Bud Brigham - Chairman, CEO and President Gene Shepherd - CFO and EVP Lance Langford - EVP of Operations

David Heikkinen - Tudor Pickering Ron Mills - Johnson Rice

Good day ladies and gentlemen, and welcome to the fourth quarter and year-end Brigham Exploration Company Earnings Call. My name is Angelic; I will be your coordinator for today. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Mr. Bud Brigham, Chairman, CEO and President. Please proceed sir.

Thank you, Angelic. Thanks to each of you for participating in Brigham Exploration Company's year-end 2007 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 are going to make some forward-looking statements to help you understand our company's results. In our company's SEC filings and the press releases that were issued yesterday, there are some risk factors that should be noted that might cause our actual results to differ from what we talk about today or from our projections. I encourage you to review our filings with the SEC. In addition, 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 fourth quarter 2007 results as well as our plans for 2008. Also in the event you are following the Williston Basin Bakken play, there is a map in the presentation that would be helpful to view as we describe the accelerating drilling in that very active play. So let's get started. For BEXP 2007 was a year of record production volumes, revenue and cash flow. Most importantly our substantial recent, long term investments in resource play acreage and 3D seismic began to pay dividends in 2007, highlighted by drilling successes in the North Dakota, Bakken play where we now control over 240,000 net acres. I believe that in subsequent years with the benefit of hindsight we'll look back on 2007 as a very exiting year of transition for our company, possibly even as an inflection point proceeding a period of exceptional growth in net asset value creation for our shareholders. Although the best is likely in front of us, I'd like to review our accomplishments during 2007, including 217% reserve replacement with low production cost and high present value reserves added at a total proved finding cost of $3.88 per Mcfe. Our production costs were low, driving superior margins in 2007. A major contributor was our 12% decrease in lifting an operating expense to a very low $0.71 per Mcfe. And partly as a result our cash gross profit per unit was $6.83 per Mcfe that's the second highest in our history to $6.88 per Mcfe in 2005. For the year, we achieved a 13% increased in 2007 average daily production to a record $41.6 million cubic feet equivalent per day. Our strong production growth and rising oil and natural gas prices drew a 20% increase in revenue, including hedge settlements but excluding unrealized hedging gains and losses to a record $125 million. A 24% increase in EBITDA to a record $106 million, a 19% increase in per share operating cash flow before changes in working capital to a record $2.03 per share. And over the last several years, we've assembled the most impact full acreage position given our size of any public company in the Williston Basin Horizontal Bakken play. We now control over 240,000 net acres in the Williston Basin Bakken play, including over 88,000 net acres east of the Nesson Anticline in Mountrail County and extensional areas, and this position continues to grow. In Mountrail County we've now drilled four apparently successful horizontal Bakken wells. And these and third-party operated wells are beginning to delineate the very attractive economics of the play. We believe that our recent accomplishments in the Williston Basin are the most important. Given the huge amount of attractively located acreage that was accumulated for a new era of more consistent long term growth for our shareholders. Particularly important near term is our acreage east of the Nesson Anticline where there has been of flurry of recently strong drilling results and where we now control over 88,000 net acres in Mountrail County and the surrounding area. Our acreage position here continues to grow and in this area we have now drilled four successful Bakken completions in four attempts. Now if you look at the entirety of our Williston Basin acreage, about 240,000 net acres and assume 640 acre spacing, this position provides us with the potential to drill over 375 net horizontal Bakken locations. And we currently have six net wells planned during 2008 to explore their acreage. Clearly with the success, our activity will accelerate but needless to say this is a huge position for the company of our size. A quick look at horizontal Bakken drilling illustrates why operators are enthusiastic about the plays economics. I will give two quick examples. First, assuming average gross reserves of 450,000 barrels of oil per well, $4 million to $5 million completed well costs and flat $80 per barrel oil prices, the play generates finding cost of $1.55 to $1.94 per Mcf equivalent and rates of return of 79% to over 100%. Second example, with the same assumptions, utilizing lower gross average reserves of 300,000 barrels of oil per well, the play generates finding cost of $2.34 to $2.93 per Mcf equivalent and rates of return 31% to 50%. To view it more simplistically again utilizing the above assumptions a dollar invested in a horizontal Bakken well appears to generate $5 to $6 in cash flow over an estimated 40 year production life. Of course today's oil price generates much stronger returns then net of my assumed flat $80 oil price. The economics of the horizontal Bakken play bode very well for our future providing us with the multiyear inventory of drilling projects with the potential for generating very substantial growth in net asset value. We believe this puts us in an enviable position today. Our growing Bakken position and the historical success we've enjoyed in our conventional plays such as the Vicksburg in South Texas has provided us with exciting opportunities for our next phase of growth. As we move forward, we'll continue to exploit our competencies in our conventional plays particularly in the Gulf Coast and the Anadarko Basin. Although drilling in our conventional play can generate volatile results particularly in the Gulf Coast which can also generate very choppy production responses. Over a multiyear time period that exploration has and we think should continue to generate strong rate of return on our investments. Given the volatility associated with conventional exploration it was back in late 2005 that we begin making the very substantial long-term investments and our unconventional plays in order to diversify our drilling inventory. We are very excited about the results of this initiative. We now believe we have the opportunity we were seeking to complement our successful exploration program with a repeatable, predictable and likely very strong rate of return unconventional drilling program. In terms of production it's also a new beginning, to some degree we are rotating from investing the largest portion of our drilling expenditures in short reserve that plays along the Gulf Coast, to now investing the largest portion of our drilling expenditures in high quality Bakken oil projects, which provide estimated 30 to 40 year reserve lives albeit generally with less near term production. This change, combined with the pause we've taken in our Vicksburg drilling, which has now resumed and our late year 2007 divestiture, has resulted in lower net production volumes for us as we commence 2008. We expect the resumption of our Vicksburg drilling and the new joint venture in Southern Louisiana combined with our continuous horizontal Bakken drilling to resume our historical production growth trajectory, providing us with more consistent sequential quarterly production growth as we move through 2008 and into 2009. Given the longer reserve lives associated with the Bakken production, we'll benefit from stronger production volumes in subsequent years, smoothing out our production growth profile. Over time, our growing resource drilling should provide more consistent and predictable production growth. In addition, our Bakken oil volumes also provide substantially greater cash flow per equivalent Mcfe of production, given the relative pricing for oil today. So although production is lower as we begin 2008, overtime our cash flows should benefit from this rotation into an oilier mix reflecting the higher prices provided today by equivalent oil volumes. When you consider our track record in our core conventional plays and our growing inventory and our promising unconventional plays. It's very apparent that we're entering a new and exciting era of long-term growth. 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 performance and our operational plans for the remainder of 2008. Gene?

Thanks Bud. For 2007 production volumes averaged to a record 41.6 million cubic feet of equivalents per day an increase of 13% over our 2006 volumes. In the fourth quarter of '07 our production volumes averaged 35.5 million cubic feet of equivalents per day, which exceed the mid-point of our fourth quarter 2007 production guidance that we had issued in November of last year. Our fourth quarter volumes declined 18% sequentially from our third quarter volumes and 9% from our fourth quarter 2006 volumes. The sequentially decline resulted from a combination of a pause in our Vicksburg drilling rig line in order to reprocess our Diablo 3D data and complete the structural reinterpretation of our Diablo project area. By the way we have since resumed our Vicksburg drilling and last month spud the Sullivan C-38. Number two, the natural decline experienced in our Southern Louisiana, Bayou Postillion production volumes and lastly the impact from our Granite Wash assets sale which closed on September 1st, 2007. Our fourth quarter 2007 revenue including hedging settlements increased by 12% to $29.1 million relative to that, in 2006 due primarily to higher commodity prices. Pre-hedged commodity prices increased 25%, which generated an additional $5.7 million in revenue. This increase was partially offset by $2.2 million decrease in revenue due to the afore mentioned decrease in production volume and $400,000 decrease in cash hedge settlement gains. Full year 2007 revenue including hedging settlements increased you 20% to $124.7 million. Full year revenue was positively impacted by $10.4 million due to increased production volumes and $10.4 million due to a 7% per Mcfe increase in pre-hedged commodity prices. Please note that the revenue figures I've just quoted excludes $2.8 million and $5.8 million of before tax non-cash losses associated with the mark-to-market value adjustments of our unsettled commodity revenues contracts for the fourth quarter and full year 2007 respectively. Our per-unit lease operating expense decreased 10% to $0.70 per Mcfe in the fourth quarter 2007 from $0.79 per Mcfe in the fourth quarter 2006. Lower operating and maintenance expense accounted for the decrease and was partially offset by higher workover expense. Lower compression rental, equipment rental and salt water disposal expense accounted for 56% of the per unit decrease in fourth quarter 2007 operating and maintenance expense. For the full year 2007 lease operating expense decreased 12% to $0.71 per Mcfe from $0.81 in 2006. For the year lower operating and maintenance expense and lower ad valorem taxes were partially offset by higher workover expense. Lower salt water disposal, chemical testing and treating and equipment rental expense accounted for 81% of the per unit decrease in full year 2007 operating and maintenance expense. On a per unit basis production tax for the quarter increased $0.30 per Mcfe in the fourth quarter of 2007 from $0.16 in the fourth quarter of 2006. Production taxes for the full year decreased to $0.17 per Mcfe in 2007 from $0.30 in 2006. These variances in production taxes for the fourth quarter and full year 2007 relate primarily to the timing of high cost gas production tax abatements received in connection with our recent Vicksburg and Mills Ranch wells. On a per unit basis general and administrative expense for the fourth quarter 2007 increased by 29% to $0.72 per Mcfe from $0.56 in 2006. The majority of the increase in the fourth quarter of 2007 G&A expense was driven by an increase in employee compensation expense. For the full year 2007, general and administrative expense increased by 3% to $0.62 per Mcfe in 2007 from $0.60 per Mcfe in 2006. Our per-unit depletion expense increased by 13% to $3.94 in 2007 from $3.50 in 2006. The higher depletion rate was due to an increase in finding and development costs incurred in 2007 and an increase in future development costs associated with the company's yearend 2007 proved reserves. If you include our income statement discussion EBITDA increased by 13% in the fourth quarter of 2007 and increase by 24% for the full year 2007. Net income for the fourth quarter 2007 excluding the impact of our non-cash hedging gains was $3.4 million or $0.07 per share. Net income for the full year including the impact for both our non-cash hedging gains and our ceiling test impairment was $17.9 million or $0.39 per share. Moving on to the balance sheet, at yearend 2007 we had $13.9 million of cash, $10 million outstanding under our senior credit facility and had a borrowing base of $101 million, and $158.5 million of senior notes. In terms of our leverage statistics we ended the year with a total debt-to-book capitalization ratio of 39% and a total debt-to-EBITDA ratio of 1.7 to 1. In terms of capital expenditures during 2007, the company spent a total of $126 million with roughly $97 million or 77% of this capital consisting of drilling expenditures, $18 million or 14% consisting of land and seismic expenditures and the remainder consisting of our capitalized cost and other property and equipment. In 2008 we intend to more fully benefit from our resource play acreage investments that we've made over the last several years, $103 million drilling budget that we announced in February reflects a 72% increase in Rocky's drilling capital to $41 million. In 2008 we anticipate drilling and our participating in 16 Bakken wells and one Red River well. The budget that we announced also has spending of an additional $10.5 million on land and seismic in order to continue to grow over our opposition in the prolific Williston basin. Overall for 2008, the Board of Directors has approved $134 million total capital expenditure budget, which represents a 6% increase relative to that in 2007. Of our $103 million of budgeted 2008 drilling expenditures, 71% will be spent on development prospects with the remaining 29% spent on our exploratory prospects. Based on the discounted commodity prices that we are using for forecasting purposes, our current outlook for 2008 has its funding between 85% and 90% of our drilling, land and seismic budget, out of a combination of discretionary cash flow and the proceeds from the sale of our Granite Wash assets that we closed in September of 2007. The CapEx budget that we announced for 2008 is not constrained based on our inventory of drilling opportunities. On the contrary, our inventory of opportunities in the Bakken, the Vicksburg, Southern Louisiana and Hunton would call for a substantially larger drilling budget. However given where our stock price is trading and our desire to not over tax our balance sheet. We have arrived at a budget that leaves us with significant additional debt capacity beyond we used in 2008. Outperforming our risk-to-cash flow forecast, our drilling results during the first six months of 2008 that significantly derisks a portion of our resource play acreage would allow us after mid-year to announce an increase in our 2008 CapEx budget. We look forward to update you on those plans. In our earnings release yesterday, we issued production gas for the first quarter 2008. In terms of our expectations for the quarter we are forecasting production volumes to average between 30 and 32 million cubic feet equivalents per day. Given that it is early in the evaluation of our Bakken acreage and the fact that we could experience a wide range of outcomes on our initial wells. We are electing not to provide a full year production forecast, but we'll revisit this decision as we move through the year. However beyond the first quarter of 2008, we expect to generate sequential quarterly production growth over the remaining three quarters of 2008. As Bud has already stated after having invested heavily over the last two years in the Williston Basin in land and several horizontal pilot wells, we are very excited about the Bakken reserve creation opportunities that we have in front of us for 2008. As we prove up our acreage and the associated economics in the Bakken, we have the opportunity to build out a substantial wedge of relatively low risk repeatable drilling locations. However, the reserve life of the Bakken relative to our shorter reserve life gas weighed Gulf Coast projects means that we do not get the near-term production impact with each drilling dollar invested in the Bakken that we get in the Gulf Coast. From a revenue standpoint, the higher Btu equivalent price for oil, partially mitigates this issue and positively impacts our resource play project economics. However, these benefits are not enough to overcome the high initial, but less predictable production rates that we were able to generate in the Gulf Coast. As we continue to build upon the success that we have had thus far in the Williston Basin, we feel that the Bakken's longer live oil reserves and the developmental risk profile will compliment our shorter reserve life gas weighted exploration activities in the Gulf Coast. We are very excited about the opportunity we have to put capital to work in both of these areas. That concludes my remarks, I'll now turn the call back over to Bud.

Thanks Gene. As I previously discussed, analysis of the Bakken shines a very positive light on our future. Drilling results in and around our acreage indicate the opportunity for very attractive proved developed drilling costs with excellent margins and strong returns on our drilling investments. The Bakken and the Vicksburg where we have a very long track record of generating strong returns, the focus of roughly two-thirds of our 2008 E&P CapEx budget. Looking back to last year, if some of you may recall, our foremost goal as we began 2007 was to generate attractive total proved finding costs. And we made progress in that respect, given that our 2007 total proved finding costs for our low operating costs and high value reserves was approximately $3.88 per Mcfe. I think it will become evident as I discuss our 2008 plan and opportunity we have, particularly in the Bakken to grow reserves that our result in 2007 are likely poor shadowing an extended period of meaningful high value reserve additions at low finding costs, providing us with the opportunity to generate accelerated growth and shareholder net assets value. So, now I'll move forward by updating you on our unconventional program beginning with the Williston Basin. We were ramping up in the Bakken with a continuous drilling program, while we continue to develop other resources plays. I encourage you to view the map attached to our corporate presentation to follow our Bakken discussion here. In recent years, we've made very substantial investments in the Bakken. One of the most exciting domestic onshore oil plays that we've seen in years. After numerous high rate discoveries in the area by other operators, our investments began to deliver tangible early results with our first three operated Mountrail County, North Dakota, horizontal Bakken completions. The Bergstrom Family Trust, the Hynek and the Bakke apparently confirmed commercial Bakken reserves on a portion of our very substantial acreage position in the play. Yesterday, we announced the completion of our fourth Mountrail County, horizontal Bakken well, the Hallingstad, which commenced production at an initial rate of 450 Boe per day. We're encouraged by the early results of the Hallingstad, which appears to be a strong producer performing quite a bit better than the Bergstrom, which is located just over a mile to the east. Approximately five miles to the west of the Hallingstad EOG completed the Austin 26 #1H, which was recently announced, as producing at an hourly early rate of 3,060 barrel of oil per day. We have a meaningful acreage position within a few miles of the Austin 26 #1H, including interest in two sections directly offsetting the discovery. The largest working interest, direct offset we own is immediately south of the Austin 26 #1H, but we're on a 25% working interest, and which is reportedly planned to be drilled later this year. Also nearby, we have a second 25% interest section two miles to the south and also east of the 26 #1H towards the original Parshall field wells, which EOG is also evidently planning to drill this year. As shown on our Mountrail area map in our corporate presentation, we control about 7,000 net acres in the Parshall Field area, including acreage offsetting EOG's three other previously announced high rate Austin discoveries, which are located about four miles to the north of the Austin 26 #1H in the same township. Provided the Parshall field area is developed on 640 acre spacing, this area would provide us with roughly 11 net wells. Double that, a 320 acre spacing is validated, which we believe to be more likely than not. Assuming potential reserves of 900,000 barrels per well as reported by EOG, our net reserve potential in the Parshall field area alone is 6.3 million barrels of oil equivalent, or 37.8 Bcfe and of course double that a 320 acres spacing is utilized. Given the accelerating drilling pace announced by EOG, Whiting, and other private operators and of course ourselves, we expect drilling in this area to meaningfully impact our production and reserves this year. We're now drilling the Manitou State 36 #1H at a current depth of over 9,000 feet. It's located about a mile to the east of Hynek. Later this month we'll use this rig to spud the Johnson 33 #1H in our North Stanley area. We believe this area, where we controlled about 7,300 net acres has many attributes in common with the Parshall/Austin area, including good porosity and excellent potential for some extensive fracturing. The North Stanley area is about 15 miles northwest and generally on trend with EOG's three Austin producers, which are located in the northern portion of 154 north-90 west. Following the North Stanley well, we currently plan despite an offset to the Bakke in April, after which in June we plan to commence a key well in an extensional area where we control about 36,000 net acres. Our aggressive pursuit of acreage in this extensional area was driven by our belief that this area also has many attributes in common with the Parshall/Austin area. We'll have more to discuss on this area later in the year. On that point as we look forward, as a company there is no basin domestically that we'd rather be in than the Williston Basin. The fact that we now control over 240,000 net acres in this oil laden province provides our shareholders with tremendous option value. For example, although potential reserve recoveries of 300,000 to 900,000 barrels per horizontal well is attractive and substantial these volumes represent only 5% to 15% of the estimated Bakken oil in place. Historically, the Bakken has experienced several phases of exploration and exploitation impacted by innovations and technology. As operators innovate and with continuing advances, there is no question that we will ultimately recover more of the oil and the formation. Further, as we and other operators acquire our 3D seismic and drill additional wells. We believe that plays targeting other producing horizons, some of which maybe drilled horizontally will be developed providing additional option value to be realized overtime. So summarizing for the Williston Basin, we expect to drill or participate in the drilling at least 17 gross wells or about six net wells in at least four different areas of the play this year. We are allocating about $48 million or 40% of our exploration and drilling capital budget to the Williston Basin. With continued success, we could potentially pick up an additional operated rig around mid-year and increase our budget. Given the apparently strong and economic attributes of the Bakken play and our over 240,000 net acres. This play has the potential to drive our growth for the next decade or possibly longer. Our unconventional inventory is not limited to the Bakken, we control roughly 66,000 net acres in the Mowry play of the Powder River Basin, where we drilled early wells providing us with both encouragement and frustration. Importantly, we successfully drilled and have run Swellpackers in our latest well, the Krejci 1-32H, which is scheduled to be fraced later this month. We should have results in April for this key well, and those results will determine how much future drilling we will conduct in the play. Lastly regarding unconventional plays, we continue to investigate other unconventional plays that we think could compete and compliment our existing inventory of conventional and unconventional projects. Moving on, our plan this year includes continuing to exploit our quality conventional drilling inventory and expertise along the Texas and Louisiana Gulf Coast as well as in Anadarko Basin in West Texas. Among our conventional plays, the Vicksburg has easily been our top performer over the last five plus years. The consistent high level of performance we've achieved there is despite the fact that we've aggressively drilled already proven but undeveloped locations. Our total proved reserves in the Vicksburg continue to grow, and as I mentioned our three year total proved signing cost for the low operating cost, high present value reserves in the Vicksburg was about $2.77 per Mcfe. Importantly, and as is fairly common when developing large complex fields, our recent drilling has highlighted additional areas beyond those previously identified for future development. Specifically, our successful step out wells in the Home Run Field added additional proved and probable reserves to our inventory. Combining those developments, with our recently reprocessed 3D seismic data, has yielded a new structural and stratographic interpretation indicating a quality multi-year inventory of locations. This should provide drilling opportunities for years to come. Our first 2008 test the Sullivan C-38 is currently drilling at a depth of about 10,615 feet. We have a 100% working interest in this well, which is being drilled in a most prolific fault block and offset three wells at each commenced production at rates of around 10 million cubic feet equivalent per day and each of which will ultimately produce over 10 Bcfe. So after a pause in our Vicksburg drilling, which created an eight month gap in our Vicksburg completions negatively impacting our company's, net production volumes late last year and during the first quarter of 2008. We now expect to resume our upward production growth trajectory in the Vicksburg. Over the years, Vicksburg has generated substantial free cash flow for our company, some of which has been invested in our growing resource play inventory. We expect Vicksburg to continue to benefit our shareholders in this respect during 2008. Beyond the Vicksburg, but staying in the Gulf Coast, we are very excited about our opportunities to extend the success we've enjoyed in Southern Louisiana. PetroQuest is currently completing the Cary Estate, which found about 26 feet of pay, and beginning in April, we'll drill five wells as part of our latest joint venture targeting primarily lower risk 3D seismic delineated prospects supported by strong seismic amplitude attributes. Although these are likely typical Gulf Coast shorter reserve life projects, we believe that it will provide the opportunity as we experience with our value Brazilin wells from quick payouts, high rates of return and meaningful free cash flow to compliment our drilling in our resource plays. Also in South Louisiana, in July we planned a spud the Cotten Land #5 essentially a twin to the Cotten Land #3. As many of you may recall the Cotten Land #3 is producing from 30 feet a pay with 50 feet of additional pay above the producing interval. That upper 50 feet is the pay we are going after with the Cotten Land #5. The 30 feet of pay in the Cotten Land #3 continues to perform as to commencing in March 2007 at an early rate of 27 million cubic feet equivalent per day and producing 8.1 billion cubic feet equivalent to-date, is still producing over 15 million cubic feet equivalent per day, pushing out our re-completion in the upper 50 foot pay interval. Given that this upper pay is thicker with comparable porosities and permeability this well should have a very positive impact on our production late in the year. While our production benefited from our very high rate value Brazilian wells late last year, our early 2008 production has been negatively impacted by the associated declines of these wells. Though they do continue to outperform expectations. We expect our five relatively low risk South Louisiana joint venture wells and our Cotten Land #5 to twin of the Cotten Land #3 to drive our Southern Louisiana production levels higher as we move through 2008. Finishing up our conventional plays later in 2008 after we complete the interpretation of our 180 square mile proprietary high-resolution 3D program in the Texas Panhandle, we plan to commence Hunton exploration test with substantial reserve potentials. We also plan to continue our efforts to expand activity in West Texas a product that has historically provided us with low funding costs and strong rates of return. In summary for our conventional plays inclusive of the Vicksburg, we'll invest about $62 million or 60% of our drilling capital budget to grow production and reserves. That completes our operational review. In closing while we deliver tangible initial results in our resources play inventory in 2007, I expect our operational and financial performance to be positively impacted in 2008 and subsequent years. Importantly we expect our growth in reserves and net asset value to become more meaningful and more consistent and predictable. Attributes that are very beneficial to public companies today. That concludes our call. I'd like to thank everyone for their participation; we very much look forward to reporting on our progress as we move through what should be a very exciting year. In the mean time we would be happy to answer any questions.

(Operator Instructions). Your first question comes from the line of David Heikkinen of Tudor Pickering. Please proceed. David Heikkinen - Tudor Pickering: Good morning. I wanted to step through your first quarter production guidance from the third quarter, call you expected to see growth now you are seeing a decline. Can you give us a breakdown of the regional production, Bakken Gulf Coast, Anadarko, West Texas that you had in the fourth quarter, and where you expect that to be in the first quarter now?

Yeah, David this is Bud. I'll start and these guys may want to add to what I'll tell you. I'll start with just some general comments. Part of it was the timing of our Vicksburg resumption. We thought that we spud that C-38 well earlier and obviously a 100% interest in a Floyd well. That's an impact full well in terms of production. So that's a big factor on the timing and on the gap, there's a drop in production and we've had these periods where we have gaps and wells coming online and its the nature of our conventional production in the Gulf Coast its very choppy on top and when we have eight month gap in our Vicksburg completions, obviously, we're going to see a drop in our production. But this time its compounded by South Louisiana, those terrific wells we brought online last year that despite the fact they were outperforming had some significant decline in near-term in production, but obviously drilling the Cotten Land #520 and the Cotten Land #3, that 50 feet of play relative to 30 feet that produced 27 million a day, we should have some very substantial volumes coming on there together with our continuous or our five joint venture wells that are in South Louisiana, not to mention the Bakken wells that are now beginning to contribute. So Lance or Jeff, do you guys want to add anything on that regarding David's question

I know that's kind of a general answer David, but does that help you a little bit? David Heikkinen - Tudor Pickering: Well, just trying to understand, in your last call you talked about showing growth in first quarter, now you're not. I understand you knew that you had the Vicksburg drilling timing and you knew you had these wells that were declining in South Louisiana. So just trying to reconcile between an expectation of growth and now an expectation of the sequential decline?

Well it's really timing. Obviously, if you don't have wells come on line, you just continue to see a decline and when you look we had 2 million a day of production that we sold later in the year. So you loose that then the decline in the South Louisiana and Vicksburg, if you combine those two that's 10 million a day there between those two. So, we had anticipated the C-38 coming online, well it's going to come online in the second quarter, so it didn't impact the first quarter, so it's a function of timing. David Heikkinen - Tudor Pickering: Okay, and then, on the Bakken, just wanted to go through the four wells that you've talked about from your January press release to now. The Bakke seems like it's holding in pretty well, 380 barrels per day on seven inch casing test to 310. But Hynek and Bergstrom have declined, particularly the Hynek declined considerably? Can you kind of walk us through what you'd expect for EURs for those three wells, now that you have -- some production history?

Yeah, Lance can answer that. Let me just say, we did point out or we talked about the fact that though the Hynek had a higher initial test rates, the Bakke looks like it might be the better well, that certainly is playing out that way so far, but that being said its still early. But Lance can kind of give you a feel of what our current thinking is or maybe range of reserve outcomes for those wells.

David this Lance, hi. It's obvious that we have a mix bag of the performance of the wells themselves. As far as building out decline curves, we are monitoring all the other Bakken wells in the area to build good top curves, so that we can do a better job estimating reserves. And we are updating that monthly to try and get a better handle on exactly what our reserves are. Of course, you hit it, the Bakke is holding in well and looks really great. The Bergstrom, I think is doing better than we thought initially, its really holding in while that's flattening off really flat. And Hynek started off better and is far more flattening now, so we really don't have a good strong estimate of reserves right now. We do have them based on early time data. The one thing that I would point out is Bud has a slide in his presentation out on the web, that has the drilling cost of $5.2 million and that's a pretty good idea of where our cost is averaged in our reserves. On the different ways to look at it within that matrix, we believe the average is within that matrix that he is showing on the website. So we are really excited about being able to repeat this over and over again and show good rate of returns in good multiples. David Heikkinen - Tudor Pickering: So you think you are in that 300,000 to 400,000 barrels of oil for each of these wells?

I think on an average we are in that range between the 200,000 and 700,000 barrels which I know is still a pretty broad range, but we are really not comfortable giving a good strong estimate, but in the range of that matrix that table that Bud has…

Obviously the Bergstrom or the Hynek might be kind of the lower side of that range in the Bakke and certainly the Hallingstad would be at the upper end of that range. So it's early, but at this point the way the wells are performing it looks like there is a good probability that all of them will generate reasonable returns but there is variability among them.

Right. I think if I was forced to give you an answer, right. I would say it would be in the range of 200,000 to 450,000 barrels on an average if you took all the four wells that we drilled today including the Hallingstad. David Heikkinen - Tudor Pickering: Okay. Thanks guys

Thank you

Your next question comes from the line of Ron Mills of Johnson Rice. (Operator Instructions). Please proceed, Mr. Mill. Ron Mills - Johnson Rice: Good morning. Just a couple of follow-ups early on, on a couple of things to follow what David had asked. As you look at the second quarter profile Bud, or Gene, because you are not going to complete the C-38 well in the Vicksburg until, April results, so you probably won't be able to get that well online until May. And then your Cotten Land well is definitely not a second quarter impact well. What do you have coming online, or what do you see coming online in the second quarter they can provide that first quarter sequential growth as opposed to what it looks like would be more like a third quarter startup of sequential growth?

Sure, Ron. It is going to be driven by timing and the timing on the C-38 which could be a latter part of that, but wells they have a good probability of contributing to the second quarter, the Cary Estate that PetroQuest is currently completing its own 26 feet of play. In the Bakken the continuing sequence of wells the Manitou State that's currently drilling and of course the Krejci that we're currently fraced here in the next couple of weeks. But the timing of those I mean we have been in the trough here with absent significant completions and the timing of these wells coming online will affect how much of the growth that you see in the second quarter and obviously what the C-38 should fully impact the third quarter as well as more of the Southern Louisiana wells. And one other well that I didn't mention is the Mracheck we are doing that [the] completion also in the Bakken as well that one should contribute also. Ron Mills - Johnson Rice: Okay. And then in terms of just to gas oil split you have been running 80% to 85% gas. I would assume as you drill more and add wells in the Bakken, the oil component is going to go up. How quickly and to what extent, do you think you can increase the oil component of your production?

Ron, its Gene. I would expect, just based on a conservative modeling that we are doing as far as contribution form the Bakken well, that may be in the 65% gas range in the neighborhood. Ron Mills - Johnson Rice: And is that by year-end or is that--?

That would be at year-end, yeah. Ron Mills - Johnson Rice: Okay. And Gene, one easy one for you; LOE for the fourth quarter of $0.70 per annum was well below where you had expected it to come in at $0.89 or $0.90 per annum. Was there just lack of workovers that you were expecting, and is that why the first quarter guidance is back up in that $0.85 to $0.90 range?

Yeah, I mean, obviously you know, yes. We had some workover activity, but it was below our actual, as far as the two prior quarters. And a big part of fourth quarter, obviously we sold the Granite Wash assets and we had a lot of expenses or high operating cost, assets given the amount of water those wells are producing. So, we saw a little bit of benefit given that we closed that transaction on September 1st. So we sort of missed out on the Granite Wash LOE contribution for the month of September, but obviously saw a full quarter's impact in the fourth quarter. Ron Mills - Johnson Rice: But in terms of expectations, what's driving the increase back up to the mid $0.80 range.

Well, I think we're just being may be a little bit conservative. Another issue is that we're expecting higher ad valorem taxes. So, it's really a combination of the new wells that we'll bringing on in the first quarter higher ad valorem taxes and so the Bakken wells that we completed in the first quarter and really primarily the higher ad valorem taxes. Ron Mills - Johnson Rice: Okay. On the Bakken, Lance, this might be a question for you because as soon as they find it than it's in your hands. If you look at the economic profile of a well and you look at the matrix that you will have in your presentation of 200,000 barrels to 700,000 barrels. What do those production profiles look to get to those eventual recoverabilities in terms of where do wells have to come on, and what's your engineered decline curves in each of the first four or five years before you start to get to a more stable decline period to get to those economic runs?

Yeah, Joe this is Lance. I'm sorry, Ron. Basically how we model them is we take in all the data that we have from the Bakken wells in the area and of course we don't have 10 years of production on those wells. So what we do is we try and put those together and pull tight curves. And then we do a curve fit using our [area] software program. There are hyperbolic fit curves we use in exponents that are in excess of one, so they're flattening off. And if I just look at the curves, it looks like that the final decline rate probably is not reached until about 6 years out is when you had final decline rate. Ron Mills - Johnson Rice: And based on the data that you have, how does that decline rate, I mean obviously the first three wells, the variability that has been already talked about by you'll on the call, but is it typical first five-year profile down 50% then down 30% and then down 20, 15, 10. I'm just trying to get a sense as to what that typical well profile looks like? Hello

I'm looking at it. I'm trying to figure out how to answer this so I don't mislead you so. Ron Mills - Johnson Rice: And is this $5.2 million well cost, that's I'm assuming that's a single-lateral what's the lateral link you'll are drilling?

That's a 640 section, so about 4,500 feet. Our frac jobs we've done 7 or 8 frac jobs in each of our 4 wells so the cost is variable on the number of frac jobs of course and the number of -- and we're using the Swellpacker technology right now. So that's average of the four wells that we have, that we've drilled today. Ron Mills - Johnson Rice: And then the operating costs of roughly $8,400 per month. Is that a fairly fixed component?

I think it is right now, and that number Greg and I have been talking about that number is also that's our best estimate. We haven't had enough months. We've basically, our oldest well is 2 months old, so we haven't had enough history to get a good firm cost on our operating expense, but we feel like that that's a very conservative number. So we feel like we'll be able to stay within that. The other thing what you would expect to see overtime, and I've told you this probably 10 times. You'll expect the cost to go down overtime, and if they don't go down overtime it's because you're spending more money on the completion, and you'll expect the reserves. So really what you are expecting is the cost per barrel to go down overtime, and that's going to happen. We're going to do a whole lot of things in the area we're gearing up for full scale development, we're going to be creative in trying to buy some of the, what I call dumb iron and stuff to try and lower those costs, frac tanks, metal strings those kind of things were out there right now, there its very competitive. We can bring it in a lower cost plus we're going to be figuring out ways to do things faster and better as well as everyone else. And that's part of the reason we're in the consortium to try and have open conversations with six other companies that are active in the play, so that we can learn from one another. Ron Mills - Johnson Rice: Okay. Well, I may try to follow-up on the production profile just to get a sense, and then lastly the 200,000 to 450,000 barrels that you've based on what you've seen so far that you feel comfortable that those that you always would average in that level and when you talked about the metrics of 200,000 to 700,000 barrels. Is that mainly focused on that 88,000 acres east of the Nesson Anticline or would you also include the acreage you have to the west?

We've included the larger area, I mean, as far as -- what we've -- I am sorry -- answer the question.

Well, Ron, I think that now we just have a lot of data east of the Nesson and Mountrail, so that 200,000 to 700,000 the data supports that east of the Nesson, west of the Nesson now it's just too early. We think there is a tremendous amount of option value there. We've got the Mracheck, which we are attempting to run the Swellpackers on and complete. We have 51,000 acres there and 100,000 acres to the Northwest and far eastern Montana, where there has been an activity to the south. So, that's provided some encouragement for the Bakken. A Sinclair well was recently drilled horizontal to the south of our Montana acreage, it came on at 300 barrels per day. So we are really excited about that acreage, but we don't have the data to say what range of potential outcomes that we would expect on reserve recoveries over there. Ron Mills - Johnson Rice: Alright, thank you. Let me jump off now, thanks

Okay. Thanks, Ron

There are no further questions in the queue at this time. I'd like to turn the call back over to management for closing remarks.

Well, this is Bud. Again, I want to thank everybody for participating in the call, and as I have said before we look forward to reporting on what should be a very exciting year for the company, thank you.

Ladies and gentlemen, we appreciate your participation in today's conference. This does conclude the presentation. You may now disconnect. Have a wonderful day.