SilverBow Resources Inc (SBOW) 2011 Q1 法說會逐字稿

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)

I will now turn the call over to Mr. Paul Vincent, Director of Finance and Investor Relations. Sir, you may begin.

Good morning. I'm Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy's first-quarter 2011 earnings conference call. On today's call, Terry Swift, Chairman and CEO, will provide an overview. Alton Heckaman, Executive Vice President and Chief Financial Officer, will review our financial results for the first quarter. Then Bruce Vincent, President, and Bob Banks, Executive Vice President and Chief Operating Officer, will provide an operational update. Terry Swift will then summarize before we open up the line for questions. Also present on the call is Jim Mitchell, Senior Vice President 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 assumption, 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.

Thanks, Paul, and thank you again for joining our conference call today. Our first quarter 2011 results provide an excellent example of the quality and prospectivity of our asset portfolio. We now have an expansive resource development underway in South Texas, meaningful traditional oil production in Southeast Louisiana and an emerging resource development in the Austin Chalk of Central Louisiana. The performance of these assets lead to a 21% increase in production over fourth-quarter 2010 levels. This performance, particularly in South Texas combined with the extensive project planning that is ongoing, have given Swift Energy visibility on production and reserve growth for many years to come. Improved asset performance also leads us to raise our full-year production guidance today. We now expect our production to grow 30% to 33% above our 2010 levels. Previously we had expected to grow production 25% to 30% over the prior year levels. As our asset portfolio matures and our execution continues to improve, we will continue to focus on value creation and meeting or exceeding expectations.

During the first quarter of 2011, we completed our first 2 extended lateral Eagle Ford oil wells. Those wells were drilled to lateral lengths somewhat less than the 6000-foot model that we now have in our new design. But the initial production from each of these wells was above 1000 barrels of oil per day. We're extremely pleased with these results and we're evaluating adding another rig in our 2011 program and dedicating it to accelerating oil production from the Eagle Ford and Olmos formations in this Northern portion of our AWP field.

We also grew our average daily net production 4% in our Lake Washington field in the first quarter. This was accomplished without the benefit of new wells being added, instead our ongoing recompletion and production optimization programs performed extremely well. We have resumed drilling in the field and will bring several oil wells online in addition to our production maintenance activities this year.

Along with this production growth, we are intently focused on controlling our cost structure. We have made considerable efforts to expand our ability to manage costs throughout our supply chain. This doesn't make us immune to service cost inflation, but it does allow us to have visibility on our costs and understand any increases that may take place and plan for those increases well in advance. By incorporating cost increases into our planning in this particular environment, we are able to budget and measure project economics much more effectively. Presently, approximately 40% of our major spending is accounted for under strategic business alliances and long-term contracts. As our asset base matures and continues to provide visibility on the revenue side, we will be able to increase this percentage through additional alliances and business partnerships which will help mitigate future price increases of the goods and services used in our operations, equipments and labor.

Bob and Bruce will provide some detail on our operational activity and performance in just a few minutes, but I'd like to take a moment to review some of the highlights of the quarter, which include the Swift-operated SMR 2H and the SMR 3H in our Northern AWP field area, 2 high rate Eagle Ford oil wells which where produced with initial rates above 1000 barrels of oil per day. We realize also higher than forecasted cash flows in 2011, the first quarter. This oil area in McMullen County is an example of where we would put those extra cash flows this year should we increase our capital spending.

In Southeast Louisiana, we drilled our Jelly Bowl prospect in the Lake Washington area during the quarter. This is the deepest well we've drilled in this field since 2008 and we encountered 93 feet of pay in 4 different productive horizons. We should have this well on production this month. As our corporate production profile grows and we can dedicate more capital this area, we will resume drilling deeper wells in the Lake Washington and surrounding area.

In our Central Louisiana/East Texas area, while there wasn't any drilling activity in the quarter, the performance of 2 wells last year in the Burr Ferry area has continued to impress us and our joint venture partner. As a result of this production performance, we expect our partner to move a rig into this area and begin drilling during the summer months. We're also making plans to drill a Swift Energy-operated well in this area later this year. Although we had an exceptional first quarter to start the year, we recognize that our stakeholders want to see us maintain this type of performance. How we finish the year is more important to us than how we started it. We continue to add top tier professionals to our technical and financial teams and identify external threats to our plans in the areas where we can drive improvement so that we realize the kinds of economic and operational returns that will grow the Company. And now I'll ask Alton to present the first-quarter 2011 financial results.

Thank you, Terry, and good morning, everyone. As Terry highlighted, Swift had an exceptional quarter both operationally and financially led by the solid production and revenue growth from both the prior year and sequential quarter. Our production was up over 20% from both the first and fourth quarters of 2010. And as oil prices improve, Swift's financial results for 1Q 2011 reflect this. Oil and gas sales excluding hedging effects were $144 million, a 31% increase from 1Q 2010 and a 25% increase from 4Q 2010. Income from continuing operations was $20.2 million, or $0.47 per diluted share, up from $0.37 in 1Q 2010 and $0.25 in the fourth quarter. Cash flow before working capital changes came in for the quarter at $1.86 per diluted share, and 1Q 2011 production up 29% from a year ago was up 21% from 4Q 2010 at 2.65 million barrels of oil equivalent above our guidance. Crude oil prices were 26% higher than first quarter 2010 levels while natural gas prices were 19% lower. This combination of factors resulted in a net 1% increase in our realized price per Boe in 1Q 2011.

As Terry mentioned, all of our controllable costs and metrics were favorable to guidance for the quarter. Production costs came in at $9.59 per Boe, G&A came in at $3.95, DD&A came in at an even $20, interest expense came in at $3.17 per barrel and production to Ad Valorem taxes came in at 9.2% of revenue. The result was income from continuing operations for the quarter of $20.2 million, $0.47 both basic and diluted well above first call mean estimate. Our effective income tax rate for the quarter was 37.7%, well within guidance. Cash flow before working capital changes for 1Q 2011 came in at $79 million, or $1.86 per diluted share while EBITDA was $95 million for the quarter. Quarterly CapEx on a cash flow basis was $132 million. While hydrocarbon prices have remained volatile, we have continued to lock in price floored hedges when market conditions are favorable. Most recently, for the second quarter of 2011, we executed gas floors covering approximately 50% of our expected production at an average NYMEX strike price of $4.16 per Mmbtu. Please see our website for a complete current detailed oil and gas hedging information on Swift Energy.

Let me spend just a moment to again highlight Swift's solid financial position. As of the end of the first quarter, we had no outstanding balance under our $300 million line of credit and we had $20 million of cash on hand. This strong liquidity position puts Swift on a solid financial footing to execute our 2011 strategic plan. As always, we've included additional financial and operational information in our press release including revised guidance for the second quarter and full year 2011. And with that, I'll turn it over to Bruce Vincent for an overview of our operations.

Thanks, Alton and good morning, everyone. We appreciate everybody listening in today, and I will discuss first-quarter 2010 activity including production volumes, recent drilling results, activity in our core operating areas and our plans for the second quarter of 2011. Bob Banks will then provide greater detail on some significant operational successes of the quarter and their affect on the full year of 2011 plan.

So beginning with production, Swift Energy's production during the first quarter of 2011 total 2.65 million barrels of oil equivalent, or 15.87 billion cubic feet equipment, an increase of 21% from the 2.18 million barrels of oil equivalent, or 13.11 billion cubic feet equivalent that was produced in the fourth quarter of 2010 and slightly above our previously stated guidance range. As Bob will cover in detail, we now have full scale development underway across our South Texas acreage. While we still have a great deal of work to do to move into the true manufacturing type project management process, we are encouraged by our work to date and continue to meet all of our internal benchmarks.

Based on performance during the first quarter and early in the second quarter we are raising our full-year production guidance today. We now expect 2011 production to be 30% to 33% higher than 2010 full-year production. Our previous guidance range was an increase of 25% to 30%. First-quarter production increased 29% when compared to the first quarter of 2010 production of 2.04 million barrels of oil equivalent, and 21% over fourth quarter 2010 of 2.18 million barrels of oil equivalent. This production growth was driven by the ability to complete up to 4 wells per month in South Texas utilizing our dedicated frac fleet as well as higher productivity at Lake Washington as result of our ongoing production optimization and recompletion program.

For our first quarter drilling results, Swift Energy drilled 6 operated wells and participated in 2 non-operated wells during the quarter. In South Texas, 3 horizontal development wells, 2 operated and 1 non-operated, where drilled to the Eagle Ford Shale formation in South Texas. 3 horizontal development wells were drilled in the Olmos formation. All drilling activity during the quarter in South Texas was in McMullen County, Texas.

In the Lake Washington Field in Southeast Louisiana, 1 development well was drilled. In the Brookeland Field in East Texas 1 non-operated development well was drilled targeting the Austin Chalk. 3 rigs capable of drilling horizontal wells in the Eagle Ford and our Olmos and 1 spudder rig are active in South Texas. A non-operated rig is also active currently in our joint venture in McMullen County in the Eagle Ford Shale. As Bob will highlight, we have recently completed 2 high rate oil wells in our Northern McMullen County acreage and are pursuing opportunities to bring an additional rig into our 2011 program to drill both the Eagle Ford and Olmos horizontal oil wells in the area. The well drilled in Lake Washington has been completed and is being connected to production facilities. This well will be online during the second quarter. I'll briefly review our activity in each of our core operating areas for this quarter and then let Bob highlight in more detail some of our recent activity.

First in a Southeast Louisiana core area, which includes the Lake Washington and Bay de Chene Fields, production during the first quarter averaged approximately 9,661 net barrels of oil equivalent per day, or about 68 billion cubic feet equivalent per day in this area, unchanged when compared to the fourth quarter 2010 average net production from the same area. Lake Washington averaged approximately 8,209 net barrels of oil equivalent per day, or about 49 million cubic feet equivalent per day, an increase of 4% when compared to fourth quarter 2010 average daily volumes primarily to successful recompletion and production optimization projects that were executed during the quarter. The Bay de Chene sequential production decreased 21% to 1,452 net barrels of oil equivalent per day, or about 9 million cubic feet equivalent per day. The sequential decline is due to no new drilling activity in natural declines. 1 barge rig and 1 recompletion rig are currently active in the Lake Washington Field.

Moving to our South Texas core area, which includes our AWP, Sun TSH, Las Tiendas and Briscoe Ranch Olmos Fields and AWP Artesia wells and Fasken Eagle Ford Fields, first quarter 2011 production averaged 15,123 net barrels of oil equivalent per day, or about 91 million cubic feet equivalent per day, a 52% increase in production when compared to the fourth quarter of 2010 in the same area. This increase is primarily from 5 operated and 3 non-operated new wells brought online during the quarter as well as their ongoing production optimization efforts. In McMullen County, 2 horizontal wells, 1 operated Eagle Ford horizontal well and 2 non-operated Eagle Ford horizontal wells were completed during the quarter. This liquids-rich area has been and will continue to be the focus of our South Texas development.

In our Fasken area in Webb County 2 wells were fracture stimulated and placed on production during the quarter. This is a highly productive area that we intend to hold with production and develop more extensively in a more favorable natural gas pricing environment. Our activity continues to de-risk our acreage, we are improving performance by applying more effective completion techniques to longer lateral wells in a higher-yielding liquids-rich areas. As 2011 progresses we will be able to concentrate our drilling efforts in our most productive acreage. Bob will spend time discussing these programs in greater detail.

Now let me move to the Central Louisiana, East Texas core area, which includes our Brookeland, Masters Creek, Burr Ferry and South Bearhead Creek Fields, this area contributed 2,848 barrels of oil equivalent per day, or about 17 million cubic feet equivalent per day of production in the first quarter of 2011, a 30% increase in production over fourth-quarter levels. Higher production in this area was delivered by the performance of the 2 high rate and non-operated wells in the Burr Ferry area and where completed in the fourth quarter of last year. We expect our partner in the Burr Ferry area to begin drilling operations this summer and maintain a drilling rig there for the rest of the year. We were also planning on moving an operated drilling rig into this area to drill 100% working interest well during the second half of the year.

In our South Louisiana core area, which is comprised of Horseshoe Bayou, Bayou Sale, Jeanerette, Cote Blanche Island and Bayou Penchant, production averaged approximately 1,620 barrels of oil equivalent per day, or about 9.7 million cubic feet equivalent during the first quarter. As disclosed in our press release this morning, we have engaged a third party to facilitate the sale of these assets. I'm now going to turn over it to Bob Banks to review operational highlights of the first quarter. Thanks again.

Thanks, Bruce. At the Lake Washington Field, we drilled 1 well, recompleted 5 wells and performed 14 production optimization projects during the quarter. The state leaves 1464 #8, also known as our Jelly Bowl prospect, was drilled to a measured depth of 11,846 feet encountering 93 feet of true vertical net pay in 4 productive horizons. This well has been completed and is being connected to production facilities. I expect this well to test and be on production very shortly. The recompletions we performed averaged an initial production response of approximately 480 gross barrels of oil equivalent per day. Our 14 production optimization projects, which includes sliding sleeve shift changes, gas lift enhancements and returning shut in wells to production, averaged an initial response of 224 gross barrels of oil equivalent per day. Lake Washington average daily net production grew 4% during the quarter over fourth quarter 2010 levels despite no new wells been completed. This really is a testament to the quality of the asset and the work our asset team performs to maximize productivity throughout this field system. We are currently drilling a second deep well in the field which will be timely completed by a rig that is currently performing the recompletions in this field.

In our Central Louisiana/East Texas area, we are making plans to begin drilling a 100% working interest well in the Burr Ferry area, and expect our joint venture partner to move in a rig into that area during the summer months. The first 2 wells drilled by our partner continued to perform very well. This performance has encouraged us to evaluate accelerating our plans for the area and we believe we will see increased activity from our partner as well. Over in South Texas in our Fasken field in Webb County, we brought 2 wells online that were drilled in the fourth quarter of 2010. The Fasken Eagle Ford 4H had an initial production rate of 9.3 million cubic feet of gas per day with flowing casing pressure of 4610 psi on a 20/64-inch choke after a 12 stage fracture stimulation was performed. The initial production rate on the Fasken Eagle Ford 5H well was 10.7 million cubic feet of gas per day with flowing casing pressure of 4600 psi on only a 13/64-inch choke after a 13 stage fracture stimulation. All of our wells in this area to date have exceeded our performance models. While this area is not the focus of current development activity, it is really an exceptional area of the Eagle Ford Shale, which we will develop aggressively in higher natural gas pricing environments.

In McMullen County, our joint venture partner completed the Bracken JV 5H and Bracken JV 6H during the first quarter using a newly designed stimulation technique. The initial production rate of the Bracken JV 5H was approximately 7.6 million cubic feet of gas per day, 437 barrels per day of natural gas liquids and 48 barrels per day of oil with flowing casing pressure of 5800 psi on a 20/64-inch choke. And that was after a 19 stage fracture stimulation. The Bracken JV 6H had initial production rate of 5.1 million cubic feet of gas per day with flowing casing pressure of 6520 psi on a 16/64-inch choke after a 16 stage fracture stimulation was performed. A third joint venture Eagle Ford well, the Whitehurst JV 1H was completed by Swift Energy using our dedicated frac fleet and a modified stimulation design. This will add an initial production rate of 8.4 million cubic feet of gas per day with flowing casing pressure of 6300 psi on an 18/64-inch choke after a 16 stage fracture stimulation.

Moving to our operated wells in McMullen County, 2 Olmos horizontal wells and 1 Eagle Ford horizontal well were completed during the quarter. The R Bracken 37 H Olmos well had an initial production rate of 4.8 million cubic feet of gas per day, 226 barrels per day of natural gas liquids and 8 barrels per day of oil, while flowing at a casing pressure of 5525 psi on a 16/64-inch choke after a 9 stage fracture stimulation was performed. The AFP 5H Olmos well had an initial production rate of 2.7 million cubic feet of gas per day and 216 barrels per day of oil with flowing casing pressure of 3705 psi on a 20/64-inch choke after a 16 stage fracture stimulation was performed.

On the Northern part of our AWP field, the SMR EF 2H was completed with a 16 stage fracture stimulation and had an initial production rate of 1080 barrels per day of oil and 0.6 million cubic feet of gas per day with flowing casing pressure of 3705 psi on an 18/64-inch choke. This well was drilled to a lateral length of 5,660 feet and is the first Company-operated extended lateral completion that has been performed in the Eagle Ford Shale. During the month of April, the SMR Eagle Ford 3H with a lateral length of 4850 feet was completed. The initial production rate at this well was 1300 barrels per day of oil and 1.2 million cubic feet of gas per day with flowing casing pressure of 2900 psi on a 16/64-inch choke.

The combination of completion efficiencies, the improved performance of our longer lateral wells and the development of an oil sweet spot on our Northern AWP acreage, make this area a logical place for an additional rig to be moved into continuously drilled Eagle Ford and Olmos horizontal oil wells. The addition of a fourth rig in South Texas is a decision which is easier to make based on the performance of the dedicated frac fleet we have contracted. Originally, we modeled that this fleet would complete 3 to 4 wells per month. After 6 months of experience, we are now confident this fleet can complete 4 to 5 wells per month.

While this is excellent in regards to our ability to grow production, we currently don't have enough drilling activity to keep this fleet engaged full time. During the first quarter, we released this fleet back to our vendor for approximately 4 weeks and are preparing to release the fleet again for approximately 6 weeks beginning in May. While this arrangement works very well for us economically, we would always preferred to be completing wells especially giving our recent production performance. A fourth rig drilling horizontal wells in South Texas along with the smaller spudder rig we've recently contracted, would balance out our completion net capacity with our drilling schedule and ensure that we won't need to release this crew again for the duration of our contract term.

Now while we have grown AWP liquids production 57% since the beginning of 2010, we have also grown our natural gas production 59% in the area. So of particular importance to our future production outlook, it is the previously announced natural gas pipeline extension project in McMullen County. This is a very meaningful pipeline and contract for Swift Energy. Once it is in service later this year, it will provide us ample dedicated capacity for our future AWP rich gas volumes.

As we have indicated for the past several quarters, our South Texas area has the potential to drive corporate production and reserve growth above historical levels. We are now delivering that growth in an efficient and effective manner. We are working with our service providers to incorporate performance requirements and cost projections into our planning. We've delineated our acreage and are now drilling in areas that offer the highest returns. Combined with higher-priced realizations, these factors are growing cash flows faster than expected, providing us with opportunities to accelerate our activity without altering our disciplined financial approach. Thanks for your attention this morning, and I'll turn it back to Terry to recap.

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. First-quarter production growth of 21%, or fourth quarter 2010 production, resulted in production volumes above the high end of our guidance range. We have raised are full-year 2011 production guidance from 25% to 30% increase to an increase of 30% to 33% over 2010 production levels. We completed 2 high rate extended lateral oil wells with initial production rates above 1000 barrels per day in the Eagle Ford formation of McMullen County-- of our McMullen County acreage.

Lake Washington average daily net production grew 4% in the first quarter despite no new wells being placed online during the quarter and we are about to place the recently drilled Jelly Bowl well on production. We are expecting to accelerate activity in our Burr Ferry area of the Austin Chalk with our joint venture partner and using 100% Swift Energy operated activities. Improving cash flow has provide us with the opportunity to accelerate activity without significantly altering our financial strategy. With that, we'd like to begin a question-and-answer portion of our presentation.

(Operator Instructions) Neal Dingmann with SunTrust.

Good, good. Hi, the question was just on that Northern portion of the AWP field you mentioned about adding a rig there, give me an idea of how many locations you've already identified and just kind of the potential you see there I mean as far as locations and activity over the course of the next couple years?

Well just the immediate locations we have identified on the next -- on our basic spacing in SMR, we have 6 more Eagle Fords clearly to drill and 4 Olmos horizontal oil wells to drill there. But that's based on our next -- our very initial spacing. So as we get results from that, we'll understand better what our ability to down space would be.

Okay. And then looking at just the new guidance in particular around the LOE, what was it that you were able to bring those LOE cost down in the guidance? It's-- some of the arrangements that Terry and some of you all mentioned or how were you able to do that while continuing to boost production?

Well there's 2 ways we've been able to do that. One is that clearly we did reach to the higher end of our production guidance than we had expected. And in doing that on a per unit basis, our LOE came in very good. The other thing is we are getting closer to the manufacturing element of this and we're beginning to see some cost synergies from a lot of the work that we did last year. Some of the gathering facilities, completion facilities that-- work that went on. And obviously we're trying to drive that effective LOE down per unit, but as we grow the production, the base LOE will go up.

Okay and then last question, just it looked like you had great success around extending the laterals and you sort of talked about that you would in the analyst day and just earlier in the year, is-- would that be the plan then going forward to continue with sort of those 5000, 6000 laterals, and if so, would you continue to be able to bring costs down as you continue to drill more of these wells?

Yes, absolutely. We really think looking at our contract of services and strategic sourcing agreements and understanding what our pricing structures are, we really believe that 6000-foot mark offers us the best economics currently, right now today. And so you'll see us going forward trying to get those 6000 footers around in there. There'll be times where we do a little bit less because we're dealing with a lease line or a fault or something like that. But generally our planning is more centered around the 6000 footers now.

All right, guys, thank you. Great quarter.

Thanks, Neal.

(Inaudible) with RBC.

Hi guys.

Good morning.

Good morning. Had a quick question if you guys can provide a little more color on the asset sale, kind of the timing and the rationale there?

Well yes as far as the timing, I think we announced in the release here that we've engaged Macquarie Tristone in that initiative. We're currently working very closely with them visiting the fields, putting the data packages together. I think we'll probably have something out publicly late May, early June. So continuing on through that process we'd be expected to be evaluating proposals later in the summer.

Yes, I think I would add to that that in our press release we've given you some more detail as to the fields, we won't repeat that here, and the production amounts, we have factored that into the guidance that we have this year on both our production estimates and as you'll see in our capital spend we've got a little guidance there. But we have presented what we believe is a conservative estimate of what will happen. There's certainly some uncertainty in whether or not you sell certain properties or not, we're going to do the best thing for the shareholder here.

Sure. And then just wonder if you guys could maybe give a little bit of a hypothetical on 2011 CapEx budget assuming that you guys kind of take the fourth Eagle Ford rig and that your partner is pretty active in Burr Ferry, do you guys have some idea where that would shake out potentially?

I think we have factored that in and when we build our budget, we build a discretionary wedge in it so we can easily replace that discretionary wedge if we're able to get this additional rig and drill the northern part of AWP. We have that flexibility built into the budget. But we also recognize that oil prices are a lot higher than we went into the year believing they would be. And when you run that out, particularly if the strip stays where it is, which we don't know that, but if it does, we'll have higher cash flows and we'll have an ability to add to the CapEx budget because of higher cash flows and still really try to stay out of the bank line to the extent possible. We will always try to maintain our financial discipline and balance our cash flow with our debt. We feel like the balance sheet's in great shape and we always built in some flexibility into our budget so we can adjust as we move through the year.

Adam Leap with RBC Capital Markets.

Good morning. Most of my questions have already been answered, but if there's a way to break down the additional growth, how much of that might be production growth from the optimization and recompletion versus the new well drilling.

Obviously we build models like that. We don't have those at their fingertips right here. But we did break down our expectations from our optimization from a recompletion or from our new wells. I think we'd have to get back to you with those kind of breakouts.

It is likely the production increases are going to come from increased performance and from new wells as opposed. A larger amount of the production growth is going to come from new activity as opposed to the optimization side.

I want to emphasize we always have some timing concerns with vendors. Last year, goodness know none of us want to repeat that. So we built into our budget some uncertainties there. Obviously, as we get better performance during the year we are going to take that to the bank, to say that, none the least. But we also were very pleased that Lake Washington is a great example of an area where we've been focusing on our efficiencies. We've gotten our downtime down. We're getting some great results with the recompletions. We are not projecting all that's going to just keep happening. But we do see some really good performance there. We're going to keep trying to make that happen. And of course, as Bruce and Bob said, on the models that we have for the actual Eagle Ford and Olmos wells, we are getting better at that but clearly as we drill out to play we're wanting to move to the more sweet spots, the better spots, the places where the models are outperforming as opposed to places where the models might be at the margin. So you are going to see us trying to optimize through the whole year, whether it is the timing and use of our vendors and our rigs, whether it is our completion activity in Lake Washington and the downtime efficiencies that we are getting, or whether you see us trying to get the best of the models that we are using or the best performance and move into sweet areas. We're going to do that all year long.

Okay. Thank you. Ca n you give us a little more color on Jelly Bowl? How much that will cost and do you have any production expectations?

We are going to hand that to Bob, because that was a tough well. We got it down. We are excited with the results.

Yes, this is a new area in the field, the southern area of the field that we really haven't drilled in before. And they were some velocity changes in this part of the field. We did have to sidetrack the well. The well cost, the drilling portion of the well cost, I think was in the $12 million to $13 million range. But we are very pleased with the pay sands that were encountered. They appear to be very productive pay sands. I'm going to avoid throwing our IP rate at you, but we think it is going to be very significant. And the good part about Jelly Bowl is it actually, this model now with the changes and the remapping that we are doing, we now have 4 or 5 other prospects that look very similar to this Jelly Bowl prospect now. So overall a success from a business standpoint, but we did have mechanical risk in our first well drilling on this end of the field.

What do you think the savings would be now?

I think we can drill these wells for $5 million to $6 million.

Two other quickies. I don't know if this is a good question but your average mix of your NGL barrel?

In terms of ethane, propane, butane?

Yes.

We will have to get back to you. We don't have that out on the table right now but we have the folks that can get that. We will have to get back to you.

Is the pricing correlation to crude more a result of your uplift on your crude prices versus where you're marketing your NGLs?

In terms of its relationship to crude that 50% to 60% guidance range, that's been pretty historic. It has been in that range for some time. So obviously, as crude prices get the lift, the NGLs get the left behind it.

We've seen that Adam, the last several quarters. We've been in that 50% to 60% fairway. We were, I think, 52% for the first quarter so that's how we guide.

And I think it is real important to note, that's a percent of NYMEX. It is not a percent of that HLS that we are getting in South Louisiana. In South Louisiana we were getting a big increment over the NYMEX which contributed to some much better pricing. But this NGL relationship is only the NYMEX, not to that --.

That's what I was getting at. The price increase lagged your crude price increase.

That's correct.

Lastly, on your transportation agreement, can you say who that's with and where that's going to be marketed?

We indicated that in the original press release announcing it. The one in the AWP area is with South Cross.

Biju Perincheril with Jefferies.

Good morning, congratulations on a very good quarter. A couple of questions. For the (inaudible) wells that you completed in the Eagle Ford, do you have the cost on those wells?

Yes, those wells are around some of the models that we were showing you, I think those are in the $9 million, $9.5 million range. They are holding pretty similar to what we showed you at analyst day.

Got it. And then the Jelly Bowl prospect, do you have a reserve estimate there?

Not at this time.

I don't think we are quite ready to release that. We have our estimates but there haven't been looked and audited.

Got it. And then you mentioned you're drilling a second well there? Have you spud that? What's the timing on that one?

Yes, it is currently drilling. In fact, we've already set intermediate pipe on that well.

It is over on the western side of the field as opposed to in the Jelly Bowl area, just to be sure you got that clear.

Okay. And was that included in that 4 to 5 prospect that was set up by Jelly Bowl?

No, this is a completely different part of the field. The Jelly Bowl area is a unique area that we had not drilled in before. So this is all some new prospectivity down in that area. Different from what we are doing in the rest of Lake Washington.

The one we're drilling is over on the west side, south of the Newport area. Similar to geology to what the Newport discovery was where you have an embayment in the salt. And we've got good 3-D there. So it is really different from Jelly Bowl, but it is along the lines of what we had done on the west side in the past.

Got it. And then I know you mentioned this before, but I don't think I quite got it. The production guidance for both the second quarter and full-year, does that include contribution from the properties that have been earmarked for sale? Or not?

It does -- we made some estimates as to when you might close a sale like that. And we would record production from those properties up through the closing date and then we wouldn't. So the second quarter definitely incorporates production from those properties. The fourth quarter would have a reduction of that.

Mark Lear with Credit Suisse.

Good morning, good quarter. It looks like your joint venture Partner in AWP is picking up the pace a bit and getting some better results with what we presume to be highway fracking. You talked about also altering the frac design on the well you completed there and got some pretty good results, as well. Are you able to replicate what they are doing? And do you think the application can be spread throughout that area?

What we did was different. Mainly what we did on that Whitehurst well is we pumped a high-strength proppant. So we upgraded the type of prop that we pump. We like the results of that. But clearly we are getting excellent results with our hybrid design that we are pumping right now. Petrohawk and Swift are collaborating on some of these well designs, staying in a continuous improvement mode. But I would say the time is still a little early to draw too many hard and fast conclusions about which design, which method is going to work the best overall. But the good side of it is we are working collaboratively on continuous improvement.

I think I would add to that that while we definitely believe that the frac jobs are very key to the success of developing these plays, we equally believe that the kind of rock you are drilling in is material to your success. And we spent a lot of time last year quarrying these areas, getting these analyses in, doing all the log work, petrophysical work. And some of these areas they do have better rock. So you've got to balance those two types of issues together before you lock in and say this is the best frac. It may in fact, be that you're fracking in the best rock.

Okay. And then, you may have touched on this, I hopped on another call for a second. But in terms of the inventory in that northern McMullen area, from just the well names I'd imagine it didn't really delineate the area that much. But can you maybe talk about what you think is an oily sweet spot up there and what ultimately could be the inventory?

Yes, we did get a similar question. But on the SMR lease, as an example, if we put this additional break to work, we already have locations laid out both for Eagle Ford and Olmos on our first level of spacing. The first tranche of program just on that lease would be 6 Eagle Ford wells and 4 Olmos wells. And it is an area where we can be very efficient with just skidding that rig, walking that rig over and getting the cost savings from very quick operations. You get a lot of synergies from also the way you use the frac crew spaced into those different wells that we lay out. That's one reason, I think, in the overall area I think we've disclose to you that oily window area of the Eagle Ford is about 20,000 acres. And we identified for you at analyst day, I think we had about 250 locations and a resource potential of the 60 million barrel to 90 million barrel range.

Curtis Trimble with MKM Partner.

Good morning. Obviously you varied the number of frac stages down in South Texas on both the Eagle Ford and AWP. I wanted to get a better idea of what yields you are seeing per stage and some of the thought process behind ramping up or scaling down the number of frac stages outside of obviously extended laterals or some shorter laterals?

Our goal is to get these 6000-foot laterals. And we're still in the 300-foot, 350-foot spacing range. We still think that's where we need to be without how we space these stages out. So it's really just going to be a function of the lateral length versus that spacing. Now, the variances that you see in the numbers that we report relate maybe to where we position wells in relation to a lease line, or maybe we have faults running through that we want to stay away from. So it's some of those variables that will really start to change things. In general terms, we are looking, on the 6,000 footers, for about 16 stages. And we think that's a 5 to 8 BCF equivalent type of model which would be about 0.3 to 0.5 BCF per stage, if that's what you are looking for.

Okay. Just switching gears looking at South Louisiana, and on the ultra deep prospect you guys highlighted in the analyst day, any update on timing target expectation, et cetera there?

I think we did highlight on analyst day that we've got such a deep inventory of the resource play type activities at Eagle Ford. And we don't have any lease issues in some of our very deep areas of Lake Washington. Sub salt, we are just going to be waiting on. Some of the deeper targets we can wait on. But I do want to point out that Jelly Bowl was the deepest well that we drilled in Lake Washington since 2008. So we are going back into what we would call the intermediate depths which have some much more robust economics or opportunities for us. This West Site is one such well. I'm not going to say it is a Newport look-alike because Newport was such a great well for us. But we are out there on the hunt for another Newport. When you step over into some of our other areas like Bay de Chene and our Teton type prospect over there, some of those things are higher risk, higher cost and we have decided that we would really look for partners in those kinds of things. They are not likely to be drilled this year. Probably move into a whole package of wells that we would drill next year with some partners in that regard.

Gray Peckham with SFC Financial.

Actually, I had a question about the Olmos. You mentioned in your release you had some good Olmos wells. And there's a big variability in the production mix there. I'm wondering, if you do add that rig to the program and target some what you call Olmos oil wells, do have good visibility into where you might encounter those versus a more NGL kind of Olmos well?

This northern area, we've already drilled some vertical wells there. In fact, we just refracked some, so we know that's a very, very good oily Olmos area. So that's why we were saying, if you bring in the other rig, we are going to drill a combination of those Eagle Ford oil wells and Olmos oil wells. So we are very confident in what we have there.

I will add to that, that in terms of the horizontal Olmos drilling for oil, this would be a very incremental type thing for this year. The Olmos in that area of the County has been fairly extensively drilled with lots of vertical wells. And as you go farther north it definitely becomes oil. In that particular regard, you look at these vertical completions up there that have been successful in the past, they typically can be anywhere from as low as 30,000 barrels per vertical completion to as high as 300,000 barrels, 500,000 barrels per vertical completion. But we are looking at some of those areas up there. Again, not a big big area to work with but nice increment to our business. So some of these horizontal wells where you go in with anywhere from 9 to 16 stages, if you can find that sand up there, that can be very attractive to us.

Let me just add, though, that in addition to that, what you are seeing a do down more in the southern part, even though we are in the southern part of the field, we have delineated areas that do have very good condensate yield areas. So we know where they are, as well. With our other rigs we are more focused on the better liquids-rich areas that have the good condensate yields.

(Operator Instructions) Ray Deacon with Pritchard Capital Partners.

I was just wondering if you can elaborate a little bit more on how many of the wells you think you might be able to drill to success in South Texas, given the big increase in the (inaudible) between 4 and 6? I think you said your average low is 5, right? -- in the quarter?

Yes, could you repeat that? You broke up a little on us a little bit. We want to make sure we're answering the right question.

Sure, sorry. In the Eagle Ford and the Olmos, it sounded like the plan was to try to move towards 6,000-foot laterals. And I'm just wondering what percentage do you think will be that length this year and maybe next year as well?

Okay, they are going to actually pull some papers together and get you that answer. But while we're waiting on that, Alton needs to make an announcement here to everyone that's still on the call.

Yes, I've been asked to read this. Apparently during the course of the call we learned that the webcast link provided for the call was incorrect. And the beginning portion of our conference call here to those listening via webcast was unavailable. So although this was corrected, everyone got through part of the call, so that everyone has equal access to the matters covered in this call, we will have the archived replay on our website as soon as possible. So if you missed the first part of this call, you can check our website, it will link into the archived replay. Again, we apologize for this inconvenience. Thank you.

And back to answering the question. I think for the remainder of the year our target is around 80% of our horizontals being the 6,000-foot type model.

Also, I was wondering, Devon had mentioned yesterday they were drilling a Tuscaloosa marine shale well, and it seemed like some of the acreage you have might be prospective. Any plans to test that?

We are very familiar with the Tuscaloosa marine shale. And we had a legacy position that does have that shale in and around our area. But as we've looked at it right now, we don't have the really high resistive type shale that you may see farther to the east. But we do have the shale. So right now we're just watching and waiting to see what others do, see if there's any prospectivity in our area. We certainly, to the extent we have the acreage, don't plan on letting go of it. But we don't have any near-term plans to drill into it. We're going to wait and watch and see what other people do.

Michael Hall with Wells Fargo.

Thanks, and I apologize if it's already been covered. I was hopping between calls earlier. Just curious on the fourth rig you alluded to potentially bringing on, is there any color on timing of that decision? And could it have a material impact on 2011 production?

I think the timing we'd be shooting for would be around mid-summer. There will be some additional production if we bring in that rig. But where we see the real benefits is the momentum into next year not only in terms of the production in that area, we are going to get some very nice production volumes in 2012 from the work we do in 2011. But additional to that, we are looking at our entirety of our Eagle Ford position. And we think we're going to need to ramp up one more rig at some point in 2012 anyway. Additionally, as we mentioned on the call , we've seen some gaps in that our frac crew is going so fast now our drilling isn't keeping up with that performance. So we're trying to balance out and make sure we get full utilization of that frac crew, especially given some of the results that we are having at the well. It is a multi- benefit the way we see

Biju Perincheril with Jefferies.

One quick follow-up. On the SMR 2H well, do you have a 30-day rate for either one of those?

What we can tell you, for two weeks it has been about 1,000 barrels a day average. That's probably as far as we can go. I don't think we can give you a 30 day number yet.

Okay. Is that 1,000 BOEs or just the oil component?

That's just the oil. The question is, these wells look pretty strong to us. They are doing very well, early data.

Andrew Coleman with Madison Williams.

Good morning, folks. I had a question on the asset divestiture package. Do you think you might retain any of the deep rights or is it like an override if you do sell some of those properties?

Andrew, you actually are singing my song. We absolutely plan on retaining any rights that we don't get value for. And we do see value in the exploration deep rights and we certainly plan to retain that unless for some reason we can get some pretty good value there.

Okay. That's great. And then I just wanted to confirm. Something I heard earlier on the call was that some production in South Texas. That's the largest region in the company, a little over 15 MBD, right?

That's correct.

At this time there are no further questions. You may proceed with your closing remark.

Okay, we would like to thank you for joining us on our conference call and we look forward to joining you again next quarter.

Thank you. This concludes today's conference call. You may now disconnect.