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Executives

Bud Brigham – Chairman, President and CEO

Gene Shepherd – EVP and CFO

Jeff Larson – EVP, Exploration

Lance Langford – EVP, Operations

Analysts

Scott Hanold – RBC Markets

Joe Allman – JP Morgan

Ron Mills – Johnson Rice

Mike Scialla – Thomas Weisel Partners

Steve Berman – Pritchard Capital Partners

Katherine Sabolski [ph] – Jefferies & Company

Joel Musante – C. K. Cooper & Company

Mike Canon [ph] – Orex [ph]

Houston Netherland – Natixis

Kenneth Pounds – Nutmeg Securities

Nick Van Bavel [ph]

Kenneth J. Elliott [ph]

Brigham Exploration Company (BEXP) Q4 2008 Earnings Call Transcript March 12, 2009 10:00 AM ET

Operator

Ladies and gentlemen, welcome to the fourth quarter 2008 Brigham Exploration Company earnings conference call. My name is Tanya and I will be your coordinator for today. At this time, all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of this conference. (Operator instructions) I would now like to turn the presentation over to your host for today’s call, Mr. Bud Brigham, Chairman, President and CEO. Mr. Brigham, please proceed.

Bud Brigham

Thank you, Tanya. Thanks to each of you for participating in Brigham Exploration Company’s year-end 2008 conference call. With me today, we have Gene Shepherd, our Chief Financial Officer and Executive Vice President; Lance Langford, Executive Vice President of Operations; Jeff Larson, our Executive Vice President of Exploration; and Rob Roosa, our Finance Manager.

Importantly, before we get started, I would like to encourage you to be prepared such that during the course of this call you can view our conference call presentation, which can be accessed via our website at www.bexp3d.com. It includes very helpful information regarding our 2008 results as well as our plans for 2009. We will be referring to the slides in the presentation during our discussion.

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

In addition, in this call we will use some – the terms probable and possible reserves and locations, which are unproved reserves that we do not include in our SEC filings. Please refer to page two of our corporate presentation for a cautionary note to US investors regarding the use of the terms probable and possible reserves and locations.

Finally, a copy of our company’s press releases as well as other financial and statistical information about the periods to be presented in the conference call will be available on the company’s website under the section entitled Investor Relations at www.bexp3d.com.

Now let’s get started. If you go to slide number three, you will see our outline for the call today. First, I’m going to briefly review our 2008 milestones. Following that, I’ll provide you with an update on recent activity in the Williston Basin, Bakken and Three Forks play. We will update you on the strong well performance from our most recent wells, particularly the Olson, but also the Carkuff and the Adix.

We will then discuss the current economics of the play, the fact that costs have come down faster than we anticipated, and that the drilling economics are looking good sooner than we expected. We think they will even be even better for the second half of this year. Finally, we will take a quick look at our proven, probable, and potential reserves there so that you can see where we are and opportunity that’s in front of us. Following all of that, Gene will provide a detailed financial discussion and we will finish up with any questions you have.

Getting started, slide number four shows our 2008 milestones. For the sake of time, I won’t review all of these individually, but I do want to briefly highlight one milestone. Easily the most important milestone we achieved in 2008 was number six, the implementation of economic enhancers in the Williston Basin.

I personally believe that Brigham Exploration has taken a leading position in the implementation of drilling and completion technologies in the basin with the successful completion of our Olson 10-15 well. The Olson well was the first well completed in the basin, utilizing 19 swell packers and 20 fracture stimulations in a long lateral. I’m particularly grateful to our hardworking staff that put together a great plan and fought through to completion. And I want to congratulate them on their efforts.

Looking at the remaining objectives, you can see we accomplished all but one of these. A more detailed description of these accomplishments can be found in the appendix. Now I’ll move on to update you on our recent Bakken wells and provide you our view on the improving drilling economics in the play. Slide number six is a map of our 308,000 net acres in the Williston Basin.

I’m going to first update you on Mountrail County and then we will move to Williams and McKenzie counties west of the Nesson Anticline. Slide number seven shows our Ross Area in Mountrail County. Just a quick update here. Prior to the Olson, west of the Nesson are Carkuff Bakken well and are our Adix Three Forks well in this area were our best wells. The independent engineers get these wells reserves of 427,000 and 415,000 barrels of oil equivalent respectively at today’s prices. These wells had 12 and 11 frac stages. And as you can see the Carkuff, it’s just one mile away from the weaker performing Bakken, which was drilled earlier in the year and completed with only seven frac stages.

Other new strong initial rate wells have been drilled for both the Bakken and the Three Forks in our Ross Area. Of these, you might note Whiting has very strong wells to the southeast of us. There were too many to label them all, including the highest producing rate Bakken well we know of at just over 4,500 barrels of oil equivalent per day.

In this area, Whiting also announced the successful increased density well between two good wells, confirming our and other operators’ view that two to three laterals will be needed to drain each section. Also, Whiting announced the new Three Forks discovery on the southeast portion of the map, which is the eastern most Three Forks test extending the Three Forks productive fairway further eastward of more of our acreage.

As far as our recent activity, we successfully drilled a long lateral Stroebeck, the purple rig on the map, and successfully ran 19 swell packers in a hole such that we can frac the well with 20 frac stages when the weather warms up and when we can benefit from much lower cost. We have very high expectation for this well, given how well our Adix has performed in the Three Forks just three miles away and given Whiting’s early performance from their long lateral Three Forks well just to the southeast of us.

Whiting has obviously been doing a good job with their long laterals. And combining that with our 20 frac stages gives us the opportunity for a very big well with the Stroebeck. Just a mile to the west of the Stroebeck, we drill the Anderson Bakken test through the curve where we have set pipe and are now also waiting there for the warmer weather and lower costs. Probably late in the second quarter we will get out and drill the lateral, which will be roughly 10,000 feet in length with 20 planned frac stages. By the way, we code [ph] this well through this Three Forks, and that has made us only more encouraged about how good the Three Forks will ultimately be in our Ross Area.

We will talk about reserves in a minute. A very little of the Three Forks is in our proved or probable reserves at year-end. Now, given these upcoming completions in the Ross Area, in the next three or four months we will likely have new production hue to discuss.

For the sake of time, I’m not going to spend much time on the Parshall/Austin/Sanish area other than to tell you that we are currently participating in a number of wells, and given our acreage in the area, we will continue to participate with small interests and offset the Whiting and EOG Sanish and Parshall field wells. These wells appear to have a breakeven oil price in the mid $20 per barrel. So they generate strong rates of return today.

Perhaps you want to take a look at slide number nine. We are just going to make a quick point. It’s interesting and important to note that our Middle Bakken porosities are actually better and thicker over our 105,000 net acre project west of the Nesson Anticline in Williams and McKenzie Counties than that of the Mountrail County Parshall field. However, the Parshall field area has more natural fracturing and permeability and is over pressure.

But we appear to have more oil in place in the Middle Bakken on our acreage west of the Nesson Anticline than there is in the Parshall field. It’s just that we are dependent on our multi-stage stimulations to create the mere near-wellbore permeability that’s naturally occurring in Parshall. And we think we now have clearly shown we can do that.

After our successful Mrachek with seven frac stages, we are the first operator to frac a long lateral with 20 stages. And based on the Olson’s early performance, it’s easily our best well, better than any of our operated Mountrail County wells. We think our two multi-stage frac wells in this area, the Olson and the Mrachek, combined with other emerging wells that have recently been completed in the area by other operators, indicate that our 105,000 net acres in this area is likely of Tier 1 quality, potentially better than many areas in Mountrail County.

Slide number 11 shows the west of Nesson wells prior to the Olson, with the Mrachek in blue, the seven frac stages being clearly superior to the prior wells shown with single uncontrolled fracs. The next slide, slide number 12, shows how well the Olson has performed. The Olson has produced an average of 730 barrels of oil equivalent per day over its first 30 days of production, easily the best well we’ve drilled in the play.

Slides 13 to 17 illustrate our progression for all of our operated wells, much of which occurred during the second half of 2008, improving Bakken and Three Forks well performance and economics as we increased the number of frac stages in our short laterals. As you can see on slide number 17, to date our 20 frac stage long lateral Olson well has easily outperformed roughly 400,000-barrel Carkuff and Adix wells. The Olson was still flowing roughly 430 barrels of oil after having produced a cumulative over 20,000 barrels of oil.

If you look at slide number 18, which is a plot of the number of frac stages for our Ross and Rough Rider wells relative to a third-party engineered estimated ultimate reserves, you can see the very good line fit progression and improvement in well performance as we increased frac stages. It’s interesting that the Mrachek, which as I mentioned, is our acreage west of the Nesson with more high-quality Middle Bakken porosity, actually lies above the line, which could indicate that the potential best fit line, parallel line for that area could provide better economics in much of Mountrail County. The early performance of our Olson indicates that’s a real possibility.

The following slides, number 19 and 20, also demonstrate our progress with Williston Basin drilling and completion technologies. If you take a look at slide number 21, it does a good job of summarizing our progression in the play, looking at rates of return relative to oil prices. We believe that this is a play that would be economic even in a $40 per barrel oil price environment.

Slide number 22 is an important slide. You can see on the left that drilling and completion costs have already come down 20% to 30%, and we expect them to be down almost 40% later in the year. Staying on slide number 22 and moving to the upper right chart, based on our third-party engineered Carkuff reserves and assuming today’s lower service cost environment, the short laterals would generate drilling finding costs of $10 to $12 per barrel of oil and rates of return of 29% to 38%.

It is too early to say what the Olson’s estimated ultimate recovery will be, but it’s clearly better at least at this point than the Carkuff and the Adix. And here assuming that’s a 575,000-barrel well at the estimated costs shown, it could generate rates of return of 27% to 35% in today’s environment. We expect technology to continue to advance, and that we and other operators will realize other option value in this play, including refracs, secondary recovery, and other conventional and unconventional plays that will be developed over our acreage.

Now, moving to our 2008 results and our 2009 plans, proved reserves were very disappointing, 180 degrees different than what we were anticipating at mid-year last year. Slide 24 shows our reserves by play. The biggest factors were, of course, the dramatic falling commodity prices, particularly for oil in our Bakken Three Forks play. In that play we invested the largest portion of our capital, 62% of our drilling CapEx, drilling in a $100 per barrel oil cost environment and then subsequently booking associated reserves at $44.60 a barrel.

The drilling cost and oil price mismatch element was compounded by the fact that the third-party engineers were constrained by SEC guidelines and therefore could only book PUDs to the level of their directly offsetting wells. As a consequence, proved undeveloped locations, offsetting older technology wells, were booked at lower reserve volumes are not at all relative to the volumes associated with our more recent wells completed with a greater number of frac stages.

Slide number 25 illustrates how PUDs were booked relative to offsetting producers, and then we got credit for two offsets, not the four direct offsets. Further, slide number 26 shows our 2006 Field and Erickson wells, which were drilled with very early technology, single uncontrolled fracs. The engineers were constrained by SEC guidelines. So they could only assess reserves comparable to those poor technology wells, not to the level of our 11 and 12 frac stage wells or even to the level of our seven frac stage Mrachek well to the south.

Given that the engineers were limited to those reserve levels, those potential PUDs were not even booked at year-end 2008. Our latest well is in the center of the map, the Olson, which is easily outperforming our best operated wells drilled to date, which are roughly 400,000 barrel wells. We would expect the sections offsetting the Field and the Erickson to perform similarly. But those expectations are not in our proved reserve report.

If you take a look at slide number 27, the bar on the far left illustrates how reserves were booked offsetting wells drilled with older drilling and completion technologies utilized in 2007 and early 2008. Because of this and the low commodity prices and high service cost at year end, these PUD reserves would not be considered economic. As a complete mismatch, reserves book based on high service costs, but low oil prices, and with older technologies that are not being used in our current wells.

As we and other operators have advanced the drilling and completion technologies, in the second half of 2008 we are at the second bar. Our Carkuff and Adix were our last two Ross Area wells illustrating the impact technological advancements have had in just one year. Today’s environment and technology, inclusive of more frac stages, is represented by the third and fourth bars from the left. These reflect where the play is at the present time, benefiting from more frac stages and lower service costs.

However, the engineers didn’t have enough statistical data on the benefit to the greater number of frac stages to give us credit for that in our reserve bookings, unless it was a PUD directly offsetting one of our newer wells. As a result, despite the fact that we’ve delineated by far the largest fields in our company’s history in the Bakken and Three Forks providing us with the multi-year inventory of reserves for growth and a smaller portion than we anticipated moved into the proved category.

That being said, our third-party engineering firm has confirmed that our drilling has quantified very substantial probable reserves, as summarized on slide number 28, totaling 112 Bcfe. And as a result, our 2P reserves are estimated at approximately 249 Bcfe. The Bakken and Three Forks make up the largest portion of these probable reserves, roughly 87 billion cubic feet equivalent or 14.5 million barrels of equivalent probable oil reserves. We believe that we will be moving these reserves into the proved category in the upcoming years.

The slide 28 also shows the make-up of our total 2P reserves, which brings me to a key point. Given the nature of our Bakken and Three Forks assets, the proved reserves alone do not fully encompass the truly value we’ve delineated in this play. We were very successful in 2008 defining substantial reserves on our Bakken acreage, both east and west of the Nesson Anticline.

In our view, these are large fields that we are developing. It’s just that due to the factors we discussed, a much smaller wedge of reserves moved into the proved category. Although we’ve delineated substantial probable reserves, slide 29 illustrates that in the Ross and Rough Rider Area, for example, we have significant acreage that we believe provides attractive economic that is yet is to fall into the probable category, but that we believe will over time. Further increased density drilling, which will happen, provides more upside beyond what is shown in this slide.

Briefly looking at our assets that hold meaningful value beyond our reserves, slide number 31 shows the results from the January lease sale in the Mountrail County area. As you can see, acreage in our Ross and Parshall Areas went for as much as $2,400 per acre and even $4,400 per acre, an indication of the fact that industry continues to place meaningful value on these assets.

Again, this is productive acreage, a very substantial field that’s ready to be developed with a constantly improving drilling and completion technologies. The purchase price is being paid by other operators in the play of the interest we’ve seen from companies considering acquiring some of our ownership in the play. We believe that potential joint ventures could provide us with additional capital to be in position to more aggressively step up our drilling in the best part of the cycle when costs are low and oil prices are stable or perhaps even rising.

Slide number 31 illustrates the disconnect between the valuation for our acreage by other E&P companies pursuing leasehold in the area and that of the value implied by our stock price. This is one of the reasons why we are entertaining selling up to a 50% working interest in portions of our Williston Basin acreage position.

At the present time, our Bakken and Three Forks acreage provides us with strong currency. They can position us to capitalize on an improving environment. Given that, you could see us selling a 50% interest in 25,000 to even 125,000 net acres. That would still leave us with over 225,000 net acres. So we would still likely be the public company most levered to the Bakken Three Forks play.

Now, a quick look at our 2008 drilling performance is shown on slide number 32. The overall Bakken drilling performance was poor, in part due to the $100 per barrel cost environment, but also due to the poor performing early 2008 wells, which will add on the older technology. As you can see, even with the high service costs and declining natural gas prices, we still generated solid economic returns with our drilling in the Vicksburg and Southern Louisiana. We have a long track record in both areas and a particularly deep inventory in the Vicksburg to harvest when the environment is more optimal than it is today.

Moving back to the Bakken and to slide number 33, it’s very important to note that we were very successful advancing the technologies to extract the reserves we delineated in the Bakken and Three Forks. As a direct indication of that, our three most recent wells in the Ross and Rough Rider areas are easily our best wells, averaging roughly 400,000 barrels of oil equivalent for the Adix and Carkuff wells in Ross and our 20 frac stage Olson long lateral and Rough Rider at significantly outperforming both of those wells to this point in time.

The slide number 33 shows that despite being drilling in a $100 per barrel oil cost environment, with current oil prices below $50 per barrel, those wells are still generating positive returns. Slide number 33 also shows that potential returns on those same wells in today’s cost and commodity price environment. Costs have come down more rapidly than we anticipated. After having endured the worst part of the commodity price and cost cycle, our Bakken and Three Forks inventory is providing us with attractive drilling economics today. Further, we expect that economics to only get better over the course of this year.

Gene will talk specifics on production, but as shown on slide number 34, we entered 2009 with production at elevated levels. We still have several wells that have come on line since the end of the year or will be coming on line since, which will benefit our second quarter. In addition, we have three other wells that we will be completing over the next three to four months. Two of these wells are in Ross, being the Stroebeck and the Anderson. One is the Figaro, which is west of the Nesson in our 105,000 net acres in which we completed the Olson and the Mrachek. All of these are planned 20 frac stage wells, which will benefit our production during the second half of the year.

Although we are largely hibernating to conserve cash until the environment improves, these wells will add new production later in the year. Furthermore, given that the service costs have come down more rapidly than we anticipated and the drilling economics should be even better by mid year, I think it’s very likely we will be drilling new wells during the second half of 2009.

Looking further at our production, it’s important to note that our Bakken and Three Forks drilling is generating relative growth in our higher value and longer reserve like Williston oil production volumes, as shown on slide number 35. Our fourth quarter 2008 oil volumes more than doubled, up 118% relative to the fourth quarter of 2007. This is clearly beneficial.

During 2008, an Mcf equivalent of our oil volumes generated 160% of the revenue of an Mcf equivalent of our equivalent gas volumes. Or put another way, our average 9.6 million cubic feet equivalent of daily oil production in 2008 generated revenue equivalent to 15.4 million cubic feet of our 2008 natural gas production. We expect this commodity advantage to continue that over time our relative oilier mix should make our equivalent production volumes more revenue productive for us.

Differentials have improved significantly in the Williston. As shown on slide 36 and 37, our weighted average differential was just over $10 per barrel in February and is approximately $8.50 per barrel this month. We expect differentials to continue to have seasonal variability, but also to improve over time as capacity expands.

Last of my portion of the call, slide number 38 shows our 2009 milestones. For the sake of time, I won’t review these and will instead turn the call over Gene to review our financial progress, after which we will be happy to answer your questions. Gene?

Gene Shepherd

Thanks, Bud. Before we get into a discussion of our fourth quarter and full year 2008 results, several comments about the company’s current liquidity position and the steps we are taking to ensure that the company has sufficient financial flexibility to navigate through the current economic downturn.

To set the stage, at year-end 2008, we had $40 million of cash on the balance sheet. Point number one, during the fourth quarter 2008 we began to scale back operationally given the mismatch between declining commodity prices and the elevated level of drilling and completion costs. After completing the drilling and completion operations on several fourth quarter wells in January and the first two weeks of February, we laid down our two Williston Basin rigs and have positioned the company to live within cash flow for the remainder of 2009.

See slide number 40 for a brief overview of our currently planned 2009 E&D CapEx budget. Point number two, after incurring the majority of yesterday’s announced 2009 E&D CapEx budget during the first two months of 2009, as of March 10, we had $33.3 million of cash on the balance sheet.

Point number three, slide number 41 lists several transactions that we have initiated in the fourth quarter 2008 and we are striving to complete in the next several months, which should further enhance the company’s near-term liquidity position. They are the pending sale of our Mountrail County mineral acreage and other Williston Basin acreage in seismic, which should close by the end of March and bring $7.2 million into the company.

Secondly, the potential sale of our non-operated Mountrail County acreage in the Parshall / Austin / Sanish Fields consisting of 7,715 net acres and, based on Randall & Dewey’s estimate, 19 million BOE of net Bakken reserve potential. Given its small size and the fact that we are in a non-operated position, we do not consider this part of our Williston Basin acreage to be as strategic as it once was. We are expecting offers by the end of the month and are targeting an end-of-May close.

And then thirdly, the potential sale of up to 50% of our working interest in a portion of our remaining 301,000 Williston Basin acreage for cash. We have a number of parties that are in various stages of evaluating a transaction, but it is too early to say when we might be able to close.

One general comment of the Williston Basin that Bud has already touched on, despite the US A&D markets having effectively shut down due to the lack of a functioning credit market and the currently low commodity prices, interest in our Williston Basin asset position remains very strong. This increase is exhibited by the numerous unsolicited offers that we have received for portions of our Williston Basin asset position over the last several months.

Although we are not enamored with the idea of selling any of the company’s assets in the current environment, we feel that for a company of our size, our acreage position is large enough that we can suffer some dilution and still retain sufficient reserve growth potential to drive the company’s performance when the markets do recover. In conclusion, the tremendous and well-documented oil volumes in place in the Williston Basin provide the company with an attractive currency when other funding alternatives for our industry have become less attractive.

Point number four, beyond the smaller transactions that we are supposed to close by the end of March, the completion of one or both of the two other Williston Basin acreage transactions that I’ve outlined will position the company to potentially increase our E&D CapEx budget in the second half of 2009. Improved project economics resulting from a combination of lower service costs and our higher commodity prices would also be a requirement for the company to commit additional capital.

Point number five, in order to further enhance cash flow, the company is targeting to reduce 2009 cash G&A by 10% to 15% relative to that for 2008. Further these steps will not involve a reduction in our staff. We strongly believe that such a step would be shortsighted and would adversely impact our ability to react to the eventual market recovery.

Point number six, in terms of our hedging activities, we continue to add to our hedge portfolio. Importantly and given the current bearish outlook for 2009 gas prices, we estimate that we have hedged close to 70% of our 2009 gas volumes at a floor price of $6.73 per Mmbtu.

In summary, over the last several months, we have been taking significant steps to enhance the company’s liquidity position in this very difficult environment. Based on our progress to date on each of these initiatives, we feel that we have adequate liquidity to manage through the current downturn. Further, and depending upon our ability to get one of the larger transactions that I have outlined completed, we are hopeful that we will be in a position to resume our drilling activity in the Williston Basin at some point in the second half of 2009.

Moving on to a brief discussion of our financial results, our fourth quarter production was higher than the prior year’s fourth quarter by 5%, averaging 37.4 million cubic feet equivalents per day. Further these volumes exceeded the high end of our fourth quarter 2008 production guidance that we’ve issued in November 2008 and also exceeded our third quarter 2008 volumes by 35%. The sequential increase resulted from the October and mid-December hookup to production of two of our four successful 2008 Southern Louisiana wells as well as the ramp-up of our non-operated Mountrail County activity in the Parshall/Austin fields.

On October 30, 2008, we announced the completion of two EOG wells, each with a 25% working interest. Both wells came on line at rates in excess of 1,700 barrels of oil equivalent per day. In terms of our costs, our per-Mcfe lease operating expense increased 59% to $1.11 per Mcfe in the fourth quarter 2008 from $0.70 per Mcfe in the fourth quarter of 2007, a 73% increase in per-Mcfe operating and maintenance expense accounted for the bulk of the increase, with higher work-over expense and ad valorem taxes also contributing to the increase.

For the full year 2008, lease operating expense increased 52% to $1.08 per Mcfe from $0.71 in 2007. For the full year, higher operating and maintenance and work-over expense accounted for the increase partially offset by lower ad valorem taxes. For the fourth quarter and full year, higher saltwater disposal compressor rental and electricity fuel and power expense accounted for the majority of the per-Mcfe increase in operating and maintenance expense.

Generally speaking, oilfield and service cost inflation accounted for roughly 50% of the increases that we experienced in 2008 in the absolute dollar amount of our operating and maintenance expense. Beyond this factor, the additional wells that we brought on line over the course of the year combined with our shift away from lower operating cost gas wells in favor of higher operating cost oil wells were also significant factors.

Obviously, in the current environment we are pressing our service providers to see significant oilfield and service cost deflation during 2009. The production tax increases outlined in yesterday’s earnings release for the fourth quarter and full year 2008 relate primarily to the reduction in high-cost gas production tax abatements received on our Vicksburg wells in 2008 versus those received in 2007.

On a per-unit basis, general and administrative expense for the fourth quarter 2008 decreased 24% to $0.55 per Mcfe from $0.72 in 2007. The majority of the decrease in fourth quarter 2008 G&A expense was driven by a decrease in employee compensation expense associated with the reduced levels of employee bonuses for 2008. On an absolute dollar basis, G&A expense for 2008 increased by only 3%, as decreased levels of employee compensation expense were offset by higher legal and accounting costs.

Beginning in August 2008 we began to experience a downturn in commodity prices, which continued throughout the remainder of 2008 and triggered the fourth quarter before tax ceiling test write-down of $237 million. On December 31, 2008, the Henry Hub gas cash natural gas price was $5.71 per Mmbtu and the West Texas intermediate oil price was $44.60 per barrel, which resulted in the capitalized cost net of accumulated depreciation of our oil and gas property to exceed the discount at present value of our estimated crude reserves using a 10% discount rate.

To conclude our income statement discussion, fourth quarter EBITDA decreased by 19% to $19.6 million and full year EBITDA decrease by 9% to $96.7 million. Moving on to the balance sheet, covenants under our senior notes preclude us from incurring additional debt to the extent our total debt levels exceed 25% of our adjusted proved PV value based on year-end prices as defined in our senior noted indenture.

Because of the dramatic downturn in commodity prices at year-end 2008 and because this covenant calculation will rely on 2008 year-end prices for all of 2009, we elected to draw down the remaining $32.9 million of unused capacity under our senior facility before the lower 2008 year-end prices limited our access to this unused capacity and negatively impacted our corporate liquidity.

As a consequence at year-end 2008, we had $40.3 million of cash on deposit, we are fully drawn under our senior facility that had $145 million borrowing base and had $160 million of senior notes outstanding. As I mentioned earlier on March 10th, we had $33.3 million of cash on the balance sheet.

In terms of capital expenditures, during 2008 we spent $172 million on the E&D CapEx, with roughly $136 million or 75% of this capital consisting of drilling expenditures, $36 million or 21% consisting of land and seismic expenditures. Approximately 68% of our E&D CapEx budget was spent in the Williston Basin, 16% in Southern Louisiana, and 10% in the Vicksburg.

For 2009 we are currently forecasting to spend $26.7 million on drilling CapEx, with a majority of this spending occurring in the first several months of the year. Further in 2009, net of expenditures we expect to receive $2.4 million for land and seismic reimbursements.

Assuming we accomplish the closing of one or more of the Williston Basin acreage transaction we referred to earlier, we would then be in a position to increase our 2009 CapEx budget. At a minimum we have identified an additional $16 million of Williston Basin drilling CapEx that we would like to spend in the second half of 2009, which would result in an updated 2009 E&D CapEx budget of $42 million.

In our earnings release yesterday we issued production guidance for the first quarter 2009. In terms of our expectations for the quarter, we are forecasting for production volumes to average between 30 million and 33 million cubic feet of equivalents per day.

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

Bud Brigham

That concludes our call. I’d like to thank you all for your participation. And with that, we would be very happy to answer any questions you may have.

Question-and-Answer Session

Operator

(Operator instructions) And your first question will come from the line of Scott Hanold with RBC Markets. Please proceed.

Scott Hanold – RBC Markets

Thanks. Good morning.

Bud Brigham

Good morning.

Scott Hanold – RBC Markets

Bud or Gene, can you talk a little about the revolver? I know you drew it down at the end of the year, but when is the redetermination period on that and what do you all expect? Because – is there a chance that the revolver gets reduced and you got to pay some of the cash back to it – to the banks?

Gene Shepherd

Well, we deliver a report to BofA on April the 1st and then they come back to us at the end of that month or early May. That calculation, we do get the benefit of any additional wells that were hooked up to production since the end of the year. So it’s a 12/31 report, but to the extent that we have moved additional wells into the PDP category we get the benefit for that. For example, at the end of the year we didn’t have either of the two of our Southern Louisiana wells up to production. One got hooked up in January. One got hooked up in March – or will get hooked up later this month. So those two will get moved to the PDP and will get the benefit for those in this April 1 report that we deliver. But –

Bud Brigham

We have another Gulf Coast that’s getting down too that also could be in that report as well.

Gene Shepherd

So I mean – the steps that I think to just review, the reduced level of activity in response to really the mismatch between commodity prices and service costs that we laid our rigs, as a consequence, going forward we are generating free cash flow. And as of – as I said, as of March 10, we had roughly $33 million of cash on the balance sheet. We will close these two transactions this month. And that should add roughly an additional $7.2 million of cash. And then we’ve got the other Williston Basin transactions that are on under way. So I think we feel good about our ability to get through the downturn that we are currently experiencing, including – obviously the borrowing base would be part of that. So I think we feel very good.

Scott Hanold – RBC Markets

Okay. But it seems to me the borrowing base, there is a pretty good chance that things are going to be brought down a bit when it does get redetermined. Is that a fair statement?

Gene Shepherd

Yes, I mean that’s – that's up to – it would be up to BofA to determine that. And obviously commodity prices have gotten lower since the last redetermination that works against us. We will get the benefit of some of these additional wells that have come on since the end of the year and had that hopefully no question should offset some of that price impact.

Scott Hanold – RBC Markets

Okay. Well, I guess what I’m trying to get at is, I mean, have you stressed test what you think could happen to the revolver that – to become –?

Gene Shepherd

Yes, we’ve run lots of scenarios and have done a lot of analysis. And so I think we have looked at the issue very carefully.

Scott Hanold – RBC Markets

Okay. And so based on what you see and your outlook at this point in time, you believe you can have the opportunity to ramp things up in the back half of the year given that service costs to improve and commodity prices look a little better?

Gene Shepherd

Sure. That's a function of these transactions and commodity prices and services costs. So – I mean, that’s a big part of the reason why we are taking these steps on these two larger opportunities in the Williston. All the transactions that we have listed are Bakken transactions. The A&D markets are shut down, but we were getting calls in November and December about our position in the Williston. I mean, it’s a very attractive currency to have. And so –

Bud Brigham

And Scott, I’ll just add one thing to that. I mean, all of the – everything that we are doing here is to position us. It has been a very uncertain environment. And just to conservatively position ourselves such that – you know, we are coming out of the worst part of the cycle where you’ve had a real deflation in values and cash flows and along with that, you’ve had a lag in the cost structure and so the very worst part of the cycle and we are approaching the best part of the cycle when the costs are going to be at the lowest and commodity prices at some point here will be stabilizing and eventually improving. And so all of these steps that Gene is kind of outlining here are steps that position us to have as much flexibility as possible through that cycle and be positioned coming out the other side to be able to meaningfully ramp up our activity and take advantage of this great resource we have in the Williston.

Scott Hanold – RBC Markets

No – understand and I appreciate it. I’m just trying to get a sense of – you know, let’s say the macro doesn’t improve here until the back half of ’10 and let’s say those transactions don’t close as you expect, which obviously in this market could happen. When you look at your acreage, how much drilling do you have to do on that to hold some of it? What’s the risk here? Obviously activity you couldn't really ramp it up in that case and so we’ll see the production continue to slide off. In looking at that scenario, I mean, how much of your acreage could you lose over the next couple of years if you can’t drill, specifically obviously focused at the Bakken?

Gene Shepherd

Scott, before Bud answers that question, obviously – the steps that we have taken are the significant ones. Obviously there are other steps that we’ve taken. We’ve talked about G&A, the hedge position that we continue to build out. We added some – oil prices spiked up on Tuesday – Monday or Tuesday, and we added roughly – we hedged roughly 10,000 barrels a month from April through December at a swap price of $50.75. So there are other steps that we haven’t talked about that I think mitigate risk. And the combination of those gives us sort of the sense that we are in good shape although obviously markets differ, but we feel like we feel confident.

Bud Brigham

Yes. And Scott, to answer the other part of your question is that we are very fortunate. Most of our acreage – we have 308,000 acreage, huge position, and most of it was acquired in the last year and a half. Most of it is either five-year leases or three years with a two-year kicker. We don’t have any more significant obligatory wells that we have to get out and drill to preserve acreage. So – I mean, we are in relatively a very, very good position with that asset in the field and we can afford to be patient.

Scott Hanold – RBC Markets

Okay. And one last question and I will let somebody else get on here. But looking at Rough Rider, it seems like you are pretty excited about the potential to put some pretty large number of stages on these completions and get very nice productive oils like you saw in the Olson. I guess – give me a sense of how you think the repeatability of this could be? And really outside of the Olson, are there any other analogies we can draw from wells drilled in that area? And could that be an area you really focus on when you are able to ramp up your activity again?

Bud Brigham

Yes, a couple things and then Jeff will probably want to add to it. When you look at that area west of the Nesson, obviously we don’t have the number of horizontal Bakken completions we have in Mountrail. And Mountrail, you have probably 160 Bakken completions that we have some history on. That being said, Rough Rider where we have 105,000 net acres, we have – first, we have the four wells completed, east or west, 15 miles apart across our 105,000 net acres that were all single uncontrolled fracs. And you can see it when we show the production profile.

Those wells performed almost identically. It’s pretty remarkable. They all came out about 200 barrels a day and leveled out at 50 to 90. And it shows we were successful in our effort to decline that acreage over the areas that have – as we talked about, the good Middle Bakken (inaudible) porosity. We are seeing comparable performance in the area. And then moving to the multi-stage stimulations, we have the Mrachek on the south end with seven stages and we’ve got the Olson on the north end with 20 stages again, high deliverability in the Mrachek. We probably damaged, but it’s still a good well despite that.

So there is a couple of – there are operators’ wells. I mean, in addition to our single uncontrolled fracs, there were two (inaudible) uncontrolled fracs across our acreage. They are identical to those other in production performance to our wells to two of the uncontrolled fracs. And then now there are several, which were not – we don’t have specific information to provide on the call, but there are several new multi-stage completions in the area that are confirming what we are seeing with our multi-stage completions.

So we don’t have the number of wells that we have in Mountrail County, but that wells we have are scattered geographically across our area and they are all providing encouragement that it is a Tier 1 area. So I would say there is a good probability that there will be – one, we’ve got our figure over there, which is one of the three wells that our operations guys did a great job of successfully running the 19 swell packers and a long lateral. And that well is just waiting to be frac-ed, and once it gets warmer, we will be up frac-ing that well. But I think there is a good probability that later in the year that scenario – Rough Rider, we will be drilling some more wells. Jeff has got something else to add.

Jeff Larson

Yes, Scott, maybe just couple words on the rocks. I mean, in the Rough Rider Area, we’ve actually got some very good control points from the historic vertical wells that have been drilled in the area for the Red River deeper objectives. And we optimized the leasing of our acreage in Rough Rider on this Middle Bakken porosity membrane. We really like the looks of it on our acreage. It’s well developed. It’s continuous.

You can map it basically on both sides of the river. And then we have confirmed that. When we drilled our Olson well, we drilled a vertical post hole and we actually cored the Olson well through the Middle Bakken, Lower Bakken and upper Three Forks. We’ve got a real nice rock, you know, actual physical rock tied to our log data point. And that confirms what we are seeing in the Middle Bakken that’s real attractive. And we’ve also got excellent oil standing in the Three Forks levels [ph], which has got us excited.

Bud Brigham

Yes. Scott, I might say one more thing about the early part of your question on bringing in partners in areas. It’s an environment that none of us have seen in our last time as far as the economy (inaudible). But on the other hand, this company has been around for 18 years now, and we’ve had 18 years of we’ve been selling interest in projects and leverage in our assets in the field successfully.

And really you go back to our roots, that's how we were built because we were more capital constraint then and we were very dependent – much more dependent on that at that time. I can tell you that this is an asset that we think it’s one of the top resource plays domestically, and thus we are seeing a lot of interest. We have a high degree of confidence. We are going to have some partners, good partners in various parts of this play. And we don’t know when and who that’s going to be or how big each transaction will be, but there is no question on our mind we are going to have some good partners to help us develop this acreage.

Scott Hanold – RBC Markets

Okay. Appreciate that. Thanks.

Bud Brigham

Yes, thank you.

Operator

And your next question will come from the line of Joe Allman with JP Morgan. Please proceed.

Joe Allman – JP Morgan

Thank you. Good morning, everybody.

Bud Brigham

Good morning.

Joe Allman – JP Morgan

Hey, Gene, question for you here on the covenants for your bank debt and for your notes. Could you talk about what the covenants are and what do you think happens to some of the more restricted covenants if actually you don’t get to sell any incremental assets beyond that 7.2 million, which seems done deal?

Gene Shepherd

Yes. The covenants in the senior notes are incurrence covenants. So it’s not – doesn't really create any real issues for the company. The bank covenants, we’ve got a current ratio test, which certainly we feel – our cash on the balance sheet in generating positive cash flow in the transactions we feel good about, the fixed charge coverage ratio, we’ve got to maintain a fixed charge coverage ratio. It’s essentially EBITDA to our income statement interest, which is GAAP interest. It’s not total cash interest expense. It’s the interest expense that flows through the income statement.

So to the extent we are capitalizing a portion of that interest, that’s not captured in that calculation. So – and then as far as the EBITDA, the numerator, we get to recognize the gain from, say for example, this asset sale is roughly in the neighborhood of $2 million. So we’re paying leaving six on the mineral sale and our basis is four. So that flows through that calculation and we get the benefit for it. We have modeled them. We’ve looked at them. We stress test them. Obviously it’s a difficult environment, but we feel good with the steps that we are taking to get through the year. And obviously the mineral sale will help. These additional wells that we are bringing, that’s helped and will help, but that’s probably all that we are in a position to say currently.

Joe Allman – JP Morgan

Okay. So I mean, if you don’t get to sell the additional assets, it could be a little touch-and-go, but if you do, it certainly helps out the situation. Is that accurate?

Gene Shepherd

Yes. I mean, I think the covenants are – the covenants, we’ve done the calculations. As you have the higher price months roll off last year, it becomes – that hurts. Working to our benefit is a set of the wells that we are bringing on in the transactions that we are working on. But –

Bud Brigham

Wells we are completing in.

Gene Shepherd

Yes. So it’s – obviously we’ve looked at all those issues. We are taking the whole series of steps that we’ve outlined, the hedging, the G&A reduction, in an effort to get through the year. And obviously we wouldn’t want to be in a position we have to count on some external transaction where we are not in control. Obviously to the extent we are trying to get one of those other transactions done, we can’t pull the trigger for somebody. If they want to come in and buy some of our Williston Basin acreage, that’s up to them. So we feel like we are taking steps that we feel like we have control and we can execute on to allow the company to get through this difficult period.

Joe Allman – JP Morgan

Got you. And then in terms of the non-operated Bakken properties that you are marketing, what is the production from those properties? And what do you think is the timetable to get that assets sale done?

Gene Shepherd

I think bids are due – you're talking about the non-operated –?

Joe Allman – JP Morgan

Yes, the (inaudible).

Gene Shepherd

Bids are due at the end of the month, and we are sort of targeting an end-of-May close. And the feedback we are getting from Randall & Dewey is there is a lot of interest and it’s – so we are optimistic about getting the transaction done when it’s going to come down to valuation. And so – but just based on the number of inquiries and the data room visits, it is a great area. That package for us isn’t just strategic. I think we learned a lot initially from the initial farm-out that we did with Northern Oil and Gas.

It sort of gave us some insights that we didn’t have at that time and allowed us to put our acreage position together. We’ve learned that. We got that information. It’s non-operated. It’s not – from a size standpoint, it’s not a huge portion of our acreage. And then probably it’s been so heavily drilled up maybe not as much optionality certainly that exists on other places – other portions of our acreage where we haven’t been as active with the drill bit. So it’s just – I think it’s a good transaction for us to do. It’s not horribly strategic. We can get something done and get it done on a timely basis. And it certainly helps the company on a number of fronts.

Bud Brigham

We can forward you the flier if that would be helpful to you, too.

Joe Allman – JP Morgan

Okay, that would be great. And then what’s the production from there?

Bud Brigham

Jeff is running to get that. We don’t have that out of the top of our head. We’ll have that for you here in a minute.

Joe Allman – JP Morgan

Okay, great. And just another one quick – revisions, could you break out the revisions, proved developed versus PUDs on the reserves?

Bud Brigham

Sure. Lance is looking that up for you.

Lance Langford

For the year – Joe, you asked about production. As of January, it was 477 barrels a day for that non-operated package.

Joe Allman – JP Morgan

Okay.

Bud Brigham

That was barrels of oil equivalent per day.

Joe Allman – JP Morgan

So, just on that, Gene, or Bud, your Williston Basin production overwhelmingly is coming from operated properties then?

Bud Brigham

Yes, you bet. We had over 2,000 barrels a day. I think it’s like – something like that 2,200 barrels a day or something.

Joe Allman – JP Morgan

Got you.

Bud Brigham

Yes. I mean, if you look at our Olson that’s come on line, that’s – that's 100% in Olson – working interest? Yes, 100% in Olson. I mean, that’s a big well for us. It’s on line producing so strongly. And then the cost up in the Adix – second half of the year wells, that’s the break in our oil production. We got the additional wells that we will be completing during the course of the year, Joe, that will also provide production as we move through the year.

Joe Allman – JP Morgan

I can just wait, and catch that other offline.

Bud Brigham

Okay.

Lance Langford

The revisions, it is about 50/50, Joe. It’s a little more on the PUDs than the proved developed.

Joe Allman – JP Morgan

Okay, got you. And was that mostly PUD, that was just PUDs you just couldn't book at all or was it PUD tails or –?

Lance Langford

Yes, it was PUD tails. It was a little bit of both. But when you run year-end prices last year for this reserve report, you gain back that entire revision.

Joe Allman – JP Morgan

Got you. Okay. All right, very helpful. Thank you.

Bud Brigham

You’re welcome, Joe. I’ll just mention – the three of the wells that I mentioned that we will be completing during the course of the year, we’re just waiting for costs to come down and warmer weather, or high equity wells, you know, the Figaro with the 20 frac stages, 90% working interest; the Stroebeck, which will also have 20 frac stages, is 80% working interest; and the Anderson that will also have 20 frac stages is at 62% working interest.

Joe Allman – JP Morgan

Okay, very helpful. Thank you.

Bud Brigham

You’re welcome.

Operator

And your next question will come from the line of Ron Mills with Johnson Rice. Please proceed.

Ron Mills – Johnson Rice

Good morning. Just as it relates to the joint venture that – or venture activities that you're thinking about, in what form or fashion do you all – are you trying – is it trying to be one big joint venture, or are you looking at several potential ventures or taking all comers as the case may be?

Bud Brigham

No, we’ve had – Ron, this is Bud. I’ll take the first shot at that. We’ve had a couple of primarily proposals from parties that have been just buying in at a price per acre, which is obviously preferred from our perspective for a number of reasons, including given that at some – once they bought in we're on a head's up aligned basis and moving forward together. So I think that that’s the most likely.

We have had one party that proposed both buying in on a promoted cost per acre and then also carrying us on wells, which we are considering those proposals as well, but it’s not our preferred proposal. These cases are on the joint venturing or acreage participation, non-proven participation in our acreage in a play. Again, as we said on the call, Ron, and as you know, given how much acreage we have, if we sell down, as I said, 25,000 to even on 125,000, sell 50% working interest to somebody, we are still going to have over 225,000 net acres, just a huge position for our company our size.

Ron Mills – Johnson Rice

Okay. And then from oil production standpoint, you talked about what the production was in the assets for sale. But can you break your oil production down by Williston Basin and Gulf Coast?

Bud Brigham

Ron, we do have that one slide that shows the Williston oil production. So you can look at that and – because I don’t have it out of top of my head, maybe these guys do. But you can look at that slide and then look at the – the far slide shows our net oil production. And you can take a lot off of those slides.

Ron Mills – Johnson Rice

Okay. And then from – Gene, it sounded like you added some recent hedges. Can you give a quick summary of what your current hedge position is?

Gene Shepherd

Yes. We have – let me just quote you some equivalent volumes. We have – we've got roughly – we've got about six – it’s like about six Bs – excuse me. We’ve got close to five Bs hedged for 2009. That would be roughly 1.4 Bs in the first quarter, 1.4 Bs in the second quarter, 1.1 Bs in the third quarter, and then 0.8 Bs in the fourth quarter. We are pretty heavily hedged on the gas. There's really not a lot of additional volumes to hedge on the gas side. Part of the trade that we did earlier this week, we did some swaps and added some pretty nominal volumes in the fourth quarter, and so that really gave us sort of maxed out on the gas side.

We haven't been very heavily hedged on the oil size. As a matter of fact, before Monday or Tuesday – my days are running together. But we had hedge volumes through June and then we had no over-hedges beyond that. And so we did a very major transaction that I outlined where we added ten contracts a month from April through December, 10,000 barrels a month and swapped that at 50.75. So obviously we’d rather – we're not enamored with doing those types of trades, but we feel that certainly doing those transactions in ’09 when obviously we want to have as much protection as possible that it makes sense. We’re looking for spikes in the market, and certainly we’ve got a nice spike on Tuesday. And we look for other similar opportunities to add to that hedge position, probably more so on the oil side. As we add this other Southern Louisiana discovery in March –

Bud Brigham

And possibly the Texas Gulf Coast.

Gene Shepherd

And the Texas Gulf Coast discovery that Bud referenced earlier that will give us more gas volumes to hedge. We’ll just have to evaluate it at that time where gas prices are, and obviously it’s been a pretty weak market. So we are glad that we – other than the small volumes we did on Tuesday that our hedge position on the gas side was largely in place, as reflected in that weighted floor price that I referenced of $6.73.

Ron Mills – Johnson Rice

Okay. And Bud, on the well cost, your long laterals look like they have gone from the mid-nines to the mid-sixes, and the short laterals from plus or minus six down to upper fours. Of those cost savings so far, can you try to break those down in terms of well cost versus complete drilling costs versus completion costs, and where you think the incremental 10% to 15% can continue to come from?

Lance Langford

Ron, this is Lance. Yes, those costs – basically what we are doing on all those costs, and they are coming across the board, of course, our AFEs are heavily weighted towards the completion side. So over 50% – I think it’s in the 60% range or 60-something percent range is completion dollars. But what we’ve been doing every month to month-and-a-half, we’ll go out and rebid all of our products and services to multiple services companies, and they are routinely going down. This last time just the stimulation portion went down $0.5 million in a month and a half. But they are coming down across the board. My group is – we are meeting and talking about how to not only push down our capital, but push down our LOE in all facets of our expenses. I know that doesn’t exactly answer your question, but I think those continued costs are going to continue to come down on the rig and on the drilling side and on the completion side.

Gene Shepherd

You know, 5.22, that’s all put together, we think at mid-year that short lateral goes from maybe 4.8 million today to maybe in the 4.2 million range that’s our goal for the short laterals. And then the long lateral goes from 6.5 million today, which is down from 9.5 million last year, it goes from 6.5 million maybe down to 5.8 million or so.

Ron Mills – Johnson Rice

Okay. Thank you, guys.

Gene Shepherd

Thank you.

Operator

And your next question will come from the line of Mike Scialla with Thomas Weisel Partners. Please proceed.

Mike Scialla – Thomas Weisel Partners

Good morning, guys.

Bud Brigham

Good morning.

Mike Scialla – Thomas Weisel Partners

If I’m understanding you right, it sounds like restarting your Bakken drilling is really contingent on the sale or is there a combination of oil price and cost reduction that would trigger that as well?

Bud Brigham

Gene might want to add to what I say here. All these steps that we’ve taken here are just to position ourselves given the uncertain environment. So we have maximum flexibility. And so it can be a combination of things positioning ourselves to resume drilling in a meaningful way, and prices improving to do it. But I think it’s very likely that we will be leveraging our assets. And that’s something we’ve done every year of our company’s history and with a lot of success.

And of course we’ve had an environment as difficult as this, but on the other hand, outweighing that is we've never had an asset as leverageable as this one. And so I think we’ll get help in a lot of different areas in our initiatives underway that will put us in a position. We have a high degree of confidence to be able to pick up the drilling at mid-year. So the answer is, any of those above will help, but we think the likely outcome is that’s going to be a combination of those that’s going to put us in a position to aggressively ramp up during the second half of the year.

Gene Shepherd

I don’t want to mislead and misrepresent. I mean, clearly there is the scenario where higher commodity prices and declining service costs put us in a position to get back to work in the Williston Basin. So I might have overstated that in my comments earlier. We’ve got so many different initiatives that we’re working at to sort of underpin the company’s liquidity position. And we are excited to get these two smaller transactions closed in March. I think what we are trying to do is create optionality on enhancing the company’s liquidity. And we’ve got all these different initiatives working sort of in parallel. Certainly we don’t have to have all of them come to fruition to create the kind of environment or we could – certainly one would be in a position to get back to work in the Williston Basin in the second half of the year.

Mike Scialla – Thomas Weisel Partners

Sure. Okay. And then did you run any sensitivities on your pretax PV10 with any higher oil price cases?

Bud Brigham

Yes, we should add – and it’s pretty remarkable when you run it. I think that’s one of the things – and Lance, I don’t know if you have that in here with you. But we’ve got probably more optionality on that. I can imagine there are many companies that are trying to have optionality on that. In fact, we were putting [ph] together, potentially have it as a slide and maybe that’s something we will incorporate in there. So we have run it and it’s very meaningful. And I’m sorry we don’t have it right in front. Gene has it. I’ll let him say.

Gene Shepherd

Yes. The SEC case, obviously PV10 of 288 based on a strip case that we ran on 128 produced 421.

Bud Brigham

From 288 to 421 going from SEC to the strip.

Mike Scialla – Thomas Weisel Partners

And what was the strip oil price at 128?

Gene Shepherd

I’m looking at the gas prices, I think it’s – oil prices – you know, there was – I can’t tell you what the strip. Unfortunately I don’t have it, but –

Mike Scialla – Thomas Weisel Partners

Okay. Well, you can [ph] get that. That’s no problem.

Lance Langford

It was a strip case on the 28th of January. It looks like it does up to $68, but that’s net of differentials. So there is a positive and negative differentials that usually flow through on a well-by-well basis.

Bud Brigham

You know, the first year average gas price was – but you’re seeing these are netting the differentials.

Gene Shepherd

Right. So it goes up to $68.

Bud Brigham

You are saying that –

Gene Shepherd

In the out-month – out-year.

Bud Brigham

Out-year. So it’s not on –

Gene Shepherd

It starts off at 44, 54, 58, 60.

Bud Brigham

Those are years –

Gene Shepherd

Those are the first years, yes.

Bud Brigham

Yes, the 44 in 2008 and – what do you say –?

Gene Shepherd

If you can get that, probably the most efficient thing to do would be just to get the strip for 128. I’m sorry we don’t have that.

Mike Scialla – Thomas Weisel Partners

No, that’s no problem. Thanks, that’s helpful. And then can you give your latest thoughts on the Middle Bakken and the Three Forks as to whether or not there are separate reservoirs? And have you seen any testing or done any yourself to determine that?

Bud Brigham

Well, I mean, I think companies are getting asked that less, I think, and we've heard other operators say like down there in Dunn County, I don’t think they are competing for reserves in the Bakken and the Three Forks. And they are actually drilling a well down there to confirm that where they will have a lateral in the Bakken above the lateral in the Three Forks. Clearly if they are not competing down there, we are not in Mountrail County because the separation is roughly double where a Ross Area – the separation between the laterals in the Middle Bakken and the laterals in the Three Forks. And importantly, the Bakken – and that’s about a 100 feet of separation there in Mountrail County. And importantly, also the Lower Bakken Shale is that it’s thickest there in the Ross Area in the western Mountrail County, in the Ross Area were the thickest Lower Bakken Shale. And there is a pinch point there Lance can talk about. Why don’t you go ahead and mention that.

Lance Langford

Yes. This is Lance. There is a couple of things. One is that on the only Three Forks well that we’ve completed well within a mile-and-a-half of the Carkuff. And the way those wells stimulated, they are both of course –, one is 11 stage and one is a 12 stage frac. And the way they stimulated the pressures and rates required and the fluids required to actually stimulate and were completely different. So it’s not a definite that there is no communication, but it sure appears to be that you stimulate in completely different intervals. So – and that’s been consistent with what we’ve heard from other operators.

Also there is a pinch point in the shale between the Three Forks and the Bakken that we’ve done with Schlumberger doing some rock property studies and some modeling. And I think that’s the problem why they are not communicating. And I will look at it as a problem because we have to drill two wells where if we could properly stimulate those zones, we could get double the reserves or hopefully double the reserves. So right now there is a pinch point in the Lower Bakken between the Middle Bakken and the Three Forks that’s going to pinch off any kind of conductivity of a frac wing. So I think that’s something that we are going to have to try and figure out as an industry in the future.

Gene Shepherd

There is going to be more opportunity to the west as you get – or down in Dunn County or further to the west in our Rough Rider Area, roughly the separation between the Middle Bakken laterals and the Three Forks laterals is then or there than it is [ph] in Western Mountrail is about 65 feet over there relative to the 100 feet in Western Mountrail with less shale. So there is more opportunity there, as Lance was saying, potentially for the industry to figure out how to frac and that’s going to get both reservoirs with one lateral.

Mike Scialla – Thomas Weisel Partners

Okay, great. And then just last question from me. I understand your reluctance to give full year production guidance. Just wondered if you can give us an annual decline rate on your base production right now?

Lance Langford

This is Lance. And I was looking at that today, but basically it’s in the 30% range in there. There is variability, because you can’t really tell just looking at the base production, because we always have pump changes and fall recompletions and asset [ph] jobs that increase production that you don’t show in our particular production forecast that we put out.

Gene Shepherd

Yes. But it really is a function of – you have to look back and see what wells have you brought on recently because obviously those wells are going to see higher decline rates. To the extent we are not spending capital further out in the years, we would expect to see that decline rate arrest. So –

Bud Brigham

Yes, plus you would be doing more work-overs in other things that will have arrested as well.

Mike Scialla – Thomas Weisel Partners

So, maybe 30-ish percent for a quarter or so and then flatten out a little bit over the course of the year?

Bud Brigham

Certainly we would expect to see that – moderate.

Gene Shepherd

One thing on the full year guidance, I mean, our expectation – we put out a budget and we're being very conservative in managing the business in that cycle, I think as we should be, but our expectations are we are going to be spending – in the second half year, we are going to be investing capital drilling wells and that’s going to impact our late year production and will be back to ramping up our production more significantly at that point in time. So I think as we move through the year and we get more visibility on that and those expectations, we will likely be updating the budget.

Mike Scialla – Thomas Weisel Partners

Appreciate it. Thank you.

Bud Brigham

Yes, thank you.

Operator

And your next question will come from the line of Steve Berman with Pritchard Capital Partners. Please proceed.

Steve Berman – Pritchard Capital Partners

Hi, good morning. Another non-op question as it relates to the Parshall / Austin / Sanish stuff you have for sale. EOG had shut in some wells there because I guess of the high differentials waiting on a pipeline. I assume that might be impacting you a little bit late, maybe that 477 barrel a day number you gave before might be understated. Is there any connection there?

Lance Langford

This is Lance. The 477 was in January, and I can’t remember when exactly EOG did their shut-ins. I was thinking it was in February as a reduction in production. But the way we are modeling our EOG wells in the production forecast, we are taking a – they are shutting in 60% of their – choking their production back 60%. And so we’ve put a wait factor reducing our production on all the EOG wells 60% in our production guidance numbers that we’ve provided.

Bud Brigham

But you do raise a good point that in our first quarter guidance, that’s incorporated in our guidance. So it is – you raised a good point. It’s somewhat curtailed by EOG in that instance. And once obviously those wells are either be ramped back up at some point or at least they will have a flatter profile than they otherwise would.

Lance Langford

This is Lance. Jeff just pulled out the press release, and Whiting announced – I'm sorry. EOG announced that on February 5 that they were reducing their production.

Steve Berman – Pritchard Capital Partners

Do you have a February production number for that acreage relative to the 477 in January?

Lance Langford

No, I don’t have it in front of me.

Bud Brigham

But do you say 60% maybe or (inaudible) are all those wells –

Lance Langford

Well, there is more than EOG in here. EOG is just a portion of that 477. And my guess is a quarter to half of that number is EOG probably.

Bud Brigham

So maybe that’s a 20% reduction from that number because of the curtailment.

Steve Berman – Pritchard Capital Partners

And that 19 million barrel equivalent number you cited before, is that kind of a 3P number?

Gene Shepherd

That’s Randall & Dewey came up with potential there about 19 million barrels.

Lance Langford

Yes, that is a 3P number.

Steve Berman – Pritchard Capital Partners

Okay. And then what oil and gas price benchmarks are you assuming for ’09 to get to your statement that you feel you will be cash flow positive for the year?

Gene Shepherd

We’ve looked at a number of different cases running models and looked as strip prices. And historically we’ve run different discounts to the strip. Given where the prices are today, those discounts are not as significant maybe as we used in the past. But we’ve run a whole long list of price scenarios just to make sure that we covered all our bases.

Steve Berman – Pritchard Capital Partners

Okay. And the – I think I see it here on slide 41, the $6.5 million in the money hedge value, has that changed at all? Does that include –?

Gene Shepherd

It does not include the transaction that we did early this week. So I mean, based on the – we did that trade in the morning, and the market sort of cracked out in the afternoon. So there should be some value there, but I wouldn’t guess it would be too significant.

Steve Berman – Pritchard Capital Partners

But most of that value is in your gas hedges.

Gene Shepherd

Yes, correct. I mean, there is really – until we did the trade on early this week, as I said, we didn’t have – we had June volumes hedged on the oil side, and that was really it.

Steve Berman – Pritchard Capital Partners

All right. That’s it for me. Thanks, guys.

Bud Brigham

Thank you. We appreciate it.

Operator

And your next question will come from the line of Katherine Sabolski [ph] with Jefferies & Company.

Katherine Sabolski – Jefferies & Company

Hi. I think most of my questions have been answered by now. Thanks for all the great disclosure in your presentations. At year-end, do you have your accounts payable balance available?

Gene Shepherd

At year-end, we got about $10 million working capital deficit at year-end. So that excludes – excluding cash was the $10 million working capital deficit.

Katherine Sabolski – Jefferies & Company

Okay. And accounts payable currently is sort at the same level I assume?

Gene Shepherd

Yes, I have to go back and look. But it’s – yes, I don’t know out of the top of my head how that number might have changed. Ask your question again –

Bud Brigham

She said now –

Gene Shepherd

Now – sorry. Yes, I just – you know, we’ve been focused on generating year-end numbers. We began to get data on January, but it’s just too early we don’t have a real clear picture yet.

Katherine Sabolski – Jefferies & Company

Okay. And looking forward to the second quarter, given your reduced CapEx budget, do you think it might be possible to maintain production volumes or would it be more likely to see a slight reduction just due to natural decline?

Bud Brigham

Well, we’re not – of course, we hadn’t put out full year guidance, but we do have the South Louisiana well that’s going to come on line. It’s going to materially impact the first quarter. It will be on line for the second quarter. We have a Red River well that’s coming on line. That’s not going to impact the first quarter. It will impact the second quarter. There are some competing factors. We have the EOG shutting in their wells for part of the first quarter. That should really flatten out into the second quarter. And Lance, do you want to add something?

Lance Langford

Yes. We could also or we will also see some declines from the divestitures as we close them because of the effective date on the non-op is in the mark.

Bud Brigham

Right. And then on the other hand, we have other wells that we will probably completing here as we get into warmer weather, the Figaro and the Stroebeck and the Anderson, which will contribute incremental additional production volumes. So it’s a roundabout way of not really answering your question, but giving you a lot of the data points that factor in one way or the other.

Katherine Sabolski – Jefferies & Company

Well, that’s great. Thanks a lot for your help.

Bud Brigham

Thank you.

Operator

And your next question will come from the line of Joel Musante with C. K. Cooper & Company. Please proceed.

Joel Musante – C. K. Cooper & Company

How are you doing, everybody? I just had one quick question. What’s your – for your proved developed PV10 reserves, what’s that number?

Gene Shepherd

Proved developed PV10?

Joel Musante – C. K. Cooper & Company

Yes.

Bud Brigham

You want the SEC pricing?

Joel Musante – C. K. Cooper & Company

Yes.

Gene Shepherd

At year-end, PV10 is 170 million – 171 million.

Joel Musante – C. K. Cooper & Company

Okay.

Gene Shepherd

172 million.

Joel Musante – C. K. Cooper & Company

All right. All my other questions have been answered.

Bud Brigham

All right. Well, thank you.

Joel Musante – C. K. Cooper & Company

Thanks a lot.

Operator

And your next question will come from the line of Mike Canon [ph] with Orex [ph]. Please proceed.

Mike Canon – Orex

Hey, guys. Just a question on the borrowing base redetermination. Is there a formula attached to that or is it fairly subjective in terms of the prices that Bank of America uses as well as the service cost that they factor in?

Gene Shepherd

They will use their price deck, I mean, whatever that price deck is at the time we are doing the redetermination. So it is a very subjective exercise. Generally the non-producing reserve as a percentage of the total borrowing base, they are capped out at roughly 25%.

Mike Canon – Orex

And that’s for what part?

Gene Shepherd

Non-producing, essentially the PUDs and the what’s not hooked up to production. So that’s why when I mentioned earlier bringing these two, we have these two discoveries in Southern Louisiana that aren’t hooked up. We tested them. We generally know what rates, but the fact that they are not producing gas to sales, at year-end you leave them in the non-producing category. But we will get credit for those in April. So it’s – there is a big subjective – it's not just a formula. I mean, they do sort of a calculation based on the company’s assets and then they also do a cash flow calculation and sort of look at the combination of the two and make an assessment.

Mike Canon – Orex

Do you get any credit for your acreage in the Bakken that’s not producing?

Gene Shepherd

No, not in the borrowing base, no.

Mike Canon – Orex

Okay. Was it reserve reports due April 1 and they have 20 days to calculate whatever they think the borrowing base is going to be?

Gene Shepherd

Right.

Mike Canon – Orex

And then they go to lenders, so –?

Gene Shepherd

Then they put word out to the other banks and make it – what they will do is make the recommendation to the other banks.

Mike Canon – Orex

You basically have between now and sort of mid-May. If you needed to get something done to pay down the revolver and be within on size, if you will?

Gene Shepherd

Yes, but I mean, I think we’ve outlined. We’ve got cash. We will be building cash.

Mike Canon – Orex

Has there been any other private land sales or any other evidence since January? I mean I see the slide that you provided, but it has evaluations remained the same per acre in the Williston, the Bakken generally?

Bud Brigham

Yes, what was the question, I’m sorry?

Gene Shepherd

Mike just asked if –

Bud Brigham

Sorry, Mike.

Mike Canon – Orex

No, if there is any more recent data on acreage sales, private or leased?

Bud Brigham

No, that was the most recent one that we put up on that slide. That was January BLM and –

Lance Langford

Jeffrey has put out our report back in December.

Bud Brigham

That was on that leasehold.

Lance Langford

Okay, okay.

Jeff Larson

And the next sale will be late March, early April.

Gene Shepherd

Yes, you can get what Jeff has reported. It adds a little color on that. What’s the date on that, do you have it, Jeff?

Jeff Larson

January 29.

Bud Brigham

January 29, that’s regarding that lease sale. It adds some color. It’s obviously a real strong sale. So, just to give indication of the industry’s interest, which was (inaudible).

Lance Langford

When is the next one, Jeff?

Jeff Larson

It’s scheduled for late March, early April. Yes, the BLM sale.

Mike Canon – Orex

Okay. That’s helpful. And then the strip case that you ran at the end of January, I think you said it was 4.21. How much of a decline in service cost was factored into that case versus any cases you ran at the end of the year?

Bud Brigham

It wasn’t factored in at all. You raise a good point. I mean, it’s – the service costs and to develop those PUDs have come in quite a bit. So, no, that’s not even inclusive of that.

Gene Shepherd

The development costs in that particular report were roughly $167 million.

Bud Brigham

But we assume it’s down 30% from that. That makes it 120, so net 40 million.

Mike Canon – Orex

Does that make a material difference in terms of probables being converted in the PUDs in terms of your engineer reports? I mean, have you run estimates on what the current decline in service costs would add potentially versus your year-end reserve estimates?

Bud Brigham

No, but I mean that is something we probably should look at.

Mike Canon – Orex

Okay.

Gene Shepherd

The numbers keep changing so quickly right now. And we have run our economics on every kind of – as it’s going down.

Bud Brigham

Yes, (inaudible) economics. We don’t run the reserve report, but –

Gene Shepherd

Well, but we update the reserve report. And as we add well, as we hook up the Southern Louisiana well, we will update the report. And we don’t go back and retrack the (inaudible). We look at all the – we typically – in the past when we do these redeterminations, we don’t typically redo the capital expenditures, the AFEs. But it might be something that in this environment to discuss with the banks.

Bud Brigham

In the past you haven’t seen the kind of movement. This is unprecedented in a six-month period to kind of moving on the cost side. But you raised a really good point.

Mike Canon – Orex

I was just curious on what cost today versus cost at year-end versus I mean even since the end of January when you ran your own strip case had to have come down 10%, 20%.

Bud Brigham

It’s more than that, I think.

Gene Shepherd

I mean, we did do it –

Bud Brigham

Since year-end.

Gene Shepherd

Since year-end. But since we did our year-end report, we’re probably down –?

Bud Brigham

Because we did in February.

Gene Shepherd

Yes. As you’re finalizing in February, so we’re putting those numbers together at year-end. So we’re getting some of that benefit.

Mike Canon – Orex

Okay.

Gene Shepherd

We have a good improvement on current prices.

Bud Brigham

Yes, yes.

Mike Canon – Orex

Okay. And there would be some PUD conversion there and probables that were not economical?

Gene Shepherd

That’s right. And more than anything, it just would make the overall PV10 go up.

Bud Brigham

And we it will look much better at mid-year, just the trend lines on this. I think the costs are going to be down further at mid-year as per our slides.

Mike Canon – Orex

Okay. And what was the PV10 associated with the 75 acres – or 7,700 net acres and 3P reserves in Mountrail?

Bud Brigham

Is that the marketing with the PV?

Gene Shepherd

I don’t know if we want to release that right now.

Mike Canon – Orex

That will be – that’s obviously a component to it.

Gene Shepherd

Right, right.

Mike Canon – Orex

Whatever price you get.

Bud Brigham

That’s right. That’s right.

Mike Canon – Orex

What’s happened over the last six months? I guess, really last four months in terms of commodity prices, I mean, you had a really – let’s say, you were, relatively speaking, under hedged. I mean, has that changed your mindset going forward in terms of hedging strategy and your target ratios?

Bud Brigham

Well, it did change our minds. You’re right. Over the course of that period, we have put in hedges just kind of to cover ourselves in this uncertain environment, and thus 70% of our gas is hedged.

Lance Langford

Yes, we were pretty lightly hedged in November. And coming into October we were very minimal. We have added substantially to our hedge portfolios since October of last year.

Bud Brigham

And we like – everybody saw the concern about the gas prices with all the supply. And so we got more aggressive with our hedging, and we’re opportunistic. And Gene and the guys did a great job, when you’d see a little spike in the gas prices working with the consultant to put on some more hedges. And I think that’s part of the reason you’d look at our – our hedges are pretty attractive, particularly relative to when we put them on.

Mike Canon – Orex

Have you all engaged anyone more broadly in terms of strategic alternatives to enhance shareholder value?

Gene Shepherd

No.

Mike Canon – Orex

No? And does your – suppose you raised a significant amount of capital from one of these sales, I guess it all depends on the acreage value that I assume in the acres sold, how much you could actually raise, but it could be material. Does your revolver agreement allow you to buy back your bonds, which are trading at the stress levels today? And is that something you’d consider?

Bud Brigham

That is certainly – I mean, it just doesn’t make sense in the environment today. We’ve looked at it. There’s an opportunity for somebody to take advantage of that discount, but it just doesn’t make sense for the company to do it.

Mike Canon – Orex

Okay. Well, thank you. That’s it for me.

Bud Brigham

Okay, thank you.

Operator

Your next question will come from the line of Houston Netherland with Natixis. Please proceed.

Houston Netherland – Natixis

Good morning, gentlemen. I don’t have the presentation in front of me here, so I apologize if this stuff is covered in the presentation. But I think I heard you say the majority of your $37 million will be spent in the first several months of ’09. Could you give me a little bit better idea of, specifically in 1Q, what that number might look like?

Gene Shepherd

Yes, Houston. It’s – I mean, I think, as I said, majority is probably the right – if you look at our total E&D spending, our total drilling expenditures for the year of roughly $27 million, all but maybe $3 million or $4 million will be spent in the first quarter.

Houston Netherland – Natixis

Okay.

Gene Shepherd

Yes, but that’s based on the current budget, obviously. And hopefully, we’ll be in a position to put out some kind of updated budget later in the year.

Houston Netherland – Natixis

Okay. And then, I think I heard you say the market value of your hedges is around $7 million. Is that right?

Gene Shepherd

Yes, $6.5 million. And that was as of ’09 [ph].

Houston Netherland – Natixis

Okay. Now, are there any covenants in place that would prevent you guys from selling your hedges to give your liquidity a little boost?

Gene Shepherd

Not that I know of.

Houston Netherland – Natixis

Okay. And then just a quick one here. Can I get a capitalized interest number for the fourth quarter?

Gene Shepherd

Fourth quarter, it’s 2,000 – it was probably – I will have to get that for you. Out of the top of my head, I don’t have the right hedge here in front of me.

Houston Netherland – Natixis

Okay then. Thanks very much.

Bud Brigham

Thank you.

Gene Shepherd

Thank you.

Operator

And your next question will come from the line of Kenneth Pounds with Nutmeg Securities. Please proceed.

Kenneth Pounds – Nutmeg Securities

Hi, gentlemen. Finally someone touched on a little bit what I think is one of the real key issues here and it’s, I think, aptly demonstrated on slide 49, which is oil pipelines and refineries. Someone else mentioned that there were some people shutting in because of the high differentials. I think it’s very critical that for everyone on this play and the valuations that you all would like to receive now and in the future and the recognition you deserve for your work here to receive good prices. How close are we to some of these proposed pipelines or alternative solutions that would help you all close the differentials?

Bud Brigham

Yes, this is Bud. I’ll just give a quick little comment, and Lance, he knows a lot – so much more about that than I do and he can answer your question a lot better than me. But just generally, my understanding of EOG, and Lance may add onto this, is that they were shutting, as you said, because of the differentials but also just recognizing that the oil prices were very low relative to probably their outlook over the longer haul. And given the significant amount of reserves and production capacity that they had there, they thought it would make sense to curtail their production and bring it back up and produce that out at a later date. But so, Lance may have more data on that.

Lance Langford

I believe they announced that they were going to bring it back on in first quarter of 2010 and –

Bud Brigham

Which is when –?

Kenneth Pounds – Nutmeg Securities

Well, the call is not about EOG. The call is about the differentials, and Canadians are having the same problem for a different reason. But how close are we to one of these pipelines that you’re looking for here on your chart?

Lance Langford

Well, basically, most of these pipelines that are on the chart are already constructed. Enbridge is going to have an increase in their capacity that they will have the capital investment completed somewhere in first quarter 2010 and that will be an additional 50,000 barrels a day. There are also all these rail stations. And what I was getting ready to say about EOG, they are building their own loading station, buying their own frames, and basically the cars so that they could transport their own crude.

And so I think what they’re doing is trying to lower that portion of the oil that has to be railed out, lowering that differential to as low as you possibly can. I think they’re doing a great job, and I think there is probably a dozen other companies doing the same thing, trying to get rail costs as low as possible. So, what portion that doesn’t make it via pipeline will go via rail. As far as the largest pipeline expansion as Enbridge, should be done first quarter 2010, there’s a whole bunch of other things in the works, both on the gas side and the oil side in this area. So there is really not a good timetable on those other expansions.

Kenneth Pounds – Nutmeg Securities

That really seems to be the key for you guys. I mean, there’s a lot of interest right now that you got differentials what they got down to 14 or something and now you said 8 or 8.50. And so, that really seems – it seems to be a real classic bottleneck situation here that’s really hurting you all. Second question, since you said you were 70% hedged in natural gas and you’ve gone higher since, but there are some people thinking that natural gas might go into the trees and stay there. There’s potential for more L&G coming to our shores. Have you considered shutting in some of your unhedged natural gas production or your higher-cost natural gas production?

Bud Brigham

Well, this is Bud. Maybe I’ll start with that. I mean, we share the concern near-term on natural gas. On the other hand, we did take – we’re seeing a rig response and we’ll see a supply response. In my view, you might see more volatility in natural gas if we have – clearly going to be a soft year this year, but as we get into next winter, it could be really soft as I know some are concerned it could. But as we get in to next winter, we’re going to begin to see the supply response. And if we have some cold weather, you could see strong gas prices in the winter.

But clearly, there’s a lot of supply out there that can be turned on with the rig activity. And so you could see a balancing out of the supply and demand, but with probably more volatility over time. As far as us shutting in gas production, I think it’s probably unlikely. 70% of our gas is hedged or maybe north of that. Our LOEs are relatively low relative to peers. I guess it would just depend – because we really hadn’t thought about it much, but it would depend on how low gas prices got because our gas production would still be profitable at probably lower levels than many operators. Gene, do you want to add anything to that? Okay.

Kenneth Pounds – Nutmeg Securities

Okay. And finally, you talked about selling as much as, well, I guess 100,000 acre selling 50% interest and 100,000 acres or more in your play. Do you have an internal number? It sounds like back of the envelope, are you looking for $75 million to $100 million or that sort of type number to make it worth your while to go through this process?

Bud Brigham

No, we don’t. It’s really – a lot of factors is found in the right partner in the right area. There are a lot of companies interested. And some are more interested in one area and some are more interested in another. I think the probability is it’s less likely that we’ll have one partner coming in for a big chunk of participation. It’s more likely that we’ll have one, two or three partners in different areas, maybe for 20,000 acres here, maybe 50,000 acres there, or something like that. And so it’s not that we’re going into this with a set target number or goal. It’s trying to optimize our value on the assets with the right partner, which means, of course, it will help us to optimize the value over the long haul if this one has a good partner in there.

Kenneth Pounds – Nutmeg Securities

Great. Thank you.

Bud Brigham

You’re welcome. Go ahead, Gene.

Gene Shepherd

Yes. Houston has asked a question about capitalized interest for the fourth quarter. And for the full year, capitalized interest was $4.8 million. For the fourth quarter, it was $1.4 million.

Bud Brigham

Any other questions?

Operator

Your next question will come from the line of Nick Van Bavel [ph], private investor. Please proceed.

Nick Van Bavel

Hello, Bud and Gene. It was a great presentation. I just had a question, I guess it’s really for Gene, about booking reserves. My understanding is SEC is amending their reserve recognition standards for the end of the year. And my question is, what impact is that going to have on your reserves and what impact would it have had on your 2008 reserves had those new rules been in place?

Lance Langford

This is Lance. And basically, those rules if they get passed, what they will do is, for one thing, our PV10 would have dramatically been higher because you’ll take the average price through ’08 and use that as your year-end instead of using the December 31 price, which was obviously low. So when you have that, you’ll have a higher PV10, which will give you more production on the tail-end of your producing reserves and also you’ll have more of your PUDs come in to play which will – are improbable, which you can’t report today. They will become PUDs next year, more of them will. And then you’ll also be able to document and report probable reserves also. So I think it’s going to be a better tool for the investors and it will be better for us to quantify the assets that the company has.

Bud Brigham

And the other factor related to that, which isn’t as much to do with the changing of our guidelines, but there will be more statistics, more wells out there with the 10 to 12 and even long laterals with 20 frac stages. So if they get enough statistics, then they will be more comfortable booking PUD to the level of a newer technology wells.

Nick Van Bavel

Yes. I guess my understanding was that they were specifically targeting, amongst the other changes they were making with regard to pricing, they are also specifically targeting, helping a resource play such as the Bakken to where you weren’t forced to book just neighboring locations. But Gene, if you can show that that was statistically accurate across entire region, you would be able to book much more of those probables into PUDs.

Lance Langford

That’s correct. This is Lance. So, instead of just doing the two offset PUDs, if you can show continuity to the reservoir and productivity of the reservoir, you can book more PUDs. And that’s exactly we’re at. I think that’s what it should be. I mean you should be able to try – our goal should be to try and actively reflect the value that we’ve proven up. And so hopefully next year, if everything gets passed, it will be a transition year, but it will be interesting to see the impacts on proved reserves and PV10.

Bud Brigham

And it could be a real inflationary factor on the reserves.

Nick Van Bavel

Yes, it seems like it would have an enormous impact on your reserves.

Bud Brigham

I think you’re right.

Nick Van Bavel

Okay. Thank you.

Bud Brigham

Thank you.

Operator

And your next question will come from the line of Kenneth J. Elliott [ph], private investor. Please proceed.

Kenneth J. Elliott

Good morning, gentlemen. How are you?

Bud Brigham

Fine. How are you?

Kenneth J. Elliott

Very good, sir. Well, Bud, first let me say, this is my first opportunity to call in. I’ve been a long-term shareholder and I want in all these era of negativity pay a professional compliment to your shareholder department. They have been very responsive in both written material and phone call. They have done a great job.

Bud Brigham

Well, good. Thank you.

Kenneth J. Elliott

Bud, let me direct this to you because I come from a little more of an energy experience with the practical level you might say. Your Q&A has been phenomenal. I want to reference, for everybody’s review and listening, two great articles. One, the Oil & Gas Financial Journal December 2008 with an excellent article on yourself and the company. And then recently, the part publication, $100 a copy, the play book, the Bakken Shale. Page 37, and I’m taking – I’m back up (inaudible). Going on the basis with the current Q&A has probably solved everybody’s mind, the fundamental question is simply this. Are we going to survive without the threat – or wait a minute I'll say it backwards. Can you navigate the company through this critical environment without worrying about qualified opinion from our auditors and some statement that were in near violation of our lenders’ covenants? I think that’s pretty well been answered adequately in my mind. I want to go a little long term and very positive. In the Bakken book, page 37, there is a Williston Basin resource inventory. You just take those figures if you’re still comfortable with them, discount 50%, and given the attention that the Bakken play is being given like in my area of California, which was similar to the – equal to the midway sunset – and correct me if I’m wrong, Bud, if these figures are still correct – are we not in an incredible strategic position long-term assuming we get through the short term?

Bud Brigham

Yes. And I don’t have that figure in front of me, but we do have slides that we’ve had in our Corporate Presentation head. When you look at the USGS assessment, this Bakken play will be the largest oilfield in North America in the last 40 years. I think you’re right. And you’d look at even at production and we’re so early in the drilling in the Bakken Three Forks play that already the production is north of a 100, and I think it’s 135,000 barrels a day. And you look at the North America’s largest oilfield at Prudhoe Bay is 315,000 barrels a day and on a significant decline. So it’s not inconceivable that in the next five to seven years that the production from the Bakken and Three Forks could exceed that of North America’s largest oilfield. So I think it’s going to be – and I think you make a good fundamental point over that time period, over the next five years. It’s going to be very important for our country, for our trade balance, for our energy security, and for the domestic industry.

So I think you’re exactly right, and you’re hitting on what we’re striving to do through this – once in a lifetime as far as my last time economic storm that we’re in, to manage our way through that such that we can be optimally positioned coming out the other side to capitalize on it. And Jeff was just reminding me another key point that’s relative to your larger point is that there is going to be so much option value because if those articles talk about there’s so much oil in place, and the option values over time whether it’s refracs, whether it’s increased density drilling. Of course, the Three Forks right below it; it’s just starting to be scratched, and then secondary recovery, CO2 (inaudible) pilot projects. So this is going to be a 20, 30-year play, and it is going to be of real importance domestically.

Kenneth J. Elliott

Two observation – well, one observation and one question. Recently, in the Oil &Gas Journal was a very small but specific comment saying that the Bakken play or Bakken Field is getting special attention by the current administration. Is that referencing a previous question that came up or statement about the pipeline bottlenecks, et cetera? Or is there further incentives planned for the Bakken?

Bud Brigham

I have not heard that, but I would be interested to see that. Some may think there is a real need. It certainly would be very beneficial for the country and for the industry, but I have not heard that. So if you find anything on that, I would love to see it.

Kenneth J. Elliott

I think I’ve sent that to Rob Roosa in the Oil & Gas Journal.

Bud Brigham

Yes. And unfortunately, Rob is not in here, but I’ll ask him about that. But we do know that the governors there of those states are very focused. The states of the political – politicians there are very focused and were involve through the alliance and other associations out there in supporting their efforts.

Kenneth J. Elliott

Well, of course, my State of California, Bud, has not been very complimentary to oil and gas. So you can understand why we’re in trouble out here.

Bud Brigham

Sure, sure.

Kenneth J. Elliott

One last thing is this. The current Q&A I think or hopefully has solved the issue of our survivability or violation of loan covenants. Having said that, given the potential reevaluation by the SEC in speculating on the common stock, isn’t this stock ridiculously discounted or having been shred as to the true potential value, or is there something out there that we’re not seeing?

Bud Brigham

No, I would agree with you 100%. I think management here believes that, and we’ve recognized our stock is undervalued. I think we’re buyers at this level.

Kenneth J. Elliott

Would management and the Board be of themselves considered buying the stock themselves or maybe you just answered it?

Bud Brigham

I’m speaking of myself. I would. I’ve been locked up, but I won’t be. So it’s something I’ll definitely be looking real hard at.

Kenneth J. Elliott

Sure. Well, once again, thank you very much. And just wishing you a good drilling and continue to be a long-term shareholder. Thank you.

Bud Brigham

Great. Thank you very much. I appreciate the call

Kenneth J. Elliott

You bet. Thank you.

Bud Brigham

Okay. Bye-bye.

Operator

There are no further questions at this time. This concludes the question-and-answer session. I would now like to turn the call back over to Mr. Bud Brigham for closing remarks.

Bud Brigham

Well, thank you. That concludes our call. I really would like to thank everybody for their participation in our call, and we look forward to reporting on our first quarter results. Thanks.

Operator

Ladies and gentlemen, thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. And have a great day.

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Source: Brigham Exploration Company Q4 2008 Earnings Call Transcript
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