SilverBow Resources Inc (SBOW) 2010 Q1 法說會逐字稿

Good morning. My name is Darrah. At this time, I would like to welcome everyone to the Swift Energy first quarter conference call.(Operator Instructions). Mr. Paul Vincent, you may begin your conference.

Good morning. I'm Paul Vincent, Director of Finance and Investor Relations. I'd like to welcome everybody to Swift Energy's first quarter 2010 earnings conference call. On today's call, Terry Swift, Chairman and CEO will provide an overview. Alton Heckaman, EVP and CFO will review the financial results for the quarter, follow by Bruce Vincent, President, and Bob Banks, EVP and COO, will provide an operational update. Terry Swift will then summarize before we open it up to questions. Also present on today's call are Mike Peterman, SVP operations, and Jim Mitchell, SVP, commercial transactions and land.

Before I turn it over to Terry, let me remind everyone that our presentation will contain forward-looking statements based on our current assumptions, estimates, and projections about us, our industry, and the current environment in which we operate. These statements involve risks and uncertainties detailed in our SEC reports, to which we refer you along with cautionary statements contained in press releases and our actual results could differ materially. We expect our presentation to take approximately 25 to 30 minutes and have allowed additional time for questions.

Thanks, Paul. Again, thank you for joining our conference call today. It is a very exciting time for Swift Energy Company. During the first quarter of 2010, we brought our first production from the formation in south Texas online. Results from these first wells are at the top end of our expectations and support our belief that our acreage in this region has the resource potential to be transformational for the Company. As of the end of the quarter, we had two operational horizontal rigs and drilling full time for Swift Energy in this play. One smaller rig drilling vertical surface holes and one non operated horizontal rig. Before going any further, though, it is necessary to comment on the recent accident that occurred in the Gulf of Mexico. Unfortunately, this accident is having an environmental impact that will be substantial.

And while not directly impacting our operations along the Gulf Coast, the effects will be felt by the communities we're involved in and the friends and families of the people who work for us and with us. Not to be overlooked by the lasting effects of this accident is the tragic loss of life, which serves as a reminder to all of us that our business is a business that involves significant risk at times. There can never be enough said about our commitment to health, safety, and environment. Swift Energy is committed to a safe workplace, environmental stewardship, and operational excellence. We recognize the importance of integrating health, safety, and environment, HSC, management processes into all of our work activities.

We approach all of our operations with this attitude and will continue to do so. In south Texas, we've recently taken steps operationally to improve our efficiencies as we accelerate our activity. As Bob will discuss in greater detail, we're now drilling the vertical surface holes for our horizontal wells with a small rig as part of a batch drilling program we've launched. We now have a water production handling and management program in place and operational. We have improved our supply chain management capabilities, and we are aligning with our midstream partners to reduce supply and service delays as much as possible. While natural gas prices remain weak, the oil and natural gas liquids markets pricing is considerably strong. Our current production is weighted towards crude oil and natural gas liquids, which provides us stronger cash flows. We have adjusted our 2010 capital program to take advantage of this stronger liquids pricing environment by focusing oil and liquids production as we continue evaluating and delineating our entire acreage position. This focus should add higher value production, but slightly lower full-year production volumes than previously guided. Our drilling results, on the other hand, also support increasing our previously stated year-end reserve guidance from growth of 5% to 10% to a mean range of growth 8% to 12% over year-end 2009 levels.

We are also increasing our daily average production exit rate guidance from 27,500 barrels of oil equivalent per day to 28,000 barrels of oil equivalent per day . Bruce and Bob will detail all of our operational activity and performance in just a few minutes, but first I'd like to highlight some of the results of the first quarter which include the swift operated Fasken 1H well, the PCQ1H and the non operated Bracken JV1H Eagleford discovery wells. The Fasken Eagleford 1H in Webb County tested at a rate of 9.4 million cubic feet of gas per day. The PCQ1H in McMullen County tested at a rate of 1,134 barrels of oil per day and 1.1 million cubic feet of natural gas per day. Our first AWT joint venture well, the Bracken JV1H well, drilled by our joint venture partner in McMullen County, tested at a rate of 9 million cubic feet per day. All three of these strategic test wells have demonstrated the potential three distinct areas within our position in Eagleford. So far in the second quarter, we have already drilled one horizontal well in the gas formation as well as one operated and one non operated joint venture Eagleford shale well.

The operated Eagleford well, 1H, established a new technical drilling limit for Swift Energy of 21 days to PD. All three wells are awaiting completion operations and will be online this quarter. Two operated rigs and one non operated rig are currently drilling horizontal wells in south Texas and will continue to work for the Company for the remainder of 2010. As activity levels pick up, we also expect improved performance, results, and lower cost. In southeast Louisiana, our Lake Washington production maintenance program is ongoing as is the shallow well drilling program. We continue to find large sections of pay sands at relatively shallow depths in this field resulting from this program. We are now preparing an ultra shallow drilling program for the second half of the year to bring oil reserves shallower than 5,000 feet on production quickly in response to higher than expected crude oil prices.

We are also preparing a deeper exploitation target in Lake Washington for the second half drilling schedule. At Bay de Chene, we expect to move a barge rig into the field to drill our uptick Teton during the second quarter. This will be the first oil drill in this field in almost two years and represents the first test of our recently updated 3-D seismic interpretation of the salt dome at DDC. Finally our east Texas, central Louisiana area, the first well targeting the Austin chalk in our joint venture area of Burr Ferry field is being partner during the second quarter. We're also preparing plans for a well in the Masters Creek field in central Louisiana to be drilled late in the second quarter or early in the third quarter. This well will test new geo steering technology and drilling techniques, which if successful, may lead to sizable increases in oil production and reserves in this area.

Opportunity sets like the one we put together at Swift Energy company don't happen by accident. Our inventory of oil and natural gas development and exploration projects, perhaps the most extensive in the Company's history, is only possible because of the tireless effort of our people during what was one of the most difficult commodity, price, and economic decline environments the country's experienced. We've come out of that strong. As I mentioned earlier, it is a very exciting time at Swift Energy, and I'm proud to be a part of it. And now I'll ask Alton to present first quarter 2010 financial

Thank you, Terry, and good morning, everyone. Having balance in our portfolio has served us well during the first quarter of 2010, as we see continued improvement and oil prices and weakening natural gas prices. Swift Energy's financial results for the first quarter reflect this. Oil and gas sales, excluding hedging effects, were $110 million, a 44% increase from 1Q 2009. Our income from continuing operations was 14.2 million or $0.37 per diluted shares, consistent with 4Q 2009 levels and beating the current first call mean estimate.

Cash flow, before working capital changes, came in for the quarter at $1.69 per diluted share. And first quarter production, although down 14% from 1Q 2009 levels was within our guidance at 2.09 million barrels of oil equivalent. Earnings for 1Q 2010 are therefore up substantially from the prior year. Crude oil prices were 90% higher than a year ago, while natural gas prices for the first quarter were 13% higher, leading to an overall 67% higher price BOE in 1Q 2010. Swift's realized average price increased to $53.81 per BOE due primarily to crude oil prices increasing to an average of approximately $78 per barrel overseas, compared to $41 per barrel in 1Q 2009 allowing swift to increase gas revenues 44% over first quarter 2009. As Terry mentioned, we continue to focus on our control of cost and methods which all came in at or below guidance for the first quarter came in at $4.52 per barrel BD&A came in at $18.72 per BOE. Production costs came in at $9.12 per barrel. Interest expense came in at $4.07 per BOE. And production and taxes came in well below our guidance at 10.5% of revenue. The result was income from continuing operations for the quarter at $14.2 million. $0.37 per share both basic and diluted. Our effective income tax rate for the quarter was 37.6%, again within guidance.

Cash flow, before working capital changes for 1Q 2010 came in at $64 million or $1.69 per diluted share, while EBITDA is $70 million for the quarter. Quarterly CapEx on a cash flow basis was $63 million. Let me spend just a moment to highlight solid financial position. At the beginning of the first quarter 2010, we had no outstanding balance under our line of credit. With respect to our line of credit facility, with our ten-member bank group that currently runs through October, 2011, our borrowing base and commitment amount will recently reaffirm at $277.5 million. Thus, we are well positioned to fund our CapEx budget for 2010. With respect to switch hedging activity, we have purchased covering a meaningful percentage of approximately half of our domestic oil and natural gas production for the second quarter of 2010 in an average INEX price of approximately $4.73 per MMB per for gas and $78 per barrel for oil. Please see our website for complete and current detail hedging information.

And as always, we've included addition financial and operational information in our press release, including guidance for the second quarter as well as for the full year 2010. Swift is well positioned financially to take advantage of the opportunities in front of us. And we have the strength and flexibility to handle the continuing price volatility that has become the norm in our industry. With that, I'll turn it over to Bruce Vincent for an overview of our operations.

Thanks, Alton. And good morning, everyone. We certainly appreciate everybody listening in today. Today, I will discuss first quarter 2010 activity, including our production volumes, our recent drilling results, activity in our core operating areas, and our plans for the second quarter of 2010. And Bob Banks will then provide greater detail on significant operational successes of the quarter and their effect on our full-year plans. Beginning with production. Swift introduced production during the first quarter of 2010 totaled 2.04 million barrels of oil equivalent, or 12.27 billion cubic feet equivalent, a decrease of 8% from the 2.21 million barrels of oil equivalent produced in the fourth quarter of 2009. And within our previously stated guidance range.

As Bob will discuss in greater detail, to improve longer term project efficiencies, we actually slowed our completion activity during the first quarter. This was done to give our operational professionals the time to prepare and commence a multi rig drilling program in south Texas that will allow for longer term drilling and completion scheduling and an operating environment that emphasizes safety. As Terry mentioned, this measured approach to preparing our organization for the growth potential we now see from our own results, causes us to lower the higher end of our production guidance for the year but also allows us to raise our reserve guidance rate to 12% growth over the year. And to raise our year-end average daily production exit rate forecast at 28,000 barrels of oil equivalent per day. First quarter production, when compared to first quarter 2009 production of 2.37 million barrels of oil equivalent, decreased 14%. Even though we accelerated our spending and activity levels during the first quarter. Year-over-year declines result primarily from the reduced spending and activity levels throughout 2009, freezing problems that we encountered in southeast Louisiana due to unusually cold or colder temperatures during the winter.

Unscheduled maintenance at our 6700 platform in Lake Washington and of course natural decline. The second quarter of 2010, we expect production to increase as our drilling and completion activity increases and new production comes online. For our first quarter of drilling results, Swift Energy drilled eight wells during the quarter. Three horizontal wells, two of which were operated and one non operated, and all were classified as exploration wells were drilled at the Eagleford shale formation in south Texas. One shallow vertical oil well, developmental well, was drilled in the Olmos formation in McMullen County Texas also during the quarter. Two rigs, capable of drilling horizontal wells in the Eagleford and/or Olmos are active in south Texas with the principal focus being the Eagleford shale. A lower cost rig that is drilling surface holes on our horizontal location is also active.

Additionally, a non operated rig is currently targeted in the Eagleford shale in our joint venture area and operated by our joint venture partner. This rig is operating in McMullen County. Four wells drilled during the first quarter in the Lake Washington field and Plaquemines Parish, Louisiana, one was completed and three were plugged and abandoned one of the wells was plugged due to mechanical difficulties but was successfully redrilled during the second quarter. One barge rig is currently operating in Lake Washington. We also expect a barge rig to move into the Bay de Chene field later in the second quarter to begin drilling in that field. I'll briefly review activity in each of our four operating areas for the quarter, and I'll let Bob detail the highlights of our activity.

Starting with southeast Louisiana, which includes the Lake Washington and Bay de Chene fields, production during the first quarter averaged approximately 10,399 net barrels of oil equivalent per day or approximately 62 million cubic feet equivalent per day, again, net, in this area. A decrease of 20% when compared to our fourth quarter 2009 average net production for the same area. Lake Washington averaged approximately 7,909 net barrels of oil equivalent per day or approximately 47 million cubic feet equivalent per day. Again, a decrease of 18% when compared to the fourth quarter 2009 volumes. Primarily due to freezing problems associated with unusual cold temperatures, as well as unplanned equipment repairs and four that expected first quarter drilling results along with of course. Bay de Chene sequential production decreased 26% to 2,489 net barrels of oil equivalent or about 15 million cubic feet equivalent per day net.

This sequential decline is somewhat exaggerated as the fourth quarter saw higher than expected oil production from flush production back online from the hurricane damage as the repairs were completed from the previous year. Our 2010 operating plans include one barge rig to maintain activity in lake Washington field and one rig moving into the Bay de Chene field later in the second quarter and drill perhaps three wells this year. In our south Texas core area, which includes AWP, Sun TSH, Briscoe Ranch and Las Tiendas. First quarter 2010 production averaged 8,777 net barrels of oil equivalent per day or approximately 53 million cubic feet equivalent per day, a 22% increase in production when compared to fourth quarter 2010 production in this area. This increase is primarily attributable to the contribution in the R Bracken 36H and AFP1H in our AWP field, our new newest horizontal completions in the Olmos end. In McMullen County, two horizontal discovery wells, BCQ1H, 100% working interest. And the Bracken JV1H, a 50% working interest, were drilled through the Eagleford shale formation during the first quarter.

These wells represent the first Eagleford production in McMullen County. In Webb County, the Fasken Eagleford horizontal discovery well was drilled and completed and is producing at a restricted rate because of current market limitations. While there are many strengths in this area presently, we believe this is a highly prospective area for future development. And additional market capacity can be easily added. The successful discovery de-risk portions of our acreage provide us with our own production and reserve data for analysis and planning and should provide visibility for us and you on where we expect to see growth through the drill bit in years to come. Bob will provide some more specific details from these wells in addition to our plans for drilling program in 2010. In our AWP field in McMullen County, we finished drilling one well in the northern portion of the field during the first quarter. This vertical well targeted oil in the Olmos formation and was recently put online. Swift Energy currently has ozone rig drilling shallow surface holes and two operated rigs drilling horizontal Eagleford objectives in McMullen County in areas we believe will yield oil and liquids rich gas production.

One non-operated rig is also drilling in our non venture area in McMullen County. One 100% horizontal Olmos well, one horizontal Eagleford well, and one 50% non-operating joint venture Eagleford well are actually already concluded drilling operations during this quarter and are now awaiting completion. Bob will spend a little more time discussing these programs in greater detail. The central Louisiana, east Texas core area, which includes our Brookland, Masters Creek, and South Bearhead creek fields, contributed 1,168 barrels of oil per day or 10 million cubic feed equivalent per day. Now, our production in the first quarter of 2009. There was no significant operation activity in this area during the quarter. In our south Louisiana core area which is comprised of Horseshoe Bayou, Bayou Sally, Jeanerette, Cote Blanche Island, and Bayou Penchant and production average approximately 1,697 barrels of oil equivalent per day or about 10.2 million cubic feet equivalent per day. Again, during the third quarter. Now I'm going to turn the call over to Bob Banks for further operational highlights for the first quarter.

Thanks, Bruce. At the Lake Washington field we drilled three wells, completing one and plugging two during the quarter as mentioned. The CM a number 410 was drilled to a measured depth of 5,388 feet and encountered 79 feet of true vertical net pay. This well averaged 350 gross barrels of oil per day over the past 30 days. During the first quarter, we drilled a fourth well but encountered commercial quantities of hydrocarbons which plugged into a mechanical failure. This well was redrilled in April, number 411 to a measured depth of 5,481 feet. This well logged 334 feet of true vertical net pay over multiple horizons that will be placed on production early in the second quarter. Also during the quarter at the Lake Washington field, all seven of our recompletions performed were successful.

Average initial production from these operations was approximately 339 gross barrels of oil per day equivalent. Other activity in the field during the quarter as mentioned included our preventative maintenance program where we identified a small t leak at the bulk separator at our 6700 facility, which normally handles 2,500 barrels of oil per day. Although one planned repair required this unit to be out of service for ten days, this work eliminated the risk of this relatively minor issue from having a lasting and lingering effect on our continuing lake Washington operations. Additionally, we are installing a new aiming treating system at the CM3 case load facility in order to increase needed capacity and service additional gasless volumes to our wells. This unit double treating capacity to 36 million cubic feet of gas per day, and it is further designed to greatly improve the liability and improve our operational efficiencies, in particular on the southern end of our field.

In the Bay de Chene field, is prepared to start a well upon its arrival, this rig will drill up to three wells in and around Bay de Chene in and around 2010. Now, into south Texas at the AWP field, I would like to first provide you an update with our horizontal Olmos drilling program. The Braken 36H drilled and completed very late in the fourth quarter of 2009, is still producing approximately 5.5 million cubic feet of gas equivalent per day, and it is already produced just shy of 1 billion cubic feet equivalent in its very short life. To improve well performance and accelerate recovery, to the installations have been designed for all producing horizontal wells and are being installed during the second quarter. Also, in south Texas, we drilled and completed two 100% working interest wells and one 50% working interest well in the Eagleford shale in the first quarter. The Fasken Eagleford 1H well was drilled in one county and completed with a 12-stage. The initial production rate of this well was 9.4 million cubic feet of gas per day flowing tubing pressure of 4,550PSI on a 2264th inch choke. As Bruce mentioned, the pipeline limitations as well as being produced at a curtailed rate of 1 million cubic feet of gas per day. But this result is really at the upper end of our expectations and we believe it significantly de-risks a very meaningful position in this area.

In northern McMullen County, we drilled and completed the PCQ1H. This well was completed with a 13-stage frac and had an initial production rate of 1,134 barrels of oil per day and 1.1 million cubic feet of gas per day with flowing tubing pressure of 1750 PSI on a 24/64th inch choke. We are further delineating this northern acreage in the second quarter and expect to fracture stimulate three additional Eagleford wells during the quarter. In our joint venture area, McMullen County, our partner drilled the Bracken JV1H well, this well was completed with an 11-stage and had an initial production rate of 9 million cubic feet of gas per day with flowing tubing pressure of 5,815 PSI on a 24/64 inch choke. While awaiting additional production facilities to be installed, this well has produced at a curtailed rate of 6.4 million cubic feet of gas per day and it is still flowing at that same rate. Terry and Bruce have both mentioned the fact we will be guiding our calendar year production volume slightly lower. The primary reasons for this are first, one of our big south Texas rigs left the field at the beginning of the year to drill one well for an offset operator on a well that turned out to be very lengthy and problematic.

We have gotten that rig back and have mitigated this potential issue in the future. But securing longer term contracts for the two big rigs and by bringing in a smaller rig that will botch rig surface holes and advance mobilizes the bigger rigs. We believe this type of operation will prove to be both efficient and cost effective. Second, some of our frac schedules were not met as timely as expected. We have mitigated this pretension issue in the future by first securing a longer term contract that specifies dates and second, by building a much larger water management infrastructure in the AWP area that includes high weight water wells, storage pits, flow back pits and flow lines. This infrastructure, combined with the batch drilling approach, will allow more flexibility for us and our service providers in meeting timely frac schedules. Lastly, the most significant reason for lowering our calendar year production guidance relates to project mix.

We have now proven that we have lean gas opportunities, rich gas opportunities, and very condensate rich opportunities across our Eagleford acreage. In this regard, we are altering our originally perceived project mix to include more drilling in the condensate rich areas of our acreage position to take advantage of the stronger crude oil and natural gas and liquid commodity pricing. These wells, while yielding stronger economic returns, do not yield the same production volumes as the leaner gas areas of much of our new forecasting takes this new mix into account and lowers our first year production volumes. Although we now expect to produce slightly less crude oil and natural gas during 2010 than previously forecast, we do now expect better than expected reserves growth and to exit the year with a daily production rate of approximately 28,000 barrels of oil equivalent per day and a whole lot of momentum heading into 2011.

Now, that we have higher drilling and production data from our own wells in the trend, we believe our planning, scheduling and execution is where we need it to be to implement what appears to be a very major development program, an almost completely undeveloped asset. Thank you for your attention this morning. I'm going to turn it back to Terry to recap.

Before we open the line for questions, I'm summarize Swift Energy's first quarter results and recap some of the highlights from today's call. Our first Eagleford shale production is now online from one operating well and one inoperative well. The pace of our activity in this place is picking up, and we see meaningful production and reserve growth from this trend in the years to come. Although we've lowered full-year production guidance slightly, we are increasing our reserve guidance from growth that was in the 5% to 10% range to growth that is now in the 8% to 12% range over year-end 2009 levels. We're also increasing our average daily production exit rate guidance from 27,500 barrels of oil equivalent per day to 28,000 oil barrels equivalent per day.

In southeast Louisiana we're bringing in a rig to the Bay de Chene area to begin drilling wells that have the potential to add production in reserves to set up additional drilling inventory. Our cash flows and balance sheet can support the mere term capital intensity of accelerating activity in the Eagleford and Olmos plays. We've established operations that are scalable and flexible enough to add maneuver rigs to project areas in south Texas that offer the best returns relative to near term. With that, we'd like to turn it over to the question question-and-answer portion of our presentation

Thank you. (Operator Instructions). Your first question comes from Jason Wangler of Wunderlich.

Nice quarter. On the Eagleford, it sounds like with the focus on oil, are you going to be trying to drill up more on that northern McMullen County, the 15 gross well wells, or spread that out to more delineate the acreage?

We're very active there right now. As I mentioned, we'll be farcing three new wells during the quarter and we have additional drilling we're doing up there. We are trying to balance that out a little bit with evaluating some of our other acreage position. I think we've always said this is an evaluation year. We want to fully understand the value of our acreage. But clearly the next quarter, we're going to have quite a bit of activity in that northern area.

Obviously with the frac issues and you're trying to get the delay and things accounted for. Do you see costs moving higher in that region as well as? Because it seems like things are getting tight.

There's been some pressure. We've been able to lock in a longer term commitment and pricing for our frac crews and equipment. But clearly I know that all of the major from providers are pressuring the industry upward a little bit.

Great. Thanks, guys.

Your next question comes from Michael Hall with Wells Fargo.

Good morning.

Good morning.

Congratulations on stellar results. On the Fasken well as well as the JV well, do you have BT content on that gas or is that a purely dry gas stream in both of those wells there?

Yeah. Both of those are a little under 1,000.

Okay. And then on the cost per well front and the operated Eagleford wells, any color there?

Well, I can say that it depends on what we're doing. Many of these wells so far, as I think we've talked about in the past, we're drilling pilot holes, getting full sweeps of logs, we're cutting cores. as Terry mentioned, I believe, our Heys well, one of the wells we'll be fracing up in the northern area, we drilled that well in 21 days. And I think we set a new technical limit that we're chasing after as a result of that operation. In terms of cost, I would say we've been down as low as about $5.5 million. But we also are still up in some of these wells, depending on how much evaluation work we do up in the $8 to $8.5 million range. I think for longer term development moment, I think we've always kind of said 5 to 7 is a good ballpark, and I don't see anything that would change our thinking on that.

Yeah, let me stress that when Bob talks about these two different ranges, especially the higher cost of the initial wells, if you're drilling initially a pilot hole, straight down, before you drill your horizontal well, that's more extensive. We've also cored, taken full cores of these pilot holes on the way down. That's more expensive. We've also been doing micro seismic on all of these to fine tune and optimise our activity to how we frac the wells but we have also established where we drill the water wells in the area, drilled the big frac ponds set ourselves up for additional activities as well as the pipeline and facilities that are going in there. So, these initial wells are carrying the load of the process.

Thanks. Two more if I may. First one, infrastructure, it seems like a very positive result up to northern AWP and,, a lot of condensate production. What sort of infrastructure needs to you see there to help bring the next three wells on as quickly as possible for the rest of the year's program as well?

Actually, while we do have some changes in terms of the types of facilities you bring in relative to the gas, infrastructure is in good shape there. This is an area that has had a lot of oil production in the past. And right now I'm talking about up in the northern AWP area. We can actually get the facilities in very timely. In some cases, much quicker than the gas out in Fasken. That's going to take us a little while to get that up to capacity to market. In terms of the oil, we should note that we're finding this to be a little bit sour, so that puts a little twist on it. We want to be real safe with how we put those facilities together. But overall we don't see any problem in bringing these wells on.

When you talk about production facilities, what the well is currently waiting on is that stabilization tanks, do they condensate or any additional color on that.

Basically tanks and some additional H2 safety equipment is really all we're talking about there.

Okay. And then we talk about mix, project mix. What is the mix outlook for the end of the year about 39% gas this quarter. What does that look like maybe in your fourth quarter projections, or exit rate, if you will.

Let's get back with you on that number.

I don't think we've fine tuned it to that degree, because we still want to maintain some flexibility to move to different locations, depending on results. We do know differently today, versus three months ago, we now have drilled our first wells in several places in our acres. So we now have production on our acres. And we have a better understanding that the northern pier is a very liquids-rich area, and we want to direct more activity to that for obvious reasons. We still want to do some valuation on our wells in terms of developing a long-term development plans.

Okay. I guess one more, if I may, and then I'll jump off. I know it's early, but you've had very good success here now with your initial two wells, operated wells. Any thoughts on what the rig might look like as you look out to the end of the year, into 2011, at this point, or is it just too early?

Well, I think obviously that's something we're looking at. It's not just the two successful operated wells and the JV well, but as I mentioned, we've successfully drilled another Olmos horizontal well. And that's actually a concept well, because that's actually drilled in an area where other vertical wells were drilled so we've got to really be looking at the results of that. We drilled the Hayes 1H well and that looks to be in a very good location in the northern part, good-looking channel section. So we expect that to complete really well. We've actually drilled the vertical pilot hole of another well in the northern part of the field. And that has a very good looking both Olmos sand that is developed up in that area as well as Eagleford section. We still have to drill the horizontal section, but it looks real good based on the pilot hole. We just need to get a little bit more results under our belt before we look at ramping up. It certainly would be easy to add another rig without thinking too hard about it.

Okay. Thanks very much. Congrats again.

Your next question comes from Leo Mariani from RBC.

Obviously you drilled one well here. It clearly was in the oil condensate window. A couple other wells that were gas. Based on your results, as well as your industry can you guys give a breakdown how much in the oil window and how much more is in the dry gas window?

I think we would be shooting from the hip if we answered that.

Well, I mean, as I think I said, we have kind of flee categories here. We have the liquid-rich area, but we also have a rich gas area, and we have kind of a more lean gas area. But I would say, in terms of what percentage would be rich gas or condensate heavy gas, I would say a good half of our acreage would contain those types of attributes. So without being overly specific.

And I want to qualify that. That's really just an estimate. That's not based on a significant geologic review of our acreage.

And we're still evaluating. We're still drilling wells to test that.

I'm going to add a couple more comments to that, because I think it is an important question. In our Tuihu wells area, we have not drilled our first well yet. And that's a nice chink of our acreage, I think it's north of 15,000, between 15,000 and 20,000 acres over in that area. If is on strike to some very high condensate, almost oil wells. So, if you go to the east of it, but also if you go on strike in south, it is more gassy and some rich gas. So our Tuihu wells is an area you still need to apprise and evaluate. We've got over 8,000 to 9,000 acres over there. While the first well came out fairly dry, I think you've got to get these wells on production. We've seen some variation in very small areas, for example, down in our Olmos acreage down in AWT. In the south part of that acreage, we've seen some very high oil and condensate contributions just a mile or two away from rich gas. So I think we need further development to give you more color on that.

Okay. Thank you, that's helpful guys. Jumping over to Masters Creek is an area you mentioned. You've got some kind of oil target there. Can you give us a little bit more color kind of around what you're looking for and the size --

Well, I think you can go back to the history of the wells in that Masters Creek area. There were some phenomenal wells that came in initially, over 2,000 barrels a day, and over 10 million cubic feet a day. Very rich gas back in the early development period. All I can say is that the technologies are much, much better today than when those wells were first drilled. And that those wells were put on 2,000-acre units. And we now believe that there's an opportunity for down spacing that. We also believe that there are opportunities to drill more effectively in zone. We think that was part of the reason that you had variation of wells. There's some wells out there that would easily million dollar plus top the wells on the high side. In our judgment, there is a lot of oil still in place in that area. It is just a question of whether or not we can use the technologies to unleash it.

That area is a little bit deeper vertically, about 15,000 feet vertical before you start to turn horizontal, it is a much higher temperature, high pressure environment. And one of the things that has been developed from a technological standpoint is equipment that can withstand those kind of temperatures today that we didn't really have 10,15 years ago when we and the other industry members were developing that area. And going back and reviewing our existing wells, we believe a lot of them ended up really out of zone for some of that horizontal. Not only the 2000 acre spacing, but the fact that the wells cited there didn't stay in zone as well as we believe you can today with the technology that is available. That's also not just down spacing, but utilizing more advanced technology that will enable us to drill better wells.

All right well, roughly how many verticals did you drill out there historically and what is your acreage position?

Well, historically, some of the wells were done very, very well. There were a number that produced up to two million barrels per well.

And three to five beams that went along with it.

Yeah, those were all horizontal -- in most cases dual lateral horizontal wells

We've got about 20,000 acres that is held by production. And that would be on 2,000 acre space unit. It can be down spaced at least 1,000.

Okay. Great. Thanks, guys.

Thank you.

Your next question comes from the line of Derrick Whitfield of Canaccord Adams.

Good morning and congratulations on the quarter as well.

Thank you.

Thank you.

Extra questions on your Eagleford and Olmos. Specifically on the AWP test wells, and you can sort of bring up the topic again that you spoke up, does that change in any way your view of the delineation of the gas condensate. I know you guys have broken into northern central and southern before. Change your views on that?

We really broke it into kind of northern central and southern, because we carved out the central area because that was the JV acreage area and not so much designed to say this was the three different windows.

Yeah, in terms of where the transition occurs, we're still testing that. It would be premature to draw lines at this point.

Okay. And certainly on that JV well, there was no condensate with that well?

No. That's correct.

Okay. On the cost side, what types of cost savings are you guys expecting by using these sputter rigs?

Oh, well, you know, probably just by using the sputter rig on the well alone, just in terms of differential and time and cost is about $300,000. But there are some additional efficiencies we're working on to try to get even better advantage there. And one of the things that we're trying to build into our program is to have flexibility. One of the problems the industry is seeing with frac schedules getting delayed or coming to your location, if you're not completely cleared off, they could you have to go somewhere else before you come back. So, part of the sputter rig program in addition to the cost savings gives us the flexibility that you need to shorten that time from rig off to frac crew off to getting the well online. So we haven't put a total value to the efficiency side of the operation, but in terms of just pure cost, probably about $300,000.

Understood. Thanks for that. And then moving to Olmos, you guys mentioned the. Could you add any further color on how that might change your view on how much acreage you have and prospective for horizontal development?

Yeah, I think we talked about that a bit in the Olmos meeting. We have around 30,000 undeveloped, 40,000 acres undeveloped in the Olmos. And everything we've seen so far in that Olmos either is very rich gas or has good condensate yield associated with it.

Yeah, we haven't seen any Olmos production to be dropping, generally 1200BTU, even 1300. And sometimes had it is a condensate with it. The well that we talked about being a concept well, we're drilling it in an area where we had some vertical drilling, we need to complete the frac to get production history. But clearly if we can go back into areas that are developed because we didn't get full recovery of reserves in place, that would open up some additional potential in the AWP area.

And that would be above and beyond the 30,000 to 40,000 acres you just mentioned?

Yeah, because he's talking about --

I'm talking about the undeveloped positions.

You can go back into developed areas. We just don't know this yet. We don't want to put something on it. But it is something we discussed internally, because we don't think we've gotten sufficient drainage. And what is the best way to go in and recapture some of those reserves that are in the production developed area for the Olmos, is it additional vertical wells or can you put horizontal through there? We just need to work through that. This particular well that we just drilled and have drilled, not yet completed and fraced, did drill with nice pressure. So we're kind of looking forward to the completion in frac. Even one well won't give you the full answer. We just need -- if something were evaluated because we think there are more reserves in the developed area that we can get out.

But I think we're very happy. Olmos, we're very pleased with the results we're getting. And we think is going to get better and better. This 36H well has just been an absolutely phenomenal well. And that's what we're going for there.

Great. Sounds like a really encouraging data point. One last question, if I could, moving over to southeast Louisiana, those three Lake Washington wells you drilled in the first quarter, were they concentrated in any particular area?

No, not at all. In fact our whole strategy of the past shallow program, we've been testing all around the dome. Every part of the dome, from the north, to the south, to the east, to the west. We've kind of mitigated the rest by not working in a given area too extensively. This 411 well where we had an unbelievable amount of pay northeast part of the dome.

And in the second quarter you did complete one of those wells in the first quarter that did not work out ,

One of the ones that didn't work out had a mechanical failure. Didn't allow us to complete that well bore. We had to plug that well bore and redrill the well. It really counts as a second well when you plug one, but it really was because of a mechanical failure in the well bore. And when we redrilled it we ended up with 300 feet of net vertical effect.

Sounds like a good well. Thanks, guys, for your time and taking my call.

Thank you.

Your next question comes from the line of Biju Perincheril with Jeffries.

Good morning, guys.

Good morning. Lake Washington, you talked about some ultra shallow wells there. Is that in addition to 10 to 15 wells there this year?

That is in addition. And we have a very shallow target called the a A5 sand it is up around 2,000 feet. This 411 well we talked about where we had such an extensive amount of pay. We did see a very nice A5 sand there which is that shallow target. We know that we have lots of opportunity for that kind of drilling on the dome. It is very quick. We're talking seven, eight-day well, stuff you can bring into the system pretty rapidly.

And how many wells are we talking? Is that program already under way?

No, it is not underway yet. And I think for this year, we're probably five to six or seven of those kind of wells.

And then, do you expect to get back to sort of fourth quarter average there, and if you do, what sort of time are you looking at?

You're talking about production numbers?

Yes, yes.

Yeah, we just remodeled some of that. That's why I'm hesitating a bit. I think I have the answer to that. I think we'd have to look and dig that out, just only because we've gone through a remodeling exercise, getting ready for this new guidance.

But I'll say we have developed a strategy, basically risks and declines to try to stay on top of that and bring in some exploitation activity like Bay de Chene and Lake Washington to help us look at the upside. I'm particularly excited about bringing a rig into Bay de Chene because we're now going to be starting to access some reserve potential that can actually bring the production back up in both those fields. But we've got to drill deeper to do that.

Got it. Okay. And then Eagleford, only one well planned in Fasken and one well planned for the southern field. Is that still the plan or any changes there?

Yeah, well, in Fasken, we opened dialogues on the market outlook there. A lot is going to depend on how those dialogues and what kind of structures we can agree. But we don't really have in our schedule right now any more drilling at Fasken until we get the market sorted out. And then down in south AWT, we have a couple of combination opportunities down there between the Eagleford and the Olmos. So we will drill at least one Eagleford there, but there is a possibility that we would drill another one that would either complete the Eagleford or the Olmos depending on how the logs look. So I would say it is probably at least one.

All right. Thank you.

Thank you.

Your next question comes from Adam Leight from RBC.

A couple things left, I guess. A question on your reserve estimate. Is the increase due to timing or your expectation of higher and larger wells you're drilling?

Adam, mainly the reason we are more optimistic than we were, we've got firm core data and actual production data on our acreage now and production. And when we look at the offset production from other operators in the area compared to what we found, we just believe that we can be a little more aggressive in that reserve growth than we were at the beginning of the year. It is a lot harder data we're looking at. It is tending right now, as Bob noted, we're going to be moving these rigs to the earlier areas. So, I think it is fair to say that the oil volumes, again, they tend to be less than the gas volumes, because of the commercial value. So if we keep focusing on the oil side, I think you'll see the growth in the area that we've been talking about. That if we were back to the gas side, again, back to results we've seen, we see a lot of future opportunity grow reserve on the gas side. Very significant. So it is all about the results we've seen. The data we've seen, both ours and other industry participants.

If you recall in our February analyst meeting, we tried to keep everybody cautious, because we have yet, at the time, we had yet to drill an Eagleford well on our acreage, we've now have three. We have test production. We actually drilled several others we haven't completed. That gives us a much higher level of confidence of what the Eagleford shale looks like.

All right. And then are we asking, this was a question that was proposed earlier in terms of production mix. It looks pretty constant on average per year. Would you expect proportion to be up in 2011?

I think we've guided slightly up, and it is in our revised guidance for the full year it is a little more oily than our previous guidance.

The needle in the whole mix takes quite a bit more production. So I think our guidance shows it slightly more oily. Just slightly. That takes time to really build that up given the entire mix of the production.

Yeah. Again, I think if you built in the numbers, we're just a little under 60% oil and liquids for the year. I think the best way we can answer that is strategically we're going to be driving to keep that close to the same number at year end, given the dynamics of costing environment. But we need to put some caution there in that we're actually going to be drilling some very nice high impact types of things that also have high risk. As we go back into Bay de Chene and do some things in Lake Washington, Masters Creek and some of the other things we've talked about and should those be real oily, then they could have an impact on the exit rate certainly into our 2011 early production protrial. So strategically, we're trying to keep it close to where it is. We've got some upside activity moving around on us.

And lastly, your partner and joint venture has been using restricted flow rates. You operated wells in Eagleford area, are you going to be doing the same sort of thing?

Flow rates.

Yeah, we've also taken more of an approach where we want to manage the EURs and we want to manage the pressure draw downs and we want to manage how the well is cleaned up. We never really let these wells just open up and rip.

We didn't do that on the test either. Some of these wells, Fasken is a good example, we could have cracked that up and gotten a much higher test. We're much more interested much more in managing the reservoir than we are in trying to come out with some numbers.

In terms of using the word restricted I think it is best said that, in the Fasken area, it is a pipeline marketing statement that we're making when we saying it is restricted. And we'll give some updates certainly at the next quarter of what kind of pressure that well has got and let you ought to be able to see, it is a great-looking well, and we're just producing. In the AWP joint venture area, that's just a timing thing for us. As we're bringing more production in down there, we do have to pay attention to rich production, lean production, high condensate production, the different lines in the area are set up for different types of production. So we're just making some facility suggestions there in short-term. It is a little under the 9 million, I think it is producing a little over 6 million right now, but it tested at 9. Strong well. Again, looking at pressure and the choke sizes. We're very pleased with that well.

Thanks very much.

Take care, Adam.

(Operator Instructions). Your next question comes from Ray Deacon with Pritchard Capital.

Bruce, I just wanted to review what you were mentioning. You said you just completed an Eagleford well on 100% acreage and one on the JV acreage and also one in the Olmos. Is that right? So I was trying to get an idea next quarter how many wells you might have, horizontal between the Eagleford and the Olmos.

Kind of bringing you current on our activity. With the Olmos, we have drilled an Olmos well down on our area. If that means anything to you. That drill needs to still be completed and fraced, which we expect to happen sometime this month. That's the concept well in terms of going into a developed area and seeing how well that produces. Then in terms of the Eagleford, we have, let me start with the JV well. We have finished drilling one horizontal well in the JV acreage and we're now taking that rig and beginning a third well. That well is expected to be fraced this quarter. It may not be until early June. We're trying to firm up that schedule. Then with regard to 100% Eagleford wells, we have drilled one completely called the Haze 1H. That should also be fraced sometime later this month. We have drilled another Eagleford well up in the northern part of the area. We drilled the vertical pilot hole in the Eagleford. We ended up with a good section which we don't have the Olmos developed in that part of our acreage. But the Eagleford section looks very much similar to the PCQ well that we announced the test on earlier today. We now have to drill that horizontal, but that will get done and that fraced. So I think clearly during the second quarter, all of those things, at least four wells, if not more than that.

Let me just try to give you the bottom number. There should be five switch operated and at least one JV operated fracture stimulation during the second quarter, two of which would be Olmos wells.

Got it, yeah. That's very helpful. And thanks. I didn't hear any update of the deeper tests at Bay de Chene and Lake Washington. Are you still looking at one of those drills later this year?

Yeah. When we talk about bringing that into the free well program at Bay de Chene, two of those are very meaningful tests. Higher risk but higher returns. In terms of lake Washington, no, we're still working up a number of deeper tests there for later on in the year.

Great. Thanks very much.

(Operator Instructions). Gentlemen, there are no questions at this time. Would you like to proceed with any closing remarks?

Well, we'd like to thank everyone for joining us for our conference call and look forward to getting back with you in the second quarter Cavs conference call. Thank you.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.