Swift Energy Company Q1 2010 Earnings Call Transcript

May.10.10 | About: Swift Energy (SFY)

Swift Energy Company (NYSE:SFY)

Q1 2010 Earnings Call

May 6, 2010 10:00 AM ET

Executives

Paul Vincent - Director of Finance & IR

Terry Swift - Chairman & CEO

Alton Heckaman - EVP & CFO

Bruce Vincent - President

Bob Banks - EVP & COO

Mike Kitterman - SVP of Operations

Jim Mitchell - SVP of Commercial Transactions & Land

Analysts

Jason Wangler - Wunderlich

Michael Hall - Wells Fargo

Leo Mariani - RBC

Derrick Whitfield - Canaccord Adams

Biju Perincheril - Jeffries

Adam Leight - RBC

Ray Deacon - Pritchard Capital

Operator

Good morning. My name is [Carla] and I will be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy first quarter earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions)

Thank you. Mr. Paul Vincent, you may begin your conference.

Paul Vincent

Good morning. I’m Paul Vincent, Director of Finance and Investor Relations. I’d like to welcome everyone 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 first quarter; followed by Bruce Vincent, President; and Bob Banks, EVP and COO, who’ll provide an operational update. Terry Swift will then summarize before we open it up to questions. Also, present on today’s call are Mike Kitterman, 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 our 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.

Terry Swift

Thanks Paul. Again, thank you for joining our conference call today. It’s very exciting time for Swift Energy Company. During the first quarter of 2010, we brought our first production from the Eagle Ford Shale 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 trend has the resource potential to be transformational for the company.

As of the end of the quarter, we had two operated horizontal rigs under contract 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’s 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 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 an upset about our commitment to health, safety and environment. Swift Energy is committed to a safe workplace, environmental stewardship and operational excellence. We’ve recognized the importance of integrating health, safety and environment, HSE management processes into all of our work activities. We approach all of our operations with this attitude and we’ll 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 are now drilling the vertical surface holes for our horizontal wells with a small rig as part of the 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 service providers, vendors and midstream partners to reduce supply and service delays as much as possible.

While natural gas prices remain weak, the oil and natural gas liquids market pricing is considerably strong. Our current production mix is weighted towards crude oil and natural gas liquids, which provides stronger cash flows. We have adjusted our 2010 capital program to take advantage of this stronger liquids pricing environment by focusing our activity on 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% to10% to a new range of growth of 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 like to highlight some of the results of the first quarter, which include the Swift operated Fasken 1H, the PCQ 1H and the non-operated Bracken JV 1H, Eagle Ford discovered wells. The Fasken Eagle Ford 1H in Webb County tested at a rate of 9.4 million cubic feet of gas per day, the PCQ 1H 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 AWP joint venture well, the Bracken JV 1H 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 of three distinct areas within our acreage position in the Eagle Ford.

So far in the second quarter, we have already drilled one horizontal well and the Olmos tight gas sands formation, as well as one operated and one non-operated joint venture Eagle Ford Shale well. The operated Eagle Ford well, the Hayes 1H established a new technical drilling limit for Swift Energy of 21 days to TD. 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 work for the company for the remainder of 2010. As activity levels pickup, 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 continued to find large sections of pay sands at relatively shallow depths in this field resulting form this program. We’re now preparing an ultra shallow drilling program for the second half of the year to bring all 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 [up depth] Teton prospect 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 3D seismic interpretation of the salt dome at BDC.

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 spread by our partner during in the second quarter. We’re also preparing plans for our 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 Geosteering Technology and drilling techniques, which is successful may lead the sizeable increases in oil production and reserves in this area.

Opportunity sets life for long, we put together Swift Energy Company don’t happen by accident. Our inventory availed a natural gas development in 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 experience. We come out of that strong as I mentioned earlier, it’s a very exciting time at Swift Energy and I’m proud to be a part of it.

Now, I’ll ask Alton to present first quarter 2010 financial results.

Alton Heckaman

Thank you, Terry and good morning everyone. Having balance in our portfolio that serves with the well during the first quarter of 2010 as we’ve seen continued improvement in oil prices the 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 ‘09.

Our income from continuing operations was $14.2 million or $0.37 per diluted share, consistent with 4Q ‘09 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 ‘09 levels was within our guidance at 2.04 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 per Boe in 1Q ’10. Swift’s average realized price increased to $53.81 per Boe due primarily to crude oil prices increasing to an average of approximately $78 per barrel received, compared to $41 per barrel in 1Q ’09, allowing Swift to increase its quarterly oil and gas revenues 44% over first quarter 2009.

As Terry mentioned, we continued to focus on our controllable cost to metrics, which all came in at or below guidance for the first quarter. G&A came in at $4.52 per barrel; DD&A came in at $18.72 per Boe; production cost came in at $9.12 per barrel. Interest expense came in at $4.07 per Boe, and production and ad valorem taxes came in well below our guidance at 10.5% of revenue.

The result was income from continuing operations for the quarter of $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 ‘10 came in at $64 million, or $1.69 per diluted shares, while EBITDA was $70 million for the quarter. Quarterly CapEx on a cash flow basis was $63 million.

Let me spend just a moment to again highlight Swift’s solid financial position. As of the end of the first quarter of 2010, we had no outstanding balance under our line of credit. With respect to our line of credit facility, with our 10-member bank group, it currently runs through October of 2011, our borrowing base and commitment amount were recently reaffirmed at $277.5 million. Thus, we are well positioned to fund our CapEx projects for 2010.

With respect to Swift hedging activity, we have purchased floors covering a meaningful percentage approximately half of our domestic oil and natural gas production for the second quarter of 2010, at an average NYMEX strike price of approximately $4.73 per MMBtu per gas and $78 per barrel for oil. So we see our website for complete and current detail hedging information, and as our ways, we’ve included additional financial and operational information in our press release including guidance for the second quarter as well as for full-year 2010.

Swift is well positioned financially to take advantage of the opportunities that are in front of us and we have a strength and flexibility to handle to continuing price volatility that’s become the norm in our industry.

With that, I’ll turn it over to Bruce Vincent for an overview of our operations.

Bruce Vincent

Thanks, Alton and good morning everyone. We certainly appreciate everybody listening in today. Today, I will discuss the 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. Bob Banks, will then provide greater detail on significant operational successes of the quarter and their effects on our full-year plans.

Beginning with production, Swift Energy’s production during the first quarter of 2010 totaled 2.04 million barrels of oil equivalent, or 12.27 billion in 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 the longer-term project efficiencies, we actually slowed our drilling and 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 schedule and an operating environment that emphasizes cycling.

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 high-end of our production guidance for the year, but also allows us to raise our reserved guidance to 8% to 12% growth over week, and to raise our year-end average daily production, exit rate forecast to 28,000 barrels of oil equivalent per day.

First quarter production when compared to first quarter of 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, the 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 an unusually cold or colder temperature during the winter. Unscheduled maintenance at our 6,700 platform in Lake Washington, and of course natural declines. For the second quarter of 2010, we expect production to increase as our drilling and competition activity increases and new production comes online.

For our first quarter 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 Eagle Ford Shale formation in South Texas. One shallow vertical oil well, to be a development well was drilled in the Olmos formation at AWP field and McMullen County, Texas also during the quarter.

Two rigs capable of drilling horizontal wells in the Eagle Ford and/or Olmos are active in South Texas with their principal focus being the Eagle Ford Shale. A lower cost rig that is drilling surface holes on our horizontal locations is also active. Additionally, a non-operated rig is currently targeted in the Eagle Ford Shale in our joint venture area, and operated by our joint venture partner. This rig is operated 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 in abandoned. One of the wells was plugged as a result of mechanical difficulties, but we’re successfully re-drilled in the second quarter. One barge rig is currently operating in Lake Washington. We also expect the barge rig to move into the Bay de Chene field later in the second quarter to begin drilling the well in that field.

I’ll briefly review our activity in each of our core operating areas for this quarter, and let Bob detail the highlights of our recent activity. Starting with Southeast Louisiana core area, which includes the Lake Washington and Bay de Chene field, 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 net, a decrease of 18% when compared to the fourth quarter of 2009 volumes. Primarily due to freezing problems associated with unusually cold temperatures, as well as unplanned equipment repairs and four that expected first quarter drilling results along with of course natural declines.

Bay de Chene’s 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 an activity in Lake Washington field and one rig moving into the Bay de Chene field later in the second quarter and drilled perhaps up to three wells this year, in our South Texas core area, which includes AWP, Sun TSH, Briscoe Ranch and Las Tiendas fields.

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 of 2010 production in this area. This increase was primarily attributable with the contribution from the R Bracken 36H and the AFP 1H in our AWP field, our two newest horizontal completions in Olmos field.

In McMullen County, two more horizontal discovery wells, the PCQ 1H, 100% working interest and the Bracken JV 1H, a 50% working interest were drilled to the Eagle Ford Shale formation during the first quarter. These wells represent the company’s first Eagle Ford production in McMullen County.

In Webb County, the Fasken Eagle Ford 1H horizontal discovery well was drilled and completed and it’s producing at a restricted rate because of the current market limitations. While our midstream constraints in this area presently, we believe this is a highly perspective area for future development and additional market capacity can be easily added.

These successful discoveries de-risk, portions of our acreage provide us with our own production in reserves 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 our 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 it was recently put online. Swift Energy currently has one way to drilling shallow surface holes and two operated rigs drilling horizontal Eagle Ford objectives in McMullen County. In areas we believe will yield oil and liquids rig gas production. One non-operator rig is also drilling in our joint venture area in McMullen County.

One, 100% horizontal Olmos well, one horizontal Eagle Ford well and one 50% non-operated joint venture Eagle Ford well are actually already concluded drilling operations during this quarter and are now waiting 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 attributed to 1,668 barrels of oil equivalent per day or about 10 million cubic feet equivalent per day and our production in the first quarter of 2009, there was no significant operational activity in this area during the quarter.

In our South Louisiana core area, which is comprised of Horseshoe Bayou/Bayou Sale, Jeanerette, Cote Blanche Island, and Bayou Penchant production averaged approximately 1,697 barrels of oil equivalent per day or about 10.2 million cubic feet equivalent per day again net, during the third quarter.

Now, let me turn the call over to Bob Banks, to review further operational highlights for the first quarter.

Bob Banks

Thanks Bruce. At the Lake Washington field, we drilled three wells completing one and plugging two during the quarter as mentioned. The CM No. 410 was drilled and we’ve measured depth of 5,388 feet and encountered 79 feet of true vertical net pay. This well was averaged approximately 350 gross barrels of oil per day over the past 30 days.

During the first quarter, we drilled a fourth well that encountered commercial qualities of hydrocarbons that was plugged due to a mechanical failure. This well was re-drilled in April as the CM No. 411 to a measured depth of 5,481 feet. This well logged 334 feet of true vertical net pay of the multiple horizons and will be placed on production early in the second quarter.

Also during the quarter at the Lake Washington field, all seven of our re-completions that were performed were successful. Average initial production from these operations was approximately 339 gross barrels of oil equivalent. Other activity in the field during the quarter as mentioned included our preventative maintenance program, where we identified a small leak at the bulk separator of our 6,700 facility, which normally handles 2,500 barrel of oil per day. Although, unplanned repairs 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 amine treating system at the CM3/Caseload facility in order to increase needed capacity and service additional gas lift volumes to our wells, this new unit will double treat in capacity to 36 million cubic feet of gas per day and it is further designed to greatly improve reliability and improve our operational efficiencies in particular on the southern end of our field. In the Bay de Chene field, the Tucker Ellis is waiting for a rig to move into the field and as compared with spot a well upon its arrival. This rig will drill up to three wells in and around Bay de Chene in 2010.

Now in the South Texas at the AWP field, I would like to first provide you an update with our horizontal Olmos drilling program. The R Bracken 36H drilled and completed very late in the fourth quarter of 2009 in store producing approximately 5.5 million cubic feet of gas equivalent per day and it is already produced just short of the one billion cubic feet equivalent in its very short life.

To improve well performance and accelerate recovery tubing installations have been designed for oil 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 Eagle Ford Shale during the first quarter. The Fasken Eagle 1H well was drilled in one county and completed with a 12 stage frac. The initial production rate of this well was 9.4 million cubic feet of gas per day with flowing tubing pressure of 4,550 PSI on a 22/64 inch choke.

As Bruce mentioned, due to pipeline sales limitation, this well has been produced at a curtailed rate of one million cubic feet of gas per day, but this result is really at the upper end of our expectations and we believe that significantly de-risk are very meaningful acreage position in this area.

In Northern McMullen County, we drilled and completed the PCQ 1H. This well was completed with a 13 stage frac and has 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 24/64 inch choke. We are further delineating this Northern acreage in the second quarter and expect the frac stimulate three additional Eagle Ford wells during the quarter.

In our joint venture area, McMullen County, our partner drilled the Bracken JV 1H well. This well was completed with 11 stage frac 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 22/64 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 about same rate.

Terry and Bruce had both mentioned the fact that we will be guiding our calendar year production volumes slightly lower. The primary reasons for this are: First, one of our big South Texas rigs left the field at to 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 of securing longer-term contracts for the two big rigs and by bringing in of smaller rig the robust drill surface holes in advance of mobilizing in the bigger rigs. We believe that this type of operation will prove to be both efficient and cost effective.

Second, some of our frac schedules were not met its timely as expected. We have mitigated this potential issue in the future by first to securing a longer-term contract, which specifies track dates and second by building a much larger water management infrastructure in the AWP area that includes high rate water wells, storage pits, low back pits and flow lines. This infrastructure combined with the batch drilling approach will allow more flexibility for us and our service providers in meaning 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 a lean gas opportunities, rich gas opportunities and very condensate-rich opportunities across our Eagle Ford acreage. In this regard, we are altering our originally proceeds 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 liquid commodity pricing. These wells while yielding stronger economic returns do not yield the same production volumes as we lean our gas areas of much of our new forecasting takes this new mix into account and lowers our first yield production volumes.

Although we now expect to produce likely less crude oil and the natural gas during 2010 then 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 in a whole lot of momentum heading in to 2011. Now that we have hard drilling in production data from our own wells in the trend, we believe our planning scheduling and execution is where we needed to be to implement what appears to be a very major development program in an almost completely undeveloped asset.

Thanks for your attention this morning, and I’m going to turn it back to Terry to recap.

Terry Swift

Thanks Bob. Before we open the line for questions, I’ll summarize Swift Energy’s first quarter results and review some of the highlights from today’s call. Our first Eagle Ford Shale production is now online from two operated wells and one non-operated well, the phase of our activity in this play is picking up and we’re seeing meaningful production in reserved growth from this trend and the years to come.

Although we’ve lowered full-year production guidance slightly, we are increasing our reserved guidance from growth that was in the 5% to 10% range to growth that is now on 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 barrels of oil equivalent per day.

In Southeast Louisiana, we’re bringing in a rig into the Bayou Sale area to begin drilling wells with have the potential to add production and reserves and setup additional drilling inventory. Our cash flows and balance sheet can support the near term capital intensity of accelerating activity in the Eagle Ford 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 project.

With that, we’d like to turn it over to the question-and-answer portion of our presentation.

Question-and-Answer Session

Operator

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

Jason Wangler - Wunderlich

On the Eagle Ford, 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 you can still spread that out to come more delineate the acreage?

Terry Swift

I think we’re very active there right now. As I mentioned, we’ll be tracking three new wells here during the quarter and we have some additional drilling we’re doing up there, but we are trying to balance that out a little bit with evaluating some of our other acreage position and I think we’ve always said this is an evaluation here, 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.

Jason Wangler - Wunderlich

Then obviously with the frac issues and obviously you're trying to kind of 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 pretty tight?

Terry Swift

Well, there’s been some pressure, but 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 the major providers are pressuring the industry up a little bit.

Operator

Your next question comes from the line of Michael Hall with Wells Fargo.

Michael Hall - Wells Fargo

On the Fasken well, as well as the JV well, do you have Btu content on that gas and is that a purely dry gas stream in both of those wells there?

Bob Banks

Yes, both of those are little under 1000.

Michael Hall - Wells Fargo

Then on the cost per well front and Eagle Ford, you operated Eagle Ford wells, any color there?

Bob Banks

Well, I can say that, it depends on what we’re doing on many of these wells so far. As I think we’ve talked about the past, we’re drilling pilot holes, we’re getting full suites of logs, we’re cutting cores, like I can say that as Terry mentioned, I believe our Hales well one of the next wells that would be fracking up in the north area. We drilled that well in 21 days and I think we’ve 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 into the $8.5 million range. I think for longer-terms development moment, I think we’ve always kind of said 5% to 7% is the good ballpark and I don’t see anything that would change our thinking on that.

Terry Swift

This is Terry. 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 expensive. We’ve also taking full cores of these pilot holes on the way down, that’s more expensive.

We’ve also have been drilling micro seismic of these two fine tune and optimize our activity in terms of how we frac the wells, but we’ve also established the initial water production handling, where we drilled the water wells in the area, drilled the big frac ponds and set ourselves up for additional activity, as well as the pipeline of facilities that are drilling in there. So these initial wells are carrying a lot of the appraisal process.

Michael Hall - Wells Fargo

Two more if I may. Number one, infrastructure, I mean it seems like a very result up to Northern AWP and a lot of condensate production. What sort of infrastructure needs do 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?

Terry Swift

Actually, while we do have some changes in terms of the types of facilities you bring in relative to gas. Infrastructure is in good shape there. This is an area that had a lot of oil production in the past and right now dropping about that’s in the Northern AWP area. We can actually get the facilities in very timely, in some cases and much quicker than to say the gas out at 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 it could be a little bit slower, so that puts a little twist on it and 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.

Michael Hall - Wells Fargo

When you talk about production facilities that the well you’re currently waiting on, is that just like a stabilization tanks sort of condensate or any additional color on that?

Terry Swift

Yes, basically tanks in some additional H2 safety equipment, it was really all we’re talking about that.

Michael Hall - Wells Fargo

Then you talked about mix, in your project mix. What’s the kind of mix outlook for the end of the year, if you will? So you’re about 39% gas this quarter? What’s the outlook like maybe in your fourth quarter projections or exit rate, if you will?

Terry Swift

Let’s get back with you on that numbers.

Bob Banks

Let’s dig into the fourth quarter number to try to get number. I mean the big frac, Michael that 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 depended on results. We do know differently today versus three months ago, we now have drilled our first well in several places in our acreage.

So we now have production on our acreage and we have a better understanding with the Northern AWP is very liquids-rich area and we want to direct more activity to that for obvious reasons, but we still want to do some evaluations of our acreage for in terms of developing a long-term development plans.

Michael Hall - Wells Fargo

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 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?

Bob Banks

I think we’re obviously that something we’re looking at, it’s not just the tuning successful operating wells and the JV well, but as I mentioned we’ve successfully drilled another almost horizontal well and that’s actually a proof of concept work that’s actually drilled in the area where other vertical wells drilled and so we’re going to really be looking at the results of that, we drilled on 1H well and that looks to be in a very good location in the northern part, good looking shale section.

So we expect that to complete drill well, we’ve actually drilled vertical pilot hole and another well on the northern part of the field along it has a very good looking both on the sand and it’s on developed up in that area as well as the Eagle Ford section we’ve still have to drill the horizontal section, but we think it looks very good based on the power off we just need to get a little bit more results under our dealt before we look it ramping up, that I think it’s certainly be easy to add another rig and we don’t think too hard about it.

Operator

Your next question comes from the line of Leo Mariani with RBC.

Leo Mariani - RBC

Obviously, it looks like you guys drilled one well here, I think clearly when the oil condensate window and a couple of other wells that were gas, basically well results and well just seems many tree, can you guys give a breakdown how much risk is given the oil window and how much more is in dry gas window?

Terry Swift

I think we would be shooting from the hip, if we answer that --

Alton Heckaman

I mean it’s actually I think I said, we have kind of three categories here. We have the real kind of liquids-rich area, but we also have a rich gas area and we have kind of a more leaning gas area, but I would say in terms of what percentage would be rich gas will condensate heavy guess, I would say, good half of our acreage would be get contained those types of attributes without being only specific.

Bob Banks

As I want to quantify, that’s really just a missed and that’s not based on us on a significant geologic review our acreage.

Terry Swift

We’re still evaluating, we’re still drilling wells to test that.

Bob Banks

I want to add a couple of more comments to that, because I think it’s an important question, in our wells area we have not drilled our first well yet.

Terry Swift

That’s a nice chunk of our acreage, I think it’s north of 15,000 between 15,000 and 20,000 acres over in that area, it’s on strike to some really high condensate almost a oil well so, if you go to east of it, but also if you go on strike in south it’s more gassy and high of some rich gas.

So our Tuihu wells an area we still need to do apprise and evaluate and you get into the Fasken area, we got over 8.89 thousand acres over there, while the first well came out fairly dry, I think you got to get these wells on production and we’ve seen some variation in very small areas for example down in our almost acreage down in our almost acres down in AWP, in the south part of that acres we’ve seen some very high oil and compensate contributions just a mile or two away from some rich gas. So I think we need further development to give you more color on that.

Leo Mariani - RBC

Jumping over to Masters Creek is an area you mentioned. You’ve got some kind of oil targets there. Can you give us a little bit more color kind of our outlook, which you’re looking for and what the size of your acreage positions to be?

Terry Swift

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 over 10 million cubic feet a day, very rich gas back in the early development period or all I can say is that, the technologies are much, much better today than when those wells were first drilled and those wells were put 2,000 acre units and we now believe that there is an opportunity for down spacing that, we’ve also believed that there is opportunities to drill more effectively, and so we think that was part of the reason that you had variation in wells versus wells out there, but we’ll easily a million barrel plus type the wells in high side.

In our judgment there are a lot of wells still in place in that area just to question whether or not we can use the technologies to unleash it and that area is a little bit deeper vertically about 15,000 feet vertical, but we start turning oils out I guess, it’s a much higher temperature in our pressure environment and one of those things it’s been developed from a technological standpoint is gesturing equipment that can withstand those kind of temperatures today that we did really have 10, 15 years ago when we and other industry members were developing that area so and going back and reviewing our existing wells.

We believe a lot of them ends really out of zone through some of that horizontal wells, not only the 2,000 acres spacing, but the fact that the oil side of there didn’t stay in zone as well as we believe you can today with the technology in which available, so that’s also not just down spacing, but utilizing more advanced technology that will enable us to drill better wells.

Leo Mariani - RBC

Roughly, how many verticals did you guys drill out there historically and what’s your acreage with it?

Terry Swift

Well historically, some of the wells we’ve done very, very well, I mean there were number of it produced up to 2 million barrels per well.

Bob Banks

Three to five Boe (Inaudible).

Terry Swift

Yes, those were all horizontal…

Bob Banks

We got about 20,000 acres as held by production and again that would be on 2,000 acres facing that could be against by at least a 1,000.

Operator

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

Derrick Whitfield - Canaccord Adams

Just a few extra questions on your Eagle Ford and Olmos, just specifically over AWP test wells, and you can sort of bring it up a 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?

Terry Swift

Yes, it really broken 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 is the three different windows.

Bob Banks

Yes, in terms of where the transition occurs, we’re still testing that. It would be premature to draw a line at this point.

Derrick Whitfield - Canaccord Adams

Certainly on that JV well, there was no condensate with that well?

Terry Swift

Yes, that’s correct.

Derrick Whitfield - Canaccord Adams

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

Terry Swift

Yes, probably just by using the sputter rig on the well alone just in terms of differential in time and cost is about $300,000, but there are some additional efficiencies we’re working on to try to even can 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 and if you’re not completely cleared off then they have to go somewhere else before they can comeback.

So part of the sputter rig program in addition to the cost savings gives us the flexibility we need to shorten that time from rig off to frac crew on 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.

Derrick Whitfield - Canaccord Adams

Then moving to the Olmos, you guys mentioned the test well a little bit earlier, could you add any further color on how that might change your view on how much acreage you have in perspective for horizontal development?

Terry Swift

Yes, I think we talked about that a bit in the Analyst meeting. We have around 30,000, that’s undeveloped 40,000 acres undeveloped in the Olmos and then we think we’ve seen so far in that Olmos is very rich gas or have good condensate yield associated with it.

Bob Banks

We haven’t seen any Olmos production to be dry, generally 1200 Btu, even 1300 and sometimes that has condensate with it. The well that we talked about being a proof of concept well, we’ve drilling in an area where we had some vertical drilling. We need to complete that frac and get some 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.

Derrick Whitfield - Canaccord Adams

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

Bob Banks

Yes, because he’s talking about --.

Terry Swift

I’m talking about the undeveloped position, that’s right.

Bob Banks

If you can go back into developed areas, we just don’t know this yet. So we don’t want to put something on it, but it’s something we’ve discussed in internally, we don’t think we’ve gotten sufficient drainage and what’s the best way to go in and we capture some of those reserves that are in the production developed area for Olmos based on vertical wells or can you put horizontal rigs through there.

We just need to work through that. This particular well that we just drilled and has drilled not yet completed in frac did drill with nice pressure. So we’re kind of looking forward to the completion in frac, but even one well won’t give you the full answer. We just need something were evaluated, because we think there’s more reserves in the developed area that we can get up.

Terry Swift

I think we’re very happy, you’re asking about the Olmos. We’re very, very pleased with the results we’re getting, and we think it’s going to get better and better. This 36H well has just been and absolutely phenomenal well and that’s what we’re going further.

Derrick Whitfield - Canaccord Adams

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?

Terry Swift

No, not at all, in fact our whole strategy, 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, or the west. So we’ve kind of meditated the risk by not working a given area too extensively. In this 411 well, where we had just an unbelievable amount of pay, it’s cut up on the Northeast part of the dome.

Derrick Whitfield - Canaccord Adams

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

Bob Banks

Yes, with the smaller ones we didn’t workout. We had a mechanical failure there. It didn’t allow us to complete to get well bore. So we have to plug that well bore and then re-drill the well. So it really counts as a second well and you plug one, but it really because of the mechanical failure of the well bore and when we re-drilled it we ended up with 300 or something feet to net vertical play.

Operator

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

Biju Perincheril - Jeffries

Lake Washington, you talked about some ultra shallow wells there. Is that in addition to, I think at the Olmos you’re drilling into 10 to 15 wells there this year?

Terry Swift

Yes, that is in addition and we have a very shallow target called the A5 sand, that’s up around 2,000 feet. In this 411 well, we talked about where we had such a lot extensible amount of pay. We dint see a very nice A5 sand there, which is at shallow target. We know that we have lots of opportunity for that kind of drilling on the dome, it’s very quick. We’re talking seven, eight day well, so the stuff you can bring into the system pretty rapidly.

Biju Perincheril - Jeffries

How many wells are we talking? Is that program already underway?

Terry Swift

Now it’s not underway yet and I think for this year we’re targeting five to six, seven of those kinds of wells.

Biju Perincheril - Jeffries

Then with all those activities, 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?

Terry Swift

You’re talking about production numbers?

Biju Perincheril - Jeffries

Yes.

Terry Swift

We’ve just remodeled some of that. That’s why I’m hesitating a bit. We may 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 ratio.

Bob Banks

I’ll say that, we have developed a strategy that basically a risks to decline to try to stay on top of that and bringing some exploitation activity both in 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 starting to access some reserved potential that could actually bring the production back up in both those fields, but we’ve got to get real deeper to do that.

Biju Perincheril - Jeffries

Then turning over to Eagle Ford, I think you had only one well planned in Fasken and one well planned for the southern field. Is that still the plan or any changes there?

Terry Swift

Yes, we hope in dialogues on the market outlook, there are lot’s 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 out sorted out; and then down in south AWP although, we have a couple of combination opportunities down there between the Eagle Ford and Olmos. So we will drill at least one Eagle Ford there, but there is a possibility that we would drill another one that we could either complete in the Eagle Ford or all the Olmos depending on how the logs look, so I would say it’s probably at least one.

Operator

Your next question comes from the line of Adam Leight with RBC.

Adam Leight - RBC

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

Terry Swift

We’re adding mainly the reason we were optimistic than we were, because we got a firm data and long data and actual production data on our acreage now in 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 little more aggressive when that reserved growth can be work beginning of the year, it’s lot harder than it we were looking at, it is tending right now to be as Bob noted, that we’re going to be moving this rigs to the oilier areas.

So I think it’s fair to say that, the oil volumes again they tend to less than the gas volumes, because of the commercial value, so let we keep focusing on the oil side, I think you’ll see the growth in the area that we’ve been talk about, but 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’s all about the results we’ve seen that data we’re seeing both ours and other industry participants.

Bob Banks

Yes you have to get to back to our goals that in our February Analyst Meeting, we were proud to keep everybody cautious, because we have at the time and yet the drill and Eagle Ford well on our acreage and we now have three and we got test production. We actually drilled several others; and we have a completed not just gives this a much higher level components of what the Eagle Ford Shale looks like on our acreage.

Adam Leight - RBC

Then are we asking, the different way of question it proposed driller in terms of at production mix, it looks pretty constant on average per year. Would you expect the liquids proportion to be up in 2011?

Terry Swift

I think we’ve guided slightly up and it’s in our revised guidance added for the full-year, it’s a little bit oilier than our previous guidance.

Bob Banks

I think the new needle of the whole mix, takes quite bit more productions, so I think our guidance shows it is slightly more oilier but just slightly and that’s because it takes time to really build that up given the entire mix of the production right now.

Terry Swift

Yes, again I think if you go to numbers, were we just a little under 60% oil and liquids for the year. I think the best way we can answer that’s strategically we’re going to be driving the keep that close to the same number at year end given the dynamics with the farseeing environment, but we need to put some caution there and we’re actually going to be drilling some very nice high impact types of things that also have high risk.

As we go back in the Bay de Chene do to some times unlike watching the Masters Creek and some of the other time that we talk about and we should those be real oilier then they could have an impact on the exit rate or certainly into our 2011 early production profile. So, our strategically we’re trying to keep it pretty close to where it is, but we’ve got some upside activities that could move it around on us.

Adam Leight - RBC

Lastly, your partner and joint venture has been using restricted flow rates. Your operated wells in Eagle Ford, are you going to be doing the same sort of thing?

Bob Banks

Restricted well rates on our operated…

Terry Swift

Yes, I mean we’ve always taken more of an approach, where we want to manage the EURs and we want to manage the pressure draw down and we want to manage to way the well is cleaned up. So, we would never even in our Olmos wells before the Eagle Ford we’ve never really met these wells just open up in rip.

Bob Banks

We’re lacking again that on the test, either some of these wells Fasken is a good example we’ve got to crack that up and got the much higher challenge.

Adam Leight - RBC

You can get numbers.

Terry Swift

That’s not we’re interested a much more in managing the reservoir than we are try to come out with some numbers.

Bob Banks

Well, in terms of less using the word restricted, I think it’s best to say, then your Fasken earlier, it is a pipeline marketing statement that we’re when we saying it is restricted and we will give some updates certainly at next quarter what kind of pressure that wells got and let you will be able see it for great look at well and we’re just producing a million of that, in the AWP joint venture area that’s just a timing then for us as we’re bringing more production in down there.

We do have to pay attention to where there’s rich production, lean production, high condensate production with different lines in the area are set up for different types of production. So, we are just making some facilities’ adjustments there and short-term, it’s a little under the $9 million. I think it’s producing a little over 6 million right now, but if tested, it might strong well, again looking at presses and choke size as we’re very pleased with that well.

Operator

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

Ray Deacon - Pritchard Capital

Bruce, I just wanted to review what you were mentioning. You said you just completed an Eagle Ford 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 Eagle Ford and the Olmos?

Bruce Vincent

That’s kind of bringing you current on our activity. I saw with the Olmos and we have drilled an Olmos sand well down our half leased area that means, you think to your net and real leads to still be completed in fact, which we expect to happen sometime this month. That’s the put to the contract well in terns of going to a developed period see and we how well that produces.

In term of the Eagle Ford we are going to start with JV well, so we have drilled finished drilling one horizontal well in the JV acreage and we’re not taking that rig beginning referred well, that well expected to be frac this quarter, it may not be in early June, we’re trying to filling up that schedule. Then with regard to 100% Eagle Ford wells, we have drilled one completely called Hayes 1H that shale wills be fraced sometime later this month.

We have drilled another Eagle Ford well up in the Northern part of the area. We drilled vertical pilot hole and along through the Eagle Ford, we end up the good Olmos section, which we don’t have the Olmos developed in that part of our acreage. So that’s also plus that the Eagle Ford section looks very much similar to the PCQ well that we’ve announced just on earlier today. We now at the drill on horizontal, but really get down a nice track, so I think clearly during the second quarter, all those things that have at least four, or else if not more than that.

Terry Swift

Let me just try to give with you the bottom number, there should five Swift operator, then at least one JV operated fracture stimulation during the second quarter, two of which would be Olmos wells.

Ray Deacon - Pritchard Capital

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?

Terry Swift

Yes, when we talk about bringing that rig in for the three well programs at Bay de Chene, two of those are very meaningful test with higher risk, that higher return. In terms Lake Washington, we’re still working up a number of deeper tests there for later on in a year.

Operator

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

Bruce Vincent

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

Operator

Ladies and Gentlemen: This concludes today’s conference call. You may now disconnect.

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