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Executives

A. Langford - Executive Vice President of Operations

Rob Roosa - Finance Manager

Ben Brigham - Chairman, Chief Executive Officer and President

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

Jeffery Larson - Executive Vice President of Exploration

Analysts

Scott Hanold - RBC Capital Markets, LLC

Brian Lively - Tudor Pickering Holt

Derrick Whitfield - Canaccord Genuity

Martin Beskow - Northland Securities Inc.

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

Subash Chandra - Jefferies & Company, Inc.

Peter Mahon - Dougherty & Company LLC

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

Brigham Exploration (BEXP) Q4 2010 Earnings Call February 25, 2011 11:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2010 Brigham Exploration Company Earnings Conference Call. [Operator Instructions] I would now like to turn the conference over to your host today, Bud Brigham, Chairman, President and CEO. Please begin.

Ben Brigham

Thank you, Sean. Thanks to each of you for participating in Brigham Exploration Company's Year-End 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; 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. Rob?

Rob Roosa

So one quick point. If you're having any trouble downloading the new version of the presentation and the older one shows up, the older files might be still cache on your computer. So if you're at the Home page and you hit Control F5, you should then be able to download the newer presentation.

Ben Brigham

So Control F5. The presentation includes some really helpful information regarding our 2010 results as well as our plans for 2011. We'll be referring to the slides in the presentation during our discussion, and it will help you to be prepared with this as we'll flip through some of the slides pretty quickly.

One other note regarding the website. In conjunction with the redesign, we've added some animations, and we'll continue to add animations, which should help you to better understand our business. These can be found by clicking Operations and then clicking Technologies & Animation, and finally, clicking Animations, which is located in the central part of the web page.

Also, regarding the website, with the popularity of iPhones and iPads, we've upgraded the website with a mobile version. This mobile site link is located at the top central portion of our Home page.

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'll 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 our cautionary note to U.S. investors regarding the use of 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 4, you can see our outline for the call. As we discussed on our last call, our theme these days could be described as No Oil Left Behind. Given that we've completed our prior initiative in the Williston Basin to drill geographically dispersed wells around our acreage position in order to initially delineate the attractive economics, we've 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 several years.

The newsworthy events we'll be discussing on the call include the following. One, our planned acceleration to 12 rigs relative to our previously planned eight; two, our belief that we have the opportunity and are therefore spacing our units to drill at least four wells per horizon per spacing unit, which provides roughly 33% growth in our inventory to develop; three, the visibility we have for driving down costs given our concentrated acreage position and our utilization of smart pads; four, our continuing improvement in well performance; and five, our second Bakken discovery in Montana with the Swindle. We had hoped to be announcing our currently completing Johnson as our third Montana discovery as well as two additional significant Ross Area wells, but we didn't quite get the flow back on these wells in time.

So I'm going to start by briefly discussing the macro environment we're operating in, followed by a brief summary of our results. Following that, Lance will discuss our reserves further to provide you an operational update and discuss opportunities we have to drive down costs and update you on our facilities build-out in the field. Jeff will then provide you an overview of our current and planned activity by project area in the Williston, following which Gene will discuss our 2010 financial results and our 2011 budget.

So let's get started by first taking a quick look at the macro environment on Slide 6. As shown, oil has traded at a premium to natural gas for several years now. I think most of you agree with me that given this abundant supply of natural gas, that this relationship is likely to persist for some time now, at least the next three to four years, though I think probably much longer.

As shown on Slide 7, partly as a result, it's a great time to be compounding value for our shareholders by accelerating our activity in the Bakken and Three Forks plays. 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 oil play. Our view is that the Williston Basin, Bakken and Three Forks plays are the number one margin and return plays in North America. It's easily the best play we've been involved in.

Now for the sake of time, I won't discuss Slides 8 and 9, but they further illustrate the commodity advantage we're benefiting from in the Bakken and Three Forks plays.

Moving forward, Slide 10 summarizes the history of the Bakken and Three Forks plays and the fact that we benefit from our first-mover position in the play dating back to 2005. As a result of our aggressive early entry into the play, our acreage has concentrated in the center of the best areas of the play. Those, we believe, with the thickest Bakken and highest Middle Bakken porosities. That, combined with the outstanding efforts of our technical staff, has enabled us to lead the way in the play by completing 51 consecutive high frac stage long lateral wells in North Dakota with an average initial peak rate of roughly 2,858 barrels of oil equivalent per day. So when you look at the list of leading companies active in the play on the left, I'd point out that it's not just the quantity, but the quality of our acreage that puts us in such an enviable position. And, of course, it's our people who are successfully executing our plan.

Moving to Slide 11. You can see the updated list of our 51 consecutive high-rate Bakken and Three Forks completions in North Dakota. This list includes the three highest IP wells in the basin and the eight highest IPs west of the Nesson Anticline. Our record wells were among our recent wells. We're continuing to optimize operationally, and our results continue to improve, as we'll show you in a minute on the subsequent slide.

Now let's move forward to Slide 12. Let's look at a table illustrating our inventory. Please note that based on the information disclosed in our press release regarding the microseismic results, which were recorded during the completion of the Brad Olson #2, it looks as though we will have opportunity to drill four Bakken and four Three Forks wells per spacing unit or eight total wells per spacing unit. This update has been incorporated in this slide and, therefore, our inventory has grown from 590 net locations in our core acreage to 782 net locations. This slide clearly shows the depth of our inventory even if you assume our 484 additional potential Three Forks locations in Rough Rider are not yet de-risked.

Regarding the Three Forks and Rough Rider, Slide 13 shows the performance today to-date of our Rough Rider State Three Forks well. The State well came on at 2,356 barrels of oil equivalent per day and, as you can see, is performing almost as well as our Ross Three Forks wells and better than our competitors' Three Forks wells in the Ross Area. Obviously, that's very encouraging. Other operators have also drilled successful Three Forks wells in our Rough Rider area. So we believe that all of our Rough Rider area is productive from the Three Forks. If that's the case, then Slide 14 shows that the Three Forks locations in Rough Rider grow our inventory by 62%. Jeff will review our 2011 plans by area, but we plan to drill more Three Forks wells in Rough Rider this year to more fully delineate the economics of the Three Forks in this area.

Now please take a look at Slide 15. The results of our microseismic and our early density completion indicate that we should be able to drill at least four wells per horizon per spacing unit. The microseismic actually points to at least five, though it's too early to say. In the event we can drill more, our inventory grows meaningfully. For that reason, we will likely initiate a five-well pilot during 2011.

Still viewing Slide 15, there is one more point to make here. We're very early in developing this resource for our shareholders. We have multiple layers of value to delineate, and that will take many years. Thus, our continued acceleration makes a lot of sense. With our currently planned acceleration to 12 rigs, the current de-risked core acreage shown in red provides us with about an 11-year inventory based on the net wells we expect to drill in 2011. However, I believe it's likely an 18-year inventory inclusive of the Three Forks in Rough Rider.

Slide 16 shows our growing CapEx for 2011 as we continue to add rigs, building to 12 rigs in 2012. Gene will discuss this further in a bit, but we're adding incremental rigs her at the same pace as our ramp-up from four to eight rigs. So we're very comfortable that this is a very achievable plan.

Slide 17 is from one of our analysts and illustrates our outperformance relative to our peers. In addition to the outperformance, you can see here that our IPs have been improving over time. And we'll show you that it's not just the initial rates but the entire production curve that continues to elevate to higher levels. Obviously, this trend is very important. We're still able to innovate to improve well performance.

Moving to Slide 18. This slide shows our Williston Basin production growth through 2009. And Slide 19 illustrates the growth we've achieved during 2010. In mid-April of this year, we go from 1.5 frac crews to two dedicated crews. Thus, our rate of completion fully accelerates. Given our announced plans to add four more rigs, moving towards 12 rigs in 2012, production should continue to grow at a strong pace.

Slide 20 simply illustrates how much running room we have to develop just the acreage we've already delineated. It's an 11-year inventory at our 2011 pace without the Three Forks and Rough Rider and 18 years with it.

Slide 21 shows the impact our Bakken and Three Forks drilling has had on our quarterly oil volumes. Our fourth quarter oil production was up 218% relative to last year's Q4 and up 44% sequentially.

Looking at Slide 22, Gene will discuss our 2011 guidance in a few minutes, but we're expecting our full year oil production to grow by roughly 100%.

Slide 23 shows our historical and forecasted total net equivalent production. We expect full year 2011 equivalent production to grow roughly 81% relative to 2010 to average between 14,000 and 16,000 barrels of oil equivalent per day. Of course, oil has and will continue to trade at significant premium to natural gas, and that's reflected on Slide 24. Inclusive of that, Slide 25 illustrates our realized equivalent production growth. Just a few years ago, we were 80% natural gas. So clearly, we made the transition to an oil company at an optimal time.

Slide 26 shows our net production and associated growth in revenue and EBITDA we've achieved since we began drilling our high frac stage long lateral Bakken and Three Forks wells in 2009. This helps illustrate how misleading it is in our case to look at our valuation in terms of trailing multiples, given our dramatic growth trajectory. In my view, if you look forward at the analyst model of cash flow metrics for 2012, we're actually relatively undervalued, but net asset valuation metrics provide a more reliable valuation in our case.

Slide 27 simply illustrates our net wells drilled versus production in 2009 and 2010 by quarter. It also shows our currently scheduled drilling plans for 2011 by quarter, though this will move around some. We expect the higher level of completions to take our production to significantly higher levels particularly beginning in the second quarter.

Now moving briefly to reserves. Slide 28 shows the growth in our proved reserves, of course driven by our successful Bakken and Three Forks drilling. 2010 was a transformational year. And given our already delineated '11 tight end-year [ph] inventory, we've got many years of significant reserve growth ahead of us.

As shown on Slide 29, our proved developed reserves as a percent of total reserves were roughly flat relative to last year. Our proved developed reserves added, inclusive of revisions, replaced 562% of our production in 2010.

On Slide 30, you can see that the majority of our value is operated, and this will be increasingly the case as we accelerate our operated drilling program. That's obviously a positive in part because our operated finding and development costs are lower than that of our peers. Also, as shown on the slide, we've transformed from a company that was 80% natural gas just a few years ago to a company that is now 78% oil and growing.

Slide 31 simply illustrates that our drilling and land finding costs, inclusive of the revisions, were a very attractive $9.23 per BOE. Importantly, if you move to Slide 32, you can see that our operated proved developed drilling cost was a very attractive $15.57 per BOE. This is our engine for growth. You can also see our outperformance relative to our peers operating in the play. We generated much higher finding costs. In prior presentations, we've shown this by presenting natural production curves for our wells and our competitors' wells in the same area.

As shown on Slide 33, as we've increased the number of frac stages we've, of course, reduced the spacing between stages. This plot illustrates, for all of our North Dakota long lateral high frac stage Bakken and Three Forks wells, the improvement we've seen in well performance with more stages and closer spacing.

But it's not just about frac stages anymore. We're now innovating in other ways that are positively impacting well performance, and possibly the most encouraging aspect of the play is that we're continuing to generate improved results even today.

We have a series of slides for you quickly that will illustrate that point, looking at two different areas. First on Slide 34, in a portion of our Ross Area, you can see an average curve for our wells completed here during 2009. If you click and go to Slide 35, you can see an average production curve in orange for the wells we drilled in this area during the first half of 2010. If you click again, and go to Slide 36, you'll see the wells we've subsequently completed since mid-year last year in the same portion of our Ross Area. In fact, the Ross Area includes the recent record wells in the play including the top three highest initial rate wells and four of the top five in the basin. You can see that it's not just IPs that are getting better, we're elevating the entire production stream.

Similarly, in a sampled area of our Rough Rider project, you can click forward successively from Slide 37 to 39. Again, we're continuing to see improving well results. In many cases, we've actually fixed the number of frac stages but are innovating in other ways and continuing to generate improving performance. In the Rough Rider area, we've now completed the eight highest initial rate wells west of the Nesson Anticline. We expect this trend to continue and that our results should continue to improve.

Slides 40 and 41 illustrate the fact that we benefit from early-mover acreage position in the play in yet another way given that it's provided us with a dominant concentrated acreage position in the center of some of the best areas in the basin. In recent years, we've simply been stepping out, drilling scattered wells around our acreage to delineate the attractive economics over the acreage entire extent. But we've now entered the phase in which we can begin to capitalize on this dominant position and, in the process, generate significant operational efficiencies, providing excellent visibility for driving our cost down very materially.

Integral to this opportunity will be our utilization of smart pads. Our Ross and Rough Rider areas provide us with 188 operated 1,280-acre spacing units for potential smart pad development where we could drill as many as 1,504 gross wells. We estimate that 112 of these spacing units are stacked stand-up 1,280-acre spacing units. In other words, two 1,280-acre stand-up spacing units that adjoined each other end-to-end from north to south. These stacked 1,280 units provide additional drilling and completion efficiencies. Our 2011 drilling plans, which Jeff will discuss in his section, include 26 stacked units to be drilled in our Rough Rider and Ross areas.

By the way, also overlain on slide 40 and 41 are our midstream facilities, which are under construction and partially operational, another opportunity to capitalize on our dominant acreage position in these great areas to drive down costs and generate incremental profit centers. Lance will update you on our progress with the construction of this infrastructure.

Slide 42 illustrates a map view, our current smart pad concept for the stacked stand-up 1,280s. It illustrates our current configuration and plan for hours stacked 1,280 units with the smart pads shown in the northern end of the Southern unit.

These smart pads provide the following opportunities for us that we'll begin to realize in 2011 and will increasingly benefit from in subsequent years. First, they minimize our surface footprint; second, they reduce our drilling and completion costs; third, they allow for simultaneous zipper fracs, which we've already successfully executed in the field; and fourth, they allow for centralized tank batteries. All of the above mean less time, less equipment and lower costs in the field. We believe the combination will drive down our costs to drill and complete our wells by 10% to 20%.

There's a great deal to communicate regarding this opportunity, and we can effectively do so during the conference call. However, we prepared an animation, Slides 43 and 44 are illustrations of it, which is attached to our website. Viewing the animation should help you to appreciate the opportunities we have to become substantially more efficient in the field at developing this world-class resource. I encourage you to view that.

Now beginning with Slide 5, we'll provide you an important update on our first density project where we recorded microseismic during the completion of Brad Olson #2 density well. The separation of these two laterals averaged about 1,200 feet, which is roughly a four-well spacing distance.

As shown on Slide 46 in a Time Zero normalized display, the Brad Olson #2 has produced comparably to the first well, which is approximately 1,200 feet away to Brad Olson #1. The comparable performance is despite the fact that Brad Olson #1 was completed roughly a year earlier, in late October 2009, and also despite the fact that the Brad Olson #1 had been producing on pump at the time of our recent Brad Olson #2 completion, at a pumping rate of approximately 200 barrels of oil per day.

Our density well came online flowing comparably to the performance of the first well a year prior as shown on Slide 41. However, it's also interesting to note that the Brad Olson #2 density well has actually flowed longer than the first well, another very positive indication of the potential for more dense and development. The story depicts when the Brad Olson #1 went on pump, and we expect to put the Brad Olson #2 on pump soon. So we're very comfortable that the production data indicates no meaningful depletion of communication between the wells that are separated by an approximate four-well spacing distance.

If you move to Slide 47, you can see broad diagrams that we're using to communicate our current interpretations of the drainage areas, our current drilling plans, and some other potential opportunities in front of us. At the lower right portion of the slide is a single well bore and our current interpretation of the frac and post-frac extent based on our microseismic and early well performance. This illustration, again at the lower right, is shown on a one-to-one, vertical-to-horizontal scale. The microseismic interpreters estimated that the lateral average frac extent was approximately 500 feet in either direction in the Middle Bakken away from the borehole. We assumed conservatively for this illustration that 100% of the average frac extent is propped. But we know that while the majority of the link is propped, the entire link is not. The red areas in the upper and lower Bakken Shale illustrate areas that, based on the microseismic events, were initially frac-ed, but given that they're in the shales, the interpretation it is only the approximate area colored in yellow was propped open for production.

Staying on Slide 47, but viewing the larger block illustration above at the right-center portion of the slide, this is an illustration of our current well plan in the Bakken and Three Forks spacing unit, again with our current interpretation of the 500-foot frac extent laterally in both directions away from the boreholes. The vertical dimension is exaggerated 10:1 relative to the horizontal for illustrative purposes so that you can see our current interpretation of how the pay section in our producing units may be being drained.

One thing that was apparent in the microseismic is that the vast majority of the energy or breakage of the rock occurs within 200 to 300 feet of the borehole. We've attempted to illustrate this with darker shades of yellow near the wellbore indicating higher recoveries, which decrease in intensity away from the laterals. In my view, we're creating almost a rubble zone near the laterals, and there may be opportunities for draining more of the oil left behind between the laterals.

We believe our more numerous but shorter frac wings and thus more efficient creation of artificial permeability in drainage near the wellbore is partly a function of our increasing the number of frac stages while keeping our overall frac sizes constant. So we believe we're draining much more efficiently near the wellbore than operators using fewer stages or than those using frac sleeves.

It's our view that our current completion techniques are potentially providing us the opportunity for both better returns on our wells, as illustrated by our wells' outperformance relative to our competitors in the same areas, and potentially more wells per unit. And, of course, that means more reserves for us to develop. It also allows us to get closer to achieving our goal of No Oil Left Behind.

Based on 500-foot lateral frac extent, our well spacing provides us with the opportunity to drill four Bakken and four Three Forks wells. As shown with our current spacing plan, we actually have the opportunity to drill another 1/2 well in each unit for both the Bakken and the Three Forks. These would be unit wells spaced with the adjacent units.

Slide 48 illustrates our current microseismic interpretation of the frac extent and drainage areas for our spacing units in map views, indicating that substantial amounts of oil would be left undrained with the three wells per unit per horizon. The 500-foot frac extent indicates the potential for five wells per spacing unit, as shown at the bottom of the slide. Again, we're currently contemplating a potential five-well density pilot later this year.

Slide 49 is a block illustration of the Ross Area, which has the biggest Bakken and Three Forks resource package in the basin. Partly for that reason, I believe the Ross Area will ultimately produce more reserves per acre than any other area including Parshall and Sanish.

If you click forward to Slide 50, we're illustrating the potential we're intrigued with, as are other operators, for horizontals in subportions of our company's acreage targeting the Scallion or basal Lodgepole. I believe operators will be discussing this opportunity further during the course of 2011.

Moving forward and finishing up my section with Slide 51. We know that the shales contribute meaningfully to our production. So over the long haul, there's potential for horizontals at other levels just on the vast amounts of oil in place out of this world-class resource. When you step back and think about it fundamentally as an industry, we're developing tighter and tighter rocks. And we believe we're clearly early at figuring out how to optimally plan the oil out of this resource. There's clearly more to come.

We plan to update these block illustrations as our interpretation and plans evolve. In addition, there's good potential for other resource plays to develop, as well as other opportunities for refrac-ing and subsequent recoveries. All of this provides option value for our shareholders to potentially realize over time. So with that, I'm going to turn the call over to Lance. Lance?

A. Langford

Thanks, Bud. If you move to Slide 53, the build-out of the Williston Basin support infrastructure is underway. This support infrastructure will include the construction of our Williston Basin regional office and pipe yard. It also includes over 430 miles of gathering lines and nine water disposal wells. In 2010, we spent $33 million on infrastructure and have laid over 130 miles of gathering lines, drilled two water disposal wells and began instruction of our regional office and pipe yard. In 2011, we budgeted to spend an additional $83 million on infrastructure and will lay an additional 260 miles of gathering lines, drill seven water disposal wells and complete the construction of our regional office and pipe yard.

Moving on to Slide 54. Our 14,000-square foot regional office will be completed in May of this year and will house our Regional Manager and field personnel. We also have constructed a large pipe yard that will act as a staging area to help meet our casing and tubing needs.

Moving on to Slide 55. As you can see, our concentrated acreage position provides a unique opportunity to build out an expansive gathering system that will include over 430 miles of gathering lines, nine water disposal wells. This gathering system will help ensure execution of our drilling plans and will provide returns competitive with those of our drilling economics. It will also provide maximum connectivity to all major crude oil pipelines, which transport volumes out of the basin, and will put Brigham in a position to take advantage of all currently planned major pipeline expansions and rail options.

If you move to Slide 56. The Ross gathering system in Mountrail County has 58 miles of gas and produced water gathering lines. Our natural gas volumes are currently flowing through our gathering lines and redelivering gas volumes to Whiting gas processing plant. Our produced water volumes are currently being gathered by our lines and disposed off in our Ross disposal well. In 2011, an additional water disposal well will be drilled in the Ross Area to meet our growing disposal needs.

Then moving Slide 57. The Williams gathering system will consist of 302 miles of crude oil produced water and fresh water gathering lines. In 2010, we constructed approximately 112 miles of crude oil, produced water and freshwater gathering lines, as illustrated in blue. We also completed a water disposal well next to our regional office. This disposal well is currently fully operational and in use. By year-end 2011, the entire Williams systems should be complete and fully operational, including two additional water disposal wells.

Moving on to Slide 58. In 2011, we will construct our McKenzie gathering system, which will consist of 73 miles of crude oil, produced water and freshwater gathering lines. It will also include four water disposal wells. This entire system should be complete and fully operational by year-end 2011.

Now moving to Slide 59. If you look at the Williston Basin pipeline system, there are several major pipeline projects in the works that will provide additional capacity to transport crude oil out of the basin via pipeline. We expect to connect our Williams and McKenzie gathering systems to all these pipelines and take advantage of these expansions. This will provide us with maximum flexibility to move our crude and move it at the lowest price possible.

We will be connected to plains in Enbridge at their Trenton facility, and we will be connected to Bridger at their Alexander facility, which will interconnect to Butte, Platte and Keystone XL pipelines. We will also have easy access to multiple rail loading stations, including a possible rail loading station of our own if the need arises.

Moving on to Slide 60. As you can see, the planned expansion for the Williston Basin should provide adequate capacity for crude oil for at least the next several years. If there is a need for additional capacity in the future, there are several projects not currently approved that will move forward and provide the needed capacities.

Now moving to Slide 61. In addition to higher oil prices, which have positively impacted our Williston Basin drilling economics, the oil differentials have narrowed in 2010 to between $9 and $10 per barrel, also contributing to the enhanced drilling returns. I believe this range will continue for the foreseeable future with the possibility of some short periods exceeding $10 during the winter months or some unforeseen pipeline disruption. With that, I'll turn the call over to Jeff.

Jeffery Larson

Thank you, Lance. Please turn to Slide 62. This slide highlights our Easy Rider activity. Here, we currently have three wells waiting on completion, two flowing back and one frac-ing. We are also using our simultaneous frac technology on the Sorenson and Cvancara wells located at the bottom of the slide and look forward to reporting our results in the near future. We also have two rigs currently running in the Easy Rider project area highlighted with black rig symbols on the slide. In 2011, we plan to keep both rigs active in this project, drilling Bakken locations and at least three Three Forks locations. We're excited to report that we also plan on commencing the first well of our four-well Bakken density pilot in August of 2011, labeled in green on Slide 63. And they also test a five-well pilot in Easy Rider late in 2011. Our plans are to deploy microseismic during the completion phase of the pilot program.

Slide 64 is an update of our Rough Rider activity. We currently have nine wells waiting on completion and four rigs running in the Rough Rider project area. Three of the four rigs are drilling on two adjacent 1,280-acre smart pads units. The fifth rig seen mostly on the left side of the map represents the Delorme location that spuds in early March following the Erickson well, which has just now reached total depth.

Industry activity around our lease block has increased significantly in the last year. Currently, there are 27 rigs drilling Bakken and Three Forks wells around us. We are very fortunate in that we were the early mover in mapping and leasing in Rough Rider and believe we have the highest reservoir quality acreage in the area.

In 2011, we plan to keep five rigs active in Rough Rider for a significant portion of the year with the fifth rig returning from Eastern Montana following the drilling of two wells. We plan on adding a sixth rig in September of this year to the Rough Rider project.

We also plan on commencing the first well of a four-well density pilot in June of this year and may test a five-well pilot in the project late in 2011. Our plans are also to deploy microseismic here during the completion phase of the pilot program.

Lastly, for the Rough Rider area, an important new Three Forks completion has been released. The Tracker Scalan, which IP for approximately 1,500 barrels of oil per day, is located directly offsetting our bank's lease block on the lower right side of the slide.

Slide 65 is a zoom-in look at our Brad Olson 3 well density pilot in Rough Rider. As Bud mentioned earlier, we deployed microseismic during the completion of the Brad Olson 2 well and saw no communication between the wells with the Brad Olson 2 coming on flowing with an IP of 2,717 barrels of oil equivalent a day. Importantly, the density spacing between the Brad Olson #2 and #1H, as seen on the slide, is actually less than we plan to space our wells for a four-well density drilling, which will be 1,320 feet apart. We believe this pilot already demonstrates the need for at least four wells per unit per interval to effectively drain reserves and potentially up to five wells per unit per interval.

Turning to Slide 66. This is the highlight of the recent activity in Eastern Montana. In Eastern Montana, we have one well frac-ing, one well currently completing and one well, the Beck 15-10 located near the upper left portion of the slide, currently drilling. Following TD [ph] of the Beck well, we plan to spud the Charlie 15-10 (sic) [10-15], highlighted with a black rig symbol on the map and located one mile east of our Swindle well. The rig will then return to the Rough Rider project.

On the completion side, we're very excited about both of our completing wells. The Johnson 30-19, highlighted with a yellow tag near the lower right portion of the slide, is currently frac-ing and is located approximately five miles south of the Zenergy Sweetman well, an important Bakken control point. We participated in the Sweetman well, which IP for 1,200 barrels of oil equivalent a day, and then the well has continued to perform very well.

The second completing well, the Voss 21-11, is located approximately three miles west of our Sedlacek Trust well, which IP-ed at approximately 2,700 barrels of oil equivalent a day, and approximately six miles southwest of our Gibbins well that IP-ed at approximately 2,600 barrels of oil equivalent a day. The Voss is 100% working interest well that we recently acquired from another operator. This 2007 Bakken horizontal well was completed with a single, uncontrolled frac. We have successfully removed the old liner from the well bore and are preparing to run swell packers with 28 frac stages planned. For the remainder of 2011, our plan, when we pick up our eighth rig in May, is to move that rig to Eastern Montana and drill a group of Bakken locations. With that, I'll turn the call over to Gene for the financial update.

Eugene Shepherd

Thanks, Jeff. 2010 was a remarkable year from the standpoint of the operational and financial transformation that Brigham experienced. Before I get into a discussion of our fourth quarter and full year 2010 results, I have several comments about some of the financial milestones that we achieved in 2010 and how these accomplishments have set the stage for the further acceleration to 12 operated rigs that we announced yesterday.

Milestone number one, the expansion in our equity base. The equity offering that we completed in April 2010 was the latest step in expanding the company's equity base to accommodate the acceleration in drilling activity at our Williston Basin acreage position in our inventory that de-risked drilling locations demand. At the beginning of 2010, we had four operated rigs working. As we exited 2010, we had seven operated rigs working. And yesterday, we laid out a plan to reach 12 operated rigs by September 2012.

Milestone number two, the financial impact of our outstanding 2010 drilling results. Our 2010 drilling activities have dramatically grown our high-value oil volumes and the associated cash flows. After a partial year of drilling activity in 2009, 2010 was the first year that we have maintained 12 months of sustained drilling activity using our current Williston Basin drilling and completion formula. And our oil volumes have responded accordingly, growing 167% relative to those in 2009, further enhancing the company's 2010 year-end cash flows. And based on our 2011 oil and gas CapEx budget, we are forecasting a continuation of this production growth trend in 2011 with our 2011 production guidance that we issued yesterday targeting 101% growth in our oil volumes and 83% growth in our total production volumes.

Milestone number three, the expansion of the company's liquidity position as partially reflected by the growth in the company's borrowing base. Based on our year-end 2010 reserve report, our borrowing base under our new credit facility has grown to $325 million of availability. As outlined on Slide Number 68, combining the unused capacity under the new credit facility that closed on February 23 with our cash position at year-end 2010 gives us, $573 million of total corporate liquidity.

Milestone number four, the transformation of the company's risk profile. The senior notes offering that we completed in September 2010 marks the first time in over two years that we have used debt to fund a portion of our drilling CapEx.

Several enhancements in the company's risk profile has set the stage for the use of leverage to augment cash flow and fund a portion of our drilling CapEx. Number one, the aforementioned growth in our equity base, production volumes and cash flow; number two, the growth in our proved developed reserves, up 131% at year-end 2010 to roughly 23.6 million barrels from those at year-end 2009, reflecting the dramatic growth in the company's cash flow generating assets; and number three, the dramatically reduced risk profile of our current inventory of Williston Basin drilling locations.

51 consecutive highly economic, horizontal North Dakota Bakken and Three Forks wells had de-risked the bulk of our acreage position in the Williston Basin. Considering this success, our future drilling in the Williston Basin can be characterized as low-risk, repeatable drilling.

Yesterday, we announced our 2011 CapEx budget of $693 million, funding further acceleration in our operated rig count to 12 rigs by September 2012. As outlined on Slide Number 69, drilling CapEx comprises $582 million of our 2011 budget to roughly 66 net horizontal Bakken and Three Forks wells in the Williston Basin. Additionally, we anticipate spending roughly $27 million on land acquisitions. Finally, we expect to spend roughly $83 million on Williston Basin's support infrastructure, our crude oil, produced water and freshwater gathering systems that are under construction at Williams, McKenzie and Mountrail Counties, North Dakota. Lance has covered with you our plans to finish construction of our support infrastructure in 2011 with all systems expected to be fully operational around October 2011.

Benefiting from our concentrated Williston Basin acreage position, these investments should allow us to lower our differentials and lower our lease operating expenses for our current and future horizontal Bakken and Three Forks wells.

To wrap up our liquidity discussion, based on our 2011 oil and gas CapEx budget, it is our expectation that our 2010 year-end cash position of $248 million and our 2011 cash flow from operations will fund the majority of our 2011 budget with the unused capacity under our new senior credit facility funding the remaining shortfall.

Moving on to a discussion of our fourth quarter and full year 2010 results. Our fourth quarter total production volumes averaged 11,384 BOEs per day, which was above the midpoint of our fourth quarter production guidance of 10,500 BOEs per day. Our oil volumes totaled 9,129 barrels of oil per day, representing 80% of our total volumes. More importantly, because of the substantial favorable pricing of oil versus natural gas, which we are fully able to capitalize on by focusing on our drilling in the Williston Basin, our oil revenues represented 91% of our total fourth quarter pre-hedge revenues. Our fourth quarter production volumes included approximately 135 barrels of oil per day added to inventory during the quarter but held in our on-site tank batteries and recorded as inventory at year-end. Adjusting our fourth quarter production volumes for amounts included in the inventory results in average daily sales volume for the quarter of 11,249 BOEs per day.

Please note that our revenues for the fourth quarter include $489,000 of support infrastructure revenues from our non-operated partners in our wells that have begun to rely on transportation from our Williston Basin support infrastructure, specifically some of our wastewater disposal and gas gathering assets that were operational during the quarter. These revenues and $50,000 of associated support infrastructure expenses are broken out for the first time in our year-end 2010 financial statements. Brigham-related service infrastructure revenue and expenses are eliminated from total company revenues and expenses during consolidation.

In terms of our costs, our fourth quarter 2010 per-BOE lease operating expense decreased 35% to $5.90 from $9.10 in the fourth quarter of 2009. This decrease was largely driven by higher fourth quarter production volumes and a $2.06 per-BOE decrease in workover expense related to reduced levels of conventional asset workovers. For the full year 2010, lease operating expense decreased 22% to $6.33 per BOE from $8.16 in 2009. For the full year, higher productive volumes offset the impact of an increase in the dollar amount of our lease operating expense.

Our fourth quarter 2000 (sic) [2010] production taxes increased $2.26 per BOE due to the growth in our North Dakota oil volumes and the higher oil prices experienced during the quarter relative to that in the prior year's quarter. Production taxes for the full year 2010 increased $3.04 per BOE versus those in 2009.

G&A expense for the fourth quarter of 2010 increased $1.1 million compared to that in the fourth quarter of 2009 because of higher employee compensation costs, including reinstating our employee bonus plan in 2010, which was suspended in 2009 due to the economic uncertainty experienced in late 2008 and early 2009. G&A expense for the full year increased by $3.7 million also due to higher employee compensation costs.

Our fourth quarter EBITDA increased 216% to $51.5 million, and full year EBITDA increased by 170% to $142.5 million.

To conclude our income statement discussion in the fourth quarter and full year 2010, we incurred $1.1 million of income tax expense, which was primarily State of North Dakota income taxes, which were also 100% deferred. In 2011, we do not expect to incur any federal income tax expense because of our net operating loss carryforwards. However, in 2011, while we expect to incur roughly 4% North Dakota state income tax expense. But as was the case in 2010, we would expect 100% to be deferred.

Moving on to the balance sheet. At year end 2010, we had $248 million of cash and marketable securities on deposit, nothing outstanding under our senior credit facility and had a $325 million borrowing base and $300 million of senior notes outstanding. Of the $248 million in cash and marketable securities at year end, approximately $24 million was represented by cash and short-term equivalent and $224 million was invested in marketable securities with maturities of less than 18 months.

In terms of capital expenditures, during 2010, we spent $425 million on oil and gas CapEx with roughly $280 million or 66% of this capital consisting of drilling expenditures, $110 million or 26% on land, $32 million or 8% on field-level infrastructure and $2.5 million or 1% on seismic.

To summarize, with the benefit of our roughly 11- to 18-year inventory of horizontal Williston Basin development locations and sufficient liquidity to fund our 2011 drilling budget and beyond, we have a high degree of confidence in our ability to drive our production volumes, our reserve volumes and our net asset value per share to record levels in 2011 and beyond.

In addition to our acceleration to 12 rigs on our current core acreage, other near-term opportunities to enhance our company's net asset value are outlined here on Slide Number 70 and include the following. Number one, proving up the Three Forks potential on our Rough Rider acreage position; number two, continuing to grow our de-risked acreage position based on our drilling activities on our 105,000 noncore acres in Eastern Montana; number three, continued operational enhancements to improve EURs and reduce costs that Lance covered; four, gaining additional insight into other unconventional and conventional Williston Basin objectives such as the Scallion; and lastly, our efforts continue to grow our Williston Basin acreage position based on our organic leasing efforts and potential farm-ins, joint ventures and other similar types of transactions. That concludes my remarks. I'll now turn the call back over to Bud.

Ben Brigham

Thank you, Gene. That concludes our prepared text for the call. We'd be happy to answer any questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Subash Chandra with Jefferies & Company.

Subash Chandra - Jefferies & Company, Inc.

Wolfberry and Vicksburg, what were the latest results there and what do you have going on?

A. Langford

Well, in the Wolfberry, the last few wells, we've only operated one well, and it came in as expected just over 100 barrels a day. Our operator, Cobra, has two rigs running.

Ben Brigham

Operator for most of -- I'm sorry, for the...

A. Langford

Yes, for the majority of the acreage is Cobra. And they have two rigs running. The last couple of wells are in the 130 to 140 barrels a day on -- I think it's on the northern end of the acreage. So we're really excited about what we're seeing there. That's above what we were expecting for performance. So very excited how that's turning out.

As far as the Vicksburg, right now we don't have a rig running. We have a plan to pick up a rig, I think, in fourth quarter of this year. So we'll be drilling a couple of wells in the Vicksburg later this year.

Subash Chandra - Jefferies & Company, Inc.

The slides you had, the other zones in Williston Basin and you can do some work there, which of those zones would you say are sort of continuous-type reservoirs and which ones do you think might be discrete?

Jeffery Larson

This is Jeff. The Scallion, I think is going to be variable. We're very excited about the upside in the Scallion. It's basal Lodgepole. It's perfectly positioned. It's got a world-class source rock, the upper Bakken Shale right underneath it. So all you need is fractures or any enhanced porosity that's going to charge.

We'll see in a couple of quarters, and we like what we see. I've got the guys mapping it across the basin. I think it's got resource potential. I don't think -- I think it's going to be in the sweet spot.

Some of the other reservoirs, we're starting to really dial in on some of these other opportunities in the basin. We're looking at Miscu [ph], Dubro [ph], a whole wealth of different intervals. A number of those are stratigraphic in nature.

The other one that's got us intrigued, and you've heard of the North Dakota Industrial Commission talk about it, is the Heath/Tyler section. And that's shallower. It's about 8,500 and 9,000 feet. It's Pennsylvanian age, and it's got a group of source rocks, shales, not unlike the Bakken Shale, intermingled with sandstones that have variable porosity. And I think you'll see us core that this year. And we're getting good shows in our wells. I think you'll see us is core it in McKenzie County. And that could be a much more blanket-type resource play in the future.

Subash Chandra - Jefferies & Company, Inc.

Does that Heath -- does that change a whole lot from the Central Montana Heath?

Jeffery Larson

Yes, it's a different animal. It looks different to us.

Subash Chandra - Jefferies & Company, Inc.

The Gibbins and, I think I'm not sure I'm pronouncing it right, but Sedlacek, what happens between that area and the Voss and Johnson? So you have 2,000- to 3,000-barrel type wells. And is that going to be an indication of what could occur at the Voss and Johnson?

Ben Brigham

Yes, this is Bud. And Jeff will probably want to elaborate. But if you look, I mean, those wells are fairly proximal. The Sedlacek in the Gibbins are just across the state line, about three miles over from the state line. So as you look at the Voss and the Johnson -- maybe Jeff, you ought to go ahead and elaborate that. It looks like they're pretty similar areas, and we have good expectations for the Johnson and the Voss.

Jeffery Larson

We do. We're very excited about those completions. We've got good control points from an historic vertical control points. We've also got some modern logs, vertical logs in the area, and the geology looks the same. We're very excited about the results there.

Ben Brigham

So hopefully, the Johnson, hopefully, in the next two to four weeks, we should have some results announced together with the two Voss wells that were flowing back and some other wells as well.

Operator

Our next question comes from Ron Mills with Johnson Rice.

One.

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

Subash asked a couple. Just about Gene and a little bit on the gas side, the gas-oil split. How much of your gas gathering is already in place? And is that what's really driving your growth in gas volumes albeit at a low level? But it looks like you're pointing to increase gas volumes. Is that just due to midstream?

Jeffery Larson

I think that gas volumes, if you look at the percentage of gas volumes, it's going down, right? But gas volumes are growing just because of the associated gas with our Bakken wells.

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

But because of your infrastructure, you're able to actually sell going in?

Jeffery Larson

Yes. Right now, the only gas infrastructure that we built is over at Mountrail County, and that's built out. And as we drill wells, we will connect it. And right now, we're delivering all of our gas, the majority of our gas to Whiting's plant for processing, so.

Ben Brigham

They're Mountrail.

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

In Mountrail.

Ben Brigham

I mean, we can verify that and...

Jeffery Larson

Yes. And we're -- is gathering all the other gas in Williams, McKenzie County, North Dakota and also in the Eastern Montana. And as you probably know they've expended their system. In fact, they're drilling -- building $100-million-a-day plant in Williams County and a $20-million-a-day-plant in McKenzie County to add to their already probably the largest gatherer in that part of the country. And so all of our gas is going there. So really, our infrastructure spending has been focused on crude oil gathering and waste water gathering and fresh water and...

Ben Brigham

For the most part.

Jeffery Larson

Yes.

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

And then on the down spacing, you talked about four to five per formation. I know you have additional pilots planned in the Bakken. At what point do you expect or think you might actually test in the Three Forks as well? A lot of industries are going to four wells in the Bakken per unit, but not many people have gone to four wells in the Three Forks. So I'm just trying to get a sense as to when that might be tested.

Ben Brigham

It's a good question, Ron. This is Bud. And we've got to say -- when I say that -- clearly, it's something we've been thinking about and we need to talk about here. And we need to come up with a plan for running a pilot there in addition to pilots on the Bakken. So we don't have it laid out yet, but I'm certain we will be talking about it.

Jeffery Larson

It's definitely in our list of our priorities. It's just down the list right now.

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

And on the combination of smart pad and zipper fracs, 10% to 20% per-well cost improvements, how much would be related just to the smart pad portion versus the zipper frac? I don't know if you can break it down that way. And if you look at your units, would a majority of them be perspective for the zipper frac?

Jeffery Larson

On the zipper frac, anywhere where we'll have multiple wells on one pad, we'll be set up for zipper frac. So having the pads where we can drill multiple wells off of is tied to the zipper frac. So I think it's a combined effort and result that you get from drilling multiple wells on one pad.

I could give you the breakdown. I don't have it right in front of me, Ron. But my recollection, it's about 50-50. It may be even a little more heavily weighted towards the completion side, the zipper frac.

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

And am I reading it correctly? Because it sounds like you're starting to fix the number of frac stages in some areas and test some other variables. But you've been -- most of your wells have been between 30 and 38 frac stages. So a zipper frac could, in theory, end up saving anywhere from four to seven days per set of wells. Did I do that math correctly?

Jeffery Larson

Right. Well, the zipper frac, what it allows us to do is instead of being six to eight days to complete one well, and so that would get you 12 to 14 days, it'll get you eight to 10 days to complete two wells. And we should improve over time as we get our processes down. So it's just going to speed up our utilization of our frac crews.

Operator

Our next question comes from Scott Hanold with RBC Capital.

Scott Hanold - RBC Capital Markets, LLC

All right, so my questions are, first, as you think about the downspacing, you've been going from, say, three to four wells per drilling, you’re even down to five. But when you look at your type curves, what kind of impact do think you would have to your type curve if you went to four wells and then into five wells? Do you think it would have like a material impact? Or can you kind of quantify some of that based on the work you've done so far?

A. Langford

Well, this is Lance. So right now, the evidence we have doesn't really show any impact to the curves at all. And it's really between the four- and five-well spacing units. But as we have more data, we'll have a better feel for that. But ultimately, you want to have some communication so that you're maximizing the recoveries in each spacing unit. So ultimately, if it's five and we have some small portion of our decline in our reserves and rate that we use, as long as the economics are really there, it's best for us in the long term and also for the landowner, mineral owners.

Ben Brigham

And that one thing, Scott, we think that that diagram can help you illustrate that or help us communicate that to you guys in the market because as you see on there, as we tried to illustrate in yellow, our recovery factors are decreasing the further away you get from that lateral even at the 500-foot spacing. So there's opportunity for driving more of that oil between the well bores.

So as Lance said, it'll be trying to optimize our NAV, the present value of our NAV, by what is optimal level of development where you're maximizing the reserves but you're not doing your per-well returns. And so that's what we'll be looking for.

Scott Hanold - RBC Capital Markets, LLC

Yes, no, that's fair enough. And what I'm thinking about here is it looks like well costs are creeping up a little bit. I mean, it sounds like they're about $8 million per well now. And let's say this downspacing does obviously have some communication in which if you don't want to leave any oil in the ground, that's how you do it. But let's say you take 10% off of the EURs and your well costs come a little bit higher. I mean, I'm just trying to think of in this oil environment, it works. But at what point do you say, hey, maybe downspacing isn't the right way?

Ben Brigham

Well, Scott just to sort of repeat what Lance said, we don't -- actually, look at the Brad Olson #2. We don't see any material being in the performance of the well. In fact, the Brad Olson #2, as I pointed out, it flowing longer than the Brad Olson #1 did. So I think at this point, we have to say at four-well density, it doesn’t negatively impact the well returns at all. And so that would indicate that it's a more dense development before you start to see that.

A. Langford

And you've got to also assume, we have seen costs creep up, continue to creep up some. And you've got to also remember that the costs right now that we're seeing today are in the winter months where you have a lot of heating going on. And that'll be falling off as we move into the driving season. But as we go forward, let's look forward and see what's happening out there on pumping services. There's a lot of horsepower that's coming out on the market. I know you look at it. But at some point, those costs are coming down. But even if you assume costs don't come down, when we start drilling these multi-well pads, our costs are going to come down dramatically.

Scott Hanold - RBC Capital Markets, LLC

Can you clarify that? I mean, are we talking about...

Ben Brigham

In the 20% percent. And obviously, over time, we'll get lower definition. But 10% to 20%. So what --- we'll see then.

A. Langford

Right. And that's the really easy step for us to identify. There is really more that's going to be -- there's going to be more costs that we haven't identified in that reduction of 10% to 20%, and some of it's going to be associated with our infrastructure.

Scott Hanold - RBC Capital Markets, LLC

And on that infrastructure point, what is your, like, the sort of the -- how much money has -- when all is said and done over the next couple of years, how much will you have spent on midstream and other infrastructures? And is there an opportunity where you can potentially monetize some of that?

Ben Brigham

Yes, I think that...

A. Langford

I think the plan is, is that we invest the $83 million this year and we're sort of set. And certainly, there's opportunity above and beyond to go out and further leverage this big concentrated acreage position. But clearly, down the road, there'll be a fork in the road, and it very well could be that somebody else is going to place a higher multiple on that cash flow stream than maybe we will. But right now, what we're doing is we're the ones that are creating the value by virtue of we've put the acreage together and we're drilling those early-time wells, and we've got the best visibility around what the opportunity we have in that area. And as that becomes clear, as you see more and more activity both -- it's not only the wells that we'll drill, but it's all this other activity around our Rough Rider acreage position. These will become much more apparent to third parties as to what this asset might become worth.

Ben Brigham

So in effect, we're capturing the value arbitrage.

Scott Hanold - RBC Capital Markets, LLC

And Gene, do you just have a rough number of that $83 million spent, how much would you have spent on the Williston Basin infrastructure?

Eugene Shepherd

Yes, we spent $30 million last year, a little over $30 million. So $110 million, $115 million. And the plan is going forward, that we'll continue to spend $10 million to $15 million a year to continue to drill -- or, I mean, it's probably about $10 million a year to drill incremental saltwater disposal wells. But, I mean, that's -- we'll have to re-evaluate. Right now, the important thing is we've invested the capital to get those trunk lines in place. And now it's just more or less -- to some degree, future CapEx will be a function of what kind of third-party opportunities we can capture.

A. Langford

And we think those opportunities are going to be great because if you look at the system we're putting in place especially in Williams, McKenzie County, the connectivity to all the pipelines, it's going to make a lot of sense for other operators to hook up to us. That's not how we justified this. We justified it on our own acreage. But the value of this pipeline is going to go far in excess of what we've got modeled currently.

Operator

Our next question comes from David Eller [ph] with Raymond James.

Unidentified Analyst

I wanted to ask, once you ultimately reach the 12 rigs next year, how many of those are going to be drilling from pads? I think you mentioned that two of the rigs will be walking rigs. So how many of those remaining 10 will be a kind of pad drilling?

A. Langford

Well, the two walking rigs definitely will be -- the two walking rigs actually gets us to 10 rigs. So we've got a get two more rigs. It's likely we'll have four walking rigs out of the 12, and those will, of course, be identified for pad drilling. Even though we use conventional rigs, we can still do pad drilling. It's just not as quick and we won't save as much money using those rigs. And that being said, I'm going to let Jeff talk about how may wells we have planned.

Jeffery Larson

Yes, David, Jeff here. So I'm going to just kind of help set the side board. Of the four wells we currently are drilling in Rough Rider, three of those are on smart pads. So we're very focused on this effort, and we continue to consolidate acreage around these stacked 1,280. So you're going to see a high percentage of them in both projects via the smart pad drilling.

Unidentified Analyst

And then have you looked at any options to minimize impact of a huge WTI differential relative to Louisiana Light? Some operators have kind of mentioned being able to rail some barrels for Gulf Coast, and I kind of want to hear your thoughts on that.

A. Langford

Right. This is Lance. And so we've been looking at that for some time. When we first started looking at that, it seems like it was over a year ago. And the differentials were smaller, but when it blew out, it would go to $7. But I think it was averaging $3, $3.50. And we talk to a bunch of the rail companies, a bunch of them that are out there building facilities or have them in place right now. We're trying to figure out how to get from Burling to Northern to U.P. to St. James. And it's a doable deal. I think a lot more of that's going to happen in the near future, and we are looking at that.

Unidentified Analyst

And I'm not sure if this got answered in the press release or not, but what was the average Bakken EUR that got booked in the EUR reserves?

Jeffery Larson

We didn't release it. We just released our standard range of 500 to 700 MBOE on average for our wells, and it's falling in within that range.

Unidentified Analyst

And then last question, any more plans to add acreage? Or you can -- you currently have -- I think you've got about $25 million in the budget for land, it looks like, I guess.

Ben Brigham

Yes. We had good success last year adding acreage, primarily focusing in our core area. And we added, I believe, it was about 80,000 net acres last year. It grew by about 30%. We think we're still in a window where, particularly given our track record and our knowledge in the areas, that gives us some real competitive advantage and for somebody selling acreage, particularly if they want to retain their equity whether by our choice, given that we drill, there. For example, in Rough Rider, the eight highest IP wells west of the Nesson. So we do anticipate continuing to acquire some acreage.

Unidentified Analyst

And then if you were to acquire significant acreage, would you consider bringing in additional partners to kind of accelerate development of the vast acreage position you've got?

Ben Brigham

That's probably unlikely. If you look at the cost of capital associated with joint ventures, not to mention -- or in addition to that, there are complexities administratively in managing it, in our high rate of return areas, it doesn't make sense for us.

Operator

Our next question comes from Marshall Carter with Capital One.

Unidentified Analyst

I did have a question in the sources of capital for the June program for this year. You did list potentially selling some conventional assets. When do you plan on making a decision on that? And do you have what you would plan on selling, the reserves and oil-gas mix, on that or do you not have anything specific in mind or the timing yet?

Eugene Shepherd

Well, I mean, Marshall, all of the conventional assets are candidates to be monetized over time and then redeploy those proceeds into the Williston Basin. I think our challenge has been as we've had such a big cash position on the balance sheet, that it's hard to go monetize in what we've sort of felt like we've been in this trough as far as this market with this real weak gas prices.

Now the good news is I guess it's about 60, a little north of 65Bs. And 50 of that -- and I'm talking about just the conventional assets. The 50Bs are our position in Brooks County, our Vicksburg assets. And 47% of those volumes, 47% of the MMbtus are liquids. So that's not dry gas. I mean, those assets would trade at a premium because of the liquids content.

So I think we're watching gas prices, and, I mean, our sense is at some point in the next 12 months, that we'll do some kind of monetization. I mean, it just makes sense. I mean, certainly, we have the opportunity. Despite we having to execute in a weak gas price environment, the kind of returns that we can get by redeploying those assets, those proceeds clearly justifies the transaction. So I think we just need to get a little closer to the date when we'll be able to put those proceeds to work.

Unidentified Analyst

And one other question. You have a big production ramp over this year. First quarter was coming in a little a lower than what I was expecting. Was there an impact of winter weather either on the production or in the timing of wells being put online in the first quarter?

Ben Brigham

I think the winter did slow things down a little bit, and then some of it is just the timing, Marshall, the timing of when wells happen to come online. For example, you've got these two big Ross wells coming online. And when you look quarter-to-quarter, you have some variability just associated with that. But clearly, the winter weather did slow us down a little bit in the field.

Eugene Shepherd

I mean, some of it's just really timing. If you look at our second quarter, we saw a 43% increase in our production volumes in the second quarter of 2010, and then just that was a huge quarter. And then the third quarter, we saw a 9% increase. And so we had a 36% increase in the fourth quarter from the third quarter. And so some of this is just -- sort of it's timing as to when wells come on and where you draw the line. And clearly, the fourth quarter was a real strong quarter. Weather is always a little bit of an issue, but I don't think it's the primary issue.

Operator

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

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

Looking at your Slide 69, if I'm doing the math right, it looks like your 2010 Bakken wells cost about $7.3 million, and your forecasting you're '11 well at more like $8.7 million.

A. Langford

We're forecasting $7.9 million, and then we've got overage built in. So that could be either service cost inflation or some operational issues. So it's just a cushion that's built in to make sure that we are protected.

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

So just conservatism on your part?

A. Langford

That's right.

Jeffery Larson

Yes. I mean, if you look at our last 10 wells, they're roughly in the $8 million -- the last 10 wells that we've drilled in the basin have been in that $8 million -- $7.9 million to $8 million range, so...

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

And then the difference between the $7.3 million of 2010 to the $8 million, is that mostly inflation? Or I imagine you also have some difference in terms of the number of average frac stages between the two years.

A. Langford

This is Lance. We've had a little bit increase in cost for frac stages, but the majority of it is just because of the cost creep of the service and supplies.

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

And then looking at your result, getting wells, both the Rogney and Swindle, you've had some problems completing both of those or you didn't get them completed the way, I guess, you had hope. Is it fair to say that geology there is a little bit more complex? Has that been an issue? Or is it just a matter of getting one completed the way you want to?

Jeffery Larson

This is Jeff. No the geology looks consistent. I think it's just getting the [indiscernible] liners to bottom and some of operations issue. In fact, you see you see where the trouble is, Vachal is just a mile away from the Swindle. So I'm so excited about the area. We're getting ready to drill a well there in April.

Ben Brigham

Yes, it's just -- we haven't had many wells. So we've haven't got any liners. Again, it looks like the liners don't start that far off the bottom, and it's just unfortunate that those two wells right there did that it's just -- but really, it's nothing geological that's driving that.

A. Langford

Yes. And if you recall, the Baxter, we changed the completion on the first third and did that on purpose. It wasn't...

Ben Brigham

The Rogney.

A. Langford

I'm sorry.

Company Speaker

Well, actually, the Baxter didn't...

A. Langford

Rogney. But on the Swindle we've had about four wells that we haven't been able to get the liner to bottom. There was a manufacturing problem that we isolated it to. We feel like we've got that resolved. We know we'll have other liners. They get stuck up bottom, but it won't be for the same reason. But we've been able to get over 90% of our liners all the way to bottom.

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

Can you say what the EUR you've had the Rogney now for a while? Can you say what the EUR at that well looks like? Or at least, does it look like it will be economic?

A. Langford

It's still early. Obviously, the RPs were lower, and so we're still waiting to see what the curve looks like. So we need some time to really model out that curve and get a good EUR.

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

And then last one. I think in your last call, I'm talking about the density test, I think you had said you really need six months to a year to make a decision to see some production performance. And it sounds like on this call, you're much more optimistic about four wells per section or maybe even more. What has been just strictly the microseismic that has given you that greater confidence or has it been anything else?

Ben Brigham

Well, it's just been the history or it's a combination of two. The first, of course, is the production. That is producing comparably to the Brad Olson #1 that was completed a year earlier. And it's a real positive. Obviously, it's actually flowed longer than the Brad Olson #1 did. So obviously, these wells will flow as long as they can before you have to put them on pump. So that's a, I mean, that's pretty good data there. And that combined with the microseismic where you could see very clearly the majority of the breakage occurred in the rock really within 200 to 300 feet. But the more conservative interpretation was the average frac extent was 500 feet. So they all fit together pretty well.

Operator

Our next question comes from Derrick Whitfield with Canaccord.

Derrick Whitfield - Canaccord Genuity

Lance, as a follow-on to the previous well question, could you comment on what type of completion that comprehends and if you're projecting any savings from the smart pad in simul fracture limits into that budgeted number?

A. Langford

So what kind of completion to what?

Ben Brigham

In the $7.9 million?

Derrick Whitfield - Canaccord Genuity

Yes, the $7.9 million number. What type of completion does that comprehend first? And then second, are you projecting any savings from the smart pad and simul fracture limits into that budgeted number?

A. Langford

Into that budgeted number, we do not. So we're using a 30-stage typically for those numbers. It's a good question because sometimes, we do use 38 stages. But we're using really a combination, depending on the area, of 30 and 38 stages right now. And then we're expecting a 10% to 20% reduction in cost. But we haven't put that in our well cost yet just because we don't have that many rigs on the smart pads. And as we go through the year, a majority of the wells that we drill will be on the smart pads. And so you'll see that impact later in the year.

Derrick Whitfield - Canaccord Genuity

And then switching gears, thinking about the accelerated rig schedule, how should we project rig allocation in 2011 and 2012?

Jeffery Larson

When are the rigs...

A. Langford

They're coming on every four months.

Ben Brigham

You're asking also where they're going, which project?

Derrick Whitfield - Canaccord Genuity

Yes, the correct. But also looking to where they're going to be particularly in 2012 more so than 2011.

Jeffery Larson

Jeff here. I mean, certainly, one of the big drivers is Eastern Montana. We have continued success in Eastern Montana. You'll see us either bring either -- we're going to -- we're planning on currently bringing one rig to Eastern Montana in May after we drill these first two wells. We have continued success, so you could potentially see a separate rig going to Eastern Montana as we look out across the plan. And we'll continue to develop the Rough Rider and Easy Rider blocks.

A. Langford

Probably 1/3, 2/3.

Jeffery Larson

Yes. 2/3 is allocated to Rough Rider, 1/3 to Easy Rider. This is a function of the acreage footprint in net acres.

Derrick Whitfield - Canaccord Genuity

Jeff, could you remind me of the difference in depths and pressure gradients between the Pale Rider and Rough Rider areas?

Jeffery Larson

There's a pretty comparable -- when do you look at, I mean, it gets shallower as you go west. So you've got probably about 500 to 700 feet shallower when you look at a true vertical analysis between Rough Rider and Pale Rider. And the pressure gradients, I'm going to ask Lance.

A. Langford

The pressure gradients are the same.

Operator

Our next question comes from Brian Lively with Tudor, Pickering & Holt.

Brian Lively - Tudor Pickering Holt

Just on the pad drilling, have you guys estimated what percentage, if you assume a 12-rig program, what percentage of those rigs would be pad drilling in 2012 and 2013?

A. Langford

I would assume the majority of it by 2012, Brian. I don't know if we have an exact number. I know we've got the wells scheduled out. But I would assume the majority we'll be doing in pad drilling. But they will not all have walking rigs on it by 2012.

Ben Brigham

So I think, I mean, just to give a rough, maybe 2/3 or...

A. Langford

Let's say 60%, 75%, so.

Ben Brigham

Yes. Yes, maybe 2/3.

A. Langford

2012 would be...

Ben Brigham

Yes. And maybe 2/3, 75%.

A. Langford

Yes.

Brian Lively - Tudor Pickering Holt

And so if we think about the efficiency gains there from just the sheer net wells that you can complete every year, so you're basically 20% improved from an efficiency standpoint. And then of the 12 rigs, 2/3 of those would be really actually drilling the pad wells. Is that the right way to think about it? So you're actually drilling more wells per rig?

A. Langford

I think that is a good way to look at it. Brian, Right now, our model is we don't have it modeled in there. But as we go forward and we get a better feel for how many we have doing pad drilling and how efficient we're going to be with the zipper fracture, you'll see us layering that in our models, so.

Brian Lively - Tudor Pickering Holt

So costs hold flat. Do you expect to see total drilling complete cost in the $6.5 million range?

Ben Brigham

They will come down.

A. Langford

Yes, I definitely think they're going to come down. I think it's going to come down even further just because of lower gas prices and more, I'll say, foreign buyers…

Ben Brigham

Yes.

A. Langford

I can really feel the service company trying to move more equipment and personnel into the Williston Basin. And it's not only people that are there trying to move more people and equipment in, but a lot of the companies that hadn't made the move, they're clearly making the move into the Williston Basin.

Brian Lively - Tudor Pickering Holt

And switching over to the gas gathering question. What do you expect your gas volumes to be in that gathering system in 2012? And then what's the incremental volumes reserved for third parties?

A. Langford

I don't have that in front of me, Brian, and we haven't released that information. What we do expect to have is all of our volumes being transported through gas gathering systems either when we start flowing back or quickly after.

Brian Lively - Tudor Pickering Holt

Do you have at least what the overall capacity in terms of gas volumes will be?

A. Langford

Probably, that gathering line there is capable of doing $30 million a day as it is with just adding compression.

Ben Brigham

But that's a pretty small piece of the overall...

A. Langford

Right. You've got to remember the gas gathering is only in the Ross Area.

Jeffery Larson

So really, it's Rough Rider, all of Rough Rider right now or at least certainly Williams and Charlie [indiscernible] are dedicated to Bear Paw, which is one off. So they're gathering and processing our gas west to the Nesson.

Brian Lively - Tudor Pickering Holt

Last question I have is, I just want to make sure I understand correctly, Lance, your comments on infrastructure. It sounds like you're not expecting differentials to widen materially over the next quarter or so unless there's some unforeseen pipeline disruption. Is that correct?

A. Langford

I think what I was really saying is that I expect the differentials to average $9 to $10 over the next few years. And if you look at the Williston Basin differential, historically, even before we started drilling here in the Bakken, in the winter months, the differentials widen because the demand goes up for the low-gravity Alberta crude because they can make that crude and process it into heating oil and have higher margins. And so during the winter months, the differentials widen in the basin. And then in the summer months, it shrinks. And so that processing goes from the low-gravity crude to the good sweet crude that we have for gasoline.

So I'm saying the average is going to be that $9 to $10 in the winter months. It may bump over $10 a little bit. And then if we have some unforeseen pipeline interruption, you could have a month of that's -- we've seen the Enbridge that happened in the past where you have a month where you have a high differential, or higher than the normal.

Brian Lively - Tudor Pickering Holt

If you adjust for the seasonality then, I guess in the near term, you're still not anticipating differentials to be significantly different than year-over-year comps?

A. Langford

I'm expecting the average to be in that $9 to $10 range. And the winter is to be a little higher than in the rest.

Jeffery Larson

I mean, the first half of last year, we saw the differentials were certainly lower than where they are today by quite a bit. So we've seen that trends out in the last two quarters of $9 and $10.75 is what we've averaged. But in the first quarter of last year, we were at $6 or right around $6, which I would think is unusual.

A. Langford

That's an anomaly there.

Jeffery Larson

Yes. Right. So, I mean, we averaged $9 in the second quarter, a little north of $9 in the third quarter, $10.75 in the fourth quarter. You remember the month of October we had that Enbridge -- I forget. It's 6A or 6B. They were involved. 6A and 6B had leaks. And so the differentials widened out north of $13. So that's sort of negatively impacted the fourth quarter. And so you've seen from there differentials have recovered to a little north, at least, I mean, I'm talking about for us, a little north of $10. And they still -- and they've remain there in the first couple of months of this year, so.

A. Langford

And I think, also, if you look at the expansions that are going on out there, I think that that's going to hold those prices in those ranges. And I think there's opportunities of rallying to St. James. So I think that's going to create opportunity in the basin to have lower differentials. There's just a lot of moving parts. But the good thing, there are lots of them. And that'll have the tendency to keep the differentials down.

Brian Lively - Tudor Pickering Holt

So it sounds like just the ramp in activity will fly. I mean, you guys aren't overly concerned that that's going to be detrimental to differentials then, I understand?

Jeffery Larson

Well, but we're also taking a very aggressive approach to making sure that we could --- we're replacing our volumes. I guess, we placed our '11 volumes. We're placing '12. And in 2013, you've got to bunch of incremental capacity that's coming on. But we're also working behind the scenes doing a number of other things, Lance is, to make sure that we've got optionality around deliverability such that if we're surprised, we'll be protected, so…

A. Langford

So the majority of our growth is going to be in Williams and McKenzie County. It's our biggest acreage position. We've got a gathering line, the big transportation lines. They like that deliverability. It's consistent. It's easy to take on into their pipelines. We'll be hooked up to every major pipeline in every major expansion with our gathering line. I think with that connectivity and then working options for rails and to take advantage of things like the St. James to the cushion differentials, I think we're setting ourselves up to protect ourselves with lower differential than the norm.

Jeffery Larson

Yes, we're going to move our volumes. It's a function of cost. I think what we're trying to describe to you is we're trying to not just sit back, but we're being proactive about trying to address the issues so that we can't benefit from the capacities coming to the basin. And hopefully, that’ll have a positive impact to our differentials relative to other operators.

Operator

Our next question comes from Peter Mahon with Dougherty.

Peter Mahon - Dougherty & Company LLC

You guys have set up a pretty aggressive CapEx plan for 2011. And I just wanted to kind of get your thoughts around your comfort with the leverage on the balance sheet. Right now, I think you've got a debt-to-cap ratio of about 34%. Kind of where are you guys comfortable at with that?

Eugene Shepherd

Well, we, I mean, we have to step back and look at a combination of things. We've raised close to $600 million of equity capital since May of '09. So we've done the one transaction in September of last year. So we did the $300 million of notes. Since that time, our acreage has sort of -- at least last year, we de-risked the acreage. It's been delineated. Now we're out of the delineation mode and we're into program. We're drilling development locations. So you can argue, certainly we could take on more debt and by the nature of what it is that's in front of us. And so it's...

Ben Brigham

Our current debt level is low, I mean, if you look at today what our debt level is relative to our capitalization.

Eugene Shepherd

Yes, debt-to-EBITDA. We track all the metrics. We're certainly not going to get ourselves into situations we're overleveraged. But there's clearly another leveraging event that's out there in front of us that we intend to take advantage of. And then we'll just have to see in 2012 and beyond what kind of performance we're getting from our wells and where commodity prices are. Obviously, on the hedging front, we're really being very careful in making sure that that's another base. We've taken on some additional debt that we've added hedges so that we take sort of some of that financial risk off the table. We've put a floor around our oil volumes in 2011 and 2012 that it's a little north of $65, between $65 and $70. We're already putting volumes on in 2013 and for substantially north of that. So we think that the risk profile of the company has changed. And as a result, the way we intend to finance our financing strategy has evolved.

Ben Brigham

So I'll just add a couple of points to what Gene said. I mean, as Gene said, we've really made that across the risk profile. Particularly the drilling inventories, we've got the hedges. But also, we have -- and we're very underlevered right now. And so given that, it does make sense to complement our equity and our going cash flow with some level of debt leverage to compound our growth further.

Regarding the rig ramp, I think the one from zero to eight rigs was really the hard part. Adding four more rigs at the same pace we've been adding rigs to go to 12 rigs is going to be much easier, I think, than what we've already accomplished.

Operator

Our next question comes from Martin Beskow with Northland Capital.

Martin Beskow - Northland Securities Inc.

If you could, with the higher oil prices right now, has your approach to hedging changed at all? Are you being more aggressive right now?

A. Langford

Well, yes. We have gotten more aggressive. We sort of have a basket of -- we have a philosophy currently, and this is more a function of the eight-rig program, of wanting to hedge half of those rigs or four of those rigs. And so we hedged 100% of the PDP volumes and 100% of the incremental volumes associated with the four-rig program. As we talk about and implement going to the 12 rigs, that will probably create some additional hedge volumes.

And so, I mean, from our point of view, oil prices are the single biggest risk to the company, realizing the potential of this huge NAV creation opportunity in front of us. So what we try to do is, in terms of those volumes that we're currently hedging, 100% of the PDP and 50% of the incremental associated with four-rig program, to keep that full two years of hedge volumes in front of us.

So I would say with higher oil prices, so we have that basket, the higher oil prices, prices run up, and then we try to be opportunistic and jump in with both feet and put volumes on them. We did that a couple of weeks ago. We're looking at putting more volumes on this weak.

Martin Beskow - Northland Securities Inc.

And then also, too, regarding income taxes. You had mentioned for 2011 not anticipating any federal income taxes. And as far as the state income taxes for North Dakota, do you plan on that being even throughout the year or is that going to be more towards the end of the year? And also, what's going to be your guidance for 2012 as well? How much do you have left on your NOL?

Eugene Shepherd

So we started to reduce, I mean, if we true it up at the end of the year, but I would say if you want it for modeling purposes just assuming that's even over the course of the year.

Martin Beskow - Northland Securities Inc.

And how much NOL do you have left? So what's going to be, I guess, your outlook for 2012?

Eugene Shepherd

I mean, roughly $248 million of NOLs. So we've got plenty of potential to shelter our future cash flow, our operating income. So we're in great shape on federal state taxes or, a different matter, North Dakota. We don't have the big NOL position in North Dakota. So there, it's a function of using the IDC, which we can use to shelter our income for tax purposes.

Martin Beskow - Northland Securities Inc.

What did you end up for your producing wells for the end of the year? How many producing did you actually have up in the Williston Basin in December?

A. Langford

Gross wells or net well -- operating wells or net wells?

Martin Beskow - Northland Securities Inc.

Net wells, preferably.

Ben Brigham

58 proved developed at year end in 2010.

A. Langford

Which represented probably about a little less than -- so I think 7% of the total 782 locations that we have available to drill.

Ben Brigham

Yes. And that's not included in the...

A. Langford

That's our delineated.

Ben Brigham

Yes, I think for the three places, it's about 3%. So it will get you to 1,200 locations to drill. Just over 1,200.

A. Langford

Just our delineated acreage.

Ben Brigham

Yes.

Operator

I'm not showing any other questions in the queue at this time.

Ben Brigham

Well, we want to thank everybody for participating in the call, and it's been a really just transformational year for the company. And we look forward to reporting on our first quarter results.

Operator

Thank you. Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the conference. You may now disconnect. Good day.

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