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Executives

Bud M. Brigham – Chairman, President and Chief Executive Officer

Eugene B. Shepherd Jr. – Chief Financial Officer

A. Lance Langford – Executive Vice President, Operations

Jeffrey E. Larson – Executive Vice President, Exploration

Rob Roosa – Finance Manager

Analysts

David Heikkinen - Tudor Pickering & Co.

Joseph Allman - J.P. Morgan

David Snow – Energy Equities Inc.

Ronald Mills - Johnson Rice & Company

Chad Potter - RBC Capital Markets

John Gerdes – SunTrust Robinson Humphrey

Monroe Helm - Seem Energy Partners

Brigham Exploration Company (BEXP) Q2 2008 Earnings Call July 30, 2008 10:00 AM ET

Operator

Welcome to the Brigham Exploration second quarter conference call. (Operator Instructions) I will now like to turn the presentation over to the host for today’s conference, Bud Brigham, Chairman, CEO and President.

Bud M. Brigham

Thanks to each of you for participating in Brigham Exploration Company’s second quarter 2008 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 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 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 partially updated and will continue to update our corporate presentations which can be accessed via our website. It includes both our second quarter 2008 results as well as our plans for the remainder of the year. It also follows the venture of the Williston Basin Bakken/Three Forks Play in detail. There are some of our updated maps in the presentation that would be very helpful to view as we describe the accelerating drilling in the Bakken Play. We hope to have more updated information in our presentation soon.

Let’s get started. Today, we’re going with a little different format to give you more time for questions. All of my comments will be upfront. I will provide you with brief introductory comments and then I’m going to update you on the Williston Basin Bakken/Three Forks Play.

We have had very strong drilling results thus far in Vicksburg and southern Louisiana. Those areas were covered fairly thoroughly in our press releases.

After my Williston Basin operational summary, Gene will then give you a review of our financial results for the quarter. Following this, we will be happy to answer your questions.

First, we’re having an excellent year with the drill bit with our 100% completion rate thus far. We’ve had three successful wells in three attempts in the Vicksburg, ramping up our Vicksburg production strongly and our first three wells as part of our South Louisiana joint venture were apparent successes. The first of these wells will come online later this quarter and contribute to our substantial production ramp in the fourth quarter.

In our first quarter conference call, I outlined eight milestones for you to help you monitor our success during the year. For the sake of time, I won’t review these in detail but I believe we can put a checkmark by 7 of the 8 thus far. They included success at North Stanley, success with the Mrachek, picking up a second rig to accelerate our Bakken drilling, the enhancement of our drilling results in the Bakken through operational improvements, confirmation of the opportunity for increased drilling and early success with our conventional drilling program. I think it’s clear we can check all of those seven off. The eighth can’t be checked off just yet as success with our southern extension of the Bakken won’t occur, drilling there won’t occur until later this year.

Moving to the Williston Basin update, as I said before, we believe we’re the public company most leveraged to the Williston Basin Bakken/Three Forks Play. In my view, these are once in a lifetime plays that every independent wants to be involved in. Remarkably, these two plays appear to be right on top of each other and we’re making the most of it. As a result, to some degree, we’re a company being transformed.

The size and potential of our opportunity in the Williston Basin is vast and difficult to quantify. At this point, we believe the ultimate potential on our growing Williston Basin acreage position is 228 net million barrels of oil, possibly double that for about 450 net million barrels of oil if the Three Forks is as widespread and prolific as it appears it may be. We’ll discuss the components of this reserve potential further during the course of the call.

As announced yesterday, we began the year with our Williston Basin net production at about 100 barrels of oil per day. In June, we produced about 527 barrels of oil per day and today, our Williston Basin production is at roughly 1,500 barrels of oil per day.

We have several significant wells being completed and other potentially impactful wells drilling. This ramp-up has occurred prior to our recently announced drilling acceleration. Our second operated rig begins drilling in September. We should double our operating completions from roughly one gross operated well per month to two gross operated wells per month. Obviously, our participation in third-party operating completions in the play is accelerating as well.

As noted in our operations press release, given current commodity prices, our growing oil volumes generate substantially more revenue and cash flow per Mcf equivalent than do our gas volumes. During the second quarter, a Mcf equivalent of oil generated roughly 75% more revenue than a Mcf of natural gas. Therefore, our current Williston Basin oil production of roughly 1,500 net barrels per day which on a 6:1 conversion is 9 million cubic feet of natural gas equivalents per day would generate revenue comparable to over 15 million cubic feet of natural gas production. Although, we are generally not adding as much in near term Mcfe’s in production per dollar invested with our Bakken wells, we’re adding more revenue and cash flow for Mcfe. In summary, we’re adding more valuable production in this basin with substantial longer reserve lives and we’re doing so very consistently.

I believe it’s become important to frame expectations in the Williston Basin by considering the amount of data that’s accumulated to date in the Bakken Play. At this point, there have been over 160 horizontal Bakken wells drilled in Mountrail County with 26 rigs currently running. That’s a lot of data and it’s happening very quickly. In our view, enough wells have been drilled in the different areas of Mountrail County to say with confidence that the reserves are there for us to drill and produce and that the economics of developing our acreage is attractive.

Given that amount of data, we believe that some reasonable analysis can be generated on the reserves available for us to recover. We also believe that through other operators that at least two wells per section will ultimately be required. We accept this and a reasonable question to ask is how much oil is available for us to develop and produce on Mountrail County?

So let’s start there. In Mountrail County with a partial operating area, where drilling today has yielded officially a 100% completion rate and very high production rates, a large number of which directly offset or are approximate to our acreage. These wells have generally come online at rates in excess of 500 to 1,000 barrels of oil per day but most of late have been substantially higher. Several have produced more than 3,000 barrels of oil to date. In this area, we expect our Kvamme 2 #1H and the Slawson Payara and the EOG Austin 25-35 1H to come online in the next two to four weeks. The Austin Wayzetta 13-01H well is budding in mid-August and it should come online in early October. These wells should have a significant impact on our growing Bakken production.

So let’s attempt to answer the question of how much oil is potentially available for us to develop here. In the Parshall/Austin area, the development of our 8,700 net acres on 320 acre spacing will provide us with 27 net wells for full development. We still believe an average reserve range of between 400,000 and 1 million barrels per well is reasonable for this area, but assuming the midpoint of this range and assuming 80% net revenues, the Parshall/Austin area would provide us with net reserves per broken exploration of just over 15 million barrels of oil.

Staying in Mountrail County, we’re looking at the Ross area. We previously stated that 200,000 to 400,000 barrels per average well provided a reasonable range. However, as evidenced by our most recent wells, our operational improvements may have elevated our results above these levels. The strong production generated by our Johnson discovery and other operator discoveries outside the Ross area makes us comfortable that it’s reasonably conservative to assume the potential of 200,000 to 400,000 barrels average per well range for essentially all of our acreage in Mountrail County outside of the Parshall/Austin area. Given that we control approximately 35,000 net acres outside of the Parshall/Austin area in Mountrail County, this acreage provides us with 108 potential net locations on 320 acres spacing. It therefore appears that we may have the opportunity to develop roughly 26 million net barrels of oil outside of the Parshall/Austin area in Mountrail County.

So the total for the Bakken in Mountrail County assuming 320 acre spacing, we can potentially drill 135 net wells ultimately and develop 41 million barrels of Bakken oil. We are on a 6:1 equivalent basis, 246 Bcf of equivalent natural gas in Mountrail County. As I discussed earlier, given current commodity prices, these oil volumes are significantly more valuable than the equivalent gas volumes.

For our estimated 43,467 net acres in Mountrail County by itself provides us with the opportunity to add reserves equal to about 175% of our entire company’s year-end 2007 proved reserves. Keep in mind, that our Mountrail County acreage as impactful as it is, represents only 15% of our 293,000 net acres in the basin, illustrating our extreme leverage to the play.

We previously discussed our beliefs that the apparent fracturing in the Bakken indicates that the Three Forks interval will also be fractured. Further, we also stated that given that the lower Bakken shelf source rock at it’s very thickest in Mountrail County where the bulk of our acreage is and the Three Forks appears to have the stratographic attributes to work in this area, that we believe the Three Forks provides incremental reserve potential to be increasingly proven in Bakken in Mountrail County.

Well, now and it is happening very quickly, early Three Forks producers, though limited in number thus far, but geographically dispersed through the area, have generated at least comparable but often superior early production relative to the associated areas of the Bakken completions.

A number of key Three Forks wells have recently been drilled around our 27,000 net acres Ross block. On the western edge of the Ross area at the Nesson Anticline, Encore recently announced an apparent 1,100 barrels of oil per day, a Three Forks discovery. A couple of other apparent Three Forks discoveries have been drilled by another operator to the north and the northeast of the Ross area. These two wells are also located to the west and northwest of our North Stanley area. We are awaiting more information on these apparent discoveries.

In addition, on Monday, Fidelity announced a Three Forks discovery flowing 634 barrels of oil per day. The Fidelity Domaskin 11-29H is located in Section 29 of 154N, 92W, just four miles south from the edge of our 27,000 net acres in the Ross area and about seven miles south-southwest of our Adix 25 #1H Three Forks location.

Therefore, we believe there is reasonable possibility that the Three Forks represents another paying horizon with incremental reserves to be developed in this huge and expanding Williston Basin/Bakken field. If that turns out to be the case, assuming we do develop equal amounts of Bakken and Three Forks reserves in Mountrail County, we would have the potential to develop 82 million barrels or roughly 492 Bcf of gas equivalent of reserves in Mountrail County alone. Again, this is only from the 15% of our Williston Basin acreage that’s in Mountrail County.

Recent drilling beyond Mountrail County is beginning to provide the encouraging results we believe we’d see. For example, our recent Mrachek drilling success west of the Nesson Anticline combined with [inaudible] we and other operators grew without the benefit of swell factors and other improved drilling techniques indicates that 200,000 to 400,000 barrel wells could be very achievable over our 100,000 net acres in North Dakota west of the Nesson Anticline.

As we pointed out before, the two prior wells we drilled on this acreage in 2006 without the benefit of swell factors and instead with single fracture stimulation appear to be in the range of 100,000 to 165,000 barrels reserved wells. The Mrachek with seven stimulated intervals demonstrated the enhanced performance we can expect with more stimulation and improved techniques.

We think it’s reasonable to expect improved performance as we go forward such as we’ve seen with our most recent wells, the Johnson and the Carkuff. One of the changes or enhancements that we believe has positively impacted the performance of those two wells is the fact that we stimulated more intervals, ten in the case of the Johnson and twelve on the Carkuff. At this point, it appears that those are easily our best wells.

The next two wells we drill beginning in September in our 100,000 net acre position west of the Nesson will be longer laterals roughly with 15 to 20 stimulated intervals. We believe this 100,000 net acre position in Williams and McKenzie Counties, North Dakota will provide attractive economics for us. Assuming 320 acre spacing, this acreage provides us with another 312 potential net locations. Assuming the midpoint of the 200,000 to 400,000 barrel per well reserve range or 300,000 barrels per well as an average implies that our 100,00 net acres west of the Nesson Anticline in North Dakota has a Bakken net reserve potential of 75 million barrels of oil.

We also have about 100,000 net acres across the state line in eastern Montana which we believe to be equally attractive for Bakken and Three Forks drilling. We purchased this acreage targeting the same attributes we targeted in North Dakota, pairing us with the best middle Bakken dolemite. Thus far, this area has seen almost no Bakken or Three Forks horizontal to date. So that’s about to change. Declair and Continental are currently drilling Bakken wells and permitting Three Forks wells 10 to 15 miles to the southwest of our acreage block. Declair has already completed several Bakken wells with apparent early encouraging results.

Staying with the Bakken and utilizing the stated assumptions for that acreage and combining the two areas, are 200,000 net acres west of the Nesson Anticline provides us with 625 potential locations and a net Bakken reserve potential of 150 million barrels of oil.

For the sake of time, I won’t discuss our two consecutive Red River discoveries and the 16 prospects at least we currently have in inventory in the Red River which should grow once we complete our 3-D program later this year. There are other plays that we are working on in this area as well.

Summing up the Bakken potential on our Williston acreage, assuming 320 acre spacing and 300,000 barrels per well with the exception of the Parshall/Austin area, we are assuming 700,000 barrels per well indicates the potential to drill 915 net Bakken wells with a net result potential of 228 million barrels of oil. Again, the Three Forks potential just below the Bakken represents a potential double-down on these reserves. West of the Nesson Anticline, there has been very little Three Forks drilling thus far, though that’s changing. Continental has recently announced Mathistad 1-35H Three Forks discovery which floated an early rate of 1,095 barrels of oil equivalents per day. It’s in McKenzie County, North Dakota about 25 miles from the southeastern edge of our approximate 100,000 acres in the area.

Looking back at our eastern Montana acreage, Continental has permitted another Three Forks well not far from our acreage block. In this case, they’re evidently planning to drill for the Three Forks with the Johanna 1-32H in Section 32 of 27N, 54E, only about 10 miles southwest of the southwestern edge of our 200,000 net acres in eastern Montana. If the Three Forks does end up being another horizon for development across this huge, expanding Williston Basin field, our reserve potential over are approximately 293,000 net acres in the basin; they will double to roughly 450 million barrels of oil.

Finishing up on the reserve potential, 228 million barrels for the Bakken, potentially double that for 450 million barrels at the Three Forks is the second horizon to exploit over the Bakken field throughout the area is the best guesstimate we have right now. It’s a difficult number to quantify at the current time.

West of the Nesson where we control 200,000 net acres, there is just not much well control at this point to say what the potential is with a great deal of confidence. Ultimately, it could be larger but there is a chance that the Bakken and the Three Forks may not work in all those areas. In that event, it could be quite a bit smaller. The drilling is coming quickly however so, over time, we’ll get a much better handle on the potential in these areas west of the Nesson.

East of the Nesson is a different story, particularly in Mountrail County where we have a large amount of geographically dispersed data points. I believe given the 160 horizontal Bakken wells drilled in Mountrail County thus far, that the 41 million barrels of net Bakken reserves to develop in Mountrail County is probably a pretty good number. In addition, only a handful of Three Forks have been drilled thus far. They’re pretty well dispersed geographically and they therefore provide encouragement that all of this potential in Mountrail County could double with the Three Forks success to a net 82 million barrels of oil.

We are obviously going to be very busy developing our growing acreage in the basin. Given our accelerated operating drilling program and the accelerated pace of the other operators in the play, we now expect to participate in an estimated 56 gross wells in 2008 in Mountrail County.

The total for the Williston Basin in our 2008 drilling program combined with the potential to prove out an estimated 111 gross with 35 net Williston Basin Bakken and Three Forks locations during 2008, hitting us up for a very substantial year for total reserve growth with attractive finding costs. Given the potential 915 net Bakken locations plus the potential provided by the Three Forks, we could be growing reserves in this province for many years to come.

Looking forward to 2009, we’re preparing locations in order to further ramp up our activity. At this point, we fully expect to increase to three operator rigs around year-end and to add a fourth and fifth rig during the course of 2009. Obviously non-operator activity should continue to accelerate as well.

That completes my comments. Now I will turn the call over to Gene to review our financial progress after which we will be happy to answer your questions. Gene?

Eugene B. Shepherd Jr.

For the second quarter, our daily production volumes averaged 30.2 million cubic feet of equivalents per day within the production guidance range that we issued for the second quarter for 2008. Our Q2 production volumes declined 6% sequentially from those in the first quarter and 35% from those in the prior year’s quarter.

The decline in our second quarter production volumes was attributable to several factors. First, the fact that two of our three Bayou Postillion wells were shut-in from April 18 to May 19 due to flooding in the Atchafalaya Basin which accounted for 2.2 million feet of equivalents per day in lost Q2 2008 production, secondly, the impact from our Granite Wash asset sale which closed on September 1, 2007 which produced 1.9 million per day in the second quarter 2007, thirdly, the natural decline in our southern Louisiana Bayou Postillion production volumes, and finally, the transition that the company is going through given the recent allocation of a larger percentage of our CapEx away from our shorter reserve life Gulf Coast prospects in favor of our longer reserve life Williston Basin prospects.

Two additional points, first as reflected in the guidance we issued yesterday, we expect our production volumes to resume their upward trend for the remainder of 2008 with the potential hookup of 4 new southern Louisiana producers to sales in the third and fourth quarters, our improving and accelerating Bakken operator drilling results and the significant ramp-up of our Bakken non-operator activity, particularly in the prolific Parshall field. Second, the transition to a more resource-play focused company is something that we talked a lot about. Our enthusiasm for the Williston Basin and its net asset value creation opportunities is reflected in the updated CapEx budget that we announced earlier in the month.

As we announced on April 15, our Board of Directors approved a $54 million or 45% increase in our 2008 E&D CapEx budget to $175 million from $121 million. In the Williston Basin, our E&D CapEx budget is expected to increase to $109 million from $48 million as a result of our adding a second rig during September, additional anticipated non-operating activity and the continuation of our very significant land acquisition efforts.

As discussed on last quarter’s conference call, the early phases of our drilling CapEx reallocation began in November 2007 away from our Gulf Coast prospects in favor of our Williston Basin prospects. As a result, during the first half of 2008, our Williston Basin drilling CapEx totaled $33.5 million representing 53% of our company’s total drilling CapEx versus 0 Williston Basin drilling CapEx during the first half of 2007. Further, during the first half of 2008, we spent a total of $16.4 million adding to our Williston Basin leverage position which is greater than our company’s total acreage expenditures for all of 2007.

Both of these initiatives have and will create significant net asset value for our company and our shareholders but they do not have the first-year production impact as a comparable investment in our south Texas, Vicksburg, or southern Louisiana drilling programs.

Partially offsetting the impact of the lower first year production volumes, the strong relative oil price has benefitted our Williston Basin drilling results and led to greater revenues per Mcf of equivalent production relative to our gas-weighted Gulf Coast activities.

In summary, as we spent a larger and larger percentage of our capital budget in the Williston Basin, we expect net asset value to be the yardstick that our performance is measured by.

As far as the income statement is concerned, higher commodity prices more than offset the impact from lower production volumes and increased hedge settlement losses during the second quarter resulting in a 4% increase in revenues including hedge settlements to $35.5 million.

Second quarter 2008 revenues were positively impacted by $15.7 million due to a 74% increase in pre-hedge commodity prices. These increases were partially offset by $11.1 million decline in revenues due to the aforementioned decline in production volumes and a $3.4 million decrease in cash hedge settlement gains.

Excluding our unrealized hedging losses but including our settlement gains, average realized prices for the quarter increased by 59% to $13.08 per NCFD compared to $8.24 per NCFD in the prior year’s quarter.

On a per unit basis, our operating expense increased 18% to $0.94 per NCFD in the second quarter of 2008 from $0.80 in the second quarter of 2007. Lower production volumes accounted for the increase in per unit lease operating expense while partially offset by a 23% decrease in the dollar amount of our lease operating expense.

On a per unit basis, production taxes increased to $0.53 per NCFD in the second quarter of 2008 from $0.13 in the second quarter of 2007. The increase in production taxes for the second quarter 2008 from that in the prior year’s quarter relate primarily to a $946,000 decline in high-cost gas production tax payments in connection with our recent Vicksburg and Mills Range wells.

General and administrative expense for the second quarter increased 14% to $2.6 million from $2.3 million in 2007. An increase in employee compensation expense accounted for 64% of the increase in G&A expense while an increase in audit and tax expenses accounted for 31% of the increase.

Our per unit depletion expense increased by 15% to $4.57 per NCFD in the second quarter 2008 from $3.99 in the second quarter 2007. The high depletion expense was due to an increase in buying and development costs incurred in the second half of 2007 and the first half of 2008.

Higher commodity prices offset the impact of lower production volumes and a modest increase in expenses resulting in a 1% increase in EBITDA during the second quarter of 2008 of $29.5 million. Net income for the first quarter excluding the impact of our non-cash hedging gains was $8.1 million or $0.17 per share.

Moving on to the balance sheet at the end of the quarter, we had $48.6 million outstanding under our senior credit facility and $160 million in senior notes. In terms of our leverage statistics, we ended the quarter with a total debts booked capitalization ratio of 43% and a total debt EBITDA ratio of 2.1:1.

Recapping capital spending activity for the second quarter, expiration and development capital expenditures totaled $39.7 million of which $31.5 million went to growing expenditures, $8l.2 million went to land and G&G expenditures.

As we already stated, our Board of Directors has recently approved a $54 million or 45% increase in our 2008 E&D CapEx budget. During 2008, we expect to spend a total of $109 billion on our Williston Basin activities which represents roughly 63% of our E&D CapEx budget.

When it comes to funding, our 2008 capital expenditure budget, we believe that our forecast of discretionary cash flow, the availability we have under our senior credit facility and the proceeds from any asset sales will provide the company with ample liquidity. On June 30, we had $48.6 million outstanding on our senior credit facility with availability of $135 million foreign base leading an additional $86.4 million of undrawn capacity. Further, we would expect to exit 2008 with a significant portion of this undrawn capacity still in place.

In our earnings release yesterday, we provided production guidance for the second half of 2008. In terms of our expectations for the second half of 2008, we are forecasting production volumes that average between 30-34 million cubic feet of equivalents per day for the third quarter and between 35-44 million cubic feet of equivalents per day for the fourth quarter. In summary, the achievement of significant operational milestones in the Williston Basin, the resumption of our Vicksburg completion midway through the second quarter, and high commodity prices all contributed to a strong first half of 2008 from the standpoint of massive value growth and financial performance.

Based on these results and considering what we have in front of us, we announced a 45% increase in our 2008 CapEx budget shortly after the end of the second quarter. With our growing acreage position and improving operational performance in our Williston Basin plays combined with a string of four successive southern Louisiana discoveries, we are similarly expecting a strong second half of 2008.We look forward in reporting back to you in November with what appears to be shaping up as a very strong year of value creation for our company.

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

Bud M. Brigham

That concludes our presentation. We would be happy to answer any questions you might have.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from the line of David Heikkinen from Tudor Pickering Co.

David Heikkinen - Tudor Pickering & Co.

Just wanted to ask a question on the third quarter and fourth quarter production numbers. What determines the range of outcome when you think about major wells in South Louisiana coming back online or ramping up, and then the split of what your expectation is for Bakken production and those numbers?

Bud M. Brigham

David, this is Bud. I’m not starting into it but maybe these guys would want to add to my comments. Some of the big swing wells Parshall and our Louisiana discovery, they tested at 15 million a day which we think will probably produce at 20 million a day. It is obviously a big swing. So the timing of that well when it comes on, it’s a big factor. The other southern Louisiana wells also provide meaningful near-term production volumes so that has a big impact. Then of course, the Bakken production is ramping up and in the Parshall-Austin wells, there is a real surge in activity there that we expect to continue. So there is a big swing there if those wells initially produce 1,000 barrels a day or 2,000 barrels a day that has a big impact. So there is a lot of headroom as we exit. Gene, I don’t know if you want to add to that.

Eugene B. Shepherd Jr.

Yes, we’ve got test rates on a couple of those wells, southern Louisiana and we got the [inaudible], it’s really just a timing issue in a large degree. As far as the Bakken wells, I think our numbers are still pretty reasonably reached. I don’t know if we have really taken into consideration the results from the Carkuff well as far as the additional wells we will be hooking up in the third and fourth quarter in our Ross area.

Bud M. Brigham

One thing I might add, David, is a big swing also particularly for the fourth quarter is Cotten Land #5 which is budding currently. That well is a twin to the Cotten Land #3 which produced 29 million cubic feet per day out of 30 feet of pay so we’re simply accelerating on that well because that 30 feet of pay has made over 9 Bcf and is still making about 10 million a day. It is outperforming and it would be awhile until we got to the 50 feet level above it that looks comparable in quality. So the timing of that well coming on and it’s obviously going to be a big contributor in the fourth quarter. The rates, it is certainly capable of producing based on the lower one doing over 20 million a day but we’re certainly not assuming that.

David Heikkinen - Tudor Pickering & Co.

So thinking about the Bakken, if you’re 1,500 barrels a day, is that a gross number?

Bud M. Brigham

No, that’s our net number.

David Heikkinen - Tudor Pickering & Co.

Where would it be at year-end? What is the range of outcomes?

Bud M. Brigham

It’s hard to say. As I just mentioned, David, it’s such a big, these Parshall-Austin wells coming online, I think the enhancement we made operationally is clearly improving the performance of our wells. It parallels what you seen with EOG and the other quality operators that have drilled more wells and we’re all in bed together out here. We’re figuring out how to optimize, how to drill and complete these wells. You’ve seen with EOG increasingly higher production rates in the wells and we’re seeing the same thing. So I feel confident that it’s going to continue to ramp up, David, and it’s more difficult to model how strongly it ramps up. Another variable is our Three Forks play, the Adix which is near-term and what kind of a rate that we get on that is comparable to the Fidelity wells in the southwest. That can obviously have an impact.

Eugene B. Shepherd Jr.

A real wild card is the non-operator activity and it’s just an explosion of activity. That’s obviously given the non-operators, it’s proven much more difficult to gauge.

David Heikkinen - Tudor Pickering & Co.

Let me ask it another way. What’s your oil/gas split for the third quarter?

Eugene B. Shepherd Jr.

We haven’t really provided any guidance on that.

Bud M. Brigham

I don’t have the numbers in front of me, David and we haven’t provided guidance on it but obviously our oil production is indicated by the Bakken, it continues to grow. I would expect it, on a percentage basis, our oil production to become a larger growing percentage on our overall production.

David Heikkinen - Tudor Pickering & Co.

So I’m just trying to think through how we can build some confidence around fourth quarter numbers. I’m just struggling with the answers so far.

Eugene B. Shepherd Jr.

I think to a large degree a big component of it is the southern Louisiana wells. Obviously as we get wells hooked up to production, that will give us the ability to assess that timing factor.

Bud M. Brigham

I would suggest looking at the two components, David, looking at southern Louisiana, we got test rates on those southern Louisiana wells. We got the Cotten Land 5, we got the Cotten Land 3, so you can use those, maybe risking on that rate. For the Bakken, you can use some assumed rate on the wells we are completing over the remainder of the year and you can look at those volumes. You can project growth from that perspective.

David Heikkinen - Tudor Pickering & Co.

When you thought about activity this year, you’ve grown from 100 barrels a day to 1,500 barrels a day; you’re going to double your activity in September. Would making an assumption that you take those 1,500 barrels a day up to mid-2,500 barrel a day number? It doesn’t seem unreasonable.

Eugene B. Shepherd Jr.

The one thing I want to point out is what; we were 500 or 600 in June? So obviously the ramp from 500 to 1,500 is contribution we are getting currently from the Carkuff –

Bud M. Brigham

And the Johnson.

Eugene B. Shepherd Jr.

That’s sort of the peak rate for the Johnson. Obviously, that Carkuff rate is going to come down and normalize from that level.

Bud M. Brigham

It’s like you would say with all of the hyperbolic profiles, you would get this flush production on top. The good thing is we’re completing one operating well per month now and going to two operating wells with our commitment to the second rig. I think over time it will become a lot more consistent and more predictable as well as what you are trying to model. It will become easier.

David Heikkinen - Tudor Pickering & Co.

Just switching from the production side. In your presentation, you showed 93,000 net acres in Mountrail County. You highlighted the Parshall-Austin area and the Ross area at 47,000 net acres. Is that trying to define what you think will be core or what will be non-core? I am just trying to think through.

Bud M. Brigham

What I was trying to do, it is really a matter of how much data you have and statistics of how comfortable you can be with the outcomes on the future drilling and really what we did for this call, we focused on Mountrail County because there’s just been so much drilling there, we think there’s enough statistics in Mountrail where we have 43,457 net acres that you can say it’s a pretty good certainty, you can say it’s a strong certainty that the acreage is economic. We think you can say that it’s reasonably conservative, 200,000 to 400,000 barrels per well outside the Parshall-Austin area is reasonably conservative. So we were really starting from an area there where we have a lot of data and you can have more comfort in doing some projections on ultimately how much in reserves we can produce there. Then we are kind of moving out from there, David, other areas we are seeing scattered activity, scattered drilling is providing some data but we don’t have the density of that data that we do in Mountrail County. So we were kind of building out from there where we have more data showing us what data we have left.

Operator

The next question comes from the line of Joe Allman from J.P. Morgan.

Joseph Allman - J.P. Morgan

Bud, just following up on David’s questions. So your guidance for the third quarter is the same as it was for the second quarter. Is there any reason that your third quarter production would not be higher than your second quarter based on what you know now?

Bud M. Brigham

Maybe Gene might want to add to this. It’s really timely on these south Louisiana wells that unfortunately don’t come on until late in the quarter. We got the Bakken wells that should continue to grow but we have the natural decline of our prior south Louisiana wells and the prior Vicksburg wells so I think production should grow in the third quarter. The real ramp-up is going to occur very late in the third quarter and it will be realized in the fourth quarter.

Joseph Allman - J.P. Morgan

So what’s the total company production right now roughly?

Bud M. Brigham

We haven’t provided that out now, Joe. Clearly the new wells that have just come online are not relative to what we had in the second quarter if we had to say today.

Joseph Allman - J.P. Morgan

In terms of the development of the Bakken play, in terms of financing the development, what are your thoughts around different options for financing the Bakken development?

Bud M. Brigham

Well, Gene will probably want to answer this but we do have a lot of options. Last year, we did the small divestiture to supplement our cash flow. Clearly, production is ramping up. Our cash flow with prices is higher than we anticipated since we began the year so that’s really funding our CapEx increase this year.

Eugene B. Shepherd Jr.

Joe, at the beginning of the year, obviously our alternatives were a much shorter list. Over the course of the year, as we move through the year, our alternatives expanded. Our description of cash flow is running at a much higher level relative to what we were forecasting earlier in the year. The asset sales are something we are looking very hard at, especially on the conventional side of the business. To the extent that there’s something that we feel is mature or something that may have additional running room that maybe we are in a better position to reallocate capital and maybe generate a high rate of return in our Williston Basin play. Maybe it would be something we would consider jettisoning. We’re looking at all of those opportunities. Obviously, we got plenty of raw power under the senior credit facility as sort of a backstop. All of that is combined with the increase in discretionary cash flow but I would expect that off of this long list of alternatives, we would pick an alternative and go with it. We certainly wouldn’t plan for us to continue to use the availability under the senior facility to fund the negative free cash flow, the 100% of the negative free cash flow that we would be experiencing over the next six months.

Bud M. Brigham

For a certain period of time, we do feel more comfortable with our leverage given the delisting that’s occurred in the Bakken and the very low-risk profile. We’re very sensitive to our debt level.

Eugene B. Shepherd Jr.

We’re also sensitive to focusing on any repurchasing and trying to make decisions that are going to be accretive and really, what we’re focused on currently is how do we fund our ’09 CapEx budget. That’s what we focusing on and looking at there said running numbers on all of those options and trying to decide which one is the least to lose. It’s the most accretive.

Joseph Allman - J.P. Morgan

Is doing a joint venture of some sort an option for you as well?

Bud M. Brigham

I think that’s become less likely. You look at the cost of capital of a joint venture and there are some exceptions but over a large portion of our acreage it would not make sense to dilute our equity in that acreage in this industry free-trade structure. You could say that in smaller areas, joint ventures is a mutual benefit of both parties in areas just as we have with our consortium wells on the west side of Mountrail County. You can see some more joint operations so all of the parties benefit.

Joseph Allman - J.P. Morgan

On the west side, on the far west side of the Nesson Anticline where you reentered that one well, I know you got some more plans to do some more brief re-drilling, are you going to be doing any re-entries over there?

Bud M. Brigham

Joe, this is Bud and Jeff and Lance may want to add to this. We tried to address in the conference call the fact that it’s really interesting when you look at the primary wells that we drilled with single stimulations, an older technology, a few of those wells look like they are going to make 100,000-165,000 barrels despite that. Then we come in and reenter a well with seven intervals to stimulate and we get 627-700 barrels a day roughly. The improvement is pretty significant. Then we come to the Johnson and the Carkuff, we got to 10 and 12 intervals and get over 600 barrels a day and over 1,000 barrels a day. So we think that we and other operators out here are really moving down the curve pretty rapidly right now. In my view, it’s made the 100,000 acres that we had in Williams and McKenzie economically really attractive. We expect as we drill more wells out there to see further improvement with more intervals stimulated. One of the things that we are looking at as you said, are the existing wells that we have out there possibly re-cracking those wells. They are still producing reasonable volumes given the EURs that we see for those wells. Right now it is probably not as likely to reenter and sidetrack those but here could be other wells that we could do that on.

Joseph Allman - J.P. Morgan

The Carkuff well, the 1,100 barrel a day rate? What length of time did you flow at for that rate?

Bud M. Brigham

That well just came online in the last 24 hours. So that was the production over a 24-hour period.

Joseph Allman - J.P. Morgan

Bud, can you just talk about with the increase in the cracked stages, what are the costs associated with that? What does it cost to drill and complete a well?

A. Lance Langford

I don’t have any problem with that. Basically, what we’re seeing is the cost or increase because of two things. One is because of the cost of the number of crack jobs. The first three wells we did east of the Nesson, we did seven crack jobs. The last three, we’ve done an average of about 10.3 crack jobs. So you’re seeing probably about a half a million dollar increase because of crack jobs and casing cost has gone up dramatically, as you know which is equating to another $500,000. The good thing is we are seeing a dramatic improvement in the rates and EURs that we’re getting out of those crack jobs.

Joseph Allman - J.P. Morgan

So the recent wells that are 10-12 stages, what’s the drill and complete cost there?

A. Lance Langford

They are in the $6 million range.

Bud M. Brigham

Right around $6 million is a good number to use right now.

Joseph Allman - J.P. Morgan

Do you think you have the ability to hold steel costs constant? Do you have the ability to drive that down with efficiencies?

A. Lance Langford

We think it’s going to go down because, well we know it’s going to go down from what we’re paying right now because we’ve already ordered some pop previously and when it comes in, it will be cheaper than what we have been paying on the last couple of months. So hopefully we’ll control inflation by driving it down.

Bud M. Brigham

We tried to stay ahead of the shortage of pie costs and I think Lance and the team has done a great job. I think we’re in much better position than a lot of our competitors are and that’s going to help over the long haul. It looks like it has been a pretty hard run with pie of late so you could see it come back to a more reasonable level here hopefully in the next 3-6 months.

Operator

Our next question comes from the line of David Snow from Energy Equities.

David Snow – Energy Equities Inc.

The closest one that I see to your 1,100 barrel a day well is about 380 barrels a day. Does that suggest that your 1,100 is going to be setting a new mark going forward? It looks to me like the increase would be attributable almost entirely to the completion of it as opposed to the geology change. Can you comment on that?

Bud M. Brigham

That’s an excellent observation. It’s right next door. We think it’s a very good probability that the operational enhancements are part of that and the more intervals on the Carkuff completion are having a significant impact on the performance there. It’s not different from what you’ve seen in the Parshall-Austin area. EOG has optimized how they drilled and completed those wells. You see progressively higher rates and higher EURs for those wells. Lance, Jeff, feel free if you want to add anything to that.

David Snow – Energy Equities Inc.

How many stages did the nearest well have? Is that a seven stage track on the nearest one to that?

Bud M. Brigham

Lance, do you remember on that, on the Bakke?

A. Lance Langford

Yes, there were seven stages on the Bakke and one other thing about the Bakke. We never drilled the plugs out because we got some real, well we ended up buying something, it ended up being a harder material. So we never drilled out those plugs and we’re currently rigging up to drill those out. So there may be some upside on the Bakke over the 300,000 or 300 barrels a day type wells. There’s some upside there. It may be some geological performance but definitely we should be getting increases from the number of crack jobs that we did on the Carkuff.

Bud M. Brigham

I think you raised an excellent point. It should have come out in the call. You certainly have to believe that this illustrates the improved operational techniques out here and the impact that it can have on their production rates and reserves. You look at 27,000 acres block that we have right there. Certainly that well looks like it is above the 200,000 to 400,000 at this point EUR range that we talked about for that block over time as we drill more wells. It could be we may have the opportunity to develop more reserves there than currently forecasted.

David Snow – Energy Equities Inc.

It sounds like you are going to get those results going forward over there in the Ross area. Would you hope that will be a new mark for your performance?

Bud M. Brigham

I’m optimistic. There’s going to be geologic variability from well to well but I think it’s pretty clear the operational enhancements are having an impact on the section. So I think we’re more optimistic that we can see better results as we go forward there in the Ross area.

A. Lance Langford

I think from going to 300 to 1,000 barrels, it may not be all of them are 1,000 barrels a day but hopefully we continue. We’ve seen dramatic improvements over time with more crack jobs and just better completions. I wouldn’t reset the mark at 1,000 barrels a day but we expect to see continued improvement.

David Snow – Energy Equities Inc.

I previously heard that the Three Forks was a structurally controlled formation and you were going to look at your maps to see how much. Now, it sounds like it’s stratigraphic in your mind. What’s the geologic interpretation of the Three Forks?

Jeffrey E. Larson

We mapped it extensively off the basin proper and what we see in the Three Forks is typically focused targeting, a clean gamma ray member that is above anywhere from 20-30 feet below the base of the lower Bakken shale. We looked at existing core and we are currently getting ready to core another well actually our Anderson well. It appears to be a dolemitic member. As we know from some of our rock mechanic studies, dolemites are very conducive to fracturing. We’ve been able to map that middle, that dolemitic member around and we are hybriding our locations off where that is the thickest and the most attractive looking.

Bud M. Brigham

In summary, this is Bud, it could be enhanced by structure. It is certainly enhanced by fracturing. It’s pretty apparent that the Mountrail area, Bakken well production is enhanced by fracturing and that fracturing will not be unique to the Bakken. In fact, it is probably initiated at best and we therefore expect the Three Forks similarly to be fractured. Those are all the attributes that make us optimistic about the Three Forks and our Ross area. Of course, the nearby wells have provided further encouragement on that.

Operator

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

Ronald Mills - Johnson Rice & Company

Just a question in terms of the development plans with the Bakken versus the Three Forks. How would you plan to attack the Three Forks development since it’s so close to the Bakken? Would you do potentially twin wells or how do you foresee the development of those two different zones?

Bud M. Brigham

Well, I will make a general comment but Lance and Jeff may want to talk about it. The Three Forks is just below the Bakken and we tested our accupak of the lower Bakken shell and at it’s very thickest in western Mountrail County where the bulk of our acreage is. I think it’s roughly from lateral in the Bakken to a lateral in the Three Forks in that area; it’s almost roughly around 100 feet. We don’t see it being very likely that we would be competing for reserves and I would like to point that out in the Three Forks versus the Bakken. I think it would be incremental reserves that would be added there. Right now, I think, and Jeff and Lance may want to add to this, it will probably be a different drilling program at this point you would have to say for the Three Forks relative to the Bakken. So there is potential and we’re certainly looking at it. Associated with the potential, there’s operational challenges of drilling with two laterals, one in the deeper Three Forks and one in the Bakken, but we’re not there as far as, and these guys may want to address if we can do that at this point. Lance or Jeff, feel free to add to that.

A. Lance Langford

That’s been done. There have been other companies that have drilled the two laterals, one in the Bakken and one in the Sanish which is similar depth and distance apart. So it can be done. I think that’s where you’ll end up ultimately I think doing that. I think the big challenge is to use swell packers and get good completions on both laterals and that’s where the technology is improving right now so you can get that done. Right now, we all believe that doing the multiple stage crack jobs is key to having performance. I think those techniques will be improved and we will be doing that in the future. Right now, I think we will be doing just single laterals to test it so we know that we can get good completions on them.

Ronald Mills - Johnson Rice & Company

If you look at the cracks, they’re located so close to one another. When you design your cracks, how high vertically and low vertically are you hoping to fracture the rocks such that you don’t get communication between the two different formations?

A. Lance Langford

I think right now we would just go with our same designs that we have been using for Bakken so we don’t believe that you are going to break through and take reserves from one to the other. We are doing or did the microseismic in our consortium wells and hopefully that will give us some indication of how much break heights you are actually getting. They’re processing that data as we speak.

Jeffrey E. Larson

Looking at the cross-sections, we got existing wells very close to where our Anix well is planned and as Bud pointed out, there is about 100 feet of vertical distance between where the Three Forks well would be versus the middle Bakken well and the 100 feet consists mostly of shale. That helps meet growth.

Bud M. Brigham

One other data point I want to make, Ron, is you probably heard Continental’s call and they talked about the fact that in Dunn County where they are, they drilled Three Forks wells, which they don’t think it’s likely. Of course, they are going to confirm that but they don’t think it’s likely that they are competing for reserves. If that’s the case in Dunn County, it’s certainly the case in Mountrail County because the lower Bakken shell thickens up dramatically going from Dunn County into western Mountrail County that we are in a better position for incremental reserves.

Ronald Mills - Johnson Rice & Company

You mentioned a few times now that the thickening of the Bakken particularly in Mountrail County, is there enough data to know what the Three Forks looks like in terms of thickness as you move from either west to east?

Bud M. Brigham

Yes, hopefully it’s up now, our website presentation and cross sections. It’s probably tough to see on the PowerPoint but we got a good handle on stratigraphy of the Three Forks and it looks attractive to us.

Jeffrey E. Larson

Ron, Jeff, real quick. One thing that has got us excited is that the dolemitic member has got the regional extent to it. It does thicken and thin but we see it on the website near the Nesson Anticline as well as the east side, and I was very encouraged about the opportunity for the Three Forks play and what we call Rough Rider and in eastern Montana.

Ronald Mills - Johnson Rice & Company

One last question just on something that you don’t get asked about a lot, about your conventional program in Louisiana and Texas. As you look ahead to the remaining locations whether it’s a one rig program in Vicksburg or a number of wells left in the Ujevian South Louisiana play. As you look to 2009, do you have enough activity planned down there to kind of hold that production from that area flat on average or are you still hoping that will be a growth area when we look at the Gulf Coast outlook?

Bud M. Brigham

I think that certainly the Vicksburg, we have tremendous inventory. I think its 53 locations of inventory to drill in Vicksburg. We have plenty of inventory there. South Louisiana has been more of conventional exploration program where we leverage our knowledge base and our experience and technical ability to utilize 3-D seismic and I think the proof is in the results. We just had a great run there starting with our Bayou Postillion and now in this new venture with Clayton Williams. So it will be a manner of continuing to do those joint ventures and Jeff may want to add to that.

Jeffrey E. Larson

Ron, just to expand on the Clayton Williams JV. With continued success in the joint program, potentially three to four southern Louisiana wells in the ’09 plan with that JV.

Ronald Mills - Johnson Rice & Company

In the Vicksburg, you have given your inventory; I guess the activity level will be the ultimate governor on your growth from that area. Is the plan just to maintain your one rig in that area?

Bud M. Brigham

I think for now we have been drilling five or six wells a year in the Vicksburg so I think for now I would assume kind of that pace. Obviously, we could accelerate more than that but we got such a great use of capital in the Williston that would kind of balance the opportunities there. Jeff may want to add something there.

Jeffrey E. Larson

Just to expand a bit more on the picture, we also got a new area in the Vicksburg where they plan exploratory testing for late ’08 or early ’09. Let that be an area to keep an eye on. With success there, that would set up a development program.

Bud M. Brigham

I view this area that Jeff referred to looks a lot like Diablo, but of course now we have the Home Run Triple Crown and Forbes Field success there to set up a significant development drilling program and like we benefitted from in Brooks County.

Operator

Your next question comes from the line of Chad Potter from RBC Capital Markets.

Chad Potter - RBC Capital Markets

Can you guys comment a little bit more on the non-operated activity in the Bakken, I know you got the 56 gross well number from July. Do you expect that number to go up?

Bud M. Brigham

It went up from a prior number. I think we were at 34-40 on the prior number, up to 56. I think it’s more likely to go up, Chad, than it is to go down. Operators are continuing to accelerate their activity and we base that estimate on current proposals that we have in house and also it looked like its permanent and it will probably be drilled this year. It’s almost on a weekly basis that we get more permanents in on our acreage. An example of that, Chad, is I think we can have a lot of small-interest oil. EOG drilled that well in the Offen Township. We have 6 1/4% of it at 300,000 barrels a day. There’s going to be a lot of that, a lot of lower interest activity that we’re going to be underneath that we’ll benefit from on a cumulative basis. So to answer your question, it may be light but it is just really hard to project at any point in time. Jeff, do you want to add to that?

Jeffrey E. Larson

Just to give folks a gauge to how busy it is out there, there were 20 new permits in Mountrail County just yesterday. We got multiple geotechs, just trying to keep up with the drilling and the drilling process is really an amazing event. We’re seeing any of these on a weekly basis on an on-off basis.

A. Lance Langford

We have 26 rigs running out there. That’s 26 wells roughly being drilled in Mountrail County. It will be very, very active.

Chad Potter - RBC Capital Markets

Are you guys starting to get sort of a view into ’09? Are you starting to get permits for any of these for ’09?

Bud M. Brigham

I think most of the ones Jeff is getting right now are assumed to be drilled in the latter part of this year. We’re so busy with the near-term program that we don’t have the permits yet for the wells in 2009.

Jeffrey E. Larson

We’re very proactive in all of our areas, permitting, staking locations, positioning ourselves for even an increase in rig activity above the current tooling activity for the ’09 plan. So we’re positioning ourselves for success in the areas and try to get in front of the permitting process.

Chad Potter - RBC Capital Markets

A couple of areas I haven‘t seen much talk on. Hutton, I know originally, you guys had two wells from that lake or seismic interlay. Are those off the table at this point?

Jeffrey E. Larson

We still have two wells planned for late ’08. We’re proactively interpreting what we call our Laker data volume. We are actively leasing on a number of prospects. Our strategy there would be to button up our lease hole position and then go and drill 1-2 by year-end. I would point out across this broad shoot area; remember in the Mills Ranch area the target is about 25,000 feet. It actually goes as shallow as 10,000 feet when you go to the west side of the broad shoot. The only wells you will see us drill will be in the 12,000-15,000 foot type vertical test range.

Chad Potter - RBC Capital Markets

Can you gauge your expectations?

Jeffrey E. Larson

They got nice reserve size exposure.

Bud M. Brigham

They’re going to be active there, Chad. We got a lot of prospects and very many have reserve potential. There is so much happening in Williston that we don’t have the time in updating the market on that.

Chad Potter - RBC Capital Markets

Finally, on the Mallory, is there any future activity or is that on the shelf at this point?

Bud M. Brigham

For us, we’re sitting pat because the last round of crediting was disappointing. That being said, there’s evidently Chesapeake, EOG and others out there drilling some horizontal wells to be helpful to us. We felt like the Lone Ranger out there for a long time so it’s great to see some savvy operators out there drilling wells and we stand to benefit from that.

A. Lance Langford

There is also some activity down in Iberra in the Powder. Our expedition may benefit there with success in some of the industry. It will be offset well.

Operator

Your next question comes from the line of John Gerdes from SunTrust.

John Gerdes – SunTrust Robinson Humphrey

Lance, as far as the geometry bit of this fracturing you’re doing in the Bakken. What kind of design lengths are you attempting to achieve for these crack wings?

A. Lance Langford

John, I don’t know exactly the design lengths. Basically what we have done is vary our sizes to a place where we we’re getting the ultimate performance out of the well. We‘re also looking at what EOG and Hunt and some of the other guys are doing. You’re talking about the design in a horizontal well. It’s a difficult calculation to be made, there’s a lot of different ways on how the cracks grow. What we’re trying to do in using the consortium data is hopefully we’ll have a better indication on how and where the cracks grow. That was the main purpose of doing the consortium for us.

John Gerdes – SunTrust Robinson Humphrey

You would anticipate though that you are probably seeing the wing propagation of at least several hundred feet in length, wouldn’t you say?

A. Lance Langford

I would think so, 100-200 feet. It depends on how it propagates.

Bud M. Brigham

One thing, John, I think it’s pretty obvious that the maximum propagation would be in the middle rock, whether it’s the middle Bakken dolemite that’s a more brittle rock or the Three Forks dolemite as opposed up to the less brittle shale.

John Gerdes – SunTrust Robinson Humphrey

Let’s stay with that a moment. Jeff talked a little bit about the rock properties. Jeff, you categorized the middle Bakken as a dolemitic rock. There are some in the industry who would categorize it would have quite in the way of shale content as well. Of course you mentioned, some thoughts in terms of the Three Forks Sandish and then the lower Bakken, it sounds like you feel like it shales up a little bit more.

Jeffrey E. Larson

I think that’s right John. I think I can expand a little bit more on the middle Bakken. The middle Bakken can be variable. It certainly is dolemitic. Grading the limestone, it actually has some silt and shalic component in some areas. I feel the dolemitic factor is what we like a lot because it is very conducive to fracturing. The lower Bakken shale is extremely organic. It is very shalely by nature. When you look at it on core, it looks identical to the upper Bakken shale so it is a real organic, dark shale. That’s basically what sits below your middle Bakken target. Then the Three Forks, what we have seen from cores, it’s actually dolemitic. We don’t see the significant clastic and some of the blueprint that you see in some of the middle Bakken.

John Gerdes – SunTrust Robinson Humphrey

Lance, how much sand are you trying to put away per stage in this completion?

A. Lance Langford

It’s usually in the 200,000-250,000 pounds.

John Gerdes – SunTrust Robinson Humphrey

And the Carkuff well, what was the lateral length on that? Was it as much as 7,000 feet or was it not quite that long?

A. Lance Langford

On the Carkuff?

John Gerdes – SunTrust Robinson Humphrey

Yes, on the Carkuff.

A. Lance Langford

On the lateral itself, it was a little over 5,400 feet.

John Gerdes – SunTrust Robinson Humphrey

The reason for the line of questions again is trying to kind of gauge and you talked about this today on the call. The probability of obviously communication between these two horizons and given how close they are to one another, that’s our concern. That’s the reason for the questions.

Bud M. Brigham

I understand and we’re going to learn a lot about that. We will all be able to think with more knowledge about that before too long. I think there’s a very good probability there won’t be very meaningful communication particularly in western Mountrail County. Again, as I mentioned earlier, Continental doesn’t think there will be down in Dunn County, and the lower Bakken shell is quite a bit thinner down there. So if it’s not there, it’s certainly not in western Mountrail County where the lower Bakken shale is quite a bit thicker and we have roughly 100 feet between the two laterals. Time will tell for sure.

John Gerdes – SunTrust Robinson Humphrey

Obviously the industry is working towards ways to gauge this landscape?

Bud M. Brigham

That’s right. The consortium’s really helping with that. We’re learning a lot from that. There’s a lot of data behind the scenes that it’s hard to go over during the call. They are kind of built into our opinions out here.

Jeffrey E. Larson

One thing that really benefits us if we drill Three Forks well, it holds the Bakken rights in that section, if we drill the Bakken well; it holds the Three Forks rights. That puts us in a position where we can continue to expand on our Three Forks knowledge as well as the industry. We can hold our acreage with Bakken wells and later exploit Three Forks, vice versa.

John Gerdes – SunTrust Robinson Humphrey

Jeff, even if they were, one last question and then I’ll stop. Even if there was a degree of communication, arguably, is there anything to the theory that maybe gravity drainage would suggest possibly in the event that there was communication, that the lateral stake point would make more sense? Is it slightly deeper in the Sanish or Three Forks versus in the middle Bakken?

Jeffrey E. Larson

It’s something to think about. One thing I would throw out, John, is the industry general consensus is 9 million barrels is recoverable per section. We are only getting 10% on an individual Bakken well. I think even if there is say an argument there is some communication in the Three Forks and the Bakken. Maybe it is only a really small acceleration contributor.

Bud M. Brigham

You are increasing a percent of your reserves ultimately recovered. One thing, Lance may want to address more of the gravity here and in the second half I will turn it over to you. Your question’s interesting to me. Over on the west side of the basin for example where Continental is planning to drill a Three Forks play about ten miles southwest of our 100,000 acres there in eastern Montana. Over there, the lower Bakken shell is thinner, the Three Forks and the middle Bakken are closer together. I think that question could vary by area and that’s an area that maybe there’s a better probability that there is communication between the two horizons and Lance maybe you might talk about if it is the case over there, and there is more communication between the two laterals, the middle Bakken and the Three Forks with the gravity drainage will be beneficial to recovery.

A. Lance Langford

Gravity, that could work, I just think it’s kind of risky. Even if you frack and you create a communication during the frack job to the Bakken that over time you got that shell in there. The question is do you propagate enough in that shell and will it embed in those shells over time; therefore reduce your productivity and your EUR. I’m not comfortable saying that you’re propagating through that shell enough to get that oil. I think it would be a risky thing to pursue at this time. I think we will know a lot more once we get information from the consortium. Some people are going to start doing the Three Fork and Bakken in the same section and we’ll find out.

Jeffrey E. Larson

We’re actually planning on coring a lower Bakken shale Three Forks towards year-end in our offering. We’re going to do a bunch of rock mechanics. We’re working really hard to understand some of the questions you’re asking.

Operator

Your next question comes from the line of Monroe Helm from Seem Energy Partners.

Monroe Helm - Seem Energy Partners

EOG in their conference call earlier today said they didn’t think the Parshall field was sand on sand. In your opinion is that because of the thickness of the middle member of the Bakken? Is there something or maybe you can just comment on their comment?

Bud M. Brigham

We think it’s prospective for the Three Forks. The Sanish is used to try to test the variability of the Three Forks. I’ll let Jeff take it from there.

Jeffrey E. Larson

I think there is a fair amount of confusion with the nomenclature out in the industry. Three Forks is a stratigraphic member right below the lower Bakken shale and the Sanish is actually in a lot of places, its sandstone. It’s solid. It’s solid specifically by Anloe Field, which comes off the south end of the Nesson Anticline at an oblique angle. That’s where the Sanish is clastic, it’s where the sandstone member exists. It occurs right at the top of Three Forks. As you go deeper into the Three Forks, at a lot of the areas where we’re at, we don’t see north of EOG’s Stevens Sanish sands. What we do see is about 30 feet into the Three Forks is clean dolemitic member that’s focused on the target with a lot of success.

Bud M. Brigham

That’s Fidelity to the west of the Parshall area and south of our Ross area. We think the Three Forks is highly prospective at this point. Fidelity demonstrated that it’s productive nearby.

Bud M. Brigham

We appreciate everyone’s participation in our call and we look forward to reporting on what should be a very exciting third quarter for the company. Thank you.

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Source: Brigham Exploration Company Q2 2008 Earnings Call Transcript
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