Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Executives

Ben "Bud" M. Brigham - President, Chief Executive Officer and Chairman

Eugene B. Shepherd, Jr. - Executive Vice President and Chief Financial Officer

Jeffery E. Larson - Executive Vice President of Exploration

A. Lance Langford - Executive Vice President of Operations

Analysts

Subash Chandra - Jefferies & Co.

Scott Hanold - RBC Capital Markets

Michael Scialla - Thomas Weisel Partners

Ronald E. Mills - Johnson Rice & Co., L.L.C.

Steve Berman - Pritchard Capital Partners

Michael Jacob - Tudor, Pickering, Holt & Co.

Brigham Exploration Co. (BEXP) Q2 2009 Earnings Call August 6, 2009 11:00 AM ET

Operator

Good day ladies and gentlemen and welcome to the Second Quarter 2009 Brigham Exploration Company Earnings Conference Call. My name is Shikwana and I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will facilitate 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. Please proceed sir.

We'll resume momentarily. There has been technical difficulty.

Mr. Brigham, you may proceed.

Ben "Bud" M. Brigham

Thank you, Shikwana. Thanks for each of you for participating in Brigham Exploration Company's second quarter 2009 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 for during the course of this call, you can view our conference call presentation which can be accessed at the website www.bext3d.com. It includes very helpful information regarding our second quarter 2009 results, as well as our plans for the remainder of the year. We'll be referring to the slides in the presentation during our discussion.

During the call we're going to make some forward-looking statement 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 may use the terms probable and possible reserves and location which are unproved reserves that we do not include in our SEC filings. Please refer to page two of our cooperate presentation for a cautionary note to U.S. investors regarding the use of the terms probable and possible reserves and locations.

Finally, a copy of our company's press releases as well as other financial and statistical information about the period to be presented in the conference call will be available on the company's website, under the section entitled Investor Relations at www.bext3d.com.

Well let's get started. Our theme today is the transformation to an oil based resource play company. During the second quarter our oil revenues exceeded our gas revenues for the first time as a public company. In addition, we're anticipating our oil production volumes will grow to be roughly equal or may even exceed that of our six to one equivalent gas production volumes, during the third quarter.

We're evolving from a short reserve lot to conventional natural gas exploration company to a long reserved lot resource play oil company, with a huge multi-year inventory of Bakken and Three Forks locations. That's an indication of the debt and quality of our inventory. We now have an estimate of our reserves to be developed in our 35,200 net acre gross area of Mountrail County, where we believe both the Bakken and Three Forks reservoirs have been proven as commercially attractive. But the total reserve potential, for complete development, estimated at 66 million barrels of oil equivalent.

Of course, that does not include the potential reserves to be developed in our remaining 260,000 acres, such as the Parshall, Austin and Sanish field areas, nor does it include our Rough Rider area, less than an estimated decline where we drill our best Bakken well today, and where we control 100,000 net acres. We'll discuss these areas further, later in the call.

Now if you'll go to slide number five, you'll see our outline for the call today. We'll discuss the operating environment and the oil commodity advantage, our growing long reserve life high value oil production; we continue the improvement we're experiencing in well performance. And then update you on our activity in our Ross and Rough Rider areas. Following that Gene will wrap up our comments on our financial progress.

Looking back, our decision to defer and completing the three wells drilled late in 2008, early 2009 was the right one to make. We have seen all passes rebound substantially. At the same time, drilling and completion costs have come down 34% and are likely headed lower. And differentials in the Williston Basin year old from approximately $18 in December to about $9 in August. So each pay out that we've deferred until the current quarter is generating a substantially higher rate of return for our shareholders.

It's clear that we've acted in the worst part of the cyclone and we're just now beginning to drill and complete wells in the best part of the cycle, when costs are low and oil prices have stabilized and potentially positioned for further improvement.

As show on slide six and seven, you can see that the commodity advantage provided by oil in recent years, specially since 2006 has become even more pronounced today. In prior quarters, we discussed the fact that our six to one equivalent Mcf of our oil volumes was generating 50% more to roughly double the revenue of an Mcf of our gas volumes.

On slide seven, you can see that the six to one Mcf of our Q2 oil volumes generated 2.35 times the revenue of an Mcf of our gas volumes, which of course means that our 11 million cubic feet equivalent per day of oil volumes in the quarter based on the standard six to one conversion ratio, actually generated revenue equivalent to about 26 million cubic feet per day of natural gas.

In July it appears the oil commodity advantage wise, we estimate that our July oil volumes generated roughly three times the revenue of our six to one equivalent natural gas volumes. Given a large number of natural gas resource plays in the U.S. the potential impact of LNG shipments into the country and other factors, we believe it's likely that the commodity advantage for oil will persist for several years to come. This bodes well for our Bakken and Three Forks drilling programs.

As shown on slide eight, our guidance is for our third quarter oil about volumes to grow sequentially from the second quarter 2009 by roughly 35% which is about 73% higher than our third quarter of 2008 volumes. The main contributors to this production growth are the advancement in drilling completion technologies we're applying in the basin. We were the first operator to stimulate twenty intervals in the basin and with the anticipated completion of the Anderson, we'll be the first operator to stimulate twenty four stages in a long lateral of well.

Technological innovation is driving our initial rates. Our EURs and rates of returns are higher. As a result our Strobeck, Anderson and Figaro wells followed by our Brad Olson and BCD Farm wells are expected to meaningfully impact our company's production during the second half of the year. Further our non-operated Parshall, Austin and Sanish field wells will also continue to positively impact our production.

Slide nine illustrates our total company production on the traditional six to one equivalent conversion of oil to natural gas. Given that all of our quarterly oil sales over the last several years have been in excess of its historical six to one equivalency, given that oil was valued on a fourteen to one equivalency in Q2. And they were quickly transforming to an oil-levered enterprise. This chart is misleading when viewed as an indication of our motto for revenue growth.

Illustrating this in other way, our estimated Q3 oil production of almost 15 million cubic feet equivalent per day could potentially generate revenue equivalent to 30 to 45 Mcf per day of natural gas.

Our generated slide ten which shows our actual realized equivalency last quarter. Here we took our actual realized process for our oil and natural gas, inclusive of the transportation cost and differentials to calculate what our realized equivalency was in each quarter. This ties our production to the market value for the gas versus oil in the quarter in this effort a better illustration of our production as a motto for delivering growth and revenue and cash flow. It eliminates the skewing caused by out of branch historical six to one conversion as our oil relative to gas volumes growth.

The benefits of transforming to an oil-levered enterprise are evident on this graph. Our motto for cash generation has substantially more hostile today. Importantly, we're also replacing our shorter reserve life gas volumes with wells that should have an economic life in excess of 30 years for the long-term benefit of our shareholders.

So a transformation is happening at an optimal time, as shown on slide 11, the second quarter versus the first quarter in our history as a public company, in which our oil revenues exceeded our gas revenues. Given the growth, we're forecasting for our third quarter oil real volumes in current $70 per barrel oil prices, we expect to deliver stronger oil revenue in Q3.

As shown on the next slide, slide 12, our oil volumes grew to about 40% of our company's net production in Q2, using a six to one equivalency. Given our Q3 guidance, we expect our oil volumes to grow to about 35% sequentially to roughly 2,450 barrels of oil per day, which should be roughly 50% of our company's six to one equivalent production during the quarter. Of course, given the commodity advantage, this growth in our oil volumes will translate into a higher top line company -- excuse me, a higher top line number for our company.

Slide 13 illustrates the driver of this transformation. Our growing Williston Basin, Bakken and Three Forks oil production. Although we were hibernating during most of the first half of 2009, as you can see on slide 13, our Strobeck well which was completed in July is contributing meaningfully to a resumption of our oil production growth in the third quarter.

Not shown, but also likely to contribute particularly to our fourth quarter, our currently cracking 24 frac stage Anderson and 20 frac stage Figaro wells. Surely, thereafter our currently drilling 24 frac stage Brad Olson is direct offset to our 25 stage Olson well should also contribute fully to fourth quarter oil production volumes. After the Brad Olson, the BCD Farms may contribute to some degree to our fourth quarter volumes, but will largely impact of first quarter 2010.

As shown on slide 14 from a margin perspective, we're very well positioned to capitalize on this commodity advantage relative to our peers who are focused solely on natural gas resource plays. Given our very substantial acreage position centered in the core of the only large high quality oil resource play in the U.S. we are actually benefiting from the fact that there are five or six quality natural gas resource plays domestically. The growing natural gas supply with those resource plays are generating as compressed natural gas prices which of course is depressed the rig count and reduced service costs.

As shown on slide 14 although gas driven rig count is causing service providers to deliver lower costs to all benefit. Given that we utilize the same service providers to drill our oil wells. Those lower costs are providing us with very attractive margins; we think substantially superior to that about our gas focused peers. We are benefiting from this costs and commodity advantage arbitrage, and we expect it to continue for several years.

Now I'd like to make a few brief comments regarding well performance. As illustrated on slide sixteen, we have continued to see almost a well by well improvement in performance as we've advanced completion technology in the play. The biggest driver today has been the increasing number of frac stages. Our two most recent wells the Strobeck and Olson with 18 and 25 stages respectively appeared to be easily our best wells. And not just in terms of performance, but also in terms of their economics.

Slide number eighteen illustrates dramatically our operational advancements when applied to this point. In mid-July 2008, we were still completing short lateral wells and we saw our best results in the short-laterals when we went through 12 frac stages. In the short lateral were twelve stages our cracking was roughly 400 feet. We therefore believe we've proven in our areas that we can generate improved performance with cracking of at least sure as 400 feet.

When we looked at the long laterals with 25 frac stages, we were stretching out our frac intervals to about 475 feet. Given that we've already proven of fracing every 400 feet along the ladder is generating improved results. We're very excited about the currently completed Anderson. And the currently drilling Brad Olson wells, which both have roughly 400 foot intervals to impacts and therefore 24 total frac stages.

Ultimately, at some point we'll define what interval is too close such that we're not getting the economic benefit from an increasing number of track stages we try to enable. But clearly there remain substantial opportunity to improve well performance further through improved stimulations.

Slide nineteen shows our well by well production performance relative to reserves produced and the production curves are color relative to the number of frac stages, illustrating the improved performance as we've increased the number of frac stages.

It's important to note here that adding frac stages is relatively inexpensive as shown on slide eighteen they are crossing roughly $70,000 per stage today. And you can see that our more recent wells with more frac stages have already produced more reserves than the wells were substantially purest frac stages. Some of which were drilled a year or two prior.

The inset photograph also shows the dramatic difference in productivity of the newer technology wells. As we point out that we discussed frac stages quite a bit, as it's definitely biggest driver for our improved performance. However, there are other drivers, such as the type of profit utilized. Unfortunately, we still see some operators not increasing the number of frac stages and not using intermediate strength profits in our areas. And we believe both of which can lead to real underperformance.

Slide twenty shows just how well our new straw back Strobeck 34 discovery is performing, relative to our previously drilled Adix 3 course well in the same area. The Adix is an excellent well, but it is apparent to just drawback is much stronger that's estimate to the advances our operations staff continues to deliver.

Last regarding well performance, slide twenty one, is our updated block in a Three Folks economics block. We currently estimate that our 20 to 24 fracs stage long laterals are generating EURs of 500 to 700,000 barrels of oil equivalent per well. Given current cost, our estimated drilling funding cost would range between $315 per barrel with potential rates of return of 70 to over a 100%.

Now if you move to 24, I'll quickly update you on our Ross area in Mountrail County, where we control approximately 35,200 net acres. We believe this area is now proven for both the Bakken and the Three Folks, and as I said earlier, we estimate our reserves to be produced from both objectives at about 66 million barrels net to be EXT. That's assuming the drilling of Three Bakken and Three Folks wells per drilling unit which we think is likely.

However, if you assume two wells per unit for each objective, our net reserves to be developed here will be roughly 44 million barrels for all equivalent. In both cases, we're somewhat conservatively assuming long lateral average reserves of 500,000 barrels of oil equivalent per well and where short lateral wells are to likely to be drilled we assumed 300,000 barrels of oil equivalent wells.

Slide twenty five, shows our Ross area in the location of our 2021 barrel of oil equivalent per day initial rate Strobeck, Three Forks discovery. Slide twenty six, shows our current plan for Three Forks wells in this area in 2010. In slide 27 through 28 show what we believe to be the likely development of this area for the Three Forks.

Now if you move to slide 30 and 31; they illustrate that the Ross area is centered over the portion of the Basin with the biggest lower Bakken Shale. We believe that thicker shale interval is important given that the Bakken Shale where the kitchen has generated the hydrocarbons. And given that it's the source of the oil for both the Bakken and the Three Forks beneath it.

In addition, because the lower Bakken Shale is the thickest in this area, the separation between the producing intervals in the Bakken and the Three Forks is the greatest. We believe they are independent reservoirs with independent reserves in this area. The Continental's Mathistad well announcement to validate this conclusion. Particularly in our Ross area, given that the lower Bakken Shale which does try to separate the reservoir is roughly twice as big in our Ross area relative to the lower Bakken Shale in Continental's Mathistad area. We added a cross section to the presentation in the appendix that illustrates this.

In our view, the performance of our Strobeck and Adix wells appears to validate our belief that the Ross area may be one of the best, if not the best area for the development of the Three Forks.

On slide thirty two, you can see our currently completing Anderson well relative to prior wells. As of this morning, we've stimulated 20 of the 24 intervals in the long lateral Bakken well. But we should complete our last four and begin our flow back by early next week. As I mentioned earlier, we were the first operator to our knowledge to complete the 20 frac stages in the Basin and it now appears we'll be the first operator to complete the 24 stages.

Given the number of simulations and the length of the lateral we're fracing the Anderson has roughly the same 400 foot spacing we utilized on our 12 frac stage Carkuff well. The Carkuff produced at an initial rate of 1,234 barrels of oil equivalent per day and third-party engineers estimated the research for the well at 409,000 barrels of oil equivalent. But the Anderson, will have roughly double the reservoir exposed and hopefully double the frac stages that are part of them. We should have results to report on this well later this month.

Slide 33 to 36 illustrates the potential longer-term building opportunity presented here for the Bakken. Now finishing up our operations discussion with approximately 100,000 net acre Rough Rider area, West of Nesson Anticline, we're currently fracing our Figaro as shown on the map on slide 37. The Figaro is about five miles Northeast of Mrachek which produce at an initial rate of 727 barrels of oil equivalent from seven frac stages. We expect to commence our fallback at the Figaro within the next several weeks.

Other than to the north on the Rough Rider area we are drilling the lateral of our Brad Olson, a direct offset for our Olson discovery which continues to perform strongly as shown on slide 38. Our estimated 400,000 barrel of oil equivalent Ross area Carkuff well was previously our best Bakken well but the Olson is significantly outperforming it.

We are planning 24 frac stages for the Brad Olson relative to our prior Olson discovery which had 20 stages and commenced production of roughly 14,000 barrels of oil equivalent per day. We should be fracking this well in mid-September. Again, the same rig will move our and commence our BCD Farms about 10 miles to the Northwest later in the month of September.

As most of you know, -- excuse me that will commence later this month in August. As most of you know, we believe the Three Forks has very good potential in this area in part because we have a whole core in our Olson that shows all saturated up Three Forks. But also because other operators have recently drilled well to the Southeast of it with encouraging results given the technologies they utilized.

Lastly, regarding the potential reserves for our Rough Rider that area, we believe that while we delineated attractive drilling economics, we would like more data points before providing an estimate of the reserves to be produced in the area.

With that, I will turn the call over to Gene to review our financial progress after which we will be happy to answer any of your questions. Gene?

Eugene B. Shepherd, Jr.

Thanks Bud. Before we get into a discussion of our second quarter results, I would like to update you on several recently completed liquidity enhancing initiatives that had position the company to more fully benefit from the improved drilling result that we are experiencing in the Williston Basin.

These were significant initiatives had come on the yields out and had been positively impacted by a dramatic improvement in our Williston Basin drilling economics. The factors driving our improved Williston Basin drilling economics are as follows; by almost well-by-well improvement in initial rate in EURs that we are experiencing in our recent horizontal Bakken in Three Forks well primarily due to an increase in the length of a horizontal levers and the number of fracture stimulation stages that we're using to complete our well and an improvement in the following external factors: number one, the rebound in oil prices in December 30 2008, the 12 month oil strip was $49 per barrel versus an oil strip enclosed yesterday north of $77 per barrel. Number two; the significant price disparity between the oil and natural gas. In recent years, oil has traded at an meaningful premium to natural gas.

However, the recent strength in oil prices and the continuing downward pressure on natural gas prices has elevated the oil premium to natural gas even further based on near month prices roughly 17 to one and well above the six to one Btu equivalency. Number three, with dramatic decline in service costs, the decline in natural gas prices and the resulting decline in the natural gas rig rate has been a big factor in the dramatic decline in service costs that we have experienced over the last seven months.

Our AFE for a long lateral horizontal well at year in 2008 was $9.5 million versus an AFE for our currently drilling Brad Olson well of $6.25 million, representing 34% cost reduction. Number four, the decline in Williston Basin oil differentials. For December, our weighted average Williston Basin differential was $17.77 per barrel versus our differential for August of $9.12 per barrel.

Inclusion in the current environment, we are forecasting that typical Williston Basin horizontal well assuming strip prices and an EUR of 650,000 barrels of oil equivalent for our long laterals with 24 frac stages we'll would pay out in roughly 15 months and generating 92% of project return.

The first of our recent liquidity initiatives that I want to discuss with the $100 million equity offering that we closed in May. This was not an easy transaction to stomach and as the significant equity investment in the company have struggled with the idea of selling equity in the kind of depressed market that we experienced in the first half of 2009.

However when you take into consideration the huge net asset value creation opportunity that we have in the Williston Basin we concluded that the dilution was more than offset by the opportunity that we have in front of us. Based on the additional equity of capital the improved Williston Basin drilling environment and the improved drilling results, in June we went back to work in the basin. Our plans over the next 18 months are as follows; Number one, to complete the two remaining wells, the Anderson and the Figaro that we deferred the completion of early this year because of higher service costs, low oil prices and high differentials.

Of course, last month we announced the first of our three deferred completions; our horizontal Three Forks, Strobeck well at 2021 barrels of oil equivalent per day. Number two, to drill 12 Brigham operated horizontal wells roughly five East of the Nesson and seven West of the Nesson consisting of both Bakken and Three Forks wells. We are currently drilling the first of these 12 wells at Brad Olson well located West of the Nesson which offsets our first Olson well that are at 1433 barrels of oil equivalent per day in January.

Number three, to participate in numerous non-operated wells in Parshall, Austin and Sanish fields and lastly to carry out this 18 month CapEx plan while maintaining significant financial flexibility, exiting 2010 with our debt levels at or below where they are today.

The second of our recent liquidity initiatives which we closed in July was the extension of the maturity of our senior credit facility to July 2012. All five of the banks that had been with us over the last four year have re-upped and we've added to six banks that gives us greater financial flexibility going forward.

As a third of the somewhat less significant initiative after completing the equity offering in May we got more aggressive in hedging our oil volumes. Part of the equity offering we had 240,000 barrels hedged with $49.29 per barrel average oil price. Since the equity offering we've hedged an incremental 359,000 barrels with an average oil price of $60.63 per barrel.

With the recent strengthen oil prices as we bring on plan additional wells, it is high likely that we'll add to oil hedge portfolio. Completion of each of these initiatives as well as others steps that we had taken such as our ongoing consideration of potential joint ventures and conventional asset sales provides us with necessary financial flexibility to more fully expose our shareholders to the tremendous reserve potential that we get captured by the point over $170 million of acreage in drilling CapEx in the Williston Basin over the last four years.

This is the risk capital that has gotten us to a point where we are now entering a low risk development drilling phase of project development on 150,000 acres in our Ross and Rough Rider areas, immediately East and West of Nesson Anticline, where we intend to focus the majority of our capital going forward.

Moving to a brief discussion of our financial results for the second quarter, our daily production volumes averaged 27.2 million cubic feet of equivalents per day within the production guidance range that we had issue for the second quarter 2009. Our second quarter production volumes declined 15% sequentially from those in the first quarter and 10% from those in the prior year's quarter. This sequential decline in our Q2 production volumes was primarily attributable to number one the fact that we were hibernating during the second quarter and do not bring a significant operated well on to production during the quarter while we waited for the economics in the Williston Basin to improve.

And number two, the high production declines in our Southern Louisiana five wells that we estimate negatively impacted our Q2 production volumes by 2.7 million cubic feet of equivalents per day. Importantly for our revenues and cash flows, our order volumes continue to grow in the second quarter were at 28% relative to that for the prior year's quarters, quarter two about 1823 barrels per day.

As Bud has discussed, now that we have recently resumed our Bakken and Three Forks drilling in completion activity, we are forecasting our third quarter volumes to be up to 2450 barrels of oil per day, a 35% increase over that for the second quarter 2009 and a 73% increase relative to that for the prior year's period.

As far as our income statement is concerned, increased oil volumes and increased hedge several months were not able to offset the impact of lower commodity price and lower natural gas volumes during the second quarter; resulting in a 59% decrease in revenues including hedge settlements of $14.5 million.

Excluding our unrealized hedging losses, but including our settlement gains, average realized prices for the quarter decreased by 55% to $5.93 per Mcfe compared to $13.08 per Mcfe in the prior year's quarter. On a per unit basis, production cost increased 22% to $1.80 per Mcfe from the second quarter of 2008. Higher salt water disposal costs in compression rental expense were partially offset by lower production taxes.

General administrated expense for the same quarter decreased 13% to $2.3 million from $2.6 million in 2008. A decrease in employee payroll expense associated with our previously announced cost cutting initiatives accounted for the majority of the decrease in G&A expense. Lower commodity prices and lower natural gas production volumes were largely responsible for the 72% decrease in EBITDA during the same quarter to $8.4 million. Our net loss for the same quarter excluding the impact of our non cash hedging and inventory losses was $2.8 million or $0.05 per share.

Moving on with the balance sheet, at the end of the quarter we had $73.4 million of cash and marketable securities, $110 million outstanding under our senior credit facility and a $160 million of senior notes.

Recapping the capital spending activity for the second quarter, exploration and development capital expenditures totaled $4.3 million of which 3.6 went to drilling expenditures and $0.8 million went to land and G&G expenditures.

In our earnings release yesterday, we provided the production guidance for the third quarter 2009. As we have discussed given that the bulk of our drilling activity, reserve growth and production growth going forward will come from the Williston Basin in the future we will speak of our production volumes and oil volumes versus gas volumes. In terms of our expectations for the third quarter, we are forecasting our production volumes to average between 4667 and 5167 barrels of all equivalents per day.

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

Ben "Bud" M. Brigham

Thank you. And before we turn it over to questions, I'd like to mention a couple of events that will be participating in and hosting over the next couple of months. That might give us an opportunity to meet with you personally.

First we are going to be presenting at Enercom's 14th annual energy conference of 335, local time on Monday August 10th. That conference is being held at the Western Taper Center in Denver. The link to the webcast presentation could be found on our internet site at www. bxp3d.com. We are also very excited to announce that we are hosting an analyst and investor presentation from North Dakota on Tuesday September 22nd. The presentation will be webcast and you should look for additional details regarding the time and presentation link closer to the event. We look forward to see you at both of those events.

Now that concludes our call. I would like to thank you all for your participation and we certainly be very happy to answer any questions you may have.

Question-and-Answer Session

Operator

[Operating Instructions]. Your first question comes from the line of Subash Chandra with Jefferies. Please proceed.

Subash Chandra - Jefferies & Co.

Yes, good morning. The first question on the Figaro. Where or -- specifically how many stages might have been fraced already or is that in the very initial stages of doing so?

Ben Brigham

Yeah I'll let Lance answer it. We're about halfway through fracking that well, correct me approximately halfway through fracking that well.

Subash Chandra - Jefferies & Co.

Got it. Perfect.

Ben Brigham

It will take longer as we mentioned on the Anderson.

Subash Chandra - Jefferies & Co.

So a little bit further along on the Figaro then the Anderson.

Ben Brigham

Well on the Anderson, I mentioned we have done 20 stages out of 24 in the Anderson well.

Subash Chandra - Jefferies & Co.

That's right, okay. Any chance there's an update next week by Enercom?

Ben Brigham

No, given of that's Monday, I wouldn't expect any news about them.

Subash Chandra - Jefferies & Co.

Okay. And then could you remind me about your lease retention, sort of activity, what's required if any over the next in that 18 month plan?

Ben Brigham

Yeah this is Bud, I mean just in general we're fortunate that most of our acreage is a vast majority which is acquired in the last 18 months for two years and its predominantly five year lease old or three year lease hold for two years. So overall we're in really good shape, we do have a couple of areas that have some acreage we bought from other parties, and I know that we have been extending our acres. And we have been successful in those efforts. So I don't know if you want to add.

Jeffery Larson

And we are real pleased with our extension efforts in that area [inaudible].

Subash Chandra - Jefferies & Co.

Alright, okay. And final one, in the Q3 with the banks post performance for your equity I guess you had some of the new some of things resolved and some new terms out there by I guess the banks might be looking for -- looking to reduce the gas price forecast using and by $0.50 or so we're hearing from companies? Any thoughts there or any potential risk at all?

Eugene Shepherd, Jr.

Right in terms of prices, I think we probably have that risk on gas and on the oil side, we probably have some opportunity to hopefully find some holding in the way are today in October when the banks will be doing in the middle of predetermination see some increases.

We've been pretty aggressive in hedging oil volumes, now the upward moves so that should put up forward to some degree on oil prices to an extent. Oil prices get weaker from where they're today.

Ben Brigham

And we're even more hedged on our gas volumes that domestic on the gas volumes so that does provide some protection on the gas plant.

Subash Chandra - Jefferies & Co.

Okay great, good start. Thank you.

Ben Brigham

Well thank you.

Operator

Your next question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed.

Scott Hanold - RBC Capital Markets

Good morning guys.

Ben Brigham

Good morning.

Scott Hanold - RBC Capital Markets

You know Bud, I can kind of read into your thoughts as well Eugene's that it sound like really made that transition from a typical Gulf Coast exploration company to a research player it and in the Bakken. And I mean do you all sense going forward here the production was also going to be much more predictable for investors and can you also give a little bit color on volume past is there any risk that that comes down a little bit more where are we producing at this point time and how long is that field going to continue to be a significant part of the production base?

Ben Brigham

Yes, that was a good question. This I'll pass it off to Lance, he may want to add on to my answer. I think you can see that if you look at the Williston Bain oil production graph. I mean the opportunity that developed here is the opportunity that we are looking for and that the Bakken and Three Forks are providing very predictable and much more predictable production and reserve additions.

And given that now even on the fixed equivalent our production is going to be 50% oil, it's just going to become less of an issue with production guidance we believe for us. We're really displacing a short of reserve and less predictable therefore gas production with longer reserve loss and more predictable oil projects.

So yes that's exciting for us that transformation is underway and particular simply oil projects have 30 years roughly economic life. That's going to be beneficial in all those regards too. So, we're going to continue to become oilier as we go forward. Jeff or Lance you guys have any thing on Williston Basin?

Jeffery Larson

Yes, we've seen some declines and had operational problems and Tim has expanded on those in their conference call because they were impacted more than us that in the second quarter we get about 2.5 million a day I think you'll see some decline in and they continue on a more traditional declines of 30 to 35% decline on that volume?

Ben Brigham

And so gas production is becoming a smaller and a smaller percentage of our total company's production. We'll be less exposed to those kinds of, that kind of volatility.

Jeffery Larson

I just want to putout one thing is, the decline in volume was dominated by the -- that's ended up. We're working within Penn Virginia right now on a potential work over of that well. So we could see an actually see an increase in offset, some of the decline in third or fourth quarter.

Scott Hanold - RBC Capital Markets

Okay. And then you are focusing on the one Bakken here, your plans over the next 18 months that you might. Is that one of a single rig? And then can you elaborate on your thoughts of, what you think it is part of JV given to all the positive news flowing the potential increasing in the Bakken? What's your appetite to do some like that at this point?

Eugene Shepherd, Jr.

Yeah Scott maybe I'll start with that and these guys maybe want to add to what I say. The plan that we laid out which included in addition that the wells that have underway this year and we talked about that on the call includes current plans for 10 operated wells next year. And obviously we have the significant non-operated particularly in the Parshall, Austin Sanish areas to complement that.

That is all I funded with our capital availability, currently. I think that as we pointed out, the environment and as we talked about has inferred pretty dramatically. There is a lot of interest with the companies and our institutions willing to be involved in this one large quality oil resource domestically so I feel like there is given the discussions that we have underway that have very high probability. Then we'll bring additional capital to bear beyond what we played out of plan to the benefit of the share holders through joint ventures or other ways of financing our activity in the field under most

Jeffery Larson

I mean certainly we have an appetite to do more than the 12 operated wells. The 12 operated wells are in the bag based on the proceeds from the equity in offering and so we're actively and internally generate cash flow, but we're actively working on a number of initiatives; that will hopefully position the company to accelerate further, as degraded we could double that number of operated wells to 24 over the next 18 months as apposed to 12. I mean the acreage position we have added is huge and really we think just given the recent drilling result, that level of activity is justified.

Ben Brigham

Yeah I think the life things are trending up and we're helpful that we could have opportunity to potentially double that.

Scott Hanold - RBC Capital Markets

Okay. And that operated rig plan at this point is one rig right, I'm sorry the well count is one rig is that correct?

A. Lance Langford

Scott this is Lance. Right, so right now, just putting up we're going to stay with one rig when and if we get an industry partner to come in or a partner to come then the transaction will pick up the second rig, hopefully,

Ben Brigham

Hopefully later this year.

Scott Hanold - RBC Capital Markets

Okay. So its more sort of strategic timing times that you want to get it few wells more down there to kind of help prove up the concept of putting more energy gives the lot better economically, is that what your stating?

Ben Brigham

I think it needs, I mean the results recently I mean the level of activity, the increase that we're getting is picked up very dramatically. So it's not only industry partners we're talking the financial types as well, so

Jeffery Larson

I would think its really more Scott that we just have such a huge acreage position and so we can afford to bring in a partner on some of that acreage to accelerate and enhance the shareholders present value.

Scott Hanold - RBC Capital Markets

Can you give a little more color on what those industry partners look like are we talking large international major type companies or other, you know public independent domestic public companies?

Ben Brigham

Yes Scott I think its really a cross section, you've got, on the one hand you've got players in the Bakken and Three Forks to like we are positioned is centered in the core of the play and then like some of the extensional areas. Then you've got, you've got companies that are maybe in the gas shale plays that recognizably beneficial, they diversify into this one large high priority oil shale play and maybe have some financial institutions, as well that's interested in making investment in the play.

Scott Hanold - RBC Capital Markets

Okay. One last question, on your acreage, you have in the southern part of Texas, is any of that perspective for the Eagle Ford Shale?

Ben Brigham

Jeff go ahead.

Jeffery Larson

I'd say, some of that may be marginally but surely none of our major, none of our mix perspective there and most of our trios up in the middle, that is Gulf Coast so

A. Lance Langford

Not anything to impact Scott.

Scott Hanold - RBC Capital Markets

Okay. Alright, fair enough, thanks guys.

Ben Brigham

Thank you, Scott.

Operator

Your next question comes from the line of Mike Scialla with Thomas Weisel Partners (ph). Please proceed.

Michael Scialla - Thomas Weisel Partners

Yeah, good morning guys, just to clarify in your 5.8 million completed well cost on the 24 stage well, that's a hypothetical rate you're not forecasting that for the Anderson and the Strobeck didn't come in the play is that right?

A. Lance Langford

Yeah, Mike this Lance. Right now the AFE's that we're operating under 6.25 million completed well cost, our operations group goal is to be below six on those and we think if we had the potential to be in the 5.7 to 5.8 based on the bids and the closure that we're going on the work today.

Michael Scialla - Thomas Weisel Partners

Okay. And then, that dramatic reduction in the completed well cost, is that all due to deflation or are there any significant changes you're making that or say there, I know you talked about but, not comprising on the profit, I assume you're still using ceramic there or is there anything you're doing to reduce that cost?

A. Lance Langford

This is Lance again. So currently we're definitely going to change anything as far as the completions that we're doing are more detailed and more costly. But what we've done to offset that is by reducing the time to do it, reducing the time to drill well. We've also done a lot of turn key operations on portions of the work that I don't know a lot of people are doing out there right now, but basically, locking in cost but timing this month all together on turn key bid for the well.

We're not turn keying in the drilling contract, but we're trying to turn key is meaning the services and that motivates down to accelerate the time period on which they're done. But, we're definitely not going to cut any corners on profits and the number of stages in frac if we go anywhere we'll probably be more expensive from here forth.

Michael Scialla - Thomas Weisel Partners

Okay. Was that correct on that you are using ceramic process?

A. Lance Langford

We're using ceramic process and increase in the number of stages.

Michael Scialla - Thomas Weisel Partners

Okay. And then, on the Three Forks, as that you had said in the past that your Anderson decoy took there looked a lot better than some of the other Three Forks wells, is there -- are you looking at a sweet spot, do you think in the Three Forks may be extended from the Adix through the Strobeck over the Anderson and if so how large could that be, I guess what I'm really after is are those wells representative, do you think of all of the Ross areas for the Three Forks?

Ben Brigham

This is Bud, I think I'm going to let Jeff answer question for the most part of it, we did include that the ice attack of the lower Bakken Shale, and we think that's really important in terms of the separation between the Bakken and the Three Forks.

Slide number 31, and when you look at that our Ross area that 35,000 acres is centered right over the thickest part of the Bakken. And I think in our view it's no coincidence some of the best Three Forks wells around that biggest portion of the lower Bakken Shale. And Jeff might want to talk about some of the region.

Jeffery Larson

Yes, just to expand on that a bit more, so I guess that lower Bakken showing in its spud size of business is extremely thick Ross area. And that was basically the deposition center of the basin doing a little Bakken. We like about that, I see that Bakken Shale has got really high COC content. So it's also a major own generating Shale and the upper body Shale.

And then directly below that we have the Three Forks, they are upper 30 to 40 feet and Three Forks is got a number of dolomite numbers in it that are pores. And so basically we have a top seal off we've got more Bakken Shale we've also got a source about you, except of ideal condition for charging that up for Three Forks in our Ross area, so we're very excited about it.

A. Lance Langford

Yeah we are very excited about, we like the comment on that, we are excited about what those guys are doing and that matter I said well was a real positive and we added a cross section to the appendix that shows the lower Bakken in our Ross area is almost roughly double the thickness of the lower Bakken Shale and that has had area. So the fact that confirmed that it's an independent reservoir, independent reserves clearly in our view confirms it for the Ross area.

Michael Scialla - Thomas Weisel Partners

That's great. One last one just for Gene. Why leaving so much cash on the balance sheet, why not pay down some debt here produce the interest cost on your and then just draw on the credit facility as you need it?

Eugene Shepherd, Jr.

We've got covenant in our senior nodes, which basically based on the very low commodity prices within the last year and obviously during the first half, we haven't been materially growing our volumes that limits us from incurring additional debt. But to the extent we pay down the senior credit facility until we see higher prices at the end of the year. Basically, that these prices are set on December 30th. And in combination with that, higher volumes from our drilling activities in the second half of the year, we don't want to pay it down and not be able to get it back. Clearly though, we don't have that kind of cash on the balance sheet and certainly we'll be using all the cash. But I think it's just that we are taking a very conservative operations in terms of liquidity.

Ben Brigham

Yeah. Those are the financial flexibility.

Michael Scialla - Thomas Weisel Partners

Yeah. Thank you, very much.

Michael Scialla - Thomas Weisel Partners

Thank you.

Operator

Your next question comes from the line of Bobby Green with Johnson Rice. Please proceed.

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

Hi guys its Ron Mills.

Ben Brigham

Hey.

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

Hi. Couple of questions, just a follow up on the JV that you mentioned, I know you looked at that earlier. This year and conditions are a lot better now than they were earlier in the year. And I think you were looking at Indian Oil acreage for potential partners at that time. That's still the case or would you be more focused on potential JV partners for some stuff? I'm just trying to get a sense of it? What's your appetite is?

Ben Brigham

Yeah, Ron this Bud. I think, clearly Mountrail County's off the payable as far as JV largely Rough Rider area is largely; I think that the areas which we're in discussions with JV and areas where we have, the extension that have new position in Montana, we think that is very attractively, we think the middle Bakken we have a 100,000 acres in Montana and most of which is the Southeast of Montana. But frankly the Bakken is very attractive there. But Bakken porosity is higher quality than some of the areas where other operators are drilling some Bakken wells.

We also have a new large issues there and we had -- three consecutive discoveries. Such a great multi-area; that also has some Three Forks potential, so that's an area we're looking to JV, some of the areas where we have most of our acreage is in great shape and we do have some smaller positions that are shorter term based on we might go into partner to accelerate the development of some of those as well.

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

Okay. And from the Rough Rider area you had some private and some other public common activity in the Three Forks on that side of year declines, it seems like that they have completed wells, a little bit differently. Have you hear anything on the ground in terms of well performance or what can you take away from a couple of those other Three Forks wells, what's in that next decline so its not very much data on that side?

Jeffery Larson

Yeah this is Jeff. And we were watching a bunch of the activity obviously around this and in Rough Rider we've got on core that had completed wells, east forward of our Rough Riders acres. But the path we want is really to start but we believe it's for the most increase, our acreage and that is still being, we have a aligning county is basically it's too eastwards in the McKenzie acreage and then

Southeast acreage.

And now our very attractively in the team work almost 500 barrels a day and use white sand and one single frac. We're very encouraged by that and just as a reminder we've also got as Bud mentioned we've got a whole core in the Olson well in Rough Rider show real good looking oil saturations in upper Three Forks. Really its definitely viable target in Rough Rider and we're encourage by the fact that others are helping us test it around out acreage.

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

Okay. And I guess, just to make sure. If you all brought in some sort of JV partner is that what you would mean to accelerate your activity from some kind of that one way program to two?

Ben Brigham

Well the answer will we'll continue to improve in an environment with oil costs are certainly, what we were modeling previously the success with that we're having with the drilling although it's a -- probably out performing what we modeled. So we'll continue to success and growth in our cash flow that can provide some incremental capital for us as well.

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

Okay. And then Gene just in terms of your revolver, you talked around with Subash a little bit about gas prices down, oil prices up. And to what extent will your completions here in the third quarter be able to benefit you as well from a borrowing base standpoint issue -- determination it seemed to me whether it's in the third quarter or by year end that your borrowing based starts to get quite a bit reduced from that oil activity in the Bakken?

Eugene Shepherd, Jr.

Yeah I mean this is obviously price we talked about price and the other is the volume and we deliver report with 630 report but until late October we get the benefit as any recent completion so, just a three wells that we the Strobeck well and the Figaro the Anderson we completed this Strobeck and Figaro and Anderson in the play, just a reasonable estimate of those volumes will more than offset to run off in production during the first half of the year or so and then beyond that obviously we hope to have results in late September on the Brad Olson and then --

Ben Brigham

Non-operated activity....

Eugene Shepherd, Jr.

Non-operated activity. One additional well that's in the budget that we haven't talked about we've got one Vicksburg in South Texas that's in the budget and we've started waiting on gas prices to proceed on that well. So I think we feel really good about the volume side of the equation. The hedges that we -- the hedging that we've done I think to some degree we are pretty close to being next step on our current oil well. Obviously we are bringing these recent completions on the wells that are currently being completed will have additional volumes to hedge but certainly the hedging activities we've done here recently will put a floor on prices. We had a floor in place on gas prices we've since put a floor place on all prices. I think as far as the November predetermination we feel we're in good shape.

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

All right, great guys. Thank you very much.

Ben Brigham

Thank you, Ron.

Operator

Your next question comes from the line of Steve Berman with Pritchard Capital. Please proceed.

Steve Berman - Pritchard Capital Partners

Good morning guys. Most of my questions have been answered. I do have one, any plans -- more and more and better and better wells coming out of the Williston to capture the gas that's associated with the oil production?

Ben Brigham

Yeah, thank you. That's a good question. Firstly, West of the Nesson we are getting that quick hook ups of the gas with the infrastructure out there so within a week or two we're getting for example the Figaro once it is online and of course with the Olson once it came on line we'll have that roughly in a couple of weeks. So it's not an infrastructure issue there. There has been an issue in Mountrail County but that's really improving. Lance, do you want to address that real quick.

A. Lance Langford

Yes, this is Lance. In the Ross Area where most of our activities been in the last year and will continue to be and we're -- have part of our gathering system laid when the process is completed on that. We hope to be going to sales on all those wells in the next 30 to 60 days. And so we after that point, we don't see any problem with getting gas to the market.

Steve Berman - Pritchard Capital Partners

Terrific. That was it. Thank you.

Ben Brigham

Thank you.

Operator

Your next question comes from the line of Michael Jacob with Tudor, Pickering, Holt. Please proceed.

Michael Jacob - Tudor, Pickering, Holt & Co.

Thank you. Good morning.

Ben Brigham

Good morning.

Michael Jacob - Tudor, Pickering, Holt & Co.

Just most of my questions has been answered, just two quick ones. I think you alluded to about in the prepared remarks on the benefit of going from 475 to 450 stages and sounded like there might be additional science to try little a bit tighter spacing. Can you elaborate on that? Is that something that you're going to try?

Ben Brigham

Well, I mean Lance certainly can give a better answer than I can. But just generally speaking, in my view that's where the opportunity is. It's in the stimulation and we haven't seen the breakup year, where the fracs are getting close together, but we're not seeing a significant improvement in well performances, tightened interval and therefore increased number of frac stages. Lance, do you want to further --

A. Lance Langford

Yeah, this is Lance. So basically we've seen as we increased the numbers of stages and reduced the distance between the Swell Packers yeah, we've seen almost a linear improvement in reserves which equate into economics and crude economic. So at some point we'll see that, start to bend over and as we tighten that spacing, it will become less improvement on reserves and you will have diminishing returns on economics eventually. But we obviously think that it needs to be tighter than 400 feet right now.

Michael Jacob - Tudor, Pickering, Holt & Co.

Okay. And just trying to calibrate, our well profiles hopefully with your internal modeling, maybe any sort of color you can give us on what the key factors looking like kind of hyperbolic decline as your laws are coming in, are they pulling a little bit harder overtime or is it -- I understand on one-to-one on the initial production but as your getting more weeks and more months of production, is this--

A. Lance Langford

Right now, this is Lance right now we have two wells with 20 stages that are producing and that will result in our and those are only two in the areas that are producing with 20 stages and 400 foot interval. So overtime we will get more data and more wells in those top curves will alter, but I think that if you look out the west side we have top curves for the range that we have been giving about 5 to 700 and you can look at that and see what the key factors and just try and replicate that.

Michael Jacob - Tudor, Pickering, Holt & Co.

Great, thank you.

Ben Brigham

Thank you.

Operator

Due to time constraint, we have time for one further question. That question is a follow up from the line of Subash Chandra with Jeffries. Please proceed.

Subash Chandra - Jefferies & Co.

Back to Rough Rider and Three Forks, speaking about the Three Forks, the Rough Rider area, how does that vary from Ross? Does it have the dolomite properties and as far as anything different there or at the field?

Ben Brigham

Yes, this is -- just one comment on that and then Jeff will give you further input but if you look at our Isopach of the Lower Bakken Shale you can see that the Lower Bakken Shale is roughly on the account of fitness to the Dunn County area. So in terms -- relative to basin at that time taking it slow at Bakken Shale is roughly comparable for the Dunn County modestly so a loss area but bodes well.

Jeffery Larson

Then again, trying to get a bit more in the Three Folks and Rough Rider again with w whole core, we're really interested in this upper 50 somewhat feet at the Three Folks that's the zone that appears the real change on the West Side and that's in the Rough Rider but also on the East Side. In the Ross area we have cores well and its a mixed technology that at Three Folks you get shared intervals and then you get dolomatic intervals, it's the dolomites that have got the processing enhancement and that's where the oil reside, but there are inter related cost and it's a pretty amazing basin its real flat, you can correlate a lot of these members from the East side to the West side, we see the same, dolomatic members on both sides of the anticline.

Subash Chandra - Jefferies & Co.

Yes, if recall, once you're on the West side, you can continue west, then it looks the same for quite sometime?

Jeffery Larson

Yeah we continue Westward as far as Eastern Montana is that your question?

Subash Chandra - Jefferies & Co.

Yeah, yeah.

Jeffery Larson

Yeah, we like to -- I mean the Three Folks is viable in Eastern Montana, you guys -- you continue pass our acreage in Eastern Montana, you reached the edge of the Basin and you start loosing the Three Folks, that upper Three Folks starts, but yeah in Eastern Montana, it's a viable target. I think if we definitely, you'll see us and Bud mentioned we've got this new Ghost Rider shoot I think you'll see us drill certainly a probably a vertical test in Ghost Rider to test the Red River which we're excited about and we'll probably close the Three Forks and then Bakken there kind of confirm my thoughts there and we like the upside, there is well for both Bakken and Three Forks.

Subash Chandra - Jefferies & Co.

And just a final one on the Ross side, any rate on the Ike well that actually you did -- that could have been well, but curious if any similarities to Rough Rider?

Ben Brigham

No, we might hold on Bakken somewhat we don't have a thought on that yet and maybe take a look at it.

Subash Chandra - Jefferies & Co.

Sure. Well then, thank you.

Ben Brigham

Alright thank you.

Operator

At this time, I would now like to turn the call back over to Mr. Bud Brigham for closing remarks.

Ben Brigham

Well, thank you. We want to thank everybody for joining on us on the call and we look forward to what should be a really exciting third quarter. Thanks again.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect and have a great day.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Brigham Exploration Q2 2009 Earnings Transcript
This Transcript
All Transcripts