Bud Brigham - President and CEO Gene Shepherd - CFO Lance Langford- EVP of Operations Jeff Larson - EVP of Exploration

David Heikkinen - Tudor, Pickering, Holt Ron Mills - Johnson Rice Pavel Molchanov - Raymond James Scott Hanold - RBC Capital Markets Monroe Helm - CM Energy Partners

Good day, ladies and gentlemen, and welcome to the first quarter 2008 Brigham Exploration Company Earnings Call. (Operator Instructions). I would now like to turn the call over to your host, Mr. Bud Brigham, Chairman, President and CEO. Please proceed.

Thank you, Lassie. Thanks to each of you for participating in Brigham Exploration Company's first quarter 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. Briefly, during this call, we're going to make some forward-looking statements to help you understand our company's results. In our company's SEC filings and the press releases that were issued yesterday, there are some risk factors that should be noted that might cause our actual results to differ from what we talk about today or from our projections. I encourage you to review our filings with the SEC. In addition, a copy of our company's press releases, as well as other financial and statistical information about the period to be presented in the conference call will be available on the company's website under the section entitled, Investor Relations at www.bexp3d.com. We've also updated and will continue to update our corporate presentation, which can be accessed via our website. It includes both our first quarter 2008 results, as well as our plans for the remainder of the year. Also, in the event you're following the Williston Basin/Bakken play, there is a map in the presentation that would be helpful to view, as we described accelerating drilling in the Mountrail County, North Dakota area. So I'd like to get started with some introductory comments, including providing you with a list of what we believe are eight key milestones to watch for, as our operational program progresses during the year. In June, we'll give you a review of our financial results for the quarter, following which I'll provide you with some more detail regarding our activity in the field. First, and most importantly, our Bakken play continues to deliver encouragement for our future growth. Both the recently released USGS assessment and the State of North Dakota's Bakken formation resource study estimated the tremendous quantity of oil in place to be recovered over time. We believe that, considering our current market cap, our acreage position in the basin, which as per yesterday's press release has grown by roughly 48,000 net acres, is potentially the most impactful position of any public company in the play. During our analyst day on April 18, we began laying out our plan to develop this immense resource, and thereby transform our company. And as we discussed during our analyst day presentation, when you step back and look at the big picture, the evolution of the Bakken play is, in some ways, comparable to where the Barnett Shale play was in 2004. If we're right, then we've got very exciting 10-plus years in front of us. As we've all witnessed in the Barnett, developments will occur very quickly. Technology continues to evolve, and over time, our ability to efficiently extract more oil out of the Bakken formation will be enhanced. As has been proven out in the Barnett, we think our drilling results and the economics we generate in the Bakken will improve over time. There is no question we're in the early stages of the Bakken transformation. Over time, we believe you'll see the following; first, our activity in the Bakken will accelerate. Of course, we're already seen an acceleration of our non-operated Bakken drilling, that will become more apparent in our financial results during the second half of the year. In terms of operated wells, we currently have one rig running continuously. But we think it's very likely that we'll add a second rig during the third quarter. Given this growing level of Brigham-operated activity in the Bakken Resource play, which will be augmented by a significant number of non-operated wells, we believe our results will become more consistent in predictable, even on a quarterly basis, over time. And I can tell you that we're looking forward to that. Second, our Bakken drilling in this phase positions us for a multi-year period of drilling with low finding costs, thereby generating substantial reserve and net asset value growth. Given current commodity prices, and given our current estimates on the economics of drilling these Bakken wells, which should improve over time, we believe we have the best opportunity we've ever experienced as a public company to grow net asset value for our shareholders. If we're right about the Bakken play being comparable to the Barnett in about 2004, we've got a lot of work in front of us, but it has the opportunity to take this company to a new plateau. Let me finish up my introductory comments with eight key milestones you may want to watch for, as we move through the year. First, it would certainly be an important milestone for us if we do pick up a second rig. Doing so would be a direct indicator of our rising confidence in the play, specifically in our visibility regarding the attractiveness of the economics. Key to this decision will be the well performance in our areas of Brigham-operated and third party-operated producing wells, as well as currently drilling or soon-to-be drilling wells. In the Ross Area alone, we've drilled three wells thus far, and will soon be spudding our fourth and fifth wells in an area, which we could ultimately drill over 100 gross or 42 net wells, assuming 640-acre spacing. Continued success in this area, and therefore, our decision to go ahead and pick up a second rig, would be a significant milestone for us. Second, our currently drilling North Stanley exploration test is an important benchmark. Success there could set up another developmental program, such as that we now believe we have in our Parshall/Austin and Ross areas. Assuming 640-acre spacing, and given that we control approximately 5,800 net acres in the Stanley area, drilling success with our Johnson well could lead to the drilling of at least nine net wells, double that on 320-acre spacing. Third, our Southern extension exploration test currently planned for August will also be very important, particularly since we have over 36,000 net acres in that area. We remain very excited about our Southern area, but for competitive reasons, we're not yet ready to disclose its location. Fourth, an important milestone will be the acceleration in our non-operated participation of the drilling in the Parshall/Austin area, where we control approximately 8,700 net acres. Almost on a weekly basis, we are receiving new well proposals or new permits on our acreage in this area. We expect this drilling to increasingly impact our performance, as we move through the second half of the year. As many of you know, this area is providing extremely high rate production and estimated ultimate recoveries, so meaningful activity for us in this area will be an important milestone. Fifth, a significant milestone will be our Mrachek completion west of the Nesson Anticline. Encouragement with this well, our first attempt to apply the newer technologies, enabling us to isolate the stimulations along the lateral, would be a major milestone for us. Our control of roughly 200,000 net acres west of the Nesson Anticline provides us with very substantial option value, should the newer technologies provide us the opportunity to unlock these wells. A sixth milestone to look for would be other incremental economic enhancers in the Bakken, such as, for example, the successful implementation of stimulation isolation, for example swell packers, over a long lateral. There are several long laterals with swell packers or cemented liners for stage fracking, either underway or planned. This is just one example; there will likely be a number of incremental advancements or improvements. Thus far, EOG deserves a great deal of credit for advancing the technology in the play, and our participation with them has been, and will continue to be, of great value. But all operators will contribute to the generation of operational improvements. As we discussed during our analyst day presentation, which is attached to our website, and which I encourage you to review, we believe our Bakken's Consortium, which is a cooperative effort with most of the major operators in the play, provides us with the excellent opportunity to enhance our economics by delineating additional operational improvements and advances. Seventh, and it's really a value multiplier, would be the opportunity for increased density drilling. We believe this is very likely, given that Elm Coulee is still being actively developed with, at last count, 16 rigs running, despite the fact that roughly two laterals have been drilled per section today. Despite the economically attractive economics, we and other operators are experiencing in the Mountrail County area, we are only recovering 5% to 15% of the oil in plays. Therefore, the drilling of more wells per section to produce some of these incremental volumes appears likely. The eighth and last milestone would be to watch for early success with our conventional drilling. If I was watching our company, I'd look for continued success with our active program in the Vicksburg. We are apparently off to a good start with our first two wells, and successful Vicksburg drilling will drive our quarterly production up, as we move through the year. In addition to Vicksburg, I would look to see if we have early success with our drilling program in Southern Louisiana. Clearly, our twin to the Cotten Land #3 should provide meaningful production for us later in the year, but I would watch our first three wells and our new six well Southern Louisiana joint venture. These tests should provide a good early indication of how that program is going. We believe our conventional drilling complements our Bakken drilling well, and we're glad that both are becoming very active. They should positively impact our production volumes and financial performance during the second half of the year. That's a summary of milestones that we believe to be important as we move through the year. There is one last thing before I hand the call off to Gene. We were, of course, disappointed that our non-operated production at Bayou Postillion had to be temporarily shut in due to flooding. This temporary loss of production negatively impacts our second quarter guidance, which obviously would have been higher with those wells online. Even without that production, which will of course return, our production in the second quarter should be roughly flat or potentially still high to the first quarter. Given that we should have three Vicksburg wells, our old South Louisiana production back online, and hopefully, some new South Louisiana production online, and of course, continuous Bakken production additions coming online, our third and fourth quarters should evidence the production response that we've historically seen during periods of active drilling in the field. So with that, I'll turn the call over to Gene to review our financial progress, after which I'll briefly provide more specifics on our operational performance and our plans for the remainder of the year. Gene?

Thanks Bud. For the first quarter, daily production volumes averaged 32 million cubic feet of equivalents per day above the guidance that we had issued for the first quarter. However, our Q1 production volumes declined 22% from those in the prior year's quarter. The decline in our Q1 production volumes were attributable to several issues, which were previously discussed on our year-end conference call. The lack of recent Vicksburg completions due to the fact that we laid down our Vicksburg rig in August of last year in order to complete the structural reinterpretation of our Diablo project area; the natural decline experienced in our Southern Louisiana Bayou Postillion production volumes; and the impact from our Granite Wash assets sale, which closed on September 1, 2007. The one issue that we've not discussed as thoroughly is our reallocation, beginning in November 2007, of a significant percentage of our drilling CapEx away from our Gulf Coast properties in favor of our Bakken projects, which, given their longer reserve lives, do not generally provide the first-year production impact as our Gulf Coast prospects. Of the $26 million of drilling capital that we spent in the fourth quarter of 2007, roughly $8 million or 29% was spent on our first three Bakken wells that came on production in the first quarter of 2008. Looking ahead to the second quarter of 2008, in February, we resumed our Vicksburg drilling, and so far, spud a total of three 2008 Vicksburg wells. Further, we are currently in the process of completing our Cary Estate #1, which was our recent sub in the Louisiana exploration well that we announced in new discovery in March, as well as our Bakken Manitou State well. At least two of the Vicksburg wells, as well as our Cary Estate and Manitou State wells, should positively impact our second quarter production volumes. Higher commodity prices more than offset the impact from lower production volumes and lower hedge settlement gains during the first quarter, resulting in a 2% increase in revenues, including hedge settlements, to $30.4 million. First quarter 2008 revenues were positively impacted by $8.1 million due to a 37% increase in pre-hedged commodity prices. These increases were partially offset by a $6 million decline in revenues, due to the aforementioned decline in production volumes, and a $1.5 million decrease in cash hedge settlement gains. Excluding our unrealized hedging losses, but including our settlement gains, average realized prices for the quarter increased by 31% to $10.52 per Mcfe compared to $8.06 per Mcfe in the prior year's quarter. On a per-unit basis, lease operating expense increased 49% to $1.03 per Mcfe in the first quarter of 2008 from $0.69 per Mcfe in the first quarter of 2007. Higher-than-anticipated work-over expense of $814,000, primarily associated with two of our existing producing wells, and the impact of lower production volumes accounted for the increase in per-unit lease operating expense. These factors were partially offset by lower operating and maintenance expense, and lower ad valorem taxes. On a per-unit basis, production taxes increased to $0.44 per Mcfe in the first quarter of 2008 from $0.02 in the first quarter of 2007. The increase in production taxes for the first quarter of 2008, from that in the prior year's quarter, relate primarily to a $1.3 million decline in high-cost gas production tax abatements, recognized in connection with our recent Vicksburg and Mills Ranch wells. General and administrative expense for the first quarter increased by 19% to $2.6 million from $2.2 million in 2007. An increase in employee compensation expense accounted for 74% of the increase in G&A expense, with an increase in audit and tax expense accounting for 16% of the increase. Our per-unit depletion expense increased by 14% to $4.30 per Mcfe in the first quarter of 2008, from $3.76 in the first quarter of 2007, the higher depletion expense was due to an increase in finding and development costs incurred in the second half of 2007, relative to that in prior periods. Our higher expenses contributed to a 6% decrease in EBITDA during the first quarter of 2008 and $24.4 million. Net income for the first quarter, excluding the impact of our non-cash hedging losses, was $4.8 million or $0.11 per share. Moving to the balance sheet, at the end of the quarter, we had $19 million outstanding under our senior credit facility, and $160 million of senior notes. In terms of our levered statistics, we ended the quarter with total debt to book capitalization ratio of 40%, and total debt to EBITDA ratio of 1.8-to-1. At the present time, the borrowing base stands at $101 million, with a spring borrowing base re-determination expected to be completed later this month. Recapping capital spending activity for the first quarter, exploration and development capital expenditures totaled $45.5 million, of which $31.2 million went to drilling expenditures; $9.7 million went to land expenditures; $1.1 million went to GNG activities; and the remainder consisted of our capitalized costs, and other property and equipment. In terms of funding, our 2008 capital expenditure budget that we announced in February, we believe that our forecasted discretionary cash flow in the proceeds from the Granite Wash asset sale that we closed last September, should fund the bulk of our announced 2008 budget. The proceeds from other asset sales and the incremental availability of its senior credit facility will make up any shortfall, and should provide ample cushion to weather any downturn in commodity prices. Further, we would expect to exit 2008 with a significant portion of this availability under the senior credit facility still in place. In our earnings release yesterday, we provided production guidance for the second quarter. In terms of our expectations for the quarter, we are forecasting for our production volumes to average between 30 and 32 million cubic feet of equivalents per day. As Bud covered in his introductory comments, our Q2 guidance assumes that we will lose roughly 2 million cubic feet of equivalents per day, having two of our three Bayou Postillion wells shut in for a portion of the second quarter, excuse me, 30 to 34, I'm sorry 30 to 34 million cubic feet equivalents per day. So, the midpoint would actually be 32 million a day. In conclusion, we have begun to see our substantial Bakken acreage position impact the company, with four wells producing, a fifth well completing, a sixth well drilling, and a minimum of four additional high-working interest Brigham-operated wells planned for the remainder of 2008. Further, with the Vicksburg, Sullivan C-38 currently producing to sales and the pending completion of the Sullivan C-39, and the Southern Louisiana Cary Estate #1, we have begun to experience the impact from the conventional side of our drilling program that we'd not experienced since August of last year. And what gets really exciting is the opportunity that we think we are beginning to experience of having both our unconventional Williston Basin activities, with its longer-lived oil reserves and developmental risk profile, complemented by our conventional Gulf Coast activities, with its shorter reserve life and gas-weighted exploration profile. We look forward to reporting back to you in August with what appears to be shaping up to be a particularly strong quarter operationally for both sides of our business. That concludes my remarks. I will now turn the call back over to Bud.

Thanks, Gene. Now, I'll give you an operational overview, though I'll keep it brief in order to leave plenty of time for your questions. I'll get started with the Bakken. As we announced, we had closed yesterday on the acquisition of leasehold covering roughly 48,000 net acres west of the Nesson Anticline. We are not yet ready to disclose the location of this acreage, but we purchased it from a private operator in the trend who, like us, grilled horizontal Bakken wells with older technologies. Obviously, we believe the drilling and completion techniques we and other operators are using east of the Nesson Anticline, and that we're currently utilizing in our Mrachek completion west of the Nesson Anticline, will significantly improve the well performance in these areas. We'll get the first indication of this once we have definitive results for the Mrachek well. But we also think it's very likely we will drill an additional horizontal Bakken well west of the Nesson Anticline, using the latest technologies later in the year. In addition to the Bakken, we see a great deal of potential for other shallower and deeper objectives, as evidenced by our Richardson/Red River discovery that we made last year, and which is currently producing about 150 barrels of oil per day. We're currently drilling our offset to the Richardson, which should be down in the next few weeks. So we believe that other objectives will prove profitable for us on our growing Williston Basin acreage position. As a result of our new leasehold acquisition, we now control almost 200,000 net acres of leaseholds west of the Nesson Anticline in western North Dakota and Eastern Montana. To the east, in Mountrail County, North Dakota and the surrounding area, we control over 88,000 net acres. In total, we are now approaching 300,000 net acres in the Williston Basin, given that additional leasing is currently underway. Now, moving to Mountrail County, and initially there to the Ross Area, as mentioned in our press release last night, we are currently completing our fifth operated Mountrail County horizontal Bakken well, the Manitou State 36 #1H. This well is about one mile northeast of our Ross Area Hynek #2 1H, and about five miles northwest of our Ross Area Bakke well. We will be fracking the Manitou in the next several weeks, and therefore, we should have results sometime in late May or early June. In the next two months, we'll spud our fourth and fifth Ross Area wells back to back. Given that we control over 27,000 net acres in the Ross Area, and that we can drill over 100 gross or 42 net wells on this acreage, assuming 640-acre spacing, double that, if the area is ultimately developed on 320-acre spacing, this area would likely be a focus area for us, should we pick up a second rig during the third quarter. After we drilled the Manitou State well, we spudded the Johnson 33 #1H in the North Stanley area. We control about 5,800 net acres in this area, which is bracketed to the west and northwest by Fidelity and St. Mary drilling rigs and permits, into the east and north by the currently drilling EOG Clearwater and the permitted EOG Vanville location. Although shows are not definitive, we'd rather have them than not. And the Johnson well is currently drilling with very good shows in the lateral section. We expect to have results on this key well in June. As I previously discussed, success in this area would be an important milestone, given that we could drill over 13 net wells in the North Stanley area, assuming 640-acre spacing, double that if 320's are viable. Also, with success, if we do pick up a second rig, we would rill at least one offset here later in 2008. We now plan to commence our first South extensional test in August. For competitive reasons, we're still not ready to disclose where this position is, but we do control over 36,000 net acres, and could drill over 56 net wells there, assuming 640 acre-spacing. Moving to the Parshall/Austin area. In this area, we are benefiting from the fact that EOG, Whiting, Hunt, Hess and Murex are all picking up the drilling pace. We control about 8,700 net acres in our updated Parshall/Austin area, as shown on our corporate presentation. Assuming 640-acre spacing, we could ultimately drill over 13 net wells in this area, and of course, double that if you believe the area will be developed on 320-acre spacing. During our analyst day presentation, we compared this area to Elm Coulee, in Eastern Montana. And if you review that, you'll understand why we believe it's likely this area will also have at least two laterals drilled per section. Specifically, near-term, we will have impactful working interest in three recently permitted Parshall/Austin area EOG wells that are adjacent to recent high-rate Bakken discoveries. Next month, EOG plans to spud the EOG Austin 25-35H, which is located in section 35 of 154 North/90 West. We will have a 25% working interest in this well, which is a south offset to EOG's Austin 8-26H, which apparently produced at an early rate of 3,060 barrels per day. One mile to the southeast of this well, we will also have a 25% working interest in the EOG Wayzetta 13-01H, which is located in section 1 of 153 north/90 west, and which EOG is currently planning to drill in August. About four miles west of these wells in section 31 of 154 North/90 West, EOG has permitted and plans to drill the Austin 22-31H. We will also have a 25% working interest in this well, which they expect to spud in October. This well is the east offset to the Murex Jacob Daniel 25-36H, which is located in section 36 of 154 North/91 West. The Jacob Daniel was reported to be producing about 750 barrels of oil per day, after having already produced roughly 17,000 barrels with a reported estimated EUR of over 1 million barrels of oil. As we discussed in our press release last night, we also have interest ranging from 1.6% to 12.5% in five sections offsetting EOG's three discoveries drilled in sections 2, 3 and 9 of 154 North/90 West. As reported by EOG, these three wells were also strong; apparently producing around 2,000 barrels of oil per day initially. So in summary for the Bakken, our operated rig line is continuing, while the non-operated activity, particularly in the Parshall/Austin area, is accelerating. Potentially adding a second rig in Q3 would obviously further accelerate our Bakken activity. In addition, we have added substantially to our acreage position, providing our shareholders with additional potential option value to be realized over time provided our utilization of the newer drilling technologies can generate improved economics to the west of the Nesson Anticline. Moving very briefly to the Mowry of the Powder River Basin, we recently fracture stimulated the Krejci, and are currently testing the well. Until we have some definitive results, we don't believe it's appropriate to discuss it, but we should have results in late May or early June. I should also mention that we're pleased to see other operators pursuing the play; in particular, EOG is evidently drilling a horizontal Mowry well in the Northwest part of the basin, so that's good to see. Moving to our conventional projects, starting with the Vicksburg, after an eight-month pause in completing Vicksburg wells, our drilling there has kicked off right, with our second apparently successful 2008 Vicksburg well. The first, our Floyd Fault block Sullivan C-38 was still cleaning up at an early rate of about 3.2 million cubic feet equivalent per day. So that looks like another very good well. Our second Vicksburg well, announced yesterday, found roughly 137 feet of pay in the Home Run Field. So it also looks to be a nice producer. We should have this well completed in about two weeks. Both of these wells will only partially impact our second quarter production, but should fully impact our third quarter, as should our third Vicksburg well, which is currently drilling. Last, for our conventional plays, I will briefly move to Southern Louisiana, where we're pleased to be kicking off that program as well, with two relatively shallow, low-risk amplitude-related tests that we really like as part of our six-well joint venture. Importantly, in July, we plan to spud our twin to the Cotten Land #3, which produced at initial rates of 27 million cubic feet a day, from 30 feet of sand and which, until it was recently shut in, was still producing over 13 million cubic feet equivalent per day. Our twin wells targets the 50 feet of pay right above that producing interval, which is yet to be produced, in order to accelerate our production there. This well should materially boost our production during the fourth quarter. That completes our operational review. In closing, this is a very exciting year for our company. It is apparent that our very substantial acreage position in the Bakken is beginning to impact our results. With our Bakken drilling activity continuing to ramp up and with our conventional program also renewed, with two to three new 100% interest Vicksburg wells online for the entire third quarter, and our high-quality South Louisiana program also kicking off, we expect to post strong operating and financial performance during the second half of the year. We look forward to reporting on these results. That concludes our call. I'd like to thank all of you for your participation, and we'd certainly be very happy to answer any questions you might have.

(Operator Instructions). And our first question will come from the line of David Heikkinen, with Tudor, Pickering and Holt. Please proceed. David Heikkinen - Tudor, Pickering, Holt: Just a question as you think about South Louisiana beyond your exploratory program, what are your thoughts about selling assets and redeploying that capital into the Bakken as you continue to have success there?

Dave, this is Bud. I'll start, and some of these guys may want to add to what I say. But clearly, that's an option for us, not speaking specifically to South Louisiana, but we have a diverse conventional inventory in the Texas Gulf Coast, South Louisiana, as you mentioned; the Anadarko basin in west Texas. So, that is an option for us as we go forward, but we don't have anything specific to talk about there yet. David Heikkinen - Tudor, Pickering, Holt: How much production would you want to have in the Bakken to get some balance then, where you'd feel comfortable, where you're generating enough cash flow that you'd sell something that's more conventional that would be a cash flow generator today?

Well, I'll start again, and we'll see what these guys say. You know, in my view, it's not just production, but it's visibility of the risk profile of that program. It's very apparent that we have a developmental program there that the visibility of that production and associated cash flow is very high, and that's going to be a big factor. And obviously, to have that visibility, you're going to have some history on the production that you've established thus far, so.

And I would just add that it's not so much production as much as just liquidity, what's our basket of liquidity like, and what kind of capital do we need to spend during for the remainder of this year, and in 2009 and 2010, to develop the opportunities we said we have in front of us? And so, how do you fund that? And cash flow is one source of liquidity, but there are other sources based on the availability under the credit facilities, certainly asset sales could be a source of incremental liquidity, as well. David Heikkinen - Tudor, Pickering, Holt: Okay. And then just a simple question; in your second quarter guidance, do you have an idea of your oil/gas split? Just a percentage?

It's probably just 70% to 75% would be gas, and the rest would be oil. David Heikkinen - Tudor, Pickering, Holt: Thanks. That was it.

And our next question will come from the line of Ron Mills with Johnson Rice. Please proceed. Ron Mills - Johnson Rice: Just a follow-up on David's last question. As you look out, obviously, you'll start to see some full-quarter impact from South Texas, and hopefully, South Louisiana in third and fourth quarters. How quickly, though, do you think the oil component up in the Bakken can start to ramp up, given you potentially are going to two rigs, and what looks like to be an accelerating non-operated program up there?

Well, Ron, this is Bud. I mean, it's kind of a difficult question to quantify, but you can kind of put the math to it. With our continuous rig line operated activity ramping up, we had said, I think, at the analyst day, that we were doing in April, I believe it was, about 480 barrels per day with the Bakken oil wells. And with that continuous operated rig line, potentially a second rig operated coming online in the third quarter. But independent of that, accelerating non-operated activity, particularly in the Parshall/Austin, and of course, in the Parshall/Austin area, where you're offsetting 2,000 and 3,000 barrel a day wells, a one-quarter interest in those wells can have a material impact on the production and cash flow. So you can model it as we can and say that, as you get into the second part of the year, that oil production up there should, particularly given current commodity prices, really contribute meaningfully to our cash flow. Did that answer your question enough? Ron Mills - Johnson Rice: Somewhat. I guess I'm trying to get a sense, if you have a 2,000 barrel a day well you have a 25% interest in, it helps a lot. But if you look at your exit gas/oil split, I would assume the 70% to 75% gas that you expect here in the second quarter will continue to go down. And just trying to get a range as to where you think your exit rate can be from a gas/oil split?

Yes, over time, clearly, our percent oil will go up with this activity in the Bakken. But it is going to take time, because near-term, we're going to be drilling, picking up our activity in the South Louisiana again after a pause from last year with our six-well program in South Louisiana. And of course, a major impact on our gas production will be the twin to the Cotten Land play that we're drilling in July. And that well will impact our fourth quarter, and we're targeting the 50 feet of pay right above the 30 feet of pay that came on at 27 million a day. So, that well should add significant gas production as well. So you're going to see growth in both areas in our view, in both the oil production and the gas production. I think long-term, we're going to become oilier, because the oil production that we're adding as long as I believe 30 or 40 reserve live oil production. And on top of that, you're going to see our conventional drilling in the gas plays, which is shorter reserve life, generally high rate of return, but a choppier production on top of this steady with one continuous rig running about 1 well a month coming online in the Bakken. So, providing this base of more consistent, predictable production additions in the oil play there. Ron Mills - Johnson Rice: Okay. Were you factoring in a second rig coming in when you had talked about having 16 Bakken wells drilled in your original budget?

No. Ron Mills - Johnson Rice: So, that activity would be incremental?

It would be, yes. Ron Mills - Johnson Rice: And then next year, it sounds like you would expect to drill significantly higher-level wells, somewhere in the 30 to 40 well range if you maintain two rigs?

Yes, it would be roughly. If we had two rigs in '09, then that would be roughly 24 operated rigs, roughly. Isn't that right, Jeff?

Roughly. But Ron, just to clarify, we'd like to see that acceleration in the second half of the year. But as it stands now, we're focused, the current plan is, and it's the budget that we announced back in February that assumes one rig running in the Balkan for the remainder of the year.

Yes, we're all just trying to give you heads up that it's something we're looking hard at, and we think it's likely we'll be picking up a second rig in the second half of the year, but it's certainly not budgeted yet. It's not funds. Ron Mills - Johnson Rice: Okay. And then one last one, just the Vicksburg area. How many wells are you planning on drilling this year, but how much of an inventory do you have if you wanted to maintain a continuous drilling program in that area?

And that's in the Bakken, Ron? Ron Mills - Johnson Rice: I'm sorry, in the Gulf Coast, the Vicksburg.

The Vicksburg well? You know, we did talk about, on analyst day, our Vicksburg inventory actually grew because of the success we had last year stepping up in that new fault block, we are up in that area, that proved up a number of new locations, proven and probable, combined with our new 3-D interpretation. So we went from 34 proved and probable locations remaining to be drilled to 53 proved and probable remaining locations to be drilled. And drilling five to six a year, we've got a multi-year inventory of projects there. So we've got plenty of depth in the Vicksburg program.

And then his question was how many do we have in the budget? And we have five Vicksburg wells in the current '08 budget, the announced the February budget. Ron Mills - Johnson Rice: Great. Thank you.

And our next question will come from the line of Pavel Molchanov with Raymond James. Please proceed. Pavel Molchanov - Raymond James: Hi. Good morning, guys.

Good morning. Pavel Molchanov - Raymond James: Sorry, if you mentioned this at the beginning, but is the CapEx budget the same as it was for the beginning of the year?

Yes. Pavel Molchanov - Raymond James: And given the trend of commodity prices, are you looking to perhaps increase that as the year progresses?

Certainly, and that's when we were talking earlier about our liquidity basket, obviously higher commodity prices above what we had forecasted back in late January have enhanced our liquidity basket. So that could give us some additional opportunity by itself to raise our budget in the second half of the year.

And as we discussed, we have the option to pick up a second rig in the Bakken in the third quarter. And obviously, doing so would require us to increase our budget for the year. Pavel Molchanov - Raymond James: And essentially, any incremental dollars in your budget, would that be entirely allocated to the Bakken? Or would you also look at some other areas?

I don't think we've really said. I mean, obviously, there would be a predisposition towards the Bakken. But that's a function of drilling success not only in the Bakken, but in Southern Louisiana and in the Vicksburg.

But at that point, we'd say that's the most likely. Pavel Molchanov - Raymond James: Okay, great. Thanks very much.

And next question will come from the line of Scott Hanold with RBC Capital Markets. Please proceed. Scott Hanold - RBC Capital Markets: Hey, Bud, when you take a look at picking up acreage, specifically kind of focus on Mountrail County, obviously, it's getting a little bit more difficult, but how much opportunity is there to pick up acreage, say, from privates or just landowners who may not be capitalized to handle the uptick in activity by some of the larger operators?

Well, Scott, I'll start, and Jeff may want to add to my comments. But if you look at the operators active out there, I mean, you've got a few smaller ones. But generally, it's the Whiting's, the Hess, the Hunt's, the EOG, of course, Fidelity; it's generally some pretty substantial operators. But some of the acreage that we have acquired has been from some small, private operators. So, there's probably some opportunities there. I think generally, the leasing is pretty much, for the most part, is done in the heart of Mountrail County, and the current competition is in extensional areas.

This is Jeff here. Just to expand a little bit, I think what you're probably going to start seeing, as Bud mentioned, I mean, the dust is really starting to settle on the leasing effort in Mountrail. We are still getting some traction, we are still picking up some incremental acreage, but I think you're going to start seeing a lot of synergies with JVs, with other operators in the area. And we're already in associations with a number of folks, as I'm sure some of the other industry folks out there. So I think you'll start seeing that type of traction as well out there.

But there are a couple of smaller operators, as you said, but they're a minority, I think. Scott Hanold - RBC Capital Markets: Okay. And then when you start looking at these sort of extensional areas, is it getting pretty active out there as well or would you be willing to get a little bit more aggressive without seeing results in hopes of getting acreage at a better price, and that sort of the results and technology will make those areas work?

Well, yes, it's very competitive. Everybody and particularly those of us that have been active in the play for a while are getting smarter every day and are better able to delineate the attractive areas. And so, yes, I mean, I think with each new bit of information, you kind of high-grade the areas that you want to target. Jeff, do you want to add anything?

I would just say, we talk a lot about Mountrail and also the west side of the Nesson, but I would also keep an eye on Eastern Montana. We're going to shoot some 3-D data there late this year, and you'll see us drill at least one Bakken well in Eastern Montana. Scott Hanold - RBC Capital Markets: Okay. You talked a little bit about turning to sort of production growth. I know you all haven't really reached out to the end of '08 with some hard numbers yet, but Bud, you sort of made the comments that results over time will become more predictable, and that we should start to expect to see some production increases, typical of when you guys really started to ramp activity. Can you sort of just kind of walk us through some just sort of thoughts on seeing what kind of growth rates, could you do 15 to 20% growth in each quarter, like when you look out at 3Q and 4Q? And what things should we think about in terms of modeling this and setting expectations for the growth here this year?

Well, yes, let me take a shot at that, Scott. I mean, as we allocate capital away from the Gulf Coast towards the Bakken, that's a big factor. Obviously, we're fighting those Gulf Coast decline rates. And we've done a lot of analysis looking at the productivity of our Bakken spending versus the Gulf Coast. And generally, if you look at some middle of the road Vicksburg well, that well in the first year is probably twice as productive per dollar of CapEx from the standpoint of production generated as one of our Ross Area Bakken wells. So, it's really hard to talk about production growth when we're in this transition period and where we're migrating more of our capital away from the Gulf Coast towards the Bakken. So, I mean, there's probably not a lot more that we can say about it. Obviously, as we spend more and more capital in the Bakken and the Gulf Coast it becomes a smaller piece of our spending, then those declines won't be as significant. And I don't see us, and I don't know if Jeff or Bud, over time, I don't think we're going to leave the Gulf Coast, but at some point in the future, we'll reach some equilibrium in terms of our Gulf Coast and Bakken spending, and then going forward you won't have, you'll be fighting these factors, and you'll have a better sense on production growth.

Just one other factor that we're all aware of is of course, with oil prices where they are relative to gas, that's one thing, the relative production, and it's another thing, the cash flow resulting from that production obviously is greater today from the oil side right now. Scott Hanold - RBC Capital Markets: Right. So that's on the revenue side. And I'm just trying to get a handle on it, because as you know, when you kind of look at being in growth mode and sort of transitioning expectations and for the near-term quarters, I just want to make sure that we're at the right level. And Gene, just to sort of read into your comments, then, are you indicating kind of be careful about shooting for, say, 15%, 20% quarterly growth over the next couple of quarters? Obviously, beyond 2Q '08?

We're not really saying anything more than what we've already said in terms of our guidance. We're going to look out one quarter and we provide you with that guidance. But I will say, emphasize that we're in that transition period, and obviously, we're hopeful that there are a number of factors and one thing I didn't touch on earlier is we like to be in a position to increase our spending in the second half of the year. Obviously, that could have an impact.

Yes, and I think one thing that Gene is saying is really over a year or two time period we're in this transition, we're going to becoming more oily. And on a relative basis, more of our capital will be going to those oil drilling that generates less near-term production. This window right now, it's a little bit different in that we're resuming our Vicksburg drilling. We've got two wells coming online, and then a third, and then we've got South Louisiana kicking off. So I don't think we can say necessarily over the next two quarters. I would suggest doing bottoms-up modeling. You know, you've got a lot of history on the Vicksburg wells, and model that, and then however you want to risk the South Louisiana wells. And then, of course, that twin well coming online. So, it's going to near-term maybe look a little different than, as Gene was saying, over the next year or two as we transition, drilling more Bakken on a relative basis to the Gulf Coast. And it's definitely trading off a shorter reserve life for a longer reserve life and less near-term production for more long-term production.

I will say, Scott, obviously, we've done some of this modeling work. And we have our views in terms of what kind of production we're going to experience over the next 12 to 18 months. The big issue right now is just we're trying to be fairly conservative in terms of how we model our Bakken. And when you take those and over time, I think, we'll be able to hopefully with some continued drilling success. And I think we've been conservative, and hopefully, you will see that we'll be able our forecasting trend up to some degree, as we have more drilling success, and become more comfortable in some of these areas, particularly the southern extension in Stanley and results west of the Nesson.

That's right. And you look at the Ross Area, we're completing our third well in the Ross Area, and you have the Fidelity well to the south of it. But you've got the third well, and then we'll have our fourth and fifth wells in the Ross Area back-to-back coming up. So we're going to a have a lot better data that projects, that we will be able to forecast the productivity there.

But it's such a wide range of outcomes when you think about those areas and how early it is and how little drilling there has been. And certainly, we've done very little. And so, I would think later in the year, we will have drilled enough wells that maybe we can certainly start to have a better sense that's bracketing the range of outcomes in those areas, and being more effective and be able to come back to you with guidance for the Bakken that will be more meaningful, and therefore allow us to start providing guidance out beyond one quarter. But currently, that's just really hard to do, given where most of our capital, given we're transitioning more of the capital to the Bakken, and particularly the drilling we're doing in North Stanley in the southern extension and in the Mrachek well. These are all areas. It's early. Scott Hanold - RBC Capital Markets: Yes. Okay. No, I can appreciate that. And then, obviously, that's why I'm asking the question, we're in the same boat here. One last question. Bud, you mentioned that EOG is drilling in the northwest part of the Mowry. Roughly how far is that away from your acreage? And is there any difference in sort of that position they have versus what you all have?

Yes, it' a long way away. I mean, it's up on the Northwest side of the basin, maybe about 50 miles or so. And in my understanding is it's a horizontal Mowry well. Other than that, don't know a lot about it, unless Lance, you or Jeff do?

Well, I was just going to add, this is Lance. Abraxas called me, and they're committed to drill two horizontal Mowry wells.

And there are some private operators. We are seeing a little more activity out there by other operators, so that's a good sign. Scott Hanold - RBC Capital Markets: Okay. Thank you.

Thank you.

And our next question will come from the line of Dan McSpirit with BMO Capital Markets. Please proceed. Dan McSpirit - BMO Capital Markets: Gentlemen, good morning.

Good morning. Dan McSpirit - BMO Capital Markets: If we could talk to point number six of you're very neatly laid out eight milestones here, it speaks to the use of newer technologies, specifically swell packers over longer laterals. I ask this question trying to get an answer on; what type of economic enhancements should we be expecting here, recognizing that EOG is the driver? I assume that there's some information-sharing going on?

Dan, this is Lance. It's pretty hard to give you a number to use on what incremental reserve and production number to see based on doing longer laterals with swell packers. Well, what we do know is that we believe that the swell packers are giving us better results than non-swell packers. So, the technology is evolving. You're now seeing people; and also, the tools are evolving, so that you can run the swell packers out further, and you can run more swell packer in one well bore. So what you're going to see, it's my prediction, is you're going to see a better economic return, because you don't have to drill the upper portion of the hole. You're going to get better stimulation over longer laterals. Dan McSpirit - BMO Capital Markets: Okay, perfect. And I expect this to be used or we should expect this to be used a bit more frequently going forward here after the initial test?

I think you're going to see that, and I think you're also going to see cemented liners. And that's going to allow you to do it over longer two sections. And so you'll end up having a lot more stimulation jobs over the laterals. So you might see as many as 20 stimulations along one lateral.

Hi, Dan. This is Jeff. Just real quick; we're also, on some of our non-operated business, the Hess and [Molit well] and the Headington [De Angelis] well, both are planned 1280s with swell packers. And they're imminent on when those wells are going to spud. So I think we'll get some good information on how other folks are doing with swell packers and 1280s in the real near-term.

And, you know, given that, Dan, what we're trying to do is we're obviously staying abreast of all these innovations and these proof of concepts, testing of these technologies, and we're looking out ahead at our wells and trying to be in position which wells, if we continue to get encouraged about this technology or that technology, which of our wells will we begin to apply these technologies to? So we're thinking ahead to the second half of the year that some of our wells to potentially implement some of these incremental technologies that are evolving out there. Dan McSpirit - BMO Capital Markets: Okay, indeed. Perfect. Thank you.

And our next question comes from the line of Monroe Helm with CM Energy Partners. Please proceed. Monroe Helm - CM Energy Partners: Congratulations on expanding your position in this incredible oil play. What's you all's read on the state of North Dakota came out with their estimate for the Bakken shale and the USGS came out with their analysis of 3 to 4.3 billion barrels. What's you all's read on what both those entities assume for the recoverable oil in place? Or actually, what you think the recovery rate is at their estimate for the original oil in place? I'm sorry.

You know, Monroe, Jeff or Lance may want to add to that, but we really have not. I mean, obviously, it's a huge amount of oil in place. And so, we haven't gone and critically analyzed their numbers and what they came up with. I mean, suffice it to say, those are big enough numbers that we've got a great opportunity there. And we like the fact that their assessments show that if you look at our acreage, We're in good areas based on their word. And so, I don't know, maybe some of our technical guys, who aren't in the room right now, might have a better call to make on that. Jeff, I don't know if you want to add anything to that?

We've seen, you know, and you've seen other folks come out with estimates on anywhere from 5% oil in place to 10% of the oil in place, potentially recoverable under current methods. One exciting thing I'd point you to, to our website is page 11, notice how Eastern Montana acreage are is viewed very favorably by the USGS report, as it is by us. I mean, we understand how the Bakken kitchen works and the thermal maturation lines. And clearly, our Eastern Montana acreage is also well within that window. So we see some significant upside on our 100,000-plus acres in Eastern Montana, as well. Monroe Helm - CM Energy Partners: Okay. Continental recently on their conference call had been booking reserves similar to you guys, kind of your mid-case 300,000 plus barrels per well. They're talking about the potential to improve that. Not only on current proved recovery, but also through the potential for the Sanish formation on their acreage. Is that perspective where you are?

Yes, we certainly think it is, Monroe. And there's no question in our minds; one, you are going to improve the recoveries and the technology is going to get better, and we're going to extract more of the oil that's in plays. But two, as you said, the Sanish, three-fourths, and the other objectives, but those are horizons that we're looking at. Jeff, do you want to add anything to that?

Yes, we're a member of several consortiums; one at Colorado State University. And we have those whole sessions looking at the Sanish right now. So we're very interested in the opportunities that are there. The Sanish is highly variable. It does produce Antelope Field, and it's basically a sandstone there. But it is variable across the rest of the basin, but it has been productive in other wells. So we're definitely intrigued by it, as we are by that whole Upper [Freeport] section leading to a potential fracture, natural fracture enhancement. I mean, its right against the hydrocarbon generating source rock. So it's a great place to look for oil and gas. And then as we look to our Eastern Montana acreage, we plan on coring a number of those wells. And we'll clearly core through that Sanish interval to help us understand the opportunity over there as well. Monroe Helm - CM Energy Partners: Speaking of the consortium, you guys are drilling or have a 14% net revenue interest in these three wells with the consortium, I guess, they're called the Headington Nesson State wells. Can you can kind of talk about what the purpose of that consortium is and what you all hope to learn from these three wells?

Well, this is Lance peaking. You can probably get answers from all the seven companies that are in there, get different answers. But to us, it's really actually proving as the uncemented liner with uncontrolled frac jobs. Is that more effective or is the swell packers more effective? So, the first two wells that we will complete we'll be analyzing, do we get a more effective completion with the swell packers, which we believe, and it will prove that. And then it will also help you with frac direction, stresses and strains, how to optimally size our frac jobs with our swell packers. So I think those are kind of the primary things. There's a whole bunch of other smaller things. Monroe Helm - CM Energy Partners: Number of intervals, potentially?

Yes, number of intervals, difference between swell packers.

Lots of things.

We'll be using them micro seismic, and we'll also be re-fracking the wells, and we'll be able to see, do you get a more effective refrac with the pre-perforated liners or with the swell packers or with both? And be able to see are you creating new fractures with those refractures? So there's a whole lot of stuff that you can get out this consortium. But I hope that we'll have a second, and maybe even a third to try and prove more things in the future, because what you see out there right now and you can talk to EOG, Whiting, all the biggest players, everybody has theories, and no one really has a lot of proof. Monroe Helm - CM Energy Partners: Okay. At the end of the year, the net present value reserves less of debt is about where the stock is trading at now. Can you remind us what price depth was used at the end of the year? I mean, the prices have changed a lot since the end of the year, so maybe you can tell us what those prices were?

You're talking about the SEC price? Monroe Helm - CM Energy Partners: Yes, the SEC PV10 number.

Yes, it's less than $7.10 per Mcf, and $96 a barrel. That's the SEC price tag. Monroe Helm - CM Energy Partners: Okay.

Monroe, adding on, I mean, we do have a slide, I guess, in the corporate presentation that addresses that, as you said, that we are treading pretty close to our proved NAV, and so you look at the Bakken opportunity, that you get that as a throw-in. Monroe Helm - CM Energy Partners: Yes, I'm just amazed that a lot of questions here relate to quarterly production numbers when the real story here is growth and asset values. And as some of the earlier players in the Barnett Shale found, people quit focusing on production numbers, and start focusing on asset values, and the production numbers came later. And that drove the stocks even higher when the production finally hit in. But early on, people couldn't get their arms around the asset value growth, and it looks like the same thing is happening with your stock, just my editorial here.

That's part of the opportunity. We're kind of transitioning to. We've got an outstanding opportunity. We believe, for maybe a 10-year period here to substantially grow net asset value here. And once the market becomes aware of that and convinced of that, then that transition ought to take place on our valuation.

Yes, and I think really the issue is we're still viewed as certainly a been a Gulf Coast company and we're transitioning away from the Gulf Coast towards the Bakken. Just based on the way the stock trades, it's apparent to me that production is still the yardstick. Whereas, over time, as we grow, our Bakken spending as that becomes a bigger piece of the business, then it will be more of a net asset approach to valuation.

That's part of the opportunity for investors.

So we're sort of in that transition period, there's still a lot of focus on production, and over time, that should change. Monroe Helm - CM Energy Partners: Okay. Thanks for your comments.

And this concludes our question-and-answer session. I would now like to turn the presentation back over to Mr. Bud Brigham for closing remarks.

Well, once again, I want to thank everybody for their participation in the call, and we look forward to reporting on our second quarter results.

Thank you for your participation in today's conference. This concludes your presentation. You may now disconnect. Good day.