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Swift Energy Co. (NYSE:SFY)

Q1 2011 Earnings Call

May 5, 2011 10:00 am ET

Executives

Paul Vincent – Director, Finance and Investor Relations

Terry E. Swift – Chairman and Chief Executive Officer

Alton D. Heckaman, Jr. – Executive Vice President and Chief Financial Officer

Bruce H. Vincent – President and Secretary

Robert J. Banks – Executive Vice President and Chief Operating Officer

Analysts

Neal Dingmann – Suntrust

Kyle Rhodes – RBC

Adam Lake – RBC Capital Markets

Biju Perincheril – Jefferies

Mark Lear – Credit Suisse

Curtis Trimble – MKM Partner

Gray Peckham – SFG Financial

Ray Deacon – Pritchard Capital Partners

Michael Hall – Wells Fargo

Andrew Coleman – Madison Williams

Operator

Ladies and gentlemen, thank you for standing by. And welcome to the Swift Energy’s 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)

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

Paul Vincent

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 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 E. Swift

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 prospectively 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, Central Louisiana.

The performance of these assets led to a 21% increase in production over fourth quarter 2010 levels. This performance particularly in South Texas combined with the extensive project planning that in ongoing has 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’d 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 and exceeding expectations.

During the first quarter of 2011, we completed our first two expanded lateral Eagle Ford oil wells. Both 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 the northern portion of our AWP field.

We also grew our average daily 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 had resumed drilling in the field and we’ll bring several oil wells on line 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 cost throughout our supply chain. This doesn’t make us immune to service cost inflation, but it does allow us to have visibility on our cost 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’re able to budget and measure project in net 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, equipment 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, two high rate Eagle Ford oil wells which were produced with initial rates above 1000 barrels of oil per day.

We realized 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 flow this year should we increase our capital spending.

In Southeast Louisiana, we grew 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 pay in four productive horizons. We should have this well oil production this month. As our corporate production profile grows and we could dedicate more capital to this area, we will resume drilling deeper wells in 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 two wells last year in 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 the 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 identified external threat 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 I’ll ask Alton to present the first quarter 2011 financial results.

Alton D. Heckaman, Jr.

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 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 improves, Swift’s financial results for 1Q ’11 reflect this.

Oil and gas sales excluding hedging effects were $144 million, a 31% increase from 1Q ‘10 and a 25% increase from 4Q ‘10. Income from continuing operations was $20.2 million or $0.47 per diluted share, up from $0.47 in 1Q ‘10 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 ‘11 production up 29% from a year ago, was up 21% from 4Q '10 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 ‘11.

As Terry mentioned, all of our controllable cost 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 $20, interest expense came in at $3.19 per barrel, and production and ad valorem taxes came in at 9.2% of revenue. The result was income from continuing operations from 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 ‘11 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 floor hedges when market conditions are favorable. Most recently, for the second quarter of 2011, we executed gas floors covering 50% of our expected production, at an average NYMEX strike price of $4.16 per MMBtu. Please see our website for 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 very solid financial position to execute our 2011 strategic plan. As always, we have 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 over to Bruce Vincent for an overview of our operations.

Bruce H. Vincent

Thanks, Alton, and good morning, everyone. We appreciate everybody listening in.

Today, I will discuss first quarter (inaudible) 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 effect on the full year 2011 plan.

Beginning with production, Swift Energy’s production during the first quarter of 2011 totaled 2.65 million barrels oil equivalent, or 15.87 billion cubic feet equivalent, 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 field of element underway across our South Texas acreage. While we still have regular work to do to moving into the true manufacturing type project management process, we are encouraged by our work today and continue to meet all of our internal benchmarks.

Based on performance during the first quarter and early into second quarter, we’re 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 at 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 four wells per month in South Texas utilizing our dedicated fract fleet as well as higher productivity at Lake Washington as a result of our ongoing production optimization and the 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, three horizontal development wells; two operated and one non-operated were drilled at Eagle Ford shale formation in South Texas. Three horizontal development wells were drilled in the Olmos formation. Our drilling activity during the quarter in South Texas was in McMullen County, Texas.

In Lake Washington in Southeast Louisiana, one development well was drilled. In the Brookeland field in East Texas one non-operated development well was drilled targeting the Austin Chalk. Three rigs capable of drilling horizontal wells in the Eagle Ford and/or Olmos, and one spreader rig are active in South Texas. A non-operated rig is also active currently in our join jointure in McMullen County in the Eagle Ford shale.

As Bob will highlight, we have recently completed two high rate oil wells at our Northern McMullen County acreage and are pursuing opportunities to bring an additional rig into our 2011 program to drill both 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 on line 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 the Southeast Louisiana core area, which includes Lake Washington and Bay de Chene field, production during the first quarter averaged approximately 9661 net barrels of oil equivalent per day, or about 68 million 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 8209 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 through successful recompletion and production optimization projects that were executed during the quarter.

Bay de Chene sequential production decreased 21% to 1452 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 (inaudible). One barge rig and one 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 2010 in the same area. This increase is primarily from five operated and three non-operated new wells brought online during the quarter as well as our ongoing production optimization efforts.

In McMullen County, two horizontal wells, one operated Eagle Ford horizontal well and two 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, two wells were fractured 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 and a more favorable natural gas pricing environment.

Our activity continues to de-risk our acreage, we are improving performance and plan more effective completion techniques to longer lateral wells in 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, contributed 2848 barrels of oil equivalent per day or about some $7 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 two high rate non-operated wells in the Burr Ferry area and were completed in the fourth quarter of last year.

We expect to have a 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’re 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 and Bayou Penchant, production averaged approximately 1620 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.

Now, I’m going to turn over to Bob Banks to review operational highlights of the first quarter. Thanks, again.

Robert J. Banks

Thanks, Bruce. At the Lake Washington field, we drilled one well, recompleted five wells and performed 14 production optimization projects during the quarter. The State Lease 1464 #8, also known as our Jelly Bowl prospect, was drilled to a measured depth of 11,846 feet in countering 93 feet of true vertical net pay in four 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 being 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’re currently drilling a second deep well in the field, which will be timely completed by a rig that is currently performing 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 two 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, at our Fasken field in Webb County, we brought two well online that we 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 5A12 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 have exceeded our performance models. While this area is not in our 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 environment.

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 5,800 psi on a 20/64 inch choke. And that was after a 19 stage fracture stimulation.

The Bracken JV 6H had an initial production rate of 5.1 million cubic feet of gas per day, with flowing casing pressure of 6,520 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 fract fleet and a modified stimulation design. This well had an initial production rate of 8.4 million cubic feet of gas per day with flowing casing pressure of 6,300 psi on an 18/64 inch choke after a16 stage fracture stimulation.

Moving to our operated wells in McMullen County, two Olmos horizontal wells and one Eagle Ford horizontal well were completed during the quarter. The R Bracken 37H 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, at a casing pressure of 5,525 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 3,705 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 competed 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 3,705 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 4,850 feet was completed. The initial production rate of this well was 1,300 barrels per day of oil and 1.2 million cubic feet of gas per day with flowing casing pressure of 2,900 psi on a 16/64 inch choke.

The combination of completion efficiencies improved performance of our longer lateral wells and the development of an oil sweet spot on our northern AWP acreage make this area logical place for an additional rig to be moved and to 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 will complete three to four wells per month. After six months of experience, we are now confident this fleet can complete four to five wells per month. While this is excellent in regards to your 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 six weeks beginning in May. While this arrangement works very well for us economically, we would always prefer to be completing wells especially giving our recent production performance.

A fourth rate drilling horizontal wells in South Texas along with the smaller spudder rig we recently contracted would balance out our completion 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 is the previously announced natural gas pipeline extension project at 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 had 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’re 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 price utilizations, these fractures 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.

Terry E. 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. First quarter production growth of 21% over fourth quarter 2010 production resulted in production volumes above the high end of our guidance range.

We have raised our full year 2011 production guidance from 25% to 30% increase to an increase of 30% to 33% over 2010 production levels. We completed two high rate extended lateral oil wells with initial production rates above 1000 barrels per day in the Eagle Ford formation 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’re about to place the recently drilled Jelly Bowl well on production.

We are expecting to accelerate activity in our Burr Ferry area or the Austin Chalk with our joint venture partner and using 100% Swift Energy operated activities. Improving cash flow has provided us with the opportunity to accelerate activity without significantly altering our financial strategy.

With that we’d like to begin the question-and-answer portion of our presentation.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Neal Dingmann with Suntrust.

Terry E. Swift

We’re not hearing the question.

Operator

Mr. Dingmann, your line is open.

Terry E. Swift

Operator, we’ll go to the next.

Neal Dingmann – Suntrust

Can you hear me right now guys?

Terry E. Swift

How are you?

Neal Dingmann – Suntrust

Good, good. Hey, the question was just on that northern portion of AWP field, you mentioned about adding a rig there, can you 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 of years?

Terry E. Swift

Just the immediate locations we have identified on our basic spacing in SMI, we have six more Eagle Fords clearly to drill and four Olmos horizontal wells to drill there. But that’s based on our next very initial spacing. So as we get results from that, we’ll understand better what our ability to down space should be.

Neal Dingmann – Suntrust

Okay. And then looking at just the new guidance, particular around the LOE, what was that that you’re able to bring those LOE cost down in the guidance, some of the arrangements that Terry and some of you mentioned, how are you able to do that while continuing to boost production?

Terry E. Swift

Well, there is two 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’d expected and then doing that on a per unit basis our LOE came in very good.

The other thing as 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 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.

Neal Dingmann – Suntrust

Okay. And then last question, just looks like you had great success around extending the laterals, you sort of talked about that you would in the Analyst Day and then earlier in the year, would that be the plan then going forward to continue with sort of those 5000, 6000 laterals and if so will you continue to be able to bring cost down as you continue to drill more of these wells?

Terry E. Swift

Yeah, absolutely. We really think looking at our contracted 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 foot surrounding there, there’d be times where we’d drill little bit less because we’re dealing with a (inaudible) something like that, but generally our planning is more centered around the 6000 footers now.

Neal Dingmann – Suntrust

All right, guys. Thank you. Great quarter.

Terry E. Swift

Thanks.

Operator

Your next question comes from the line Kyle Rhodes with RBC.

Kyle Rhodes – RBC

Hi guys.

Terry E. Swift

Good morning.

Alton D. Heckaman, Jr.

Good morning.

Kyle Rhodes – RBC

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

Terry E. Swift

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 or early June. So continuing on through that process, we’d be expecting to be evaluating proposals later in the summer.

Alton D. Heckaman, Jr.

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

Kyle Rhodes – RBC

Okay. And then I’m just wondering if you guys could maybe can give a little bit of hypothetical on 2011 CapEx budget, I assume you guys kind of take the fourth Eagle Ford rig and that your partner is pretty active in Burr Ferry, do you guys have an idea of how that would shape out potentially?

Terry E. Swift

I think, we’ve factored that in and when we build our budget, we build the discretionary waging, so we can easily replace that discretionary wage if we are able to get this additional rig and drill (inaudible).

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 that, but if it does, we will have higher cash flows and we will have an ability to add to the CapEx budget because the higher cash flows in still, really try to stay out of the bank line that extent possible.

We will always try to maintain our financial discipline and balance our cash flow with out debt. We got the balance sheet in great shape and we always build in some flexibility into our budget so we could adjust as we move through the year.

Kyle Rhodes – RBC

All right. Thanks guys, great quarter.

Terry E. Swift

Thank you.

Operator

Your next question comes from the line of Adam Lake with RBC Capital Markets.

Adam Lake – RBC Capital Markets

Good morning.

Terry E. Swift

Hey, Alan, how are you?

Adam Lake – RBC Capital Markets

Most of my questions have already been answered, but just if there is a way to breakdown the additional growth, how much of that might be production growth from the optimization, recompletion or versus the new wells in it?

Terry E. Swift

Yeah, I mean, obviously we build models like – we don’t have those our fingertips right here, but I mean, we do break down our expectations from our optimization work, from a rig completion work, from our new wells. I think we’d have to get back to you with those kind of breakouts.

Robert J. Banks

But it’s likely, I mean, it’s likely the production increases are going to come from increased performance from the new wells as opposed, I mean a larger amount of the production growth is going to come from new well activity as opposed to the optimization side.

Terry E. Swift

Yeah, I want to emphasize that we always have some timing concerns with vendors last year, goodness, none of us want to repeat that. So we’ve built into our budget some uncertainties there, obviously as we get better performance during the year, we’re going to take that to the bank to say that nonetheless.

But we also are very pleased, Lake Washington is a great example, an area where we’ve been focusing on our efficiencies, we’ve gotten our downtime down, we’re getting some great results with the recompletion, we’re not projecting all of that’s going to just keep happening. But we do see some really good performance there and we’re going to keep trying like that happen.

And of course as Bruce and Bob said, on the models that we have for the actual Eagle Ford and Olmos well, we’re getting better with that, but clearly as we drill out the play, we’re wanting to move to the more sweet spots, the better spot, the places where the models are outperforming as opposed to the places where the models might be at the margin.

So you’re going us trying to optimize the whole year, whether it's the timing and use of our vendors and our rigs, whether it's our completion activity in Lake Washington, and downtime, the efficiencies that we’re getting or whether you see us trying to get the best of the models that we’re using or the best performance moving to sweeter areas, we’re going to do that all year along.

Adam Lake – RBC Capital Markets

Okay. Thank you. And can you give us a little more color on Jelly Bowl, how much that well cost and do you have any production expectations?

Terry E. Swift

We’re going to hand that to Bob, because that was a tough well. I mean we got it down and we’re – but we’re excited with the results.

Robert J. Banks

Yeah, Adam, we did – yeah, this is a new area of the field, the southern area of the field that we really haven’t drilled in before. And there 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 it was in the $12 million to $13 million range. But we’re very pleased with the pay sands we’re encountered. They appear to be very productive pay sands, I’m going to avoid throwing our IP rate actually, but we think it’s going to be very significant.

And the good part of that Jelly Bowl is it, it actually – this model now with the changes, with the re-mapping that we’re doing, we now four or five other prospects that look very similar to this Jelly Bowl prospect now. So overall success from a business standpoint, but we did have mechanical risk in our first well drilling on this end of the field.

Adam Lake – RBC Capital Markets

So what do you think the savings would be now with your learnings?

Robert J. Banks

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

Adam Lake – RBC Capital Markets

Two other quickies. Can you tell what’s your – I don’t know if it’s a good question, but your average mix of your NGL barrel?

Terry E. Swift

In terms of ethane, propane and butane, we’ll have to get back to you, we don’t have that, Adam, to say right now, but we got the folks that can get that, we’ll have to get back on that.

Adam Lake – RBC Capital Markets

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

Terry E. Swift

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

Robert J. Banks

Yeah, and we’ve seen that Adam the last several quarters. We’ve been kind of in that 50% to 60% fairway. I think 52% for the first quarter. So that’s kind of how we are.

Terry E. Swift

Yeah. And I think it’s really important to note that that’s a percent of NYMEX. It’s not a percent of that ATL list that were giving you South Louisiana. South Louisiana really giving a big increment all with the NYMEX which contributed to some better, it’s much more pricing but this NGO relationship is only the mix not to debt.

Adam Lake – RBC Capital Markets

All right. That’s what I was giving because you didn’t give the price increase lag, your crude price increases.

Alton D. Heckaman, Jr.

Correct.

Robert J. Banks

That’s correct.

Adam Lake – RBC Capital Markets

And lastly on your transportation agreement. Can you say who that’s with and how that’s going to be marketed?

Robert J. Banks

Yeah, we’ve indicated that in the end of original press release announced. They’re in the AWP areas with South.

Adam Lake – RBC Capital Markets

Sorry I must have forgot. That’s great, thanks.

Robert J. Banks

Thanks Terry.

Operator

The next question comes from the line of Biju Perincheril with Jefferies.

Biju Perincheril – Jefferies

Good morning. Congratulation on a very good quarter.

Robert J. Banks

Thanks.

Alton D. Heckaman, Jr.

Hi Biju.

Biju Perincheril – Jefferies

Just a couple of question, so these have been lateral, nor that you can do it in Eagle Ford, cost on those wells?

Alton D. Heckaman, Jr.

Yeah, those wells are kind around some of the models that we were showing to you. I think those are in the $9 million, $9.5 million range.

Biju Perincheril – Jefferies

Okay.

Alton D. Heckaman, Jr.

They are pretty similar to what we showed you at Analyst Day.

Biju Perincheril – Jefferies

Got it. And then the Jelly Bowl prospect, kind of reserve estimates?

Alton D. Heckaman, Jr.

Yeah. We are not done that yet.

Terry E. Swift

I don’t think we’re quite ready to release that. We have our estimates but they haven’t been looked at and…

Biju Perincheril – Jefferies

Got it. And then you mentioned you’re drilling that second well or have you spud that or is that timing unbalance?

Alton D. Heckaman, Jr.

It’s currently drilling. We have already set intermediate pipe in that well.

Terry E. Swift

It’s on the western side field as opposed to in the Jelly Bowl area, just to be sure you got that clear, so.

Biju Perincheril – Jefferies

Okay. And was that included in that four to five prospect, that was – has been put up by Jelly Bowl or is it...

Alton D. Heckaman, Jr.

No, this is a completely different part of the field. The Jelly Bowl area is kind of a unique area that we have not drilled in before. So this all kind of – it’s a new prospectivity down in that area, different than what we are doing in the rest of Lake Washington.

Terry E. Swift

The one we are drilling is over on the West side, South is Newport area and similar to geology what the Newport discovery where you have an embayment in the South, you got good 3-D there and its really different from Jelly Bowl, but it’s a long aligned than what we have done in the West side in the past.

Biju Perincheril – Jefferies

Got it. And then I know you mention this before, I don’t think I had quite got it. The production guidance for both the second quarter and the full year, does that include contribution from the properties that have been – you had marked for sale or it is not?

Terry E. Swift

Really, it does, we made some estimates as you when you might close the sale like that and we would record production from those properties up through the closing date and then we wouldn’t sell that. The second quarter definitely incorporates production from, those properties, the fourth quarter would have a reduction of that.

Biju Perincheril – Jefferies

Okay. That’s clear. Thanks and that’s all I have.

Terry E. Swift

Right. Thank you.

Robert J. Banks

Thank you.

Operator

Your next question comes from the line of Mark Lear with Credit Suisse.

Mark Lear – Credit Suisse

Good morning, good quarter.

Terry E. Swift

Thanks, Mark.

Robert J. Banks

Thank you.

Mark Lear – Credit Suisse

Just in terms of you talked about or it looks like your joint venture partner in AWP has pick up the pace a bit in getting some better results with – we presume to be a highway tracking. You talked about also altering the frac design on the well you completed there and have some pretty good results as well. Are you able to replicate what they are doing, and do you think the application can be kind of spread throughout that area?

Terry E. Swift

Well, what we did was different, mainly what we did on that Whitehurst well, as we pumped the high strength popping, so we upgraded the type of process that we pump, we liked the results of that but clearly we are getting, we are getting excellent results with our hybrid design that we're pumping right now, Petrohawk and Swift are collaborating on some of these well designs, kind of staying in a continuous improvement mode but I would say the time is still a little early to drive to many hard and fast conclusions about which design, which method is going to work best overall but the good side of it is we're working collaboratively on continuous improvement.

Robert J. Banks

Yeah. I think I would add to that but 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’re drilling is material to your success and we spend a lot of time last year coring these areas, getting these analyses in, doing all the log work, that fusible work and some of these areas just they do have bettered off. 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 are fracing in the best rock.

Mark Lear – Credit Suisse

Okay. And then I guess just you may have touched this I was hopped on to another call for a second but in terms of the inventory in that Northern McMullen area I guess from just the well names I'd imagine that didn't really dominate the area that much. But can you may be kind of talk about what you think is I guess an (inaudible) affair and what ultimately could be the inventory?

Terry E. Swift

Just – we did get a similar question but on the SMR maybe a (inaudible) example, if we put this additional rate 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 in that leads would be six Eagle Ford wells and four Olmos wells and it’s an area where we can do very efficient with just skinning that rig, move or [walk] in that rig over and getting to cost savings from very quick operations, we get a lot of synergies from also the way we use the frac crude spaced into those different wells that we lay out. So that’s one lease. I think in the overall – in the overall area I think we disclosed two in that quarterly window area of the Eagle Ford. It’s about 20,000 acres and we identified from – at the Analyst Day I think we have 250 locations and kind of a resource potential of the 60 million to 90 million barrel range.

Mark Lear – Credit Suisse

That’s great. Thanks a lot guys.

Terry E. Swift

Thanks Mark.

Operator

Your next question comes from the line of Curtis Trimble with MKM Partner.

Curtis Trimble – MKM Partner

Just – obviously you’ve varied the number of frac stages and so the practice on both Eagle Ford and (inaudible). I wanted to get a better idea of what you are seeing in per stage and some of the thought process behind ramping up the scaling down, the number of frac that is outside and above these rigs and with neither – or showing neither?

Terry E. Swift

Well, I think in the 650, our goal is to get to 6000 foot levels. And we’re still kind of in the 300 to 350 foot spacing rage. 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 you would put relate may be to where we position wells in Malaysia to a lease line or may be we have folks running through when we want to stay away from. So some of those variables that will really start to change things. In general terms when looking on the 6000 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 kind of what you’re looking for.

Curtis Trimble – MKM Partner

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

Terry E. Swift

Well, I think we don’t highlight on (inaudible) David, we’ve got such a deep inventory of the resource, play type activity in the Eagle Ford well. And we don’t have any lease issues in some of our very deep areas of Lake Washington, (inaudible) we’re just going to be weighing out some of the deeper targets we can weight it 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’re going back into what we would probably intermediate that’s which have some much more robust economics, all opportunities for this Swift side is one such well, I'm not going to say it's a Newport look like, as Newport was such a great well for us but we're out there on the (inaudible) Newport. When you step over into some of our other areas like Bay de Chene and our Teton type prospect over the north Blanche Island. 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. There are not likely to be drilled this year probably move to a whole package wells that we would drill next year with some partners in that regard.

Curtis Trimble – MKM Partner

Okay, very good, appreciated.

Terry E. Swift

Thank you.

Operator

Your next question comes from the line of Gray Peckham with SFG Financial.

Gray Peckham – SFG Financial

Good morning guys, nice quarter.

Terry E. Swift

Good morning, thank you.

Gray Peckham – SFG Financial

Okay, actually I had a question about the Olmos, you mentioned in your release you had some good Olmos wells and those kind of a big variability in the production mix there. I am wondering if you can add that rig to the program and target some what you call the Olmos oil wells, do you have good visibility into where you might in county wells versus a more like more NGL kind of Olmos well?

Terry E. Swift

Yeah. This (inaudible) narrowing we’re already drilled some vertical well there and that would just reflect some. So we know that’s a very, very good oil in the Olmos area. So that’s what we were saying and (inaudible) and the other rig, we’re going to drill a combination of those Eagle Ford oil wells and Olmos oil wells. So we’re very confident in what we have there.

Alton D. Heckaman, Jr.

Yeah, I will add to that. In terms of the horizontal Olmos drilling for oil, this would be a very incremental thought saying for this year. The Olmos in that area of the county has been fairly extensively drilled and with last vertical wells. And as you go forward it definitely becomes oil. In that particular regard, you look at these vertical completions out there that has been successful in the past then typically can be anywhere from as low as 30,000 barrels per vertical completion to as high as 300; 500,000 barrels per relative completion. But we are looking at some of those areas out here, again, not a big area to work with, a nice increment to our business. So some of these scores are (inaudible) with anywhere from 9 to 16 stages. So if you can find that sand up there that could be very attractive to us.

Robert J. Banks

Let me just add though that in addition to that what you’re seeing us do down more on the southern part even though we are in the southern part of the field really have dominated areas that do have very good condensate yield areas. And so we know where they are as well. So with our other rigs we’re more (inaudible) that the better liquids rich areas that have the good compensate yields.

Gray Peckham – SFG Financial

Okay. Thank you.

Terry E. Swift

Thank you.

Alton D. Heckaman, Jr.

Thanks, Gary.

Operator

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

Ray Deacon – Pritchard Capital Partners

Yeah. Hi, good morning. I was just wondering if you could elaborate a little bit more on how many of the wells you think you might be able to drill to 6000 feet in South Texas given the big increase in the MPV between four and six?

Terry E. Swift

Okay.

Ray Deacon – Pritchard Capital Partners

That your average well was five, right in the quarter?

Terry E. Swift

Yeah. Let’s maybe – could you repeat that, you kind of bogged up little bit. Let me make sure we’re answering the right question.

Ray Deacon – Pritchard Capital Partners

Yeah, sure. Sorry, I just – it was in the Eagle Ford and Olmos, it sounded like the plan was to try to move towards 6000 foot laterals and I’m just wondering kind of what percentage do you think will be that link this year and maybe next year as well?

Terry E. Swift

Okay, well, we are going to actually pull some papers to get there and get you that answer, but while we are waiting on that, Alton needs to make an announcement here for everyone who is still in the call.

Alton D. Heckaman, Jr.

Yeah, let me – I’ve been just have to read this. Apparently, during the course of the call, we learn that the webcast link provided for the call was incorrect and the begin portion of our conference call here to those who listening via webcast was unavailable. So also this was corrected, every one got through part of the call. So with 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 first part of this call, you can check our website for the link to the archived replay. Again, we apologize for his inconvenience. Thank you.

Terry E. Swift

Okay. And back to answering the question, I think for the reminder of the year, our target is around 80% of our horizontals being the 6000 foot type model.

Ray Deacon – Pritchard Capital Partners

Thank you. And also I was wondering Davon had mentioned yesterday they were drilling a Tuscaloosa Marine Shale well and it seem like some of the acreage you have might be prospective. I guess any plans to test that?

Terry E. Swift

We’re very familiar with the Tuscaloosa Marine Shale and to the extent that we have a legacy petitioned that does have that Shale in and around our area but as we have looked at it right now, we don't have really highly resistive type Shale that you might see further to the east. But we do have the Shale, so right now we're just watching and wait and see what others do and see if there is any prospectivity in our area, we certainly to the extent we have the hat acreage (inaudible) but we don't have any near-term plans to drill into, we're going to wait and watch and see what other people do.

Ray Deacon – Pritchard Capital Partners

Great. Thanks Terry.

Terry E. Swift

Thanks Ray.

Operator

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

Michael Hall – Wells Fargo

Thanks. I apologize this, since a lot have been covered, hoping between calls earlier. But just on the fourth ring you’re potentially brining on. Is there any timing on that decision and could it have a material on 2010 production?

Terry E. Swift

Yeah, I think the timing we would be shooting for would be around mid-summer. There will be some additional production if we bring in that rig. So, yeah, I mean, but where we see the real benefits is the momentum in the next year, not only in terms of the production in that area. We’re going to get some very nice production volumes in 2012 from the work we do in 2011. But additional to that, we’re looking at our entirety of our Eagle Ford position and we think we’re going to move to ramp up one more rig at some point in 2012 anyway.

Additionally, as we kind of mentioned on the call, we’ve seen some gaps and our frac crew is going so fast. Now our drilling isn’t keep 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’re having at the well. So it’s kind of a multi benefit the way we see it.

Michael Hall – Wells Fargo

Got you. Thanks guys.

Operator

Your next question is a follow-up from Biju Perincheril from Jefferies.

Biju Perincheril – Jefferies

Hi. One quick follow-up on that, the SMR 2H well, do you have a 30-day rate for any – even one of those?

Terry E. Swift

Do we have a [Multiple Speakers]

Terry E. Swift

Yeah, what we can tell you, for two weeks it’s been about 1,000 barrels a day average. That’s probably as far we can give, I don’t think we can give you a 30-day number yet.

Biju Perincheril – Jefferies

Okay. So is that 1,000 Boe or just the oil component?

Terry E. Swift

Yeah, that’s just the oil. I mean, the question is these wells look pretty strong to us, they are doing very well, early data.

Biju Perincheril – Jefferies

Okay, perfect. That’s all I have. Thank you.

Terry E. Swift

Okay. Thanks Biju.

Operator

Your next question is from line of Andrew Coleman with Madison Williams.

Andrew Coleman – Madison Williams

Hi. Good morning folks.

Terry E. Swift

Good morning, Andrew.

Alton D. Heckaman, Jr.

Hey, Andrew.

Andrew Coleman – Madison Williams

I had a question on the asset divestiture package, do you think you might retain any of the deep rigs, like an override if you do sell for those properties?

Terry E. Swift

You are actually singing my song. We absolutely plan on retaining any rights that we don’t 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.

Andrew Coleman – Madison Williams

Okay. That's great and I just want the confirm some of that I heard early on in the call that production there in South Texas now, in fact that’s the largest region in the company (inaudible), right?

Terry E. Swift

That’s correct. Yeah.

Andrew Coleman – Madison Williams

All right. Good job, nice work.

Terry E. Swift

Thank you.

Alton D. Heckaman

Thanks a lot.

Operator

At this time, there are no further questions. Management, do you have any closing remarks?

Terry E. Swift

Okay. We’d like to thank you for joining us on our conference call. And we look forward to joining you again next quarter.

Alton D. Heckaman, Jr.

Thank you.

Terry E. Swift

Thanks.

Operator

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

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