, between the Parshall Field area and the Nesson Anticline, as outlined in red on the Mountrail County map in our investor presentation. The results in this large area have been more variable, probably in part due to different operators utilizing different drilling and completion techniques, but also because it's a large area geographically and there's likely quite a bit of variability in the reservoir quality.

Over the last 12 months, it appears that nine wells have been completed by operators in this area, and it's apparent that the strongest producers are among the most recent wells drilled, which we believe indicates that operators are finding more optimal operational techniques for drilling and completing these wells. Although the numbers will move over time as more wells are drilled and likely with results varying by area, at this point it appears that the average estimated reserves to be recovered by the recent wells in this western Parshall area could be between 400,000 and 600,000 barrels per well.

Assuming the midpoint of 500,000 barrels per well and an average net revenue of 80% implies an approximate $13 per barrel drilling -- finding cost or roughly $2.17 per equivalent Mcfe. Therefore, though the results are likely to vary by area and operators will likely find more prolific and less prolific areas, it appears that the economics of this western area, east of the Nesson Anticline, at least to this point, look very good as well. Assuming the average net recovery of 400,000 barrels per well and 37.5 to 75 net locations on our acreage, depending on spacing, our current acreage in this western area could yield 15 million to 30 million barrels of unrisked potential reserves, depending on whether the acreage could be developed on 640 or 320 acre spacing.

Lastly, we believe that our 14,000 net acres in extensional areas east of the Nesson Anticline have similar attributes to that of the Bakken in the Parshall Field area. Obviously, for competitive reasons, we can't identify where this acreage is. However, we do expect to commence drilling to test these areas early in 2008. With success, this acreage could provide 21 to 43 net locations, depending on whether the ultimate spacing would be 640 or 320 acres.

Assuming a net of 400,000 barrels per well, this acreage provides us with the unrisked potential for 8 million to 17 million barrels of oil. So looking at our acreage position in total, with success, we have the potential to drill 340 to 680 gross locations or 66 to 133 net wells, depending on the spacing. Utilizing the previously discussed assumptions, we believe that we are exposed to an unrisked reserve potential of between 28 million and 56 million barrels of oil.

That being said, it's early, and these potential numbers are based on wells that have been drilled by other operators in various areas. We expect drilling results to vary geographically, and though we think we purchased our acreage in the right areas, we think that there will be sweet spots that provide more prolific production, such as that seen in the Parshall Field area.

Obviously, on the other hand, there will be areas that are not as attractive economically. Further, we want to point out that there's additional optional value in the Bakken beyond the initial expectations and early production performance, particularly when you consider the tremendous amount of oil in place in this reservoir and the associated low recovery factors currently contemplated, even in the very substantial potential reserve numbers I just ran through.

Therefore, the Bakken provides very meaningful long-term option value via future opportunities, such as those provided by improved drilling and completion technologies, refracing, and of course, higher oil and gas prices.

As I said early in the call, all things considered, if you like this play then you need to take a look at Brigham Exploration. Given our size, we believe we have the most impactful position in the play of any public company, and we have attached a slide to our presentation to help illustrate that.

One last comment on the Bakken, which I also alluded to early on, currently higher oil prices and the technological advances that are having such a positive impact on Mountrail County have made us more positive about the approximately 100,000 net acres we control west of the Nesson Anticline. At some point in 2008, we or one of our competitors will test these technologies, including swell packers, west of the Nesson Anticline. Obviously, our very large acreage position there provides us with additional and very substantial option value.

Before I move out of the WillistonBasin, I should also mention that we're drilling the Richardson 25 #1 in Sheridan County, Montana, with Northern Oil and Gas. We have a 90% working interest in this well, which targets the Red River and the Mission Canyon. It's in an area that has generated good Red River production, including a well we drilled in the 1990s that will produce over 300,000 barrels of oil.

We have a large 3D data set here and a number of other prospects to pursue. So we have other plays to pursue on our acreage in the Williston beyond the very active Bakken play.

Lastly, I will finish up by briefly updating our activity in the Powder River Basin Mowry shale play. There are a number of differences between the Williston Basin Bakken play and our Powder River Basin Mowry play, and one of them is the number of operators active. Unlike the Williston Basin Bakken play, where we have benefited from numerous operators who have been drilling horizontal wells and experimenting with various drilling and completion techniques, to date we have been the only operator in the Mowry making a meaningful effort to figure out how to drill, complete and produce the substantial amount of oil in place.

However, that is slowly changing. There are a few operators with drilling either underway or plans for the Mowry in the Basin. For example, one private operator with whom we've had fairly extensive discussions, is currently drilling a horizontal Mowry well may prove beneficial to our efforts here.

Without going into the details regarding our four Mowry wells drilled to date, these initial wells have provided us with both encouragement and frustration. So, we're glad to see other operators involved in the play. We are also very much looking forward to applying the knowledge we've gained from our previous drilling and completions, including the core analysis from our (inaudible) well drilled earlier this year and combining that knowledge with the swell packers and the other drilling and completion technologies that are having such a positive impact on the Williston Basin Bakken play.

In the next few weeks, we will spud the Krejci #1-32H, and in doing so we plan to implement the best technologies, including swell packers, and all that we have learned thus far. As you may recall, we attempted to utilize the swell packers on our prior well, the State #1-16H, but we were unable to get the swell packers through the curved section and into the lateral.

Our casing program on the Krejci #1-32H should allow us to utilize the swell packers. We are updating our matrix for current prices, but when you look at it, it's apparent that the higher oil prices have a dramatic impact on the potential economics here. The combination of the shallow depth and the associated lower well costs are real advantages to this play. The Krejci #1-32H is a significant well for us, and we hope to report a successful completion during the first quarter of 2008.

Lastly, as I mentioned on our last call, we may add another potential resource play. Given that we have two unconventional oil projects underway, it's more likely that our next project would be gas. We're currently developing other potential resource, large-scale drilling projects. Given how competitive some of these are, we might not disclose some of them until we've drilled at least one proof-of-concept well. That completes our operational review.

In closing, thus far in 2007, we are on track to achieve record production volumes, record revenue and record EBITDA. Although we have had a several-month lull in our drilling program, including a pause in our continuous Vicksburg program, that's over, and we're now very busy in the field, with 11 significant wells either drilling or soon to be spud.

We expect our drilling activity to generate a resumption of our growth in production volumes during the first quarter. More importantly, our year-end drilling in the Bakken and the Mowry has the potential to very materially impact our growth in shareholder net asset value, potentially providing us with the multi-year inventory of predictable, low-risk and attractive rate of return resource projects that we've been looking for.

That concludes our call. I'd like to thank everyone for their participation. We very much look forward to reporting on our fourth quarter results. In the meantime, we'd be happy to answer any questions.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed.

Scott Hanold - RBC Capital Markets

Good morning.

Bud Brigham

Good morning.

Scott Hanold - RBC Capital Markets

On those Granite Wash assets you sold, you sold it for, what, $35 million, I think you said? What was the reserves attributed to that sale?

Gene Shepherd

At the end of the year, end of '06, I guess, correct me -- it was about 13?

Bud Brigham

About 13 Bcfe, and at the time of the sale, it was a little over 16 Bcfe.

Scott Hanold - RBC Capital Markets

Okay. Thank you. And so what had your activity been there? Remind me. Have you been doing much there? If I remember right, it's an area you liked when gas prices are high, but it did become challenged when they did sort of dip in this, say, sub $7 level. Is that a fair statement?

Bud Brigham

I'm sorry, Scott, we have one correction on the number we just put out there, and Gene, if you don't mind repeat it them.

Gene Shepherd

At the time of the sale, the Granite Wash was 23 Bcfe. So 13 at the end of '06 and 23 at the time of the asset sale.

Bud Brigham

So, I'm sorry, Scott, if you don't mind summarizing that question, we would --

Scott Hanold - RBC Capital Markets

I guess taking a look at your activity there, can you can give us a sense of what you had been doing prior to the sale there? And if my memory serves me right, and correct me if I am wrong, you thought that area sort of was challenged when gas prices were below $7?

Bud Brigham

That's correct, Scott. This is Bud. I'll start, but these guys may want to add to what I say. But yes, we drilled some real nice wells during the course of 2006. That, I think, proved up additional opportunities out there, but it's a higher operating cost play that in a sub $7 price environment, the locations are certainly not competitive and become marginal, but a nice option value and higher prices. And just when we looked at it relative to our other projects, they were not competitive. The rates of return were not competitive. And so we did not foresee an active drilling program in there, given our other inventory. So it made a lot of sense for us to divest it to another operator who had a lot of expertise in that area and was active.

Gene Shepherd

And one other comment, I think it's an area where it requires some scale and the benefits from scale and getting out and drilling a lot of wells and bringing on a lot of wells onto production and the scale in terms of operating costs, the benefits from scale in terms of operating costs. For example, one of the reasons our operating costs were down in the third quarter was that we closed the Granite Wash asset sale on September 1. So there was some very slight benefit we saw in terms of operating costs. And we will see, in this next quarter obviously a bigger benefit from having sold those assets and really getting rid of the associated higher operating costs.

Scott Hanold - RBC Capital Markets

Okay. Thank you, that's good. Kind of moving up to the Bakken, obviously, Bud, you gave a pretty good overview here. You've answered most of my questions, but just kind of a clarification on one point. I guess you're looking to expand your acreage position. Can you give us a little insight into -- is there much more to pick up there? Again, how do you guys think you're going to be able to add additional acreage there? I know it's becoming very competitive, given where oil prices have been and what results to date have been?

Bud Brigham

Scott, this is Bud. I'll start and Jeff may want to add to it. But, basically, in Mountrail County, if you're not already on the ground, it's pretty much done. We're picking up -- we have guys on the ground and we have a lot of going concern there, so we are picking up some small tracts, additional acreage in Mountrail County. I think that the larger portion of our additional acreage acquired will be in the extensional areas that we, having been out in the play early and done a lot of mapping, we're really excited about it.

We think they have the key attributes comparable to the Parshall area that provides excellent potential. So, I would expect going forward that, but we do have a lot of pending acreage that's going to coming in Mountrail County that gets us up around that 60,000 net acre number. Growth substantially beyond that would primarily be outside of that area. Jeff, do you want to add anything to that?

Jeff Larson

I would just add quickly that in the extensional areas, we do see what we view are similar potential geologic attributes to some of the success that's been happening in Mountrail. And we hope to report in early '08 that we have established a couple of nice blocks in different extensional areas, which really give us some option value.

Scott Hanold - RBC Capital Markets

Okay. Yes, we would be very interested to see those results, and we probably should hear about, what, the first quarter, I guess you said?

Bud Brigham

I think so. I mean, all three wells, I mean, the Bergstrom is at 6,000 feet or so, and it's still, I think, likely that the most significant news, of course, will be subsequent to production testing. And so I think first quarter is probably reasonable for all three wells.

Scott Hanold - RBC Capital Markets

And Gene, I think when you talked about potential '08 CapEx allocation -- you indicated Vicksburg was going to be a focus and obviously potentially the Bakken. You didn't really say much about South Louisiana. Can you give us a little bit of color there? Obviously, success in the past 12 months has been pretty good there. Is it, sort of, you are just looking at where you can invest capital to get your better rates of return, or is it prospectivity driven? Can you kind of give us a little bit of color there?

Gene Shepherd

Well, it's going to be meaningful. It's going to be a meaningful part of our budget. Let me just say upfront that we're just trying to give you some sense as to where we might be spending capital next year, but we haven't presented any of this to the Board yet. So that's why we're being a little bit vague. But we've had a lot of success recently.

I guess, I don't know, Jeff, if you have anything to add in terms of constraints there. Obviously, we're trying to add to our inventory. We've been looking at a number of opportunities, and certainly the wells that we're drilling are going to have a -- could, if they're successful, have a positive impact on that inventory.

Jeff Larson

Yes, I think that's right. We've got a number of ongoing discussions with South Louisiana operators. We're trying to align ourselves with experts in the trend. I mean, clearly, as you look parish to parish, South Louisiana can be extremely variable, and I think it behooves companies to try to position themselves with experts. And then in the Frio trend, we've got a number of prospects in inventory in the Frio that we're actively selling down to the industry.

And as we sell these prospects down, the economics get stronger and stronger. You will see us have Frio activity in '08. A lot of it will be not as much CapEx exposure for our company, but it will give us some nice upside.

Scott Hanold - RBC Capital Markets

Okay, thank you. And one more and I'll let somebody else jump. But I think, Bud or Gene, one of you said, I think, in the [well past drilling] area, I think you said the wells on a gross basis are around 46 a day, if I'm not mistaken, 10 net to you all. Now that they're in decline, where do you think we will be, say, six months from now on those wells? What is your sort of projection at this point?

Bud Brigham

Hi, Scott, this is Bud. What we're doing is, it should be updated now or within the next hour or two is, our production graphs by play, where we've got the Vicksburg and south Louisiana and the Hunton broken out. And you can see those, as I said in the conference call text, that those wells are significantly outperforming our expectations on production. And as you said, they are producing the three wells, 46 million a day gross and about 10 million a day net.

So, they are on a decline, but it's not nearly as steep as what we had anticipated, and we are going to get -- it's going to help us on reserves here at year end. I think you can look and see the visible decline there. The down dip wells have not, to our knowledge, started cutting water. And we will get some heads-up on that prospect with those wells being significantly down dip, 250, I think, to 320 feet down dip. And so we'll get a real heads-up before that might happen, which it may not happen.

And if so, you can take that decline that you see there and project it out and see where you might otherwise expect it to be. One other thing, Scott, to remind everybody about is that the reserve loss for the [inaudible] will be extended because we are producing some 30 feet of pay and that well is making, I believe it's 21 million cubic feet per day, and we've got 50 feet of pay right up above that has yet to be produced.

So, when that well, does ultimately complete, we will be completing that zone, and so that will stretch out the production profile for that well.

Scott Hanold - RBC Capital Markets

Okay. Thank you, guys.

Bud Brigham

You are welcome. Thank you.

Operator

Your next question comes from the line of Nick Pope with JP Morgan.

Nick Pope - JP Morgan

Good morning.

Bud Brigham

Good morning.

Nick Pope - JP Morgan

Something you all could clarify a little about the timetable on the Mowry so that -- with that next well, what kind of timetable you will look at to see production and then I guess for 2008 were you thinking about for a potential number of wells there looks interesting?

Bud Brigham

Well, the Krejci well, Jeff, do you want to take that?

Jeff Larson

It looks like the Krejci well -- that's the 1-32 -- should spud. We're looking at probably a couple of weeks. And obviously that's a real important well for us, Nick, and we're trying to bring in some of the technologies that are being employed in the Bakken, the swell packer technology. We're set casing through the current section, which should prevent us from stacking it out. So, we're definitely using best practices there. We also took a core in the [State] well. We've done a lot of earth model rock mechanics, some real hard engineering and G&G analysis on that well, and that has been very enlightening to us.

We're actually changing the azimuth direction on our wellbore. So, we are actually going to drill in a different azimuth on our horizontal well. So we are very excited about that. So we're definitely trying some new things. And clearly, with success there, I think you'll see us drill a number of Mowry wells in '08. I think maybe if we're not as successful, we will probably scale back the program and maybe potentially look to the industry.

Bud Brigham

I think we still remain encouraged, though, as I mentioned on the call, we have of course been frustrated by our prior wells, the different things that we have tried and had real encouragement at times, and then we had the formation collapse from the open hole in the Krejci that was doing so well. So, I think part of the pain is that we've been the only operator trying to figure out how to plumb the oil in place out there, and it's great that we've got some other operators getting active, and hopefully Abraxas will be drilling some wells here soon.

But we're real excited about applying the swell packers here and having the opportunity to aculeate the fracture stimulation over these various intervals. And I think this will be a really important test for the company. One thing is, when you look, it's pretty surprising when you look at the updated pricing, the kind of impact that that has on the economics. The bar keeps getting lower and lower where we need to get in that play for that play to be viable and to deliver attractive rates of return.

So, we are updating the matrix on our website, and you can take a look at that, and you can see that if we get 50 to 100 barrels a day, we've got an economic well there, and of course north of that, just better rates of return. So, we are cautiously optimistic that this well will be a key well for us.

Nick Pope - JP Morgan

All right, thanks. And jumping around a little here, it sounds like you are moving back into the Frio a little bit. Can you give a little more detail on like the number of prospects you will have, in this area in BrazoriaCounty with the Frio?

Jeff Larson

The Frio obviously is a play that extends probably six or eight counties. A lot of the activity in the last several years was actually further down the coast in Matagorda, Calhoun, Jackson and those counties. So Brazoria is back up the coast a bit. It's by Danbury Salt Dome.

Bud Brigham

That's where we had a lot of early success.

Jeff Larson

Excellent -- I mean, the Lower Frio up there has outstanding reservoir quality. And this prospect actually has production in the shallow targets, and we're basically drilling underneath production, which is always a good thing -- traps, work shallow in one of these shallower zones, and the drilling is below that, and we've got about three targets. It's a good-looking prospect. It's got some nice upside.

Bud Brigham

And it's an area where we've drilled some of our better Frio wells, probably three to five years ago, some of our better Frio wells, wells that come on at 2 million to 8 million a day, and with potentially some nice reserves. As we said, the reserve potential of this well is 15 Bcf or about 11 Bcf net. So it can have a nice impact on reserves and production as we exit the year.

Jeff Larson

The second part of your question, we're currently.

Nick Pope - JP Morgan

Of the inventory, yes?

Jeff Larson

The inventory, we've got significant inventory. Remember we've got a number of proprietary 3D data mines in the Frio. We're actively marketing 12 prospects right now to the industry in the Frio, and we're getting good traction there. And again, we've got the opportunity with the way the well [carriers] work and the carriers to casing and the recovery of land and seismic dollars to really not expose ourselves to much capital of these wells, but with some real nice reserve upside. So, I think you'll see us drill some, certainly some Frio wells in '08, but with just not a lot of capital exposure.

Bud Brigham

Just the way we leverage our CapEx and enhance our rates of return, one of the key wells that we will be drilling in '08 will be our Sunset Reef well, which we're still excited to be drilling. We'll probably keep about 50% in that well, but that's about 140 Bcf target, and so it looks like that's going to be early to mid '08 well for us.

Nick Pope - JP Morgan

All right. That's all I had. Thanks a lot.

Bud Brigham

Thank you.

Operator

Your next question comes from the line of Ron Mills representing Johnson Rice.

Ron Mills - Johnson Rice

Good morning.

Bud Brigham

Good morning.

Ron Mills - Johnson Rice

Just a one follow-up question on the Bakken. The partial Austin area, the 700,000 to 900,000 barrels of potential reserves, matches what I think EOG said on their call. The areas to the west of that area that you used the 400,000 to 600,000 barrels of gross potential per location, is that based off of well results from companies like Whiting and Continental, or how was that number arrived at?

Bud Brigham

Yeah, Ron. Let me first, this is Bud. The Parshsall area, we did our own reserve analysis of all the wells that have been completed out here and are producing, and EOG's number that they have quoted has been 900,000 barrels gross, 700,000 barrels net. So, primarily because we didn't operate and are not in those wells, we maybe using a broader range on that, 700,000 to 950,000 gross, so 640,000 is a midpoint net. And anyway, but we came out -- generally, when we look at the production curves agreeing with their number in that East Parshall area.

To the west, we also looked at all the wells. There's nine wells to the west of it in that West Parshall area. And looking at the profile, there's more variable, because you are geographically dispersed with different operators using different techniques. It is wells drilled by Whiting, wells drilled by Petro-Hunt, wells drilled by Hess, and probably a couple other operators that I can't recall right off the head. But, so we've got historical production data and did a decline curve analysis on those, and that's why we used that number that I talked about, I think 400,000 to 600,000 barrels, with 500,000 being the midpoint, and our actual number that we came up with using decline was a little bit better than that midpoint, and it's been moving up as we get more history on those wells.

But there is quite a variety on those wells and there are some that are just really outstanding and some that are not as good a producers, and we think the area is going to be quite a bit variable.

Ron Mills - Johnson Rice

Okay. And on the Vicksburg, it sounds like you're going to restart your drilling program there in December. Can you walk through, kind of like you've done on the Frio, what some of your inventory is in that area? And I know you've had a relationship in the past with Exxon in terms of farm-ins. Is that another potential area of growth?

Bud Brigham

Yeah, Jeff will take this.

Jeff Larson

Hi, Ron its Jeff. I think you'll see us continue to develop the fields. There is activity that you'll see in Home Run Field in 2008. Remember, that's the field to the west. And obviously, this Floyd Fault Block, we're real excited about the new interpretation. It's really opened up the fault block, and we think there's, opportunities for multiple locations in the Floyd Fault Block. We really like to look at what this new processing is showing us. And as you go to the east, Triple Crown, clearly you'll see us drill some additional Triple Crown wells in 2008. And also, in these extensional areas that Bud has mentioned, we're starting to get some traction. You may see us drill a well or two in some Vicksburg areas you may not have heard of before in 2008.

Ron Mills - Johnson Rice

Okay. And then Gene, just a couple of quick ones for you. The fourth-quarter production guidance being lower, do you know how much of that is related to just a slowdown in your Vicksburg activity versus either natural declines or risk production from that last well in south Louisiana?

Gene Shepherd

We have broken it down, and about 12% of the decline is asset sale, and then the Vicksburg piece, which is a combination of not bringing on new wells and the plans we're seeing in the Vicksburg are roughly 36%, somewhere in the 35% range, and then somewhere in the 30% range, what's left is, another component of that is southern Louisiana, which might be in the neighborhood of 30%. These are sort of ballpark numbers.

Ron Mills - Johnson Rice

Right.

Gene Shepherd

And the remainder is just sort of normal declines that we're seeing in the base production.

Ron Mills - Johnson Rice

Okay. And how quickly from a production contribution standpoint from the drilling activity that starts up in December do you expect to be able to return to that sequential growth? In other words, are we looking at -- is first quarter going to be a time that you can expect some growth, or is it going to be more or later first quarter and into the second quarter, before you really have the startup of the Vicksburg program again really start to hit?

Bud Brigham

Ron, really -- it's Bud -- it's not just the Vicksburg. I mean, we've got 11 significant wells that are drilling or that will be drilling here by the end of the quarter that will impact the first quarter. And it's really unusual that this quarter, the fourth quarter that we didn't have any material -- or we're not forecasting, anyway, any material wells to impact the quarter.

So, in terms of that Vicksburg decline, you're seeing that plus Vicksburg decline net amount that Gene talked about, 31%, plus not having new wells coming online in the Vicksburg to offset that.

So, the lost production in the quarter for the Vicksburg is more significant than the net volumes in the decline, as the production we would have brought on. But it’s 11 significant wells that we are drilling that will impact the first quarter, so that's a lot of material wells. It's commencing the C-33, a Floyd well, which has been -- where we've had 10 million a day wells come online, and that well should be online to impact part of the quarter.

But it's also the southern Louisiana well that's currently drilling. It's a [Randall] that's in a great producing area for us in the Frio that's currently drilling. It's the three Bakken wells that will be drilling and the Mowry well should contribute as well. We've got a West Texas well that is [a spud] that is drilling. So, when you add them up, there's 11 total wells that will impact.

Ron Mills - Johnson Rice

The Red River wells?

Bud Brigham

The Red River wells and Williston.

Jeff Larson

Hi, there Ron, its Jeff, just real quick also, Bud mentioned it in the prepared text, we're also positioning for success in the Bakken. We've got, if you look at our slide that we've got on the website, with success in any of these three areas that we're drilling in the Mountrail County, we're positioning to quickly be able to move rigs and drill offset wells.

Bud Brigham

So, specifically on your question, I think, Ron, clearly the production should be up from the fourth quarter to the first quarter. How much it is will depend on the timing of all these wells coming online.

Ron Mills - Johnson Rice

Okay and then finally, Bud or Gene, just on the 2007 versus 2008 capital, you spent roughly $90 million year to date. What are you planning on spending in the fourth quarter?

Gene Shepherd

Well we are not -- we haven't really updated our budget. I think what we were talking about at the beginning of the year was $114 million, $115 million of total CapEx for '07, and I think roughly $91 million of that was going to go towards drilling CapEx. So it's going to be in that neighborhood. There's going to be -- you're not going to see a significant variation from what we announced at the beginning of the year. Obviously, the mix is going to change.

Ron Mills - Johnson Rice

Okay, and then given your comments, it sounds like you'll probably increase your capital budget next year relative to this year, and the availability that you have on your borrowing base and the expected cash flows -- do you all see that getting you all through the 2008 program?

Gene Shepherd

Yes. If you just take -- we currently have almost [$90 million] of availability under the credit facility, if you put that aside for a second, just based on the production -- you just take the guidance for the fourth quarter, and I think you can back into a roughly $15 million cash flow number and annualize that at [$64 million], $50 million to $60 million of cash flow, and then add the proceeds from the Granite Wash asset sale, you are approaching $100 million, and that's without dipping into the incremental availability under the credit facility that existed prior to the Granite Wash sale.

Ron Mills - Johnson Rice

And that excludes any sequential growth from a production standpoint?

Gene Shepherd

Obviously, that's a function of the guidance we issued yesterday. We issued guidance based on the current pricing environment, and obviously prices will have an impact on cash flow.

Ron Mills - Johnson Rice

Right.

Gene Shepherd

So, I think we're in a good position to see an increase, and how big of an increase will be a function of commodity prices and what kind of impact we see from -- certainly a big impact from the current very high level of activity in the deal. There's some other, certainly nothing in the magnitude of Granite Wash, but there's some other asset sales that we went to market with late, probably a couple of months ago that could generate some nominal dollars.

And again, a lot of the Granite Wash and those transactions, we embarked on those transactions because we were concerned about the stock price and at the same time wanted to be in a position to increase our drilling CapEx in '08. So in effect, we were looking at the asset sales as sort of a source of equity capital to balance the availability under the credit facility.

Ron Mills - Johnson Rice

Okay. All right, thank you guys.

Bud Brigham

Thank you.

Operator

Your next question comes from the line of Marshall Carver with Tudor Pickering. Please proceed.

Marshall Carver - Tudor Pickering

Yes. Good morning. I had a few questions for you. On the fourth quarter production number, it's a pretty wide range. What would cause you all to be at the high end versus what would put you all at the low end?

Bud Brigham

This is Bud. It's just timing. It just depends on the South Louisiana well getting done and coming online. It's just the timing of these wells late in the quarter, and if some of them do happen to impact. Also, there's potential in South Louisiana to put those wells, in fact, I think Gene was talking about putting those wells on compression.

Marshall Carver - Tudor Pickering

Okay.

Bud Brigham

Obviously, if we get those wells on compression, you're going to see a real bump-up in the rate there. We're refracing some wells here and there. So there's a number of primarily of workovers Bayou Postillion compressions and things like that that could have an impact on it.

Marshall Carver - Tudor Pickering

Okay. Any feel for F&D costs for the year? We're 80% of the way through the year at this point, so any feel for that?

Bud Brigham

No, Marshall. A lot is really happening right now. You look in terms of we've had some good results, when you look at the potential non-developed impact, a lot of it's happening here in the fourth quarter. And of course, a couple of big exploratory wells, these two exploratory wells with PetroQuest in South Louisiana, the Randall would a be nice reserve add for us. That's a pretty low-risk shot, gives us a good opportunity. Of course, in the Bakken, we're adding reserves. Other operators are proving up reserves for us, and of course our three wells are very significant, as is our Mowry well. So, a lot's happening in the field for us right now in that area.

Marshall Carver - Tudor Pickering

With the Bakken wells probably not reaching TD until after year end, I guess those would not be part of the reserve report, right?

Bud Brigham

No, Marshall, those reach TD by year end, and we will be completing them right about that time. So they should get in the reserve report. It's just unlikely we'll have definitive results to report to the market till we get a reasonable production test on it of some duration.

Marshall Carver - Tudor Pickering

Right. You've talked a lot about these Bakken wells and are very optimistic out there. What do you think are the biggest risks? Is it geological or completion, or what would be the most likely forces if you didn't have a 750,000 barrel well?

Bud Brigham

Marshall, this is Bud. Maybe I'll stop, and Lance and Jeff may want to add to it. The great thing about this place, you're not going to drill a dry hole. I think in these two areas that we are drilling, you're going to make commercial wells. If you look in -- one thing I should've mentioned earlier, if you look at, for example, that West Parshall area, the EOG has kind of been out in front, in our view, as far as how to drill and complete these wells, as evidenced by the improvements they've seen using the swell packer technology and drilling the single laterals.

And we think if you look at that West Parshall area, a lot of that technology has not been implemented, but technology is improving, and that's why the recent results have been stronger for wells over in that area. So, I think the probability is extremely high that we're going to make good wells here, in my view. It's just my view. And the question is how good will they be, and I would think -- Lance, you guys tell me, I would think the biggest risk factor might be operationally. What do you guys think?

Lance Langford

Well, I think operationally, I really don't think it's a big risk. I think there is some risk. There always is when you're drilling new type wells in new areas. But I personally just think the risk is what is the range of the reserves per well.

Marshall Carver - Tudor Pickering

What do you think the good wells that are 700,000 to 900,000 barrels, what would be the lower end?

Bud Brigham

It's hard to say. I mean if you look, based on our -- it's early. We don't have a lot of history, but wells that have come online in the last 12 months or so in that west area, it looks like they are about 500,000 barrel wells on average. But you've got a big spread. You've got some 1 million barrel-plus wells and then you have some wells that are poor performing, which, by the way, generally the wells that were poor performing are right over by the Nesson and probably not using, or it appears to us they're not using a lot of the latest drilling and completion technology.

So there's a big variability, and it looks like to us that the technology being utilized is a big differentiator in this play. So I would think, to answer your question, I would think that 200,000 to 300,000 barrels might be kind of the lower end of expectations, and 200,000 would certainly be disappointing for us. Jeff, Lance, I don't know if you want to add to that.

Lance Langford

I think if you go back and look at some of the poorer areas and using the poorer technology, you're kind of looking at a baseline of 100,000 barrels, and moving into an area that's obviously better using better technology to complete the wells, I think you could expect a multiple of that.

Marshall Carver - Tudor Pickering

Okay. That's very helpful. Thank you, guys.

Bud Brigham

You are welcome.

Operator

Your final question is from Jack Aydin with KeyBanc Capital Markets. Please proceed.

Jack Aydin - KeyBanc Capital Markets

The benefits of being last is that every question has been asked. That's okay. My question to you, Bud, is this -- I see you participated with EOG in the Parshall sales with about 1.3% working interest. I assume I am correct on that?

Bud Brigham

Yes, we have a very small working interest in Horizon, which is a successful EOG well, and we have 1%, and it's comparable to the other Parshall Field wells in the area.

Jack Aydin - KeyBanc Capital Markets

My question to you is this, are they sharing with you all the information and you have a window -- you have a look on everything they do?

Lance Langford

Jack, this is Lance. I can't say that they are sharing everything, because we don't know exactly what everything is, but we do have an interest in the well. Our operations people in drilling and completion are talking to their people that are actually doing the drilling and completions. We've drill acted there, sharing the information on the well that we have an interest in, because we have the rights to that information.

So, we think they're freely sharing that information. As far as the operational side, we also have all the service companies. Although they won't tell you who is doing what, they will tell you what is being done successfully in the area. So I think we have a really good feel. We also have a partner that we are sharing information with, has a lot of interest with the EOG in multiple wells, and they're getting a lot of information. So I think there is a lot of sharing going on between everybody out there.

Bud Brigham

I might add just a couple of things to that. I mean, basically, we're using the same service with the same service contractors out there. And for example, the well that's drilling in the Bergstrom Family Trust, just drilled a well for our partner, Hunter Oil, in the north end of the Parshall Field, with the same techniques, using the single laterals and the swell packers. So I think we're going to be going about this essentially the same way that EOG is.

Jack Aydin - KeyBanc Capital Markets

Did you run a 3D on your acreage?

Bud Brigham

No. We have a lot of 2D seismic that we're utilizing pretty extensively out here. I think at some point we will probably be shooting 3D out here, and we think that would be helpful. But fortunately, we have key 2D lines along the profile that we needed to orient these wells.

Jack Aydin - KeyBanc Capital Markets

Okay. Well, I appreciate it. Thank you.

Bud Brigham

Thank you.

Operator

There are no further questions in the queue.

Bud Brigham

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

Operator

Thank you for your participation in today's conference. This concludes your presentation. You may now disconnect, and have a good day.

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Source: Brigham Exploration Q3 2007 Earnings Call Transcript
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