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Executives

Bud Brigham – Chairman, President and CEO

Gene Shepherd – CFO and EVP

Lance Langford – EVP of Operations

Jeff Larson – EVP of Exploration

Analysts

Brian Lively – Tudor, Pickering, Holt

John Freeman – Raymond James & Associates

Subash Chandra – Jefferies

Derrick Whitfield – Canaccord

Ron Mills – Johnson Rice

Scott Hanold – RBC

Eugene Lipovetsky – Zimmer Lucas Partners

Brigham Exploration Co. (BEXP) Q3 2010 Earnings Call Transcript November 2, 2010 10:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the Brigham Exploration Company third quarter 2010 earnings conference call. My name is Gen and I will be your coordinator for today.

At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer session towards the end of today's conference. (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's conference, Mr. Bud Brigham, Chairman, President and CEO. Please proceed, sir.

Bud Brigham

Thank you, Jen. Thanks to each of you for participating in Brigham Exploration Company's third-quarter 2010 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, David Brigham, Executive Vice President of Land, Legal and Administration and Rob Roosa, our Finance Manager.

Importantly, before we get started, I would like to encourage you to be prepared such that during the course of this call, you can view our conference call presentation, which can be accessed via our website at www.bexp3d.com. It includes very helpful information regarding our third-quarter results as well as our plans for the remainder of the year. We will be referring to the slides in the presentation during our discussion. It will help you to be prepared with this, as we will put through some of the slides pretty quickly.

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

In addition, in this call, we may use the terms probable and possible reserves that we do not include in our SEC filings. We may also discuss locations, which include proved reserves, as disclosed in our SEC filings.

Please refer to page two of our corporate presentation for a cautionary note to U.S. investors regarding the use of the terms probable and possible reserves and locations.

Finally, a copy of our company's press releases as well as other financial and statistical information about the periods 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.

So let's get started. First, if you'll go to slide four, you can see our items for discussion which are also the key takeaways for our call. I'm going to start by briefly discussing the major transformations of our company that's occurring this year, including our dramatic production growth, which is a good proxy for our very substantial 2010 proved reserve additions.

I will also discuss our continued strong drilling results and our near-term catalysts. Following that, Gene will discuss our record financial performance and Lance will discuss our well out-performance and the fact that generally speaking, our wells continue to outperform that of our peers in the same areas.

Lance will also update our operational progress and update you on our infrastructure project and our current initiatives to secure additional services to be prepared for potential further acceleration in 2011.

In summary, our theme for today's call could be described as no oil left behind, given that we completed our prior initiative in the Williston Basin to drill geographically dispersed wells around our acreage in order to initially delineate the attractive economics. We have subsequently turned our focus towards evaluating operational enhancements in an effort to further enhance our recoveries and improve our efficiencies at extracting oil from this huge resource.

So our theme of “No Oil Left Behind” summarizes our effort to optimally extract as much oil in place on our acreage as possible. We expect to be discussing that quite a bit over the next year or so.

So let's jump right in by first taking a quick look at the macro environment on slide six. As shown, oil is traded at a premium to natural gas for several years now. I think most of you agree with me that given the abundant supplies of natural gas that this relationship is likely to persist for some time now, at least for next three or four years.

As shown on slide seven, partly as a result, it's a great time to be compounding value for our shareholders in the Bakken and Three Forks play. Given that, we were pleased to pull forward our seventh rig and further accelerate our drilling in 2010. Also, the fact that the rig count in the gas play should come down over time should help to further mitigate potential cost increases in our play.

Moving ahead to slide nine, you will see the list of our 40 consecutive high-rate Bakken and Three Forks completions in North Dakota. We are continuing to optimize operationally and that is showing up in our recent well results. We just announced a record well west of Nesson with our Abelmann, which came on at a peak rate of 4,169 barrels of oil equivalent per day.

We also just brought online another monster well in the Ross area with the Clifford Bakke, which was fraced with 38 stages and came on for a peak rate of 5,061 barrels of oil equivalent per day.

This is one of four monster wells that we brought online in the Ross area. It's pretty remarkable when you consider that we drilled eight long lateral Bakken wells in Ross that have an average early peak rate of 3,988 barrels of oil equivalent per day and they provided us with the three highest initial rate wells in the basin and four of the top five.

Lance will review the production curves for these wells. And you will see that based on its early performance, the Clifford Bakke may be the best of the monster wells. It will also demonstrate that these wells are continuing to outperform our competitors' wells in the same area.

Slide 10 illustrates our early well performance relative to our peers. Again, we will have more specific examples of this later in Lance's section. Our outperformance is a function of two things.

First, we were a first mover in the play, focused on the right geologic attributes, so we're blessed with acreage in some of the very best areas.

Second, our technical team has been a leader for the industry in innovating and optimizing operational technologies in order to deliver the best possible returns on invested capital. They've enabled us to transform areas initially thought to be uneconomic to marginally economic early on and now to highly economic.

Moving to slide 11, you can see the general improvement we've seen over time, partly relating to our increasing the number of frac stages, which we believe leads to a more effective stimulation along the length of the lateral.

You can see that our recent Clifford Bakke Monster well with 38 stages, but at this point, the most elevated curve, even above our prior Monster wells. The Clifford Bakke averaged 3,657 barrels of oil equivalent per day during its first week of production.

Moving forward to slide 12, this slide shows our Williston Basin production growth through 2009.

And slide 13 illustrates the growth, we have achieved thus far in 2010.

Since the end of the third quarter, we have had partial access to a second frac crew, thus, the rate of completions has accelerated. Further, since September 30, we have announced eight new wells impacting our fourth quarter.

In 2011, we will continue to ramp up to at least eight rigs and we expect to have two dedicated frac crews working for us, providing us with further acceleration of our completions and production additions.

Slide 14 shows the impact of our Bakken and Three Forks drilling, is having on our quarterly oil volumes. Our third-quarter oil production was up 144% relative to last year's Q3 and up 14% sequentially. Our guidance is for the fourth quarter to be up approximately 27% sequentially and 182% relative to the fourth quarter of 2009. That would put our full-year oil production up 155% relative to last year's volumes.

Now let's move forward to slide 16 to look at a table illustrating our inventory prior to giving you an update on our activity in the field. This slide shows the depth of our inventory without derisking the Three Forks and Rough Rider, which of course, has already begun with our recent State success that came on at 2,356 barrels of oil equivalent per day. It's encouraging also to look at the solid seven-day rate for the State well. It compares favorably to the seven-day rates for our Ross area Three Forks wells.

Slide 17 shows that with continued success in the Three Forks and Rough Rider, our inventory grows by 61%, a huge increase in our asset value to develop here.

Also, we assumed three wells per producing horizon in this table. However, based on our work thus far, we increasingly believe there is potential for more wells per producing horizon. And we are therefore preparing two four-well increased density pilots for the first half of 2011, one in Rough Rider and one in Ross.

Please take a look at slide 18. Obviously, four-well development across our core would increase our potential reserves to develop here by a third to an estimated 1,269 net locations.

A related point in this regard, which Lance will discuss in his section, is that we believe our utilization of more frac stages combined with the perf and plug method, has likely shortened our frac extent, but with much more efficient drainage near the wellbore. Our motto is now “No Oil Left Behind”. And we think our recipe is more efficient with regard to draining a larger portion of the oil that's in place.

Still viewing slide 18, there is one more point to make here. Although some early movers in the core of the play are getting pretty far along in the development of their inventory, you can see that we have hardly scratched the surface of ours. We've got multiple layers of values to delineate for our shareholders and that will take years. With eight rigs running, the currently derisked core acreage shown in red provides us with about a 14-year inventory, though it may be 19 years with the Three Forks and Rough Rider.

Right now, we are delineating proved reserves for one well per unit in our core areas, which will be followed by then getting credit for the second. We think likely then our third and possibly our fourth or even more in each production unit for each producing horizon.

In terms of the numbers, as illustrated on slide 18, excluding our single-stage long laterals drilled in 2006 which didn't materially drain reserves, we had only 17 net multi-stage long lateral wells booked as proved developed at year end last year. That was less than 3% of our inventory without the Rough Rider Three Forks and less than 2% with it.

2010 will be a huge transformation for us. In our press release, we announced bringing online our seventh rig earlier than previously anticipated. And primarily as a result, we could have as many as 45 new net locations booked as proved developed at year end. That's up from the 38 we previously forecast.

So that's up to 45 new net locations potentially booked this year with improved technology relative to the 17 total proved developed locations that were previously booked at year and last year. We had a record year for reserves last year after drilling 7.5 net wells. So drilling 6 times as many wells this year will materially change our proved reserve picture at year end.

Even with all that drilling, we'll only have up to about 61 net long lateral high frac stage wells booked as proved developed at year end, which is only about 10% of our currently derisked inventory and only about 7% if you believe the Three Forks will continue to work in Rough Rider. Again, that's assuming three wells per producing horizon and that we don't derisk more acreage in Montana or our other extensional areas. So we've got many, many years of value accretion ahead of us for our shareholders.

Now, moving forward to slide 20, in our Ross area, we brought online 8 exceptional long lateral Bakken wells with an average IP of almost 4,000 barrels of oil equivalent per day. Our most recent Ross area well announced yesterday was the Clifford Bakke, which came online at 5,061 Boepd. The Clifford Bakke gives us the three highest initial rate wells drilled by any operator in the basin and four of the top five. These monster wells are providing the top initial rates in the play, but the outperformance relative to our competitors' wells is also apparent in their subsequent production performance, which Lance will review.

So I'll just summarize the apparent economics of these wells. In general, these four wells are paying out in less than one year, therefore, they're generating rates of return well in excess of 100%. And it appears the EURs should range from about 800,000 barrels of oil equivalent per day to in excess of 1 million barrels of oil equivalent.

As shown on the slide, we're just getting started developing this area, having eight net operated long lateral Bakken wells. Assuming three wells per producing horizon in Ross, we could ultimately drill up to 168 net wells in the Ross area alone.

So to date, we estimate that we have drilled only about 5% of our inventory in Ross, and of course, less than that if we can drill four wells per horizon.

As shown on slide 21, Whiting Sanish field is immediately south of our Ross area. You can see that they are further along in their development. And as you can see, they are already drilling three Bakken wells in some of their units and doing a great job. We are benefiting from their activity and from the fact that we're just getting started with planning our development of this area. This provides us with a distinct advantage, an opportunity to set up for more efficient development with a better understanding of the attributes of the reservoir.

One example of this, our north-south alignment of our laterals makes our development much easier administratively. We're not having to cross units or drill wing wells with subsequent density wells.

Also, we believe that the Sanish field area is more naturally fractured than the Ross area, which is one reason we believe we may have the opportunity to drill more than three wells per spacing unit to totally develop our reserves. Our wells are likely draining a smaller area, but doing so relatively more efficiently as evidenced by our well performance.

Regarding that, Lance will discuss the fact that we believe that our use of more frac stages with the perf and plug method, is generating more frac wings though with less reach away from the lateral, allowing us to more efficiently drain reserves near the laterals and therefore, to potentially also drill more wells to develop our units.

This, combined with our belief that the Ross area is not as naturally fractured as Parshall and Sanish leaves us to believe that we may have the opportunity to drill four more wells per unit to fully develop much of our acreage.

As shown on slide 22, we therefore currently have a four-well pilot test planned to commence in the Ross area during the second quarter of 2011. Finishing up with our Ross area, we currently have two rigs drilling, one well fracing and additional completions expected during the fourth quarter.

Moving forward to slide 23 in our Rough Rider area. In this area, we've had 30 consecutive completions with average IPs of 2,487 barrels of oil equivalent per day and we've just bought online our record well for the area, the Abelmann 23-14 #1H

At an early peak 24-hour rate of 4,169 barrels of oil equivalent per day. This well is located in the lower portion of the map, just right of center. The Abelmann is an example of our continuing to tweak how we drill and complete these wells to generate further improvements in well performance.

We also recently brought online our first operated Three Forks well in Rough Rider, the State 36-1H # 2H at a peak 24-hour rate of 2,356 barrels of oil equivalent per day, which continues to perform well. Its seven-day average rate is in the range of our Ross area Three Forks Wells. It's at the upper right with the purple label. This well is – this is obviously a significant catalyst for us, a first step toward moving up to 362 net Three Forks locations into the core derisked inventory category. We're planning to drill at least three more Three Forks Wells in Rough Rider during the first half of 2011, which we hope will further derisk Three Forks in the area.

At the bottom of the slide, you could see how early we are in developing our acreage here. But we should have essentially all of the acreage held by production within the next three years. With continued Three Forks success, we could potentially drill six total wells per unit for full development, three Bakken and three Forks wells, or possibly more if our density drilling pilots determine that we are drilling less than about 880 feet away from our laterals.

Slide 24 illustrates our current three well pilots underway in Rough Rider. We've just brought online the Brad Olson #2H, which was completed with 32 frac stages at an initial rate of 2,717 barrels of oil equivalent per day. This well is an immediate offset to the Brad Olson #1H, which was completed with 28 stages and commenced production at an additional rate of 2,112 barrels of oil equivalent per day.

Although it's early, the early results for the Brad Olson #2H are quite encouraging, given that the well is located as close as about 1,080 feet to the Brad Olson #1H and its average distance from the Brad Olson #1H is about 1200 feet. That distance is closer to that we would expect to have for a four-well spacing program.

We also recorded micro seismic over this completion, in an effort to monitor and measure the extent of the frac wings.

We plan to stimulate the Brad Olson #3H later this month and we will record micro seismic here as well. It's early, but at this point we are optimistic that we may have the opportunity to drill more than our currently planned three wells per spacing unit. If we can drill four to six wells per spacing unit in our Rough Rider area alone, our derisked development drilling inventory could increase by approximately 120 to 360 net wells, which would represent a significant net asset value enhancement.

On slide 25, you can see the location of our currently underway three well density pilot and the location of our first four-well density pilot, which is planned to commence in the second quarter of 2011. It's likely we will record micro seismic during this density project as well. So that wraps up Rough Rider, where we currently have three rigs working and one well currently fracing.

Moving briefly to slide 26 to Roosevelt County in eastern Montana, inclusive of our Rogney well, we now have four apparent Bakken discoveries fairly proximal to our approximately 75,000 net acres in this area. The most recent of which is the Zenergy Amazing Grace 11-2H on the east side of the slide near the state line. This is another encouraging data point. The well had an apparent initial rate of 1,168 barrels of oil equivalent per day, a comparable early rate to the Sweetman well to the west in the same area.

In drilling and completing our first well, the Rogney, which came on for 909 barrels of oil equivalent per day, our primary goal was to learn as much as possible on this first test to accelerate our learning curve, which will now benefit us on our subsequent wells. So we didn't optimize performance with the Rogney, but we will now attempt to do so in our two wells planned for this quarter.

We are currently drilling the Swindle and immediately afterwards, we plan to commence the Johnson in Richland County later this month. The swindle should be fraced in December or January while the Johnson is currently scheduled to be fraced in January.

In addition to our wells, there's accelerating activity by other operators. We are participating in the Zenergy Beulah Irene 19-18H on the east side of our acreage block, about five miles east of our currently drilling swindle well. The Continental Baxter, which is located south and west of us, is another key well to watch.

So wrapping up for Montana, we have one rig working in this area. There are other operators who are also very active, helping to delineate economics in this portion of the play.

Last for my section, slides 27 and 28 illustrate one of our legacy assets that appear to be blooming for us. In this area of West Texas, we have over 11,000 gross and over 2,000 net acres with a total net reserve potential in the Wolfberry of approximately 5.6 million barrels of oil equivalent per day. This area has seen an accelerating level of M&A activity with very high values per acre paid for the associated Wolfberry inventory.

We are currently drilling our own well and participating as a non-operator in other wells to further delineate the value here and could potentially divest this area during 2011 to redeploy to the Williston. We have other legacy acreage and increasingly active resource plays such as the Anadarko Basin that could similarly generate incremental value for our shareholders and capital for the Williston Basin.

That concludes my portion of the call. Now I'd like to turn the call over to Gene for his financial update. Gene?

Gene Shepherd

Thanks, Bud. Given the roughly 45 net horizontal Williston Basin wells that we expect to drill in 2010 and the impact that these wells are having on our year-to-date production volumes and financial performance and will have on our fourth-quarter volumes and year-end proved reserves, 2010 is clearly a transformational year for Brigham Exploration.

As we continue to grow through our drilling program and our attractively priced acreage acquisitions, our inventory of relatively low-risk horizontal Bakken and Three Forks development locations, we continue to focus our efforts around initiatives to mitigate execution risk. As we have discussed, these efforts, together with our timeline for drilling our Williston Basin development locations, will largely determine how our shareholders will benefit from this huge relatively low risk reserve growth opportunity that lays in front of us. As an analogy, we have invested the resources and capital to build the factory and are now focusing on how many hours a day to run the factory and how to optimize its performance.

Before we review our financial results for the third quarter, I thought I would update you on several of these risk mitigation initiatives. Initiative number one, our efforts to mitigate commodity price exposure – lower oil prices represent the single biggest risk to the company. And since we negotiated to amend our credit facility to capture additional hedge capacity in May, we've been actively adding to our oil hedge volumes.

As depicted on slide number 30, at present, we have 4.5 million barrels hedged from October 2010 through September 2012, with a floor price of $65.39 per barrel and a cap price of $100.62 per barrel.

Further, our current strategy is to keep 100% of our PDP volumes hedged and up to 100% of the incremental production associated with a four-rig program hedged for up to two years, giving us meaningful protection during this critical period when we will be converting our core acreage to held by production.

Furthermore, our current strong operating margins, driven by the oily nature of our production volumes and our relatively low per unit costs, also provide protection against a downturn in commodity prices.

During the first three quarters of 2010, our operating costs were approximately $21.51 per barrel of oil equivalent, which includes LOE, production taxes, G&A and realized differentials for our oil and natural gas volumes.

Initiative number two, our efforts to enhance corporate liquidity, with close to 600 derisked development locations in the inventory and this assumes only three locations per drilling unit. And no contribution from either the Three Forks and Rough Rider or from our 105,000 net non-core eastern Montana acreage, maintaining a somewhat over-capitalized balance sheet is a key corporate goal.

Two recent developments have significantly enhanced the company's liquidity position. First, our $300 million senior notes offering that we completed in September reflects a continuation of our philosophy to pre fund our future drilling activity out beyond 12 to 18 months. After using the proceeds of the new notes offering to retire our $160 million in senior notes to 2014, the new notes offering has left us with $315 million of cash and short-term investments on the balance sheet at September 30.

Assuming October 28 strip prices, our current eight rig case and our current $7.5 million E&D [ph], this cash position and next year's cash flow should fund our 2011 E&D budget and leave us with close to an undrawn credit facility at year end 2011. The availability under the credit facility and the proceeds from any potential conventional asset sales may serve as additional sources of liquidity that could further – that could fund further drilling acceleration in 2011 and or our 2012 E&D budget.

Second, our credit facility borrowing base was recently reevaluated and Bank of America, who is our lead bank, was prepared to recommend a substantial increase to the borrowing base from $110 million currently to $225 million based on our strong Williston Basin drilling results.

Because of our significant current cash position, we did not believe that there was a need to pay for an increase in the borrowing base at the time and is elected to leave the borrowing base at the current $110 million level. We will revisit the need to increase the borrowing base in May of next year.

Finally, as depicted on slide number 31, based on the $350 million of cash and short-term investments on the balance sheet at September 30. And assuming the reevaluated but unappproved borrowing base of $225 million. Brigham has $540 million of total or potential liquidity available to it at the end of the third quarter.

Initiative number three, our efforts to plan for a future drilling acceleration – first, the 15% increase in our 2010 E&D CapEx that we announced yesterday and is depicted on slide number 32. And the opportunity this year to drill an additional seven net Williston Basin wells represents one additional source of drilling acceleration.

As we've already discussed, our current liquidity position could fund a level of drilling acceleration beyond the eight rigs that we had targeted to reach by May of next year. At present, we are in discussions with our service providers about securing additional rig, pressure pumping and profit capacity. And look forward to updating you on our drilling plans along with our 2011 CapEx budget early next year.

Now, I want to briefly review with you our record results for the third quarter.

In our third quarter, total production volumes average record 8,509 Boes per day above the high end of our Q3 production guidance and an increase of 10% sequentially and 64% from that in the third quarter of 2009.

More importantly, given our focus on drilling our Bakken and Three Forks wells, which are predominantly oil, our third-quarter oil volumes averaged 6,356 barrels of oil per day, an increase of 14% sequentially and 144% from that in the third quarter 2009.

Our Q3 oil volumes represented 75% of our total production volumes. More importantly, because of the substantial pricing disparity of oil versus natural gas, which we are fully able to capitalize on by focusing our drilling in the Williston Basin, our oil revenues represented 87% of our total third-quarter pre-hedge revenues.

As far as the income statement is concerned, increases in sales volumes, commodity prices and cash hedge settlement gains during the quarter increased revenues by $19 million, $6 million and $0.5 million, respectively. This resulted in a 134% increase in revenues, excluding the impact of unrealized hedging losses to $44.4 million, which was also a company record.

On a pre-unit basis, lease operating expense decreased 25% to $5.23 per Boe in the third quarter 2010 from $7.01 per Boe in the third quarter 2009.

Higher production volumes, a 30% decrease in the dollar amount of our workover expense and a 20% decrease in the dollar amount of our ad valorem taxes accounted for the decrease and were partially offset by a 33% increase in the dollar amount of our operating and maintenance expense. The increase in the dollar amount of our O&M expense was driven primarily by higher saltwater disposal and equipment rental expense.

On a per-unit basis, production taxes increased to $5.61 per Boe in the third quarter 2010 from $3.31 in the third quarter of 2009. Due to the growth in our North Dakota oil volumes and the higher associated taxes, production taxes were 9.7% of pre-hedged revenues in the third quarter 2010 compared to 8.3% of revenue in the third quarter 2009.

In addition to the growth in our North Dakota oil volumes, higher commodity prices and the associated increase in revenues in the third quarter 2010 also contributed to the increase in production taxes over that for the comparable period last year.

Our per-unit G&A expense decreased by $0.16 per Boe to $4.29 per Boe. Our higher production volumes drove the decrease and was partially offset by an increase in the dollar amount of our employee compensation expense.

The growth in our oil volumes and the associated increase in our revenues contributed to an 11% sequential increase in EBITDA during the third quarter to $36.8 million. Further, the growth in our oil volumes and the higher commodity prices contributed to 178% increase in EBITDA during the third quarter of 2010, relative to that in the prior year's quarter.

Our earnings, excluding the loss on the early redemption of our senior notes and our non-cash hedging losses, which is reconciled in our press release issued yesterday, was $18.1 million or $0.15 per share.

Moving on to the balance sheet, at the end of the third quarter, we had $315 million of cash, cash equivalents and investments, $300 million of senior notes due 2018 and nothing outstanding under the senior credit facility.

Further, at October 29, we had approximately $294 million of cash, cash equivalents and investments on the balance sheet.

In our earnings release yesterday, we provided an update on our spending plans for the remainder of 2010. As far as our E&D CapEx for the year, we are now expecting to spend a total of $466.1 million, representing a 15% increase in our spending relative to what we had announced in August. Higher drilling CapEx accounts for $40.3 million of the increase and will fund a 5.4 net additional Brigham operated Williston Basin wells.

The drilling capital to fund 1.6 net additional non-operated wells in 2010 is roughly offset by the completion capital associated with our Williston Basin wells, which was spud late in 2010, but will not be completed until January. This budget now has us drilling 44.8 total net Williston Basin wells for 2010.

Higher acreage acquisition and land CapEx accounts for $18.6 million of the increase. Roughly 50% of this increase went to the previously announced 6,000 net acre acquisition in our core Rough Rider project area and the remaining 50% will fund our ongoing organic leasing efforts that will primarily target our current core areas.

Also in our earnings release yesterday, we provided production guidance for the fourth quarter of 2010. In terms of our expectations for the fourth quarter, we are forecasting our total production volumes to average between 10,200 and 10,800 barrels of oil equivalent per day, with 77% of these volumes anticipated to be oil.

Using the midpoint of our guidance for the fourth quarter, would result in 2010 full-year production growth of 59% over that for 2009 for our total production volumes and 155% for our oil volumes.

This forecast reflects the continuation in the production growth that is being driven by our highly successful horizontal Bakken and Three Forks drilling program, which should take Brigham once again to record total production volumes in the fourth quarter with the expectation that we will continue to generate record volumes in 2011.

I will now turn the call over to Lance.

Lance Langford

Thanks, Gene. First I will update you on the execution of our current plan and how we are positioning Brigham to accelerate activity in the future as the opportunity arises. Then I will discuss why we believe the perf and plug method and more stages will result in better economic returns and much higher oil recoveries and our attempt to achieve our goal of “No Oil Left Behind”.

If you will move to slide 34, we currently have contracts or firm commitments in place for all critical services and products providers required to execute on our current plan. These contracts have enhanced our ability to control timing and costs such that they anticipate being able to deliver predictable and repeatable organic growth for our shareholders.

In terms of drilling services, we currently have six rigs under long-term contracts, and we have a firm commitment to go to eight rigs by May of next year. Our seventh rig will commence operations mid-November, and the eighth rig in May of next year. In addition, we are currently in discussions with neighbors to provide two to four new walking rigs in 2011. These new rigs will allow us to drill multiple wells on one location, resulting in time and cost savings for both drilling and completion operations. These rigs will either replace our currently working conventional rigs or provide future acceleration.

In terms of completion services, we have contracted with Halliburton to increase from our current 1.5 dedicated frac crews to two dedicated frac crews in first quarter of 2011. Each dedicated frac crew can complete four wells per month. With two dedicated frac crews operating beginning in 2011, Brigham should be able to frac eight wells per month, which matches our output from our planned eight-rig drilling program.

We are also in discussions with multiple service companies to provide a potential third frac crew in 2011, if the opportunity to accelerate arises. These discussions have been very promising so far. We also have contracts and commitments for ceramic proppants to mirror our frac crew capacity that I just outlined.

As we've outlined in the past, we are building oil, water and gas gathering systems, including disposal wells, to enhance our control and minimize the costs related to transportation and handling of these products. Currently, our water and oil is transported to and from the well location via truck.

Additionally, produced water is disposed of via third-party disposal wells. To accomplish our goal of enhancing control and minimizing costs, we dedicated a portion of our proceeds from our April equity offering to efficiently move our volumes via top line and dispose of our produced waters at our own disposal sites.

Our infrastructure development plan also includes building a regional office in Williston, North Dakota to provide more direct oversight of our operations around our 368,000 net acres. Through the end of September, we have spent a total of $16.3 million on infrastructure, 45% of the total $36 million budgeted for 2010. We currently have two planned gathering systems. The first system, our Ross gathering system, is located east of the Nesson Anticline in Mountrail County.

The second, our Williams gathering system, is located west of the Nesson Anticline in Williams County. We anticipate building a third gathering system in McKenzie County, North Dakota in 2011 or later.

If you will move to slide 35, our Ross gathering system consists of gas gathering line and a produced water gathering line, each of which extends over 30 miles. Currently, our gas gathering line is actively moving our Ross area gas to Whiting's processing plant.

In terms of our produced water collection and disposal, we began gathering the produced water via our pipeline and disposing of this water in our Ross disposal well in late September.

We currently do not have any oil gathering capability in the Ross area, but we may consider construction of such a facility in the future.

If you will move to slide 36, our planned Williams gathering system will consist of three separate gathering lines, each of which extends over 104 miles. The oil gathering line will collect and transport the produced oil to our central collection facility and then have the option to go to multiple major pipelines or rail loading facility.

The produced water line will gather water and transport it to our disposal well, which will be located adjacent to our Williston regional office. We will add additional disposal wells along our gathering system as our water disposal needs expand with our drilling program.

We also have installed the fresh water lines that will take fresh water from several sources for delivery to our wells. This fresh water will be utilized for frac fluids and for treatment fluids after the wells have gone on production. This entire system should be fully operational in 2011.

If you will move to slide 37, our master plan is to also build a gathering system in McKenzie County in 2011 or later. This gathering system will be similar to the Williams system and consists of three separate gathering lines, each of which will extend approximately 34 miles.

To ensure that we are able to move our produced oil for the best price, we have multiple oil contracts in place which will ensure adequate take-away capacity for our 2011 production volumes.

Further, we are also working on oil purchasing contracts for 2012 forward and a rail option to ensure we can move additional barrels if necessary.

To ensure we effectively manage the 368,000 acres, we promoted Russell Rankin to regional manager, and he and his family have moved to Williston, North Dakota. Russell is currently managing our Williston Basin field operations from a temporary office in Williston, North Dakota. Our permanent Williston regional office is currently under construction and is expected to open in the first quarter of 2011.

Now if you will move to slide 38, our plan is to continue to utilize the perf and plug method because we believe that more frac wings are created than when using the frac sleeve technology.

As I will show you in a minute, the relative production performance from nearby wells supports this view. Further, from previously acquired micro seismic, we observed that a frac wing was initiated and grew where the wellbore was perforated. Also, we know that without the presence of a perforated section of rock, as in the case of the frac sleeve method, it can be difficult to initiate and grow one or more frac wings. When utilizing frac sleeves, we would generally expect only one frac wing to be grown per stage.

In this slide, we will assume two wings are being created to be conservative. We also believe when using perf and plug method, at least four frac wings will be created because we have four separate sets of perforations for each stage.

If two wells are completed with similar sized frac jobs, the perf and plug well will create two times as many frac wings and those wings should have about half the length compared to the well using frac sleeves.

If you will move to slide 39, this conceptual slide shows you that in a 1280-acre spacing unit, with 20 stages utilizing frac sleeves, a three well per unit spacing is most effective. But notice the oil depicted in green that could be left behind between the frac wings.

Moving to slide 40, this conceptual slide shows that in a 1280-acre spacing unit with 20 stages of perf and plug, a four-well per unit spacing may be the most effective. But notice the oil that can be left behind between the frac wings has been reduced.

If you will move to slide 42, what is remarkable is that our wells using perf and plug shown in red continue to outperform offset wells using frac sleeves shown in blue. So in this case, we would have higher EURs per well and more wells per 1280 acres, so we believe we are getting both better economics per well and much higher oil reserves recovered for 1280 acres.

Now moving to slide 43, as we increase the number of stages from 20 to 30 and continue to use the perf and plug method, keeping the overall pounds of profit for each well constant, our frac wings continue to shorten. For example, we typically pump 2.5 million pounds of profit per well. On a 20 frac stage well, this means we pump 125,000 pounds of profit per stage. On a 30 frac stage well, that means we pump approximately 83,000 pounds of profit per frac stage.

As we pump less profit per stage, the frac wings shorten. Furthermore, as we pump more stages, we believe we are more efficiently – more effectively breaking up the rock along the entire length of the wellbore. And, therefore, the undrained areas between the frac wings continue to reduce. Once again, this enables us to reduce the oil left behind and increase our recovery of the original oil in place.

In conceptual slides 44, for our wells with 30 stages of perf and plug, a six-well per unit spacing may be the most effective. But notice the oil that could be left behind between the frac wings has been dramatically reduced.

If you'll move on to slide 45 and even more remarkable is our reserves per well as we continued to increase – the number of stages continues to improve. So in this case, we would have higher EURs per well, more wells per 1280, resulting in better economics per well and much higher oil reserves per 1280 acres.

By next year, we hope to delineate the optimal number of stages per well for our different areas and the coinciding optimal number of wells required to drain 1280 acres. This will ensure the best economic outcome with the largest reserve base working towards our goal of “No Oil Left Behind”.

That completes my operational overview and I will now turn the call back over to Bud.

Bud Brigham

Thank you, Lance. That completes our prepared comments. Gen, we'd be happy to answer any questions.

Question-and-Answer Session

Operator

Thank you, sir. (Operator Instructions) Our first question comes from Brian Lively with Tudor, Pickering, Holt.

Brian Lively – Tudor, Pickering, Holt

Good morning, guys. Just on the down-spacing pilots, what metrics are you using to measure success? And then how long do you think it will take before you really know whether or not there's long-term interference on the wells?

Lance Langford

Well, Brian. This is Lance. First of all, we're going to basically measure the distance between wellbores and we'll be looking using micro seismic where we have micro seismic available, to try and get an indication of when and where and how far and how many frac wings are created.

Then we will be also looking at offset pressure communication. Then from that, we will use of course the production information starting with IPs. But we really need – to really get a good indication for if there's drainage or not drainage or how much drainage or whatever, we need probably a six month to a year production to get a good feel for that. But I think it's a combination of all those things. But it's really going to take six months to a year. So this time next year, we ought to have a lot firmer feel on what the drainage issues are if any.

Brian Lively – Tudor, Pickering, Holt

And then as you think about balancing activity levels with inventory, do you guys have a target years of inventory, where you would think was optimum based on NAV?

Bud Brigham

Brian, this is Bud. Maybe I'll start and these guys may want to add to what I have to say. I mean we've been in a window and there's still some degree in a window where we have had an outstanding opportunity to capture value for our shareholders out here. And, as far as – and so that’s our continued success organically, picking up acreage and with a few selected transactions as you know this year, we picked up on more acreage in our core areas on a very attractive basis. That window is going to close on that, but we want to continue to do that. And then of course, operationally, what where we’re talking about is trying to figure out how much in reserves we have to develop here, and how efficiently, and how to do it as efficiently as possible. So, we want to – our objective of course is to create as much value for the shareholders as possible. Then it comes down to what’s the most optimal sources of capital to turn that in the ground value into production and cash flow. Gene, do you want to add?

Gene Shepherd

Yes. I think you’re right. I think it’s – there’s two pieces. It’s the aggregate, sort of the growth of this big asset position that we’ve accumulated both the core and non-core then over time moving what is non-core into core, but then drilling down, then it’s – and so you have this inventory of development locations that we’ve talked about that are in our core areas. And then really, it’s about how do you accelerate and how do you bring forward those locations. Obviously out beyond five years, we’re not getting a lot of credit for drilling locations in year, for example, 2020. So, how do we accomplish additional acceleration and bring forward more of those locations in order to create more net asset value for our shareholders? So –

Brian Lively – Tudor, Pickering, Holt

Do you guys – I mean is that five years? Is that 10 years? Is that 20 years?

Gene Shepherd

Well, it’s changing. We continue to grow our – the number of development locations, and those locations – those number of locations will continue to grow next year, certainly as we de-risked the Three Forks over the Rough Rider and de-risked our Montana acreage. I don’t think we really have a timeline for developing all the development locations. I think our overriding goal is to try to find ways to bring those locations forward. Because obviously, and certainly as we did a lot of financing with equity in 2009, I think recently we have used some debt and there’s certainly opportunities to use additional debt, and that will create us – that will give us some additional opportunity to fund additional acceleration in certainly selling the non-core assets. So those initiatives, the debt initiative and selling the non-core assets will allow for a level of acceleration that we really haven’t talked much about, but certainly we are working on.

Brian Lively – Tudor, Pickering, Holt

Great. Thanks, guys.

Gene Shepherd

Thank you.

Operator

The next question is from John Freeman with Raymond James.

John Freeman – Raymond James & Associates

Good morning, guys.

Lance Langford

Good morning, John.

John Freeman – Raymond James & Associates

First question I had, last year, Lance, you’ll used to show in your presentation the – as you increase the number of stages, the cost per stage on the frac stage generally was trending down. Obviously, we’ve had pressure pumping costs have gone up dramatically since then, and I am curious like on the Clifford Bakke well, what the completed well costs was on that well and then what, on a per-stage basis, the cost was?

Lance Langford

This is Lance. So, let me just answer. Our general 30 stage well, AEPs [ph] is about $7.5 million. So, as we go above 30 stages, each stage adds approximately $40,000 per stage. And, as they go below 30, they reduce by 30,000 per stage. So you can adjust it depending – get you a good estimate depending on how many stages were completed. And on the Clifford Bakke, I think it was a 38-stage well, if that’s correct. And so you could add 8 times 40 to that 7.5 million should get you pretty close.

John Freeman – Raymond James & Associates

Okay. Great. And then, moving over to Montana, if you just had one rig running in 2011, does that allow you to hold the acres that you need to hold by the end of 2011 there? Or is it a deal where you’re going to wait for the results and then you’re going to end up having to add an additional rig to be able to hold that acreage, if it proves successful early on?

Bud Brigham

Yeah, this is Bud. Yes, right now, we are trying to delineate what is the economics of the areas, and I think based on the early indications, we should move more of it into the de-risked category over time. But, so that will help us determine what acreage we’re going to make a real effort to HBP, and if necessary to extend, but primarily to HBP. So there could be some acreage that we deem to be – it’s not based on the results, not to be core, and certainly we would be willing to let a lot of that acreage go. Jeff, do you want to add to that?

Jeff Larson

Yes. Just real quick, also there’s our activity with the Swinde well and our Johnson well, which we are planning on drilling – which has been – really going to help us delineate some of this acreage. Also, there’s a fair amount of industry activity that Bud spoke to. There’s about four or five other operators drilling in eastern Montana currently, so we’re very interested in their results also to help us optimize the acreage and decide how quickly we need to accelerate.

John Freeman – Raymond James & Associates

Great. Thanks, guys. I’ll turn it over to somebody else.

Jeff Larson

Well, thank you.

Operator

The next question comes from Subash Chandra with Jefferies.

Subash Chandra – Jefferies

Hi. Good morning. I don’t mean this as a softball question, but, I am seriously intrigued. Looking now at the IPs, 30 days, 60 days, how confident are you in areas like Rough Rider, specifically that the upper boundary of EURs will be 750?

Lance Langford

Well, this is Lance. So, in Rough Rider, it’s a large area of course, right, if you look at the overall gross acreage that Rough Rider contains. But, we have varying results from one end to the other. The good news is, we have really good economic results across it. We haven’t disclosed what the range is on the outcomes in Rough Rider. What we have disclosed is, is that overall in the Bakken plain itself, that the average of all of ours are going to fall within the 500 to 700 million Boe top wells. So –

Bud Brigham

Well, do think it may be early next year as we get – you know, we’re accumulating more data that, particularly after UN we may be able to provide more definition of the different areas and maybe some different EURs for different areas?

Lance Langford

And I think we’re going to see better EURs based on us tweaking our completion techniques.

Subash Chandra – Jefferies

All right. So, as you sort of describe the results over a very broad area from the early wells to the latest, and with some of these later wells doing as well as they have, how much of the change in performance would you attribute to geology over the Rough Rider area? And how much would you attribute to completion design? Or in other words, if you look at the entirety of Rough Rider, how much do you – how much of a role do you think geology plays versus your completion techniques?

Bud Brigham

This is Bud. I’ll probably start and Jeff will follow up, and Lance will probably add, but clearly geology plays a significant role as there’s variability through the area. And then you just overlay on that the technology in a given area to improve the results.

Jeff Larson

This is Jeff here. I just would add – and I think we’ve spoke to this in previous calls, we were fortunate to be one of the early movers in Rough Rider and there’s lots of historical working data points. And we optimized our acreage on the West Williston Bakken porosity. That being said, there is variability in the (inaudible) rocks.

Subash Chandra – Jefferies

Okay. Got it. And my second question is, in Richland County, and you referenced the Baxter well, in Richland County, looking at your – at the shaded boxes of your acreage position from east to west, how – how different do you think that might be from Rough Rider, or how similar? And do you – Continental seems pretty confident that they could use your Rough Rider techniques, and re-invent that northern extension of the play. And was curious what your thoughts were there?

Jeff Larson

Jeff again. You know, when we started right against the state lines, real proximal to the (inaudible) townships, there is (inaudible) probably develop our acreage from east to west across the eastern Montana area; very confident about that area. We’d really like to look for that. That’s where our Johnson well is going to be. As you continue to go westward, the Continental is drilling west of us. They are now completing the Baxter well. And we – and I think you also realize they’re also permitting others wells directly to the west of us. So they are bullish to the west of us which we’ve got very encouraged about the western edge of our block.

Also, Ursa and others are very active in that part of the play. And so we’re very intricate in that and here going to (inaudible) some of those wells.

As you go to the northwest of the (inaudible) had some very good encouragement. We talked about – it has been on the call as Zenergy. And then also remember the Zenergy sleeping well is a real nice early time data points, basically north of our block.

And then as you continue to go through the north when you get up around the Sweetman, as you go to the northeast of our Swindle well, the EOG has permitted over 40 locations. We’ve got a company called Cardinal very active to the north of us. And folks are well aware that Widing [ph] has just come in and picked up over 100,000 acres real profitable for us in the north and to the east. So we think their activity is going to pick up significantly.

Subash Chandra – Jefferies

Okay. And just one final one for me. Could you just remind me what Richland County net acreage is first and second? Do you know by any chance how many stages were used in the Amazing Grace? And how many do you plan to use – is being used in the Beulah Irene?

Bud Brigham

Jeff, real quickly on the Beulah Irene –

Jeff Larson

Yes.

Bud Brigham

Go ahead.

Jeff Larson

Beulah Irene was 28 stages. And the Richland is 105,000 acres that’s – Richland, I’m sorry.

Bud Brigham

But together we don’t have a breakdown by county. But the – that’s what we call the greater (inaudible) area is 75,000 net acres. But it’s – we don’t have a breakdown in front of us of the Richland versus regional county.

Subash Chandra – Jefferies

Okay. And, Amazing Grace, any idea how many stages employed?

Bud Brigham

I don’t. They’ve been – the way they’ve gone about it has been approaching our recipe. So we would – we don’t know, but we would expect that it would be a high number of 20 to 28 stages probably.

Subash Chandra – Jefferies

Okay. Great. Thank you all.

Operator

The next question is from Derrick Whitfield with Canaccord.

Derrick Whitfield – Canaccord

Good morning, guys.

Bud Brigham

Good morning, Derrick.

Derrick Whitfield – Canaccord

Based on your completion enhancement testing to date, are there any generalizations you guys can make about your experience and what you have learned in your core project areas? And I’m specifically interested in your thoughts on the other variables outside of stages?

Bud Brigham

Well, I mean this is Bud. We – Lance’s team is doing a lot of innovating, and we haven’t a number of different areas where we are isolating other variables and just varying one element, and we’re learning a lot from that. We’ve not – so I think you are seeing that in some of these recent wells. We’re not to the point yet that we are ready to talk about that, you know, about other elements and the role that we are having because we are real early and we’re just beginning to get some data, but we are encouraged. We are continuing to see improving well performance.

So, I did think it illustrates that we are continuing to move down the learning curve and advance the economics of the play. So, I think – it just – I think to me, you got like the trend that the results continue to improve.

Lance Langford

Yes, Derrick, this is Lance. I think one thing is we want to make sure that our early-time improvements materialize into EURs and long-term improvements. So it takes some time that we really want to analyze it before we start – and understand it before we release results.

Derrick Whitfield – Canaccord

Thanks, guys. That’s helpful. And then maybe, as a follow on to the previous question on your inventory, would be interested in what specific sort of organizational objectives you guys would need to check off before pursuing any more aggressive development program.

Bud Brigham

This is Bud. These guys will probably add to it, but just as we ramped up from 1 to 4 rigs and then 4 to 8, we try to be very incremental and try to be sure that we put out and move forward with a plan that we can deliver on. And so, all of the elements that are necessary to accomplish that are being worked on, whether it’s personnel and Lance talked about the equipment and the services and all. So we’re very deliberate about lining up a program before we come out and are committed publicly to moving forward with it. I don’t know if you guys want to add anything.

Lance Langford

Yes, Derrick, I might just add that you know, it takes a lot of time and thought to do it well, and we are preparing ourselves even though we are not ready to go ahead and accelerate. We are preparing in every avenue to be prepared so that we can do it seamlessly like we have in the past. So –

Derrick Whitfield – Canaccord

Got it. That’s good. And do you guys think you have the personnel and staff today to go to a 10 to 12 program or would that also require some additions as well?

Lance Langford

I think it would be small additions. I think we have the base group. You know we’re not going to take on four rigs overnight; that’s just not how we operate. So, it would give us the lead time we need for the personnel that we need to add. I think Jeff and I and David and all our groups would add some personnel, but as a percentage, it would be very small.

Derrick Whitfield – Canaccord

Terrific. Thanks for the color there, guys.

Bud Brigham

Thank you.

Operator

The next question comes from Ron Mills with Johnson Rice.

Ron Mills – Johnson Rice

Good morning. Couple of questions. One, on just the Olson infill program, in the first well, 2100 barrels a day and 20 stages and – I think it was 20 stages, and then 28 stages for this one at 2700 barrels a day, any differences in the completions other than just the number of frac stages? Or how are you comparing and contrasting those initial wells?

Bud Brigham

Just more frac stages is the only difference.

Jeff Larson

Actually from – the infill wells are all at the same stages.

Bud Brigham

Yeah, but from the Olson 1 to Olson 2, we have more stages.

Ron Mills – Johnson Rice

Okay. And in the Olson, you’re going to maintain just testing it, a three well program, but it sounds like from a spacing standpoint, it would be equivalent to a four well in spacing. I just want to clarify. Are you doing the four-well infill program, are you going to test that in Rough Rider or Ross next year?

Bud Brigham

Well, we’re going to – we’ve got a four well pilot plant for both Ross and one for Rough Rider. And, yes, I’m glad you picked up on that, Ron. I talked about the fact it is interesting when you look at the Brad Olson #2H relative to the 1H, it averages about 1200 feet away from the 1H. So, I think it’s a very early data point, but it’s an encouraging data point that the Brad Olson 2H came on at a higher initial rate and we will have to see how it performs over time. But that spacing, 1200 feet, it’s more closer to what you would have with four well density drilling as opposed to three. So, it’s a really encouraging but also very early data point that we have there.

Ron Mills – Johnson Rice

Okay. And, Lance, I think you talked about – you were talking to neighbors about walking rigs for 2011, and also while at the same time talking to completion companies about a third dedicated frac crew. I mean – I assume it’s fair to read into that, that the preferences to accelerate next year as opposed to let two of your conventional rigs going. And if that’s the case, when you look at Ross versus Rough Rider versus the growing Montana activity, how would you foresee that rig schedule being allocated?

Lance Langford

Well, as far as replacing the rigs or accelerating with those rigs, right now, the decision hadn’t been made. We’re just trying – were all trying to prepare for acceleration, if the opportunity is there, the financing – if we sell, divest of some of our assets, and that opportunity is available for us. So, right now we haven’t made the decision. We’re not pulling any triggers on accelerating. So really we’re just trying to prepare for acceleration if it happens.

As far as if it does happen, where would you accelerate rigs? I think that depends on how much success we have in Montana, and how much success we have in the Three Forks and Rough Rider. And we will continually – Jeff does this on a daily basis or weekly basis, probably daily basis. He looks at where the need is. And he has to balance expiring leasehold with where we add the most production or where we add the most reserves. So it’s a constant changing process, and with the success in Montana, we will need additional rig there, at least the one additional. So –

Ron Mills – Johnson Rice

Okay. And then, when you all talk about your all’s inventory, you talked about 9900 acres in Montana being de-risked or I guess core is the way you describe it. And that’s the acreage that you have closer to the Southern [ph] Sick well.

Just out of curiosity, what’s the thought process, given you have a Rogney well up towards the northwest with EOG data and other data, at what point do you – what’s going to require to start pulling some of that incremental acreage into your core in Montana?

Jeff Larson

Hey Ron, Jeff here. Just real quickly, the two townships that are directly west board of the Sedlacek [ph] we think are de-risked. And the big drivers there obviously is our (inaudible) control point, which is the east side.

And then directly to the northwest of those townships, we’ve got the Zenergy Sweetman well, which is good – really timed well with an EUR over 300,000 barrels. And we think we can definitely do better with our completion technology, so that’s the logic of that first acreage block.

And then, going forward, the big drivers of the – as you move further to the northwest, our Swindle well is going to be a real important piece of business. That is where we’re going to try our full Rough Rider style frac. So we will have a long lateral with the multistage. And then also, we bought the Zenergy well eastward of us is a real important data point, as are the continental wells. So we’re continuing to just monitor the industry activity and also, the Sweetman well and our Johnson well are going to be big, important data points for us in eastern Montana, and that’s towards year end and early next year.

Ron Mills – Johnson Rice

And, depending on results from Swindle, is it fair to assume that more your activity because you have more data points at this point, would be more focused in that southeast portion down around the Zenergy and Johnson and Sedlacek wells versus up around your Rogney? And if so, is there something driving that geologically, a difference or is it just a lack of well data?

Jeff Larson

I think it’s just pretty much control points and I think we’re going to be really driven by our success. Swindle, if that becomes a strong data point for us, you’ll see us certainly accelerate our activity around the Swindle, as with the Johnson.

Ron Mills – Johnson Rice

Okay. And then Gene, one just financial question, you have eight rigs to come on – the eighth rig to come on in May. At what point are you all – how many wells are you all now factoring in to drill per rig? Just trying to get a sense; obviously the CapEx levels will run up from the fourth-quarter run rate because you are adding rigs throughout the year. But, just trying to get some sort of sense as to how many rigs or wells each rig can drill now?

Gene Shepherd

We’re assuming for modeling purposes, $10.5 million, Lance – with these initiatives he’s working on, his team is working on, with that over time, you can see some improvement there. So, but for modeling purposes today, we’re forecasting $10.5 million.

Ron Mills – Johnson Rice

Okay. And the assumption is $7.5 million well costs, you all think that costs are starting to level off where that’s a pretty good run rate?

Lance Langford

Yes, I still think it’s $7.5 million for 30 stages and then it goes up or down $40,000 or stage. I think costs have kind of leveled off. I’m sure they are going up a little bit here or there, but once we start, like with our disposal systems and our gathering systems, as they start kicking in, that’s going to take our costs the other way.

Ron Mills – Johnson Rice

But the $7.5 million, if I look at your most recent wells, most of which have been kind of 34 to 38 frac stages, is that more the plan given the results you’ve seen? Or do you think that – I guess I’m asking, at what point do you think that frac – number of frac stages versus economic utility starts to break over?

Lance Langford

Yes; you know the – as far as the number of stages, we’re varying. We may be varying them a little more wildly – or widely in the near term. But we just need enough data points – we need 20 stages versus 30 stages versus 38 stages – you know, more of that. And so you’re going to see it vary back-and-forth. Right now a bunch of 38s, because we have a bunch of the 30, the 28, the 32 stages. So we’re drilling a lot of the 38 stages in the current areas, and then we will watch production.

But I would expect us to continue to vary until we find the optimal number of stages in each area. And we may ultimately have six different areas that we use different number of stages. I don’t know what the answer is yet.

Bud Brigham

We’ll just not say yet, Ron, as far as being able to give you more definition than that.

Lance Langford

I know you want – you’d really like a year of production on every well so you could really analyze it. Because you want to make sure the long-term and the near-term are both beneficial.

Ron Mills – Johnson Rice

Right. I understand. I was just trying to get gauge. It sounds like between 30 and 38 you’re talking about $7.5 million to $8 million well costs spread over a 7- to 8-rig program. And so, I was just trying to gauge what kind of level of CapEx that would be.

Gene Shepherd

Yes, just to give you some sense, if you exclude the wells that we announced yesterday, just the – so and looked at the last five wells that we have drilled excluding our more recent wells, the average costs have come in right around 7.3, or the average costs have come in around 7.3. So we’re in the neighborhood of the 7.5. And certainly I think we’ve talked about the fact that next year, we expect and who knows to see some moderation in service costs as additional capacity is moved into the basin.

Now that excludes those last five wells; I’ve excluded the Rogney and the Sedlacek. The Rogney was sort of a science experiment; and the Sedlacek, we had some settling issues with that location that added to our costs there.

Ron Mills – Johnson Rice

Okay. Great. Thanks, guys.

Lance Langford

Thank you.

Operator

The next question is from Scott Hanold with RBC.

Scott Hanold – RBC

Good morning, guys. So, can I ask you a question, in terms of when you’re looking at the potential down space ultimately to maybe six wells per spacing unit, you’ve talked about tonnage, about 2.5 million pounds of property being put away. Why wouldn’t you, on a say like a 30 stage frac, just increase your tonnage and potentially reduce the number of wells you drill? Can you talk about sort of the trade off there?

Jeff Larson

You know, I think that’s one of the things that go into optimizing your frac job. So, initially, we’ve been focused on the number of stages, and once we get the answer to that, then that’s another variable to start to vary. There’s things like that.

There’s things like the size of your (inaudible), the amount of proppant; the profit concentrations that you pump it at. Do you go to eight pounds? Can you go higher than that?

We’re varying lots, tweaking a lot of things like that, so I think that what you get is one of the important factors of frac design as we go forward.

Scott Hanold – RBC

Okay. Is – when you look at it just from the high level, is increasing the tonnage per well, if you can reduce the well counting – with the well count for spacing it by say 1 to 2 rigs on average, would that be more economically feasible because it’s going to be much cheaper than just drilling another well?

Bud Brigham

So, I think that’s one of the things that we have to determine. I think that’s one of the things that we’re trying to answer.

Scott Hanold – RBC

Are you like piloting something where you are testing higher tonnage levels or is that sort of the next stage after you do the four-well pilot?

Bud Brigham

You know, we’re in the process of testing a lot of the other variables other than stages currently.

Scott Hanold – RBC

Okay.

Bud Brigham

Just like we said earlier, we’re not ready to discuss those things because we want to make sure that our early time and long-term data supports itself before we start putting out results. So we need some time.

Scott Hanold – RBC

Okay. And on those four-well pilots in Rough Rider and Ross, when are they going to commence? When do you start drilling those pilots, and when can we hear some sort of initial results from some of that?

Bud Brigham

I think they’re both in the second quarter – April I think is one of them, I guess.

Jeff Larson

Yes, Scott, Jeff here. Yes, the Ross area, we’re looking at – I apologize, I’m shifting through my notes here. Ross area, we’re looking like April, May. And then in the Rough Rider area, it’s looking like May, June timeframe.

Scott Hanold – RBC

Okay. And when you think about going to four-well pilots, and then ultimately it could be six, how do you go about planning for that spacing? Obviously, there have been a number of wells drilled in this play already. And, so how do you attack sort of the architecture of actually orienting the wells and optimizing everything?

Bud Brigham

I’ll just make a general comment, but Jeff will have more specifics, but I mean clearly, part of the opportunity we have is we are early in our development but the sooner we can figure that out, the better because you have a legacy. As you have seen early on, operators thought they had to drill – or had to drill across lease lines but thought they would – to hold a 1280 and thus, Whiting and others have wells – diagonal wells, and it creates issues on subsequent development. We are blessed in that we don’t have that issue for the most part, and that sets up for more efficient development. So, we want to figure it out as early as we can. Jeff, do you want to talk more about that?

Jeff Larson

Yes, just to add a little bit more. The timing and the understanding of the density spacing is very critical. Just to expand on that, obviously, as you change you have to go back to the commission and read permits and work through density orders. So we are trying to be real proactive and really try to understand our optimal spacing. And also, we’ve – and we spoke a bit about this on the last call, we are also optimizing by drilling basically two adjacent standup 1280s together, basically drilling the first well and then you drill the second well, which optimizes Lance’s operations both drilling and completion. But that also helps us – we can drill a density well say in the 1280 in the south and we will drill our first well in the 1280 to the north. So we’ve really been able to optimize our activity in that regard as well.

And then Lance’s guys are also looking at pad designs. Do you build two large pads to drill all your wells on these two adjacent 1280s? So there’s a lot of those kinds of things going on also, and there is the need for subsurface easements as you drill off one pad into another 1280. So there’s lots of kind of detailed things that we’re working through very actively. And that’s why, as Bud pointed out, that’s why you’re seeing us move forward and drill these density pilots, so we can understand sooner as opposed to later and set up the most efficient density drilling.

Scott Hanold – RBC

Okay. Fair enough. And, I’m going to ask this question a little bit different; I know Ron and a few others have kind of addressed it. But when you look at, based on what you know today, when you look at sort of Easy Rider, Rough Rider in Eastern Montana, and I think maybe Easy Rider is probably the – obviously the most advanced, but what is your optimal well design, I mean, what does your typical well look like in that area if we’re kind of to look at what you’re going to do on average going forward? Is it going to be sort of a 7.5 million well cost, 30 stage frac type of well?

Bud Brigham

Well, this is Bud. Lance will probably want to add to what I have to say, but we’re still really trying to define that. But you’ve certainly seen in the Ross area with the – as we’ve increased the number of stages, the Clifford Bakke, early on, is outperforming the other wells with 38 stages. So, we’re still trying to define that, Scott. But clearly as Lance laid out, it’s a (inaudible) plug; it’s a high number of stages; it’s a high strength [ph] profit. We’ve isolated those elements – of importance. And so now we are trying to figure out in the different areas, and we think they are going to be different, what’s the right optimal number of stages and then we are working on the other things we’ve touched on as well.

Scott Hanold – RBC

Okay. But implicitly, the more we go west, the more frac stages based on what we know today. Is that seemingly fair?

Lance Langford

That’s what you would think, but I’m not sure the results are showing that yet, so –

Bud Brigham

There seems to be more variability.

Lance Langford

We need more time and need more production. But that’s – I think that if you just look at engineering and common sense, that’s what it would say, but I’m not sure that it’s saying that.

Bud Brigham

The data is maybe not saying that in every instance.

Scott Hanold – RBC

Okay. And I apologize if you said this. This is my last question, on Swindle and Johnson, the stuff over in eastern Montana, how many stages are getting put on each of those wells?

Jeff Larson

I’m not even sure we’ve made that determination yet.

Bud Brigham

It will probably be around 30, don’t you think, or 32? One of you –

Lance Langford

It will probably be 30 to 38.

Jeff Larson

Yes. It will be 250 to 300 foot spacing between the stages, so – you know, we sit down and look at each one and the technical team sits down and looks at it and determines that.

Scott Hanold – RBC

Okay. All right, guys. I appreciate it. Thanks.

Lance Langford

Thanks to you.

Operator

The next question is from Eugene Lipovetsky with Zimmer Lucas Partners.

Eugene Lipovetsky – Zimmer Lucas Partners

Hi. How are you guys?

Lance Langford

Doing great. How are you?

Eugene Lipovetsky – Zimmer Lucas Partners

Doing well, thanks. Actually, a follow-up question on the Montana wells that you are about to drill – are drilling, the Swindle and the Johnson. First question is, it’s my understanding that there’s a fair amount of water in and around that area. Am I correct in thinking that?

Lance Langford

I think as you go north of our acreage block, you see where the Swindle is; as you go to the north, north of our acreage, we think that definitely the water saturations increase in the Middle Bakken member. We think there’s evidence for that not only from historic data points, but also there’s some introduction data points to the north that are pretty high water cut.

Eugene Lipovetsky – Zimmer Lucas Partners

Right. So given that there is a higher water cut, does it make completing these wells during the winter months more expensive? Because if I recall correctly, last year, I don’t think you guys had as much of a problem with this, but some of the operators commented on the fact that things just move along slower in the winter months, especially when there are – when there is a fair amount of water to handle, to transport and to dispose ultimately. Can you comment on whether or not you foresee this being an obstacle in your winter operations, especially in the high water cut areas, such as the Ghost Rider?

Lance Langford

Well, this is Lance. So, water cut – increased water cut definitely increases the LOE, but it’s not dependent on winter or summer. I don’t think it’s going to create higher cost in the winter for drilling or completion operations either. So, I am not sure that I understand your question because I can’t –

Eugene Lipovetsky – Zimmer Lucas Partners

My question is simply whether or not you think that it’s going to cost more to complete these wells in the winter given that the water cut is higher than it is out east?

Lance Langford

No, I don’t think so.

Eugene Lipovetsky – Zimmer Lucas Partners

Okay.

Bud Brigham

Yes, we don’t see that.

Lance Langford

The typical cost of drilling and completing wells in the winter go up primarily for – just because you are burning a lot more fuel heating both the people and the equipment and the fluids for fracing. But as far as it being in a wet area or a dry area, I don’t see a problem there.

Eugene Lipovetsky – Zimmer Lucas Partners

But, if you used about $9000 per month per well as your LOEs in the Rough Rider and Ross, what would you say is the estimate for Montana?

Lance Langford

You know, I think you just do it – we have a variable part of our LOE and you could probably put $2.25 for every barrel that those wells produce and if they produce more water, they’re going to be that proportionate using $2.25 a barrel, somewhere in there more, so.

Eugene Lipovetsky – Zimmer Lucas Partners

Got you. Last question is – are the Swindle and Johnson wells going to be targeting the Middle Bakken member?

Bud Brigham

Yes, that’s correct.

Eugene Lipovetsky – Zimmer Lucas Partners

Great. Thank you so much, guys. Really appreciate it. Good quarter.

Bud Brigham

Great, thank you. Thanks for joining us.

Operator

Ladies and gentlemen, this will conclude our question-and-answer session for today. I would like to hand the call back to management for closing remarks.

Bud Brigham

Hi, Jen. I want to thank everybody for joining us for the call. It’s a really exciting time for the company. And we particularly look forward to reporting our year-end results.

Operator

Ladies and gentlemen, we thank you for your participation in today’s conference. This concludes the presentation and you may now disconnect. Have a good day.

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