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Executives

A. Langford - Executive Vice President of Operations

Ben Brigham - Chairman, Chief Executive Officer and President

Unknown Executive -

Jeffery Larson - Executive Vice President of Exploration

Eugene Shepherd - Chief Financial Officer, Principal Accounting Officer and Executive Vice President

Analysts

Joseph Magner - Macquarie Research

Ronald Mills - Johnson Rice & Company, L.L.C.

Stephen Berman - Pritchard Capital Partners, LLC

Subash Chandra - Jefferies & Company, Inc.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

Marshall Carver - Capital One Southcoast, Inc.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Andrew Coleman - Madison Williams and Company LLC

Unknown Analyst -

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Brigham Exploration (BEXP) Q1 2011 Earnings Call May 4, 2011 11:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the Brigham First Quarter 2011 Earnings Conference Call. [Operator Instructions] As a reminder this conference is being recorded. I would now like to turn the call over to your host, Bud Brigham, Chairman, President and CEO. You may begin.

Ben Brigham

Thank you, Stephanie. Thanks to each of you for participating in Brigham Exploration Co.'s First Quarter 2011 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 VP of Land and Administration; and Rob Roosa, our Director of Finance.

Importantly, before we get started, I'd 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 first quarter results as well as our plans for the remainder of 2011. We'll be referring to the slides in the presentation during our discussion so we'll help you to be prepared with it, as we'll flip 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 2 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 period 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 5, you can see our outline for the call. Our theme these days is No Oil Left Behind. We're determined to fully and optimally exploit this world-class resource for our shareholders. The news, or the events, we'll be discussing on the call include the following: First, the remarkably constructive environment continues. And we're very comfortable it should persist for some time. Second, in March, for the first time, our Williston Basin production exceeded 10,000 barrels of oil equivalent per day. And although the winter weather slowed everyone somewhat, our completions are currently accelerating given that we now have 2 fully dedicated frac crews working, which will have an impact on our second quarter production, and also given that over time, we'll increasingly benefit from our efficiency initiatives in the field that will both reduce our costs, while also further accelerating our rate of completions.

Third, in the Williston Basin, we've all seen some cost creep. But given higher commodity prices, our returns are roughly equivalent. Our 600,000 barrel of oil-equipped well still generates roughly $12.3 million of NPV, an 89% rate of return, and remarkably pays out in about 1.2 years.

Fourth, during the quarter, we brought on another record Williston Basin well and the highest-rate Bakken completion in Montana to-date. So we're continuing to see steady improvement in well performance. And it's not all about increasing frac stages anymore. It's amazing that we've now completed 59 consecutive long lateral high frac stage wells in North Dakota with an average initial peak 24 hour rate of 2,860 barrels of oil equivalent per day.

Fifth, we continue to have success adding attractive high-value acreage. As a result, we've now grown our core holdings 6% to 217,900 net acres.

If you give us credit for the Three Forks potential in Rough Rider, this equates to a roughly 20-year inventory that are accelerated 2011 drilling pace.

Sixth, success in the Three Forks in our Rough Rider area is expanding. Other operators have drilled key Three Forks discoveries proximal to our acreage. Thus, we're very excited about the 3 Three Forks wells that we're drilling or will be drilling over the next several months to further delineate the economics of the Three Forks in our Rough Rider area.

Seventh, we'll show you the production from our Brad Olson #2H, which was drilled at a 4-well spacing distance from the Brad Olson #1H. You'll see that it flowed 4x as long and more than twice the barrels of the Brad Olson #1, which was completed a year earlier. So our density drilling so far continues to support the opportunity to drill at least 4 wells per horizon per unit. And we've got additional pilots this year to further delineate the potential for more dense development.

Eighth, our teams have generated several exciting opportunities to delineate other potential resource targets over our acreage. We have projects planned this year, and we increasingly think it's likely that other resource plays will blossom for us.

Similar to what we've seen in West Texas, there's an old saying, the best place to find oil is where it's been found before. And that clearly applies to the Williston Basin.

Ninth, Lance will discuss our cost efficiency efforts and our support infrastructure build-out.

And then tenth, we'll finish up with Gene, who will provide you a financial update.

Now moving to Slide 7, you can see that the commodity advantage favoring the oil persists. And we think it's likely to continue for the next 5 years or so.

On Slide 8, you can see our realized equivalences for oil versus gas, and this updated Slide 9, so that you can see why we believe the Bakken/Three Forks are the top resource play in North America. We're fortunate to have an early leader position and be right in the middle of it.

On Slide 10, you can see another way the macro continues to be supportive. Differentials for us had stabilized over the last 2 years at $8 to $11 per barrel. But it recently trended down to around $6 per barrel in April and May, certainly better than we expected. And we expect this will have a positive impact on our second quarter revenues.

Moving to Slide 12, you can see the dramatic growth in production we've achieved. We look to call the experience, its coldest winter in years, with record levels of snowfall. This impacted activity in the basin, and for us, it particularly impacted our shared equipment, particularly our asset to the shared frac crew.

Despite those delays, which are apparent if you look at January and February, our Williston Basin production exceeded 10,000 barrels of oil equivalent per day for the first time during March.

And today, we're benefiting from accelerated completions, given that on March 31, as we commenced the second quarter, we've received our second fully dedicated frac crew. Thus, our rate of completions has accelerated. Obviously, this will positively impact our second quarter and the remainder of the year.

On Slide 13, you can see the impact our Williston drilling is having on our company's quarterly oil production volumes, including our forecast for Q2 and the full year.

If you forward to Slide 14, you'll see our total equivalent productions. Our first quarter production was up 109% relative to the first quarter of 2010. However, primarily because of the weather delays, particularly with our shared frac crew, our first quarter production was flattish with Q4. This was an abnormality. This resource play is a production and reserve growth machine, and this was the worst winter in years, which mitigated one quarter of our ongoing production growth. Those of you who follow us may know that we beat our guidance every quarter last year, given that our wells have tended to outperform. So being at the lower end in Q1 was a result of unusual circumstances.

Some of this extreme winter weather trade over into the early part of Q2, particularly last week. But we factored that in to our guidance. And despite that, we're still forecasting solid 15% sequential growth. With 2 dedicated frac crews operating in the field today, our rate of completion to the field has accelerated materially. So we're comfortable with our Q2 forecast, which factors in the aforementioned down time, but we remain very comfortable with our previously issued full year production guidance as illustrated on the slide.

Moving to Slide 15. You can see that our dramatic growth in production volume is compounding with higher oil prices to drive our marketable growth in revenue and cash flow. Our first quarter 2011 revenue was greater than that of the entire year 2009, and greater than the first half of 2010.

Given current commodity prices and our forecast for production growth, the second quarter revenue and cash flow will clearly be very strong.

Now taking a look at the economics. Slide 16 shows the returns in this play remain very robust. The higher prices have offset the cost creep that we've seen. So our 600,000-barrel of oil equivalent well still generates a PV10 value net of capital costs of just about $12.3 million. This same well would pay out in about 1.2 years and generate a rate of return of about 89%.

Slide 17 shows that even at lower oil prices, this play generates solid returns. And of course, we get excellent support from our hedges. For example, we've recently hedged approximately 900,000 barrels of oil with an average floor of $86 per barrel that provides headroom up to an average of $139 per barrel.

And we need to point out that these returns are prior to the efficiencies that we're just beginning to realize in the field.

Slide 18 shows that we've grown the number of stacked 1,280-acre units to 108 in our Rough Rider area. Our concentrated position provides us with the opportunity to achieve substantial efficiencies in the field as illustrated on slides 18 and 19. We'll also benefit from pump efficiencies, thanks to our infrastructure build-out that will largely be completed in the fourth quarter.

Slide 20 illustrates our current smart pad spacing plan. Matt will briefly discuss these later in the call.

Slides 21 and 22 are our updated high frac stage long lateral well list.

And Slide 23 illustrates that we continue to outperform our peers in the play.

Now moving to Slide 24, you can see the updated improvement we've seen over time in our well performance. And early on, this improvement was primarily driven by our increasing the number of frac stages. However, it's not all about frac stages anymore. In certain areas, we're actually fixing the number of stages and barring other elements.

Slide 25 and 26 are updated, and show the improvement we've seen in the average production curves for 2 specific areas as we continue to innovate.

Clearly, we're not hitting the wall here. The trend is very encouraging, results continue to improve. We are working with service providers, testing some new and potentially revolutionary tools in the field that Lance will discuss.

When you think back, nobody could have possibly envisioned swell packers beforehand, and the kind of impact they've had on these resource plays. We're optimistic that we'll experience other breakthroughs, that could also be potential game-changers. We'll continue to be innovators and our shareholders will continue to benefit from that.

Slide 27 is an update of our density pilot in Rough Rider. Of note, the distance between the Brad Olson #1 and the Brad Olson #2 is roughly equivalent to a 4-well spacing distance. We've also now brought online the Brad Olson #3.

So if you forward to the next slide, Slide 28, you can see the production performance for these wells. The Brad Olson #2 is shown in green, which was completed a year after the Brad Olson #1 shown in orange. At the time we completed the Brad Olson #2, the #1 well was on pump, producing about 200 barrels of oil per day.

And you can also see that the Brad Olson #1 went on pump after making about 23,000 barrels in about 34 days.

One year later, the #2, on the other hand, subsequently flowed 134 days. And during that time period produced 49,000 barrels of oil, and is now ready to go on pump.

Had there been pressure depletions or communication, the #2 well would've required a pumping unit more quickly than the first well. And that clearly was not the case. Also, once these wells are put on pump, the production rate typically increases. And the later they're put on pump, the more they typically increase. You can see this back on Slide 24.

Further, as you can see on Slide 28, the Brad Olson #3 has commenced production comparably to the first 2 wells. As mentioned in our press release, we also completed 2 additional density wells, including the Williston Basin record Sorenson #2H, which also shows no communication with the offsetting well in this production to-date.

The Sorenson lateral was an average of about 1,763 from the initial Sorenson well in the unit, while portions of the lateral was closed just 1,500 feet. And both wells came online with initial peak rates of over 5,000 barrels of oil equivalent per day. Those are amazing wells.

So this data, combined with our microseismic, continues to support the opportunity we believe we have to drill at least 4 wells per production unit. We have several additional pilots planned for this year to try to determine how many wells per unit per horizon we can drill as soon as possible, so that we can space and locate our wells as optimally as possible.

Moving to Slide 29. And you can see, we've updated our table given the growth in our acreage position. The 2 transactions captured high-quality acreage in areas where we've drilled strong wells with very attractive economics.

As a result of those acquisitions and our drilling success in Montana, our de-risked core acreage has grown to 217,900 net acres.

Now this table assumes no credit for the Three Forks in Rough Rider, where we drilled our successful State Three Forks well, with the updated production curve shown on Slide 30.

Our State well is shown in orange, and our Ross Area long lateral Three Forks wells are shown in purple. As you can see, all of our Three Forks wells, including the State in Rough Rider, are outperforming our competitors' Three Forks wells in the Ross Area.

If you move to Slide 31. You can see a map of our Rough Rider areas, with recent third-party operated Three Forks discoveries highlighted. These wells are further delineating apparently attractive Three Forks drilling economics around our acreage. So we're looking forward to drilling and completing our 3 planned Three Forks wells shown on the map over the next several months.

The first of these, the Irgens 27-34 #2H, is currently drilling.

If you move to Slide 32, this table shows our core inventory if you believe the Three Forks wells will be delineated as commercial over our Rough Rider acreage, which I believe is likely.

Slide 33 illustrates the depth and optionality of our acreage inventory. Assuming continued Three Forks success in Rough Rider, we have a 20-year drilling inventory. And that's at our accelerating 2011 pace.

If we can drill one additional location per horizon per unit, that could add another 330 net potential wells for another 5 years of inventory.

Slide 34 is an updated map of our Rough Rider area, where we have 4 rigs running and where we've now completed 41 consecutive long lateral high frac stage wells with an average peak 24-hour rate of 2,658 barrels of oil equivalent per day.

You can also see our density pilot projects planned for Rough Rider on this map.

Slide 35 is an updated map for our Ross Area in Mountrail County, where we currently have 2 operated rigs drilling, a Bakken and a Three Forks well.

In this area, we recently completed the new record well for the basin, our Sorenson 29-32 #2H density well, which produced at a peak 24-hour rate of 5,230 barrels of oil equivalent per day.

As a result, we now have the 4 highest initial rate wells in the Williston Basin, all of which are on this map in our Ross Area. You can also see our density pilot planned for the Ross Area on this map as well.

Slide 36 is an updated map of our Montana activity. At the lower right, you can see our Johnson 30-19, which came on at 2,962 barrels of oil equivalent per day, apparently the highest rate of any Bakken well completed in Montana.

Other operators were also very active in the area, and they also provided some recent encouraging data. We have 6 wells either completing, drilling or going to be drilled in this area in the near term, so we should have a good amount of exciting news to report here. With success, we can meaningfully grow our core acreage in this area.

Now to wrap up my portion of the presentation, if you view slides 37 to 40, you'll see our current interpretation of drainage, as well as our current spacing plans for our units. Two things to point out here. First, based on our density pilots in the microseismic, we do think there is good upside potential for more dense development beyond 4 wells per horizon. Therefore, we will be checking higher densities with our planned 2011 density pilots.

Second, the more we investigate, the more encouraged we get about other potential resource targets, as listed on the left side of slides 39 and 40. We expect one of several of these potential resource plays to blossom in the basin, and we're planning drilling projects to delineate these opportunities.

With that, I'll turn the call over to Lance for a quick update on our facilities and infrastructure construction in the field. Lance?

A. Langford

Thanks, Bud. As Bud discussed earlier in the presentation on slides 18 and 19, our highly concentrated acreage position in both Rough Rider and Ross will allow us to develop a significant portion of our acreage using our smart pad development plan.

This development plan allows us to drill 2 stacks, 1,280-acre space units from a common drilling pad, one 1,282 north and one 1,282 to the south.

This will provide us 3 primary means to reduce our drilling and completion costs.

First, we will utilize walking rigs to more efficiently drill multiple wells at the same time. Second, we can more efficiently utilize our frac crews by simultaneously frac-ing wells, and potentially frac 2 wells over a 9-day period versus 14 days, if the 2 wells were frac-ed independently.

So far, we have completed one simultaneous stimulation and are in the process of completing our second. Third, we will reduce the surface footprint of our drilling locations and this will reduce the amount of surface equipment per well, thereby reducing our capital costs.

Beyond smart pads, we are also testing new technologies that will help us be more efficient and reduce cost. In particular, we're testing new sliding sleeves technologies that are meant to mimic the performance of perf and plug in the terms of the number of frac points created between swell packers. And at the same time, achieve the time savings associated with these slide sleeves systems. We'll be testing these technologies over the next several months.

Overall, we believe these enhancements will generate 10% to 20% in cost savings in terms of drilling and completion capital. It is significant when you think there are approximately 760 locations remaining to drill in our core de-risked inventory.

Our concentrated acreage position also allows us to efficiently develop support infrastructure over the vast majority of our acreage position.

We will construct approximately 433 miles of oil, produced water, fresh water and natural gas gathering lines at Williams, Mckenzie and Mountrail counties.

If you review slides 43 through 46, you can see the maps which depict our planned gathering systems. Overall, we anticipate spending about $83 million in 2011 on infrastructure.

This infrastructure project will make our operations more efficient in terms of reducing our dependence on trucks, and it is anticipated to reduce our oil differentials and lease operating costs.

We're currently building out our portions of this project. For example, we just completed drilling our third disposal well in Trenton, which is just to the southwest of Williston.

Our much larger effort is to put the remaining gathering line in the ground. This will begin once weather conditions improve. Our crews are ready to go and we anticipate getting the pipe in the ground before winter.

We also expect the gathering system to be fully operational before year-end. Once this Rough Rider system is fully operational, we will be able to operate through the winter and wet season, and eliminate the need for almost all the trucks we use today.

Our drilling fluids and frac fluids will come from our locations or to our locations via our pipeline. The water that has flowed back from our frac jobs and the produced water from our wells will be transported from our locations via our pipeline and disposed of in our disposal wells.

The oil produced from our wells will be transported from our locations into 4 major transportation lines that will carry the oil out of the basin.

As you can see, we will be able to operate more efficiently and save significant costs, especially throughout the winter and rainy seasons.

Finally, at present time, we are forecasting our Bakken and Three Forks AFEs to be about $8.9 million with 30 frac stages. This is roughly inline with the $7.9 million AFE that we were forecasting in April when you take into consideration the 10% overage factor that we had included in our budget to account for any service costs inflation or operational setbacks.

Roughly 50% of this increase is associated with higher pressure pumping costs, and 10% associated with higher drilling day rates.

This higher AFE does not factor in any of the benefits that we've begun to realize in 2011 from the previously mentioned operational efficiencies. We also expect cost savings to grow during the remainder of 2011 and into 2012. If you take into account the 10% to 20% cost savings that I previously outlined, our AFEs could be below the $7.9 million that we've forecasted in February.

I will now turn the call over to Gene, who will update you on financial performance.

Eugene Shepherd

Thanks, Lance. Before we get into the discussion of our financial results, I'd like to make several comments about what turned out to be a record quarter for the company.

First, during the first quarter, we achieved record financial performance. Revenues from oil and gas sales reached $76 million, a sequential increase of 15%, and an increase of 163% from that in the prior year's quarter.

EBITDA reached $62 million, an increase of 193% from that in the prior year's quarter. And since ramping up our drilling activities in the Williston Basin, our per unit operating margins reached a record $54.06 per barrel, driven by record revenues, which more than offset an increase in our LOE in production taxes.

Second, the company has and will continue to maintain a strong balance sheet and strong liquidity position.

As reflected on Slide 51, in March 31, we had $193 million of cash, cash equivalents and short-term investments on the balance sheet and no outstanding balance under our new credit facility with a $325 million borrowing base. Further, we would expect that as we execute on our 2011 drilling plan, where we are currently forecasting to spend $582 million on drilling CapEx, that we would see a significant increase in our borrowing base, which will get redetermined in October.

Third, the company has a large and growing inventory of development drilling locations: 763 remaining Bakken and Three Forks development drilling locations at year end 2010, based on our assumed 4 wells per drilling unit. Each of the 2 reservoirs on our current core acreage, assuming no credit for the Three Forks and Rough Rider. We therefore have substantial upside to these numbers with our Rough Rider, Three Forks and Eastern Montana Bakken potential, which we will be evaluating extensively in the second quarter and throughout the remainder of 2011.

Lastly, for the first time since we've been drilling horizontal wells in the Williston Basin, the company is now beginning to dedicate significant resources to achieving efficiencies in the field in an effort to drive down our drilling completion costs. We can do this thanks to our large and concentrated Williston Basin acreage position. Our expectation is these efforts will result in savings in our drilling and completion costs of 10% to 20%. Furthermore, we expect the benefits of these efforts will be phasing in gradually, beginning in the current quarter through the remainder of this year and into 2012.

One additional comment about the higher drilling completion costs that we are currently experiencing in the field. In the budget that we announced in February, we were forecasting $7.9 million AFEs plus a 10% overage factor to protect against any potential drilling well cost overruns. Therefore, not a big difference between the $8.7 million that we were forecasting in the budget and the $8.9 million that we are currently experiencing.

As a consequence, we believe that we are still operating within the original 2011 budget that we outlined in February.

In summary, given the recent history of strong oil prices and the outlook for a continuation of this trend into the future, the consistency and steady improvement of our Williston Basin drilling results and the opportunity we have to begin to realize significant efficiencies to reduce our costs and leverage the growth in our high-value oil production as we accelerate in the manufacturing phase of development, we feel confident that we have the opportunity to continue to achieve record financial performance for the remainder of 2011 and for many years to come.

Moving on to a brief discussion of our financial results. Our first quarter production volumes averaged 11,314 BOEs per day, which represents a 109% increase from that in Q1 2010. And we're roughly in line with our production volumes in Q4 2010.

Given our focus on drilling, our Bakken and Three Forks wells, which are predominantly oil, our first quarter volumes were 81% oil. And our oil production averaged 9,211 barrels per day during the quarter. This represents a 159% increase in our high-value oil volumes from that in Q1 2010. Importantly, because of the substantial pricing disparity of our oil versus natural gas, which we are fully able to capitalize on by focusing our drilling CapEx in the Williston Basin, our oil revenues represented 92% of our total first quarter pre-hedge revenues.

Our first quarter total production volumes reflect an increase in our oil inventory of approximately 732 barrels held in our on-site tank batteries at March 31, adjusting our Q1 2011 production volumes for the growth in our oil inventory results in average daily sales volumes for the first quarter of 11,306 BOEs per day.

On a per unit basis, lease operating expense, which includes operating and maintenance expense, expense workovers and ad valorem taxes, decreased 16% to $7.58 per BOE in the first quarter 2011 from $9 per BOE in the first quarter 2010. In terms of our per unit lease operating expense for the quarter, the increase in our Q1 production volumes relative to that in the prior year more than offset the increase in the dollar amount of our Q1 operating expense.

Production taxes increased to $7.56 per BOE, or 10.1% of our pre-hedged revenue in the first quarter 2011, from $5.19 per BOE, or 8.7% of revenue in the first quarter of 2010. The increase was due to the growth in our North Dakota oil volumes, which are taxed at an 11.5% rate, and higher oil prices.

General administrative expense for the first quarter increased to $3.4 million from $3.1 million in 2010. An increase in employee compensation expense accounted for the bulk of the increase in G&A expense.

Recapping capital spending activity for the first quarter, our oil and gas capital expenditures total $123 million, of which $111 million went to drilling expenditures, $7 million went to land expenditures and $5 million went to support infrastructure.

In our earnings release yesterday, we provided production guidance for the second quarter. In terms of our expectations for the second quarter, we are forecasting for our production volumes to average between 12,000 and 14,000 barrels of oil equivalent per day, with 82% of these volumes forecasted to be oil. The midpoint of our Q2 guidance would represent an approximate 15% sequential increase in production volumes relative to that for Q1 and a 68% increase relative to that for Q2 last year. This forecast reflects the continuation in production growth that is being driven by our horizontal Bakken and Three Forks drilling program that will take us to record production volumes in the second half of 2011 and beyond.

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

Ben Brigham

Thank you, Gene, and that concludes our call. I believe some would be happy to answer any questions you may have.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Brian Lively from Tudor, Pickering, Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Lance, you talked about tackling the cost side now. Just wondering, would you consider actually reducing the number of frac stages? I know that's a question we always present, but just in an effort to maximize rate of returns with current well cost, would you adjust your completions down a bit and maybe sacrifice a little bit of production?

A. Langford

No, Brian. Today, we've seen improvements in our rate of returns and the EURs with more stages. I don't see us reducing below our 30 to 38 stages that we've been doing over probably the last 6 months or so. So no, I don't think so. I think we'll just be hurting our returns on our investments if we start dropping them down.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

And then thinking about the $8.9 million well cost for 30 frac stages. Is the rate through for us then that you're probably going do more than 30 frac stages on average, and so the efficiencies you gain in the second half of the year should offset the higher cost?

A. Langford

Well, the $8.9 million is the 30 stages. But we are expecting, and we will see cost savings due to efficiencies. I mean, we're already seeing it. As we go forward, over 60% of our wells will be zipper fracs. And so what you're doing instead of reducing the number of stages, you're just being more efficient getting those stages off, as I discussed in the prepared portion of this conference call. So we'll see that among the other things that we're doing with our infrastructure and our disposal systems and those things to continually increase the amount of cost savings as we go into 2012.

Ben Brigham

So the answer is yes, Brian. Okay?

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Okay. And then just on the first quarter, how many completions did you actually get hooked up?

A. Langford

I think that we did in the first quarter. What we did as far as -- as our stimulation. We averaged somewhere between 5, maybe 6 a month on our stimulation. And the biggest problem we had is we should be doing about 4 with our fully -- our single frac crew that we have 100% of the time. We had some slow downs, slot slow downs and that primarily in moving and then when the weather was really cold and windy. But with the extra frac crew that we were supposed to have half of the time, the reality, that frac crew had a lot of operational problems when it was away from us. And we only got 1 frac a month instead of 2 out of that frac crew through the entire winter.

Ben Brigham

And Brian, one thing as to payment on that production charge is it was kind of back-end loaded in the quarter, probably because of the weather. The majority of completions were in March, and that's when our production, for the first time in the Williston, exceeded 10,000 barrels of oil equivalent per day.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Right. And so the -- I think the guidance number was about 65.7 net completions for this year, is that still the goal?

Eugene Shepherd

Yes. And we had forecasted for the first quarter, I think, 16.4 net locations, and we actually got off 14.8 roughly in that neighborhood, roughly.

Ben Brigham

So a little bit below what we had forecasted for the first quarter, and that's production. And then -- and what we had was a little bit of delays as well. It was kind of loaded in the quarter to some degree.

A. Langford

So once we've got the 2 dedicated frac crews, Brian, we're doing a lot more zipper fracs as we go forward. We're going to become a lot more efficient with that equipment.

Ben Brigham

One thing I think Lance pointed out is that equipment, and also the infrastructure we build on the field is really going to insulate us in future winters from these kind of conditions that we had this winter. It's going to make us a little bit -- really, and Lance could talk more being uniquely positioned relative to our competitors to operate in those kind of environments.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

And then on the -- just finally on the cost increases. I mean, do you think that your cost increases are reflective of the overall pressure of the basin? Or because of your longer-term contracts, do you feel like you're more shielded from additional cost creep going forward?

A. Langford

Well, I think that -- our contracts are with neighbors in Halliburton. I think that our contracts are very favorable if you compare it to the overall basin contracts. I'm not saying that there aren't other people that have favorable contracts like ours, but I think ours are on the favorable side. And I know that there are a lot of operators that are using neighbors in Halliburton, or that aren't as big and don't have much work, are paying more. I know they're paying more for the products and services and probably getting poor equipment and people.

Operator

Our next question comes from Ron Mills from Johnson Rice.

Ronald Mills - Johnson Rice & Company, L.L.C.

Just to follow on Brian's questions. Lance, over what time period do you think it would take to be able to realize 10% to 20% cost savings? I'm sure that, that marches out over time, but how long do you think it would take for those efficiencies to fully be seen?

A. Langford

Right. And I think you could read that in my text is that I was saying that we're seeing those efficiencies begin now. Of course, we only have 60%, a little over 60% of our go-forward locations for the next 12 months, our zipper fracs, our multi-well pads. So only 60% are going to be impacted by those cost savings. The big game changer is we've got the 2 different sets of frac sleeves that we're testing that are been developed by 2 of the major service companies. If those work, those are game changers. Instead of completing 4 wells a month, we ought to be able to double and maybe triple the number of stimulations we can do with the same frac crew. So all that equates to money. On our rigs, we've got good working rigs now, we've got new walking rigs that are coming in that we've ordered. Those walking rigs are going to make us more efficient, and those are going to be layered in over time. We're also looking at retrofitting some of the existing rigs with walking systems, and that will happen over time. If we decide to go full-scale that way, that will take a while. So I suspect, to get to that full 20% just in efficiencies, for us to get there, it's going to take us into late 2012. But we're going to start walking through that, and depending on how well things work and how fast we could implement it is going to determine when we see those efficiencies.

Ronald Mills - Johnson Rice & Company, L.L.C.

Okay. And then on the last call, you spent a lot of time really walking through the infrastructure and the impact. What's still the timeline for both the Rough Rider and the Ross projects to really be operational? And then as you look ahead then, which would probably be later this year, but fully felt next year. What kind of operating cost improvements do you think that those projects will result in? I know you expect both op costs to come down, but also differentials to improve. Just trying to get some practice around that.

A. Langford

Well, let's talk about timing first, and then we'll talk about cost. So in Ross, we have a gas gathering system where we're delivering that gas to Whiting, to their processing plant. Right now, that's fully operational. We also have a saltwater, or produced water, gathering system and disposal well, and that's fully operational. The only things that will change over there is that we will spend some additional capital on additional well this year, a saltwater disposal well. And that's just to meet our production growth needs in the future. And so we'll have that. That one well will be fully operational later this year. So over there, we're pretty much seeing the impact that were going to have. The bigger impact is going to be in the Rough Rider area, which is -- approximately 2/3 of our core acreage is located within that, and that's where we have the fresh water line, the saltwater line and the oil line. And so the impacts are going to be greater over there because we've got more of the lines that move the fluids around instead of utilizing trucks. We've got probably 2/3 of the Williams County portion of our pipeline done. We're waiting for this wet season to dry up, and then we'll -- we've got all the crews in place. We've got a number of crews that are going to be putting those gathering lines in place. That should be fully operational by year end, but we'll start implementing portions of those immediately. We already have one disposal well that's operational. We're already using the fresh water line to a number of our wells that we're completing right now. But it won't be until fourth quarter till their fully operational. And so if you want to see -- let's talk about the impact in Rough Rider, what that has, and so what that's going to mean to us. And if you think about these roads during the wet part of the season or when it's cold and windy, when visibility is low in North Dakota, when it shuts down our operations, that won't happen when we have these facilities in place, because those trucks that are transporting -- and you can't imagine the amount of fluid that's being transported and how bad it's tearing down locations and roads and how much money we're spending on that. That won't occur. That will be wiped away. And we're tracking what kind of cost savings. Everything we've been modeling has been really just on the transportation cost. It hasn't been the snow removal, the shutdown times, the road repairs. Those costs have been significant this winter. And that's not just us, that's everybody. We're going to eliminate most of that. The only major needs for trucks will be when we move our rigs and our factories. And when you have the zipper fracs and the multi-well pads...

Ben Brigham

With the concentrated acreage position.

A. Langford

Right. With that concentrated acreage position, the trucks move a lot less. So we're going to see all these benefits that are, hard for me to sit here and tell you what those costs are and how much it's going to mean. It's going to be significant. I know that. Hopefully, as we get the system up and running, we get enough history, we'll be able to quantify you after next year compared to this year and the last year in what we've spent. That being said, our pipeline systems are 100% owned. Everything we're charging is going to be below market rate. So to dispose -- to transport a barrel of saltwater to a disposal well, I think it's going to be about $1.75 a barrel. I think that's hit $1.65, $1.75. While much of the time now is in the basin, it can cost you as much as $6 to $7 to transport a barrel of water to a disposal well, and that's a couple of things. One is the long lines at disposal wells. The other thing is sometimes, the disposal wells have contracts with certain trucking companies. They take that barrel to the disposal well they say, "Hey, we're full", they take it, put it back in a frac tank in their yard. And then they got to take a truck later when the disposal company calls to say, "we got room", pick it up again and take it back to the disposal well. So, I mean, there's significant costs that I can't quantify for you, but I can assure you, they happen to us and everyone else out there. And on 2/3 of our core acreage, we're going to eliminate most of those costs this next winter.

Ronald Mills - Johnson Rice & Company, L.L.C.

Okay. And then moving over to Montana, the question is twofold. Once you get more data, I assume that you're -- at least some gleam in your eye is also thinking about the infrastructure build-out over in Eastern Montana. But probably more importantly, in terms of the core acreage, you have -- the Beck well is completing, the Gobbs well is completing and the Charley well is drilling all up in that Roosevelt County acreage, which as of now, still is not included in your core de-risked acreage, and you haven't really had a clean completion yet. Can you just provide a little bit of information on the Beck and the Gobbs and how the drilling of those went? And were you able to get the liner all the way down, which actually provides the opportunity to have a good completion?

A. Langford

Yes. As far as the drilling operations on both those, we haven't had any substantial operational problems. The one thing that we do know is we have down in the southern part of our Montana acreage, we feel like we've delineated some of that. And we're going to -- we know that we're going to continue to delineate additional acreage in Montana, it's just a matter of how much. And then you mentioned infrastructure. Once we get an understanding of what that's going to be and what areas are going to be included in our core, we'll probably start looking at infrastructure over there. And that will probably occur summer of 2012.

Eugene Shepherd

And then, Ron, jab through it real quick, just to give you a general timeline on the completion of the wells. We're looking at early summer fracs for those 2 wells. Rigging that Lance spoke to and Bud spoke to a little bit, we're being very systematic going forward about continuing to delineate the acreage and...

Ben Brigham

The 6 total wells, I guess, either completing or awaiting completion or near-term drilling, that we'll have word on over the next 4 or 5 months.

A. Langford

Set offs. There is also a lot of off-set operators off-rig [ph].

Eugene Shepherd

And lastly, were very interested in the industry activity scene. Whiting's drilling to the north of us. We know that rig's going come down and drill another well, very proximate to our acreage, following the completion of the Johnson well. We're going to be in that second well with a pretty significant acreage position out of working interest. Oasis now has the two rigs running eastward of us and north of us. A lot of activity. Ursa's completing to the southwest of us. And, obviously, Continental's got a large block to the west of us. They've got both a Bakken and a Three Forks well that we're watching the completions on. So really, a lot of activity. Oasis has got their Three Forks Williston well, getting ready to complete right on the state line. Obviously, another big driver for us in Eastern Montana. So lots of exciting things, a lot of permitting going on, very active commission activity, we were just at the commission again, very busy. A lot of folks there, spacing their units and trying to secure permits.

Operator

Our next question comes from a Subash Chandra from Jefferies & Company.

Subash Chandra - Jefferies & Company, Inc.

Yes. I guess to sort of sum up a bit on the cost issues, which I guess dominated the discussion today. Reading between the lines, there should not be a CapEx creep of any type this year, all else equal, based on the current well program?

A. Langford

Correct.

Subash Chandra - Jefferies & Company, Inc.

Okay. And could you remind me again, what the second frac crew does? I think we went over this on the prior call as well. Just a refresher.

A. Langford

This is Lance, and I'll talk about that. But basically, one of the benefits for us and Halliburton in having a dedicated frac crew that works for one company is that we get in a rhythm and a system of how sand's brought out, what kind of sand, what kind of profit, what kind of fluid, how much fluid. And we get in a system, and you become more efficient. One of the problems that we had with the shared frac crew is that it would go away and work for other operators that had different designs and completion techniques. And what happens is, is you don't have the efficiencies of the machine moving. And that's problematic, not just for us getting the frac crew back, but for Halliburton to have to try and make those changes, going from one company to the next company to the next company. And they've expressed that is one of the big benefits with us. We do make changes, they're small changes and we give them lots of lead time. But for the most part, we have the big machine moving, and it's all just doing the same thing every day. Those frac crews, the frac crew that went away, it was supposed to go away for 2 weeks and come back for 2 weeks, typically went away for 3 and came back for 1. And I can only imagine what was happening there. You had different kinds of stimulations, they had problems getting the fluids and the proppants and the right stuff there, and things were just much slower. So that's the real benefit of having a dedicated frac crew. We also...

Subash Chandra - Jefferies & Company, Inc.

If you would just wrap a number on it? How many completions per crew per month do you anticipate?

A. Langford

So under the old perf and plug, doing one well at a time, you would anticipate 4 wells to be completed in a month, per frac crew. And as we move in, if we do zipper fracs, if we have about 50% time savings. So you do 1.5 wells -- I'm sorry. In the 9 days, so you do 3, do about 6 wells in a month if you had zipper fracs all the time. And of course we only have 60%, over 60% of our locations in the next 12 months are going to be zipper fracs. But then you take it, if you do the -- if you can get the new frac fleets to work in a replicate perf and plug, and we get the same economic results out of the production, then you can double and triple your efficiency with those frac crews.

Subash Chandra - Jefferies & Company, Inc.

The new frac sleeves in terms of innovations, sort of how far out there is it? Is it sort of a big step forward in terms of getting this to work or -- because I think some of the stuff that you and other Bakken operators may have tried early on, which would have been tremendous, sort of didn't get there because of costs and just mechanical issues. And sort of how would you gauge those innovations?

A. Langford

So we're testing the tools from the 2 different companies right now. And operationally, we'll get them to work and we'll be able to execute the sleeves that they have. The big question is, is once you can get the frac jobs away, are they really mimicking what we're seeing on the perf and plug? Are we really creating as many frac lanes as we are with perf and plug? And so we've got to get -- mechanically, we've got to help them get to the point where they're operational, and then we've got to have good comparisons here but with offset wells with the same number of stages and see how production fares and see if operable or better. I mean, you'll never know. It might be even better.

Subash Chandra - Jefferies & Company, Inc.

All right. Okay. And the final one for me. So when we're looking at the 8 well per section, how did you sort of pick the locations you did initially? How did you high-grade where you would test this? And what conditions should we be looking at, whether it's vertical displacement between the Three Forks and the Bakken and relative thickness between them, communicability? I mean, how are you looking at it? And how would that apply to the balance of your acreage?

Jeffery Larson

So Jeff, I'll start and then hand it over to Lance or Ben, anyone. The big drivers in kind of any pilot in Rough Rider and also in Ross, I mean, the big driver is just land. I mean, we're very excited about these pilot projects, and we make sure we had a high working interest in these different units. And, I mean, we're going to do one in Rough Rider and one in Ross. And when those will get done timely, they're big drivers.

Subash Chandra - Jefferies & Company, Inc.

Okay. So there's no geologic attributes that led to those locations?

Ben Brigham

No. I mean, when you look both of the units, the Rough Rider one was right in the middle of our block, and the Ross one is right in the middle of our block. So we jump down [indiscernible] [1:05:14] it's good acreage position and we think it's a good place to test.

Subash Chandra - Jefferies & Company, Inc.

Sounds good to know.

Operator

Our next question comes from Marshall Carver from Capital One Southcoast.

Marshall Carver - Capital One Southcoast, Inc.

A couple of questions. I know you have the additional frac crew coming on and completion should accelerate. Do have a set schedule in your guidance of how many net wells you expect to be completed by quarter? How many were completed in 1Q and how many you expect for 2Q, 3Q, 4Q?

A. Langford

Yes, Marshall that's out there in our year-end conference call transcript. There was a slide that laid that out. And I think the second quarter was going to be sort of the high water mark in terms of spudding locations. So we're building to the second quarter and then it trended off a little bit in the third quarter And that's a function of just the change in working interest as we ramped up our activity, but...

Ben Brigham

And that moves around a little bit. But the second quarter -- so that pickup -- that second dedicated frac crew came online and began working March 31. That was when we commenced the second quarter.

Marshall Carver - Capital One Southcoast, Inc.

So that should be well spud. And so it....

Ben Brigham

I think we got wells completed. That well's completed over that 2 million.

Marshall Carver - Capital One Southcoast, Inc.

Okay. Okay.

Unknown Executive

So basically, you had some slowdown in Q1, but you would expect to catch back up in Q2, and that's how we should -- if I look back at the old slide show, that's how I should think about it changing?

Unknown Executive

Some of it was just about adding rig, it was coming.

Ben Brigham

And then as we have expressed, Marshall, I mean, the January and February ended up being lighter than what we had originally forecasted in March. It really picked up. So that production came late in the quarter. It didn't materially impact the first quarter, but we did, in March about 3,000 barrels a day. So that will benefit us in the second quarter.

Unknown Analyst -

Okay, great. And then on the year-end call, you had talked about potentially doing a "5 well per 1,280" Bakken test later this year and possibly a Three Forks downspacing test later this year. Are those plans firmed up?

Ben Brigham

Yes. And Marshall, we are working on potential higher density projects. And we don't have anything specifically we want to put out on that yet, but we are interested in testing them.

Unknown Analyst -

Okay. And then final question on acreage cost. I know you're acquiring -- and you acquired some more acreage. Are you willing to talk about where costs have gone recently on the acreage front?

Ben Brigham

No, Marshall. I'm just saying, I mean, that was very attractive acreage. For example, well, just generally, we acquired half of the acreage roughly in the south central part of Rough Rider. And I think it's another example, we're kind of competitive when you family start prior acreage, given we drill the best wells in that area. And kind of was -- [indiscernible] [1:08:20] in, in some cases, in our units there. So we were the power of choice. And so it was attractively priced. And then in Montana, we acquired -- negotiated terms prior to our Johnson [ph], right, [indiscernible] 1:08:37] out in the market. So that acreage is very proximal to the Johnson well. And so it's also very attractive.

Operator

Our next question comes from Mike Scialla from Stifel, Nicolaus.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

On Slide 28, if I'm understanding that right, the implication there is that your second Olson well is actually outperforming the first given that it flowed naturally almost 4x as long, is that correct?

Unknown Executive

Yes, certainly, absolutely. I mean, now that there's now pressure. But David said to you, "If there was, you're going to have to put on pump more quickly than the first well."

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Can you say at this point you have enough information to say that the EURs for those wells would not change? I mean, if you are going to see interference, I would assume it's going to be -- it's going to affect the final decline on the wells. But have you seen enough now to convince you that, that the EUR would be unchanged where you drilled 3 or 4 wells per unit?

A. Langford

Mike, it's Lance. So far, we've got lots of good data, and we think the wells are performing, and the EUR are not similar. But we don't have enough data until we get some substantial production data past the wells being put on pump. What we see is the early-time EURs are difficult, at least prior to putting it on pump and getting a good curve post-pump. But we do feel like the wells are performing well, the #1 to the #2 and same with the #3.

Ben Brigham

And In my preferred take, I'll refer you back to Slide 24, and you can see our wells historically, when you put them on pump, the rate comes up. And you'll see the wells had flowed longer. You put them on pump later, their production comes up more significantly. And so we really need to get history on the Brad Olson #2. We'd put it on pump for a period of time, as Lance said, before you can get a reasonable EUR. And that's at a but I think at this point, it does look comparable.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

So maybe if we're talking maybe about 6 months to a year worth of seeing those well performance on pump, and then you can kind of weigh things out as to how you want to develop the acreage position in terms of the spacing?

A. Langford

Right. I think this is a good indication. We'll probably move faster than that. But I think to really have accurate EURs, you'll probably need 6 months after the Williston put on pump.

Ben Brigham

And that's why I returned, to get pilots done as early as we can. So the sooner we can get it done the sooner that you'll get that history so we can make those judgments. And it's really the more wells that we have drilled prior to figuring that out, the more legacy issues we have in subsequent developments.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Yes, that make sense. And then, Lance, did I hear correctly? In terms of your pad drilling, you're planning on 2 wells per pad, is that correct?

A. Langford

Well, that's currently -- we have to balance holding acreage with trying to use increased density programs. And a lot of it is stepping out and improving out new acreage. We have to balance all of that. So most of our wells right now we're going to just drill one north and one South and hold the acreage other than our pilot programs. But on a go-forward basis, we will probably have many more wells on a single pad than that when we go into full-scale increased density drilling.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Right, okay. I guess that was really what I was after.

Ben Brigham

And one thing I should point out there is that our current - -we've spent -- the wells we're drilling, we're drilling on 4-well spacing. I mean, those are without permitting and planning. We're planning on one 4-well spacing. So at this point, we're there on that. So we're looking to see is more dense development optimal. So just to kind of state that general rough position of where we are today.

A. Langford

I mean, obviously, we're not going to be waiting on the pilots that we've done in the second half of the year to confirm the full wells. I mean, we're...

Ben Brigham

And beyond that.

A. Langford

That's an opportunity to justify potentially some higher level of activity per drilling unit.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Okay. And now last one for me on the infrastructure build-out. Any thoughts on bringing in a midstream partner there or do you plan on doing it by yourself?

A. Langford

We've looked at doing that in the past. And typically, the midstream guys wants you to pay for everything whether it be through production payments or, well, whatever. But we really feel like because of our acreage position we don't really need a midstream company. I think we're looking at building out our staff over time.

Ben Brigham

And let me just add one thing. I think the real issue with the bringing in a partner is bringing a partner that has division and will understand what this is ultimately going to become. And we're in the position -- we, obviously, are drilling the wells, and we've mapped out a 3-year game plan. And so we understand where we're going to be at the end of 2012. And so I think our -- and so we have a more aggressive view than others. So I think at some point it'll make some sense whether we bring in a partner or whether we do some type of monetization, whether, say, either a partner or bringing in the public. But right now, I just think that others don't maybe share our view or maybe our definition to be as aggressive as we are, so.

Michael Scialla - Stifel, Nicolaus & Co., Inc.

Probably. I mean, if you want do to monetize it, you're probably a couple of years away from that?

A. Langford

Well, I don't know. If you look at some of these other -- if you're talking about an MLC-type [ph] transaction, you don't need a tremendous amount of operating history. So yes, I mean, it's hard to say. But right now, we're focused on getting our wells plumbed, our operating wells plumbed. There's also a great nonoperated opportunity with an adjoining acreage. It's proximal to our big trunk line. But right now, we're focused on our operating locations.

Operator

Our next question comes from Joe Magner from Macquarie.

Joseph Magner - Macquarie Research

Just you touched on it earlier, but I just want to see what the ongoing effects are from the storm that hit over the weekend. I saw that the Government of North Dakota declared a state of emergency. I was curious where things stand and how that may be affecting your operations currently.

A. Langford

Well, this is Lance. Currently, our operations are back up and running. We may have some small impact on some wells with electricity, but the Williston and mostly electrical systems are up or, better, getting up right now. But we have most of our wells back up and our operations going within 3 to 5 days.

Unknown Executive

As I mentioned in my text, sort of the weather did roll over into the second quarter did impact our second quarter, but that was factored into our guidance despite that we're going to generate that strong growth that we're forecasting for the second quarter.

Joseph Magner - Macquarie Research

Okay, I just want to clarify that.

Operator

Our next question comes from Steve Berman from Pritchard Capital Partners.

Stephen Berman - Pritchard Capital Partners, LLC

Specifically in the past, you've talked a little about possibly monetizing the Gulf Coast assets. Are we any closer to that? And I think you talked about maybe waiting for some wells to come on or to just have some history on some wells. Can you bring us up to speed on that?

A. Langford

I think -- it's Lance. Still, that's another bucket of liquidity that is out there in front of us. And I think there's a high probability within the next 12 months, but we said that 6 months ago. So I think it's still an option. Certainly, gas prices are marginally north of where they were into the year. And so -- but it's something we're looking at and it's something we need to do in order to fund this huge opportunity we have in the Williston Basin.

Stephen Berman - Pritchard Capital Partners, LLC

And then the other thing I wanted to ask is there's a couple of companies recently talking about the Mary Shale [ph], I know that's -- and I'm going way back with this, but that's something you guys had or may still have. Do you still have Mary Shale [ph] assets?

A. Langford

No, Steve, we divested that. So we're no longer active there.

Stephen Berman - Pritchard Capital Partners, LLC

Right. Okay, that's it for me.

Operator

Our next question comes from Andrew Coleman from Madison Williams.

Andrew Coleman - Madison Williams and Company LLC

I had a question about maybe Slide 16. I guess could you break down or give any more detail on the $15,000 per well per month OpEx? How much of that is -- is that all fixed? And is there a variable component that goes with that or is that a mix of fixed variable?

Ben Brigham

That's a fixed component. The variable component is our saltwater disposal.

Andrew Coleman - Madison Williams and Company LLC

Okay. And approximately how much -- or I guess -- well, let's see. What goes in, in that 15,000? Is that all just pumpers or is there gas handling in there as well?

Eugene Shepherd

It's every -- well, it's not everything. It's all the operational expense other than the variable FWD [ph]. It's the pump versus electricity. It's the lubricants. It's the normal O&M, the maintenance that goes on it. If we to pull a broad pump or something, it's in there. So that workover is associated with that is in there.

Andrew Coleman - Madison Williams and Company LLC

Okay. And so then the new water handling line that's going to be built by the fourth quarter you guys mentioned earlier in the call, you said that you're now being about $6 to $7 a barrel for disposal, that's a whole variable cost? So you won't expect to see a whole lot of change up on the fixed costs here in the short term? I mean, is that true?

A. Langford

Well, no, it's not because what we're seeing in the fourth quarter is fully operational. And we already have 2 FWDs [ph] up and operating. So we'll be able to control our water and get it to our facilities. So we won't have those exorbitant transportation fees from the trucking companies because we're going to have the capacity for our own water. We're only taking our own water or disposal wells. And we've just completed drilling the third, and we're working on competing and facilitating the third disposal well. And we'll be adding more throughout the year to match our growth in water.

Andrew Coleman - Madison Williams and Company LLC

Okay. So then, as far as -- how should I think about the fixed number then? The kind of...

A. Langford

It's probably going to be in the $2.50 range, somewhere in there.

Andrew Coleman - Madison Williams and Company LLC

Okay. Yes, great. And then...

A. Langford

That's for transportation and disposal.

Andrew Coleman - Madison Williams and Company LLC

Okay, great. And then the second question I had was just on Slide 28, the Rough Rider increased density. Well, how long was the first well on there, I guess the line, 16-1H but before the 2H was drilled?

Ben Brigham

Well, we've got it online for a year, roughly, before the 2H was drilled, maybe doing -- pumping 200 barrels a day and close to 2H. It became online, flowing at a higher initial rate. Now it's comparable rate to the first well.

Andrew Coleman - Madison Williams and Company LLC

Okay. All right, great.

Operator

Our next question comes from Jason Wangler from SunTrust.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

Just a quick question on the backlog. You said there was 15 wells and you got the eighth rig coming in and the 2 frac crews. Where do you see that backlog of all when I guess as the year goes and you get a little bit more efficient? Do you still have a 5- or 10-well backlog or do think that you can get down even lower?

A. Langford

Well, I don't think it's ever going to get down that low, Jason, the reason being that backlog is included with wells. You've got to have the swell packers on for 2 weeks, and you want to have the inventory built up. You have to do a clean-out run, you've got to prep the location. So as we increased the number of rigs, you'll see that waiting on completion -- number of wells waiting on completion increase.

Ben Brigham

I love it that all you think about is doing maybe a number that's ready for completion.

A. Langford

Yes, but you still want an inventory of those because they -- you'll never know what's going to happen in the completion. And that's one of the benefits that we provide Halliburton. We always have locations ready to go. We don't have that many extra. It always sounds like there's a bunch of extra. There are some extra in that number right now, but typically, we have just enough that we needed. And as you bring on more rigs, that number is going to grow. And you're going to need it to grow because you're going to have more wells completing because you're bringing in more frac crews.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

That makes sense. I was trying to get good run rate for what it would be going forward. And then on the cost side, not to harp too much more, but maybe, Gene, are you seeing it maybe kind of flattened out now as the weather is getting better and it's getting back to kind of normal operations? Because obviously, the first couple of months, I think we saw some cost increases for a lot of different reasons.

Eugene Shepherd

Yes, well, the 8.9 is what we're seeing we're going to be incurring. You're asking about AFEs or operating cost?

Jason Wangler - SunTrust Robinson Humphrey, Inc.

Yes, the AFEs. Just if you've seen the kind of those costs come down or at least being less rather.

Eugene Shepherd

Well, yes. I mean, we were kind of there right now. So that's what the 8.9 is. Of course, when we've been having some unusual storms and it's unusually wet out there, when it's not frozen, so the costs today are going to be more than the costs in 2 weeks. But yes, as you go down through the summer and we start doing zipper fracs, our efficiency and costs, you should see it start driving down immediately.

Ben Brigham

Yes, a combination of better weather, better conditions and more efficiencies with the opportunities we'll have in the field there.

Jason Wangler - SunTrust Robinson Humphrey, Inc.

That's all. I'll turn it back.

Operator

I'm showing no further questions at this time. I would like to turn the call back to Bud Brigham for closing remarks.

Ben Brigham

Yes, just I want to thank everybody for joining us for the call. And we look forward to reporting on what will be a very exciting second quarter for the company. Thanks again.

Operator

Ladies and gentlemen, that does complete today's conference. You may all disconnect, and have a wonderful day.

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