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Swift Energy Company (NYSE:SFY)

Q4 2010 Earnings Call

February 24, 2011 10:00 AM ET

Executives

Paul Vincent – IR

Terry Swift – Chairman and CEO

Alton Heckaman – EVP and CFO

Bruce Vincent – President and Secretary

Robert Banks – EVP and COO

Jim Mitchell – SVP – Commercial Transactions and Land

Analysts

Neal Dingmann – SunTrust

Adam (ph) – RBC

Michael Hall – Wells Fargo

Derrick Whitfield – Canaccord

Ray Deacon – Pritchard Capital

Brian Kuzma – Weiss Multi-Strategy

James Pfeiffer –Wells Fargo Securities

Presentation

Operator

Good morning. My name is Lynn and I will be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy Fourth Quarter and Full Year 2010 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions) Thank you.

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

Paul Vincent

Good morning. I am Paul Vincent, Director of Finance and Investor Relations. I am pleased to welcome everyone to Swift Energy’s fourth quarter 2010 earnings conference call. On today’s call, Terry Swift, Chairman and CEO, will provide an overview. Alton Heckaman, EVP and CFO, will review the financial results for the fourth quarter. Then Bruce Vincent, President, and Bob Banks, EVP and COO, will provide an operational update. Terry Swift will then summarize, before we open it up to questions. Also present on today’s call is Jim Mitchell, SVP, Commercial Transactions and Land.

Before I turn it over to Terry, I’d like to 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 to you along with cautionary statements contained in our press releases and our actual results could differ materially. We expect our presentation to take approximately 25 to 30 minutes and have allowed additional time for questions.

Terry Swift

Thanks, Paul. And thank you, everyone for listening and for joining our conference call today.

2010 was a year of transition for Swift Energy. As our activity and our spending level shifted from our traditional asset base in South Louisiana to more predictable horizontal drilling, multistage fracing activities in the Eagle Ford Shale and almost tight gas sand in South Texas and horizontal drilling in Austin Chalk in Central Louisiana and East Texas.

We’ve made a commitment to be a top-tier organization. In 2010, we drilled 52wells, 32 of them horizontal. We witnessed our daily production in South Texas surpass daily production in South Louisiana. We continued two successful joint venture efforts, including new drilling in high rate production gains in the Austin Chalk, and we secured long-term gathering, transportation and processing with the production growth we expect in South Texas.

The past several years haven’t been just about operational transition. We have made significant and meaningful steps toward improving our entire organization. Demonstrating that safety first isn’t just a slogan, our investment in health safety and environment has developed a behavioral based culture, which has minimized HSE incidence and led to a measurable improvement in our overall SAGE performance.

On the drilling site, we’ve added high quality talent and implemented a fuel engineer training program which secures a consistent talent pool to promote engineers from within the organization. To accommodate increased production and completion activity, we bolstered our production engineering team at senior levels and we’ve also added and high graded through our supply chain management capabilities. These changes have kept us ahead of constraints that have been difficult for our whole industry and help us do better long-term planning and forecasting in our project management and decision making.

Finally, we have augmented our multidisciplinary asset teams by assigning facility and reserve engineers to work with specific field assets. These enhancements have resulted in better facility planning and overall efficiencies in the entire organization. We are proud of our team and our oil and gas professionals.

With the organizational changes I mentioned, we’ve successfully entered into the long-term service agreements that have helped us reduce our uncompleted well backlog from 12 in the fall to three today. And we’ve reduced our drilling days in South Texas from over 35 days to below 25 days. Just to mention two of the more noticeable improvements we’ve realized from our efforts in this short time period.

These improvements and efficiencies will appear in a meaningful way throughout 2011 in our operational and financial results. In the first quarter of 2011, we expect production to grow 10 to 15% over our fourth quarter 2010 levels, which were 5% higher than third quarter 2010 levels. We’ve been completing approximately four wells per month in South Texas and see the need to accelerate drilling activity to stay in balance with our completion efficiency. We are also going to begin drilling longer, horizontal laterals in our wells to improve performance and recoveries. We expect all of this to result in 25 to 30% production growth and 15 to 20% reserve growth in the coming year over 2010 levels.

Bruce and Bob will detail all of our operational activity, results and guidance in a few minutes.

But first, I will review of the few of the highlights of the quarter, which include six operated Eagle Ford wells, six operated Olmos wells, and one non-operated Eagle Ford wellbeing fracture stimulated. We’ve also dropped three operated Eagle Ford wells, two non-operated Eagle Ford wells and one Olmos well online during the first quarter of 2011.

This activity has led to production averaging approximately 27,000 barrels of oil equivalent per day during the first quarter so far. In southeast Louisiana, at Lake Washington, we are currently drilling a deep exploitation target well and expect to have results from this well in the second quarter of 2011. We also have a recompletion rig that will remain active in this field for much of the year.

Finally, in our Central Louisiana/East Texas area, the second well targeting the Austin Chalk in our joint venture area in the South Burr Ferry field was drilled. Initial production rates of this well were 840 barrels of oil per day and 10.2 million cubic feet of natural gas per day on the gross production basis.

Swift Energy has a 50% working interest in this well and a net revenue interest of 61.5%. The operating environment remains challenging as our industry is confronted with rapidly increasing service and equipment costs, extremely volatile commodity prices, and capital markets, and a decidedly anti-industry political environment.

As I have mentioned, Swift Energy is taking significant steps to mitigate the impact of these external factors and capitalize on the opportunities through our business models, and we believe that we will meet or exceed the financial targets we have set for ourselves this year.

And now I will ask Alton to present fourth quarter 2010 financial results.

Alton Heckaman

Thank you, Terry, and good morning, everyone. Thanks for joining us. Fourth quarter was another financially successful one for the company as we achieved sequential production in revenue growth over the third quarter. It solidified our overall financial position with a very successful November stock offer.

Our production was at 5% from third quarter 2010 while pricing changes were mixed. With oil prices improving significantly from both prior quarter and year and gas prices softening. Swift Energy’s financial results for the fourth quarter reflect this. Oil and gas sales excluding our hedging effects were 116 million, a 1% increase from 4Q ‘09 and a 9% increase from 3Q ‘10.

Our income from continuing operations was 10.3 million or $0.25 per diluted share, down from 4Q ‘09 but up slightly from third quarter 2010. Cash flow before working capital changes came in for the quarter at $1.65 per diluted share and 4Q ‘10 production was down slightly from a year ago levels was up 5% from 3Q ‘10 levels as Terry said in his opening remarks at 2.18 million barrels of oil equivalent.

Fuel prices were 14% higher than fourth quarter 2009 levels while natural gas prices were 5% lower. With the success in South Texas, our gas production is increasing. This combination of factors resulted in a net 2% increase in our realized price for Boe in 4Q ‘10 as compared to the prior year. We continue to vigilantly focus on our cost and metrics, as Terry said. Production costs came in with an on guidance at $10.24 per barrel.

G&A came in at $4.74 per barrel above our guidance, the result of higher labor costs, including increased performance based compensation as we continue to build a top tier talent pool in his ever tightening and competitive environment. DD&A came in at $20.35 per Boe just above guidance effective wide capital project costs continue to increase.

The interest expenses within guidance of $3.95 per barrel and production in Avalon taxes came in near the low end of our guidance at 10.2% of revenue. The result was encountered from continuing operations from the quarter of $10.3 million, which is $0.25 both basic and diluted.

Our effective income tax rate for the quarter was 40.6%, due mainly to a non-recurring small adjustment to deferred state income taxes. Cash flow before working capital changes before Q’10 came in at 66 million, or as I said, $1.65 per diluted share or EBITDA was 71 million for the quarter including CapEx on a cash flow basis with 125 million as the consciously accelerated our successful South Texas initiatives.

While gas prices have been very volatile, we have continued to lock in price floor hedges when market conditions are favorable. For the first quarter 2011, we have gas floors in place covering 50% to 60% of our expected first quarter production along with additional gas floors covering a portion of April, all in an average NYMEX drive price of around $4 per Mmbtu. Please see our website for complete and current detailed hedging information.

Let me spend just a minute to again highlight Swift solid financial position. As of year-end, we had no outstanding balance under our line of credit, and we closed the year with 86 million in cash on hand, the direct result of our successful November equity offering. This strong cash position, along with our untapped credit facility that currently has a 300 million borrowing base and runs through 2015, puts us in a very solid financial position to execute our line of site strategy. As always, we have included additional financial and operational information in our press release, including guidance for the first quarter and full-year 2011.

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

Bruce Vincent

Thanks, Alton and good morning, everyone. Thanks for being on the call. Today I will review fourth quarter 2010 activity, including production volumes, recent drilling results, activity in our core operating areas, and our plans for the first quarter of 2011. Bob Banks, our Chief Operating Officer, will then discuss significant operational activity in the fourth quarter and its effect on the remainder of 2011.

Beginning with production, Swift Energy’s production during the fourth quarter of 2010 totaled 2.18 million barrels oil equivalent or 13.1 billion cubic feet equivalent, an increase of 5% from the 2.07 million barrels of oil equivalent produced in the third quarter of 2010.

Production increased primarily as a result of an increase in completion activity in South Texas, as dedicated fracture stimulation proven equipment began working for us during the quarter. Fourth-quarter 2010 production when compared with fourth-quarter 2009 production of 2.21 million barrels of oil equivalent decreased 1%.

As we drill, complete, and produce more oil we continue to improve performance, economics, and deficiencies. For the first quarter of 2011, we expect production to increase approximately 10 to 15% over fourth-quarter 2010 production. We believe this level of production growth is sustainable throughout the year and into 2012 as a result of the organizational and operational enhancements we have made over the past two years.

While our fourth-quarter drilling results, Swift Energy drilled 12 operated development wells, two of which were plugged and abandoned in Lake Washington, and also participated in two non-operated exploration wells. The company also drilled one operated exploration well and participated in one non-operated exploration well.

In McMullen County in South Texas, one operated horizontal development well was drilled to the Eagle Ford Shale. Two operated horizontal development wells and one vertical well were drilled to the Olmos sand, and one non-operated horizontal development well was drilled by a joint venture partner to the Eagle Ford Shale.

In Webb County Texas, four operated development wells were drilled to the Eagle Ford Shale while one non-operated – excuse me, one operated horizontal exploration well was drilled to the Eagle Ford Shale in La Salle County.

The company has three rigs capable of drilling horizontal wells in Eagle Ford, and/or the Olmos all of which are currently active in South Texas. In our central Louisiana East Texas core area, we drilled one operated well and participated in a non-operated well in the Brooklyn Field in East Texas. Both of these wells were drilled to the Austin Chalk. In the Burr Ferry field in Vernon Parish, Louisiana, one non-operated exploration well was drilled by our joint venture partner. This well was drilled to the Austin Chalk to test acreage within the joint venture’s area of mutual interest.

In the Lake Washington field in Plaquemines Parish, Louisiana three development wells were drilled, one well was completed and two wells were plugged and abandoned during the fourth quarter. Three recompletions were performed during the quarter resulting in an average production increase of 183 gross barrels of oil equivalent per day for completion.

In addition to drilling and recompletion activity, 12 field optimization projects were carried out resulting in an average production increase of 75 barrels of oil equivalent per day for a project.

One drilling rig and one recompletion rig are currently operated in Lake Washington. I will briefly review our activity in each of our core operating areas for this quarter, and Bob will detail the highlight of our more recent activities.

In the South Texas core area, which includes AWP, Sun TSH, Briscoe Ranch, Las Tiendas and Fasken fields fourth-quarter 2010 production averaged 9968 net barrels of oil equivalent per day or approximately 60 million cubic feet equivalent per day, a 15% increase in production when compared to third quarter 2010 production in the same area. This also represents a 39% increase over fourth-quarter 2009 production in the same area.

Dedicated fracture stimulation equipment and personnel, improved drilling, production, supply chain and project management efficiencies have all contributed to these higher-level productions in South Texas. As Terry mentioned, the development of this core area has added a predictable, high-value component to Swift Energy’s operations.

We believe this area will continue to grow meaningfully in the quarters to come. Swift Energy currently has three operated rigs drilling horizontal Eagle Ford and/or all the objectives in McMullen County.

In Southeast Louisiana core area, which includes the Lake Washington and Bay de Chene fields. Production during the fourth quarter averaged approximately 9,692 net barrels of oil equivalent per day or about 58 million cubic feet equivalent per day, a 5% decrease when compared to our third quarter 2010 average net production from the same area.

Lake Washington averaged approximately 7,862 net barrels of oil equivalent per day or about 47 million cubic feet equivalent per day. A decrease of 2% when compared to third quarter 2010 volumes. Primarily reduced to reduce the activity and natural declines. Bay de Chene sequential production decreased 13% to 1,830 net barrels of oil equivalent per day, or about 11 million cubic feet equivalent per day.

The sequential decline is due to absence of new drilling and limited operational activity and natural declines. One barge rig is currently operating in the Lake Washington drilling an exploitation test.

The Central Louisiana and East Texas core area, which includes our Brookeland, Masters Creek, South Bearhead Creek and South Burr Ferry fields contributed 2,183 barrels of oil equivalent per day or about 13 million cubic feet equivalent per day.

Our production in the fourth quarter 2010, this was a 10% increase from third quarter 2010 production. We have been encouraged by the early results of wells drilled in our joint venture area in the Burr Ferry field in Vernon Parish, Louisiana up to this point. The company is exposed to a significant acreage position in this joint venture area and continued success would allow for another core are to demonstrate significant production and reserves growth. Bob will discuss our 2011 plans for this area in just a moment.

One non-operated rig is drilling a well to the Austin Chalk formation in East Texas in our Brookeland field currently. In our South Louisiana core area, which is composed of Horseshoe Bayou, Bayou Sale, Jeanerette, Cote Blanche Island and Bayou Penchant, production averaged approximately 1,736 barrels of oil equivalent per day or about 10 million cubic feet equivalent per day. During the fourth quarter, minimal operational activity occurred in this area during 2010.

Now I’ll turn it over to Bob and let him review the operational highlights of the fourth quarter.

Robert Banks

Thanks, Bruce. At our Lake Washington field, we drilled three wells during the quarter, completing one in PNA in the two. These wells are the final wells drilled in our 2010 shallow and ultra-shallow drilling campaign. Even though this program had mixed results in 2010, we did complete eight of 14 wells with a development cost of less than $14 per barrel. Production added through this program allowed us to maintain high levels of cash flow from the Lake Washington field during 2010.

Also, during the quarter at the Lake Washington field, we continued re-completion and field optimization projects, as Bruce mentioned. These projects are low cost and high return and will continue throughout 2011. We do benefit from strong crude oil pricing in Louisiana and the economics of these projects are extremely robust. We recently started deeper exploitation well in Lake Washington, this well should be completed in the second quarter of this year.

Moving forward, our drilling dollars will be committed to deeper, more impactful development exploitation and exploration wells in conjunction with our field optimization work. In the Brookeland field in our South Louisiana East Texas core area, South Louisiana East Texas core area we drilled one operated well and one non-operated well during the fourth quarter. Neither well is on production yet.

We are in the process of determining to what extent new reservoir analysis and drilling technology will enable us to reenter and further develop mature fields in the Austin Chalk. One non-operated exploration well, the gas ARF 18-1 (ph) targeting the Austin Chalk was drilled and completed in the South Burr Ferry field by our joint venture partner, approximately 7 miles from our first successful exploration well.

Initial production test rates of this well were 840 barrels per day and 10.2 million cubic feet of gas of gross production with flowing tubing pressure of 5,700 psi on a 32/64-inch choke. Swift Energy has a 50% working interest in this well and a net revenue interest of 61.5%.

As a reminder, our previously announced first well, the GAS RS 5-1 (ph) tested at a 1,000 barrels per day and 13 million cubic feet of gas of gross production. We are currently analyzing data and well performance from these first two wells and will transition into a detailed appraisal program later in the year.

In our South Texas operating area, six operated Eagle Ford wells, six operated development wells, and one joint venture Eagle Ford well was fracture stimulated during the fourth quarter. We’ve also fracture stimulated two operated Eagle Ford wells, one joint venture Eagle Ford well, and one Olmos well so far in the first quarter. I refer you to our press release issued this morning for an average initial production rates of all of these wells as well as for the wells that we have completed since the end of 2010.

It is important to note that the test rates of these wells are all consistently measured after the company implemented a specific reservoir management initiative that includes producing all of its horizontal wells in this core area at restricted choke settings. Initial choke settings are as well as 12/64 inch and are gradually increased to a setting of 20/64 inch and produced at this level for an extended period of time. We believe that this approach will result in shallower and initial production declines and higher initial pressures in URs.

Our engineers continually calibrate overall performance to our subsurface models and refine their approach to completion and production techniques in order to optimize our performance.

As a result, we are now extending the lateral length of our wells to take advantage of economic efficiencies. Initially, we continue to refine our completion techniques, our fluid, and our profit mixtures.

The results from some of these changes are coming in during the first quarter, and so far we like the improved initial production rates and pressure responses. We are also experiencing exceptional performance from the dedicated fracture stimulation crew and equipment.

We took control of in the fourth quarter of 2010. This equipment have continued their pace of activity in the first quarter of 2011 as well. In fact, we have been able to reduce our drilled, but not yet completed well inventory to three operated wells in one joint venture well.

Now we accelerate our drilling activity to accommodate the better than expected performance of this crew. We have made arrangements to return the completion crew and equipment to our service provider for approximately 30 days during the first quarter. This arrangement will allow us to balance out our drilling and completion activity for the rest of the year while at the same time providing us a slight financial benefit.

It is important to remind those listening to our call that while it may seem like a long time ago, Swift Energy only completed its first Eagle Ford Shale well in the first quarter of 2010.

That is a relatively short period of time for Swift Energy to ramp up activity as fast as we have. We have made major improvements to our organizational design and operating performance in a very short period of time, and we expect we will continue to deliver better and more consistent results. We expect our performance to continue to improve as we refine our shale and tight sand resource development techniques.

In 2010, we evaluated and analyze much of our Eagle Ford and Olmos acreage through strategic drilling activity. We believe this evaluation and appraisal phase of the program has now effectively de-risked most of our undeveloped Eagle Ford Shale and Olmos tight sand acreage positions.

As we move into the development and authorization phase with these assets, the time and effort we’ve put into securing drilling, completion oil tubing services, accessing our infrastructure market outlets, building the water handling infrastructure, and securing oil country tubular goods and clinical equipment, just to name a few things, will allow us to minimize the effects of service shortages, transportation constraints, oilfield inflation and other potential bottlenecks that operators in South Texas may encounter.

We still have a lot of work to do, but we now have the company to a point where our continued execution will take us to the next level. As you can see from our fourth quarter results and guidance for first-quarter and full-year 2011, we believe we will deliver. While 2010 may have been a year of transition for Swift Energy, 2011 will surely be the first of many years of performance and growth.

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

Terry Swift

Thanks Bob. Before we open up the line for questions, I’ll summarize Swift Energy’s fourth quarter results and review some of the highlights from today’s call. We are fracture stimulating completing and bringing wells online at a faster pace than originally anticipated. We are performing at high levels across all of our technical disciplines.

This is best demonstrated by our rapidly growing daily production rates. We continue to enter into strategic agreements with service providers to protect our project economics and ensure access to vital operational supplies and services. Today, our first quarter 2011 production has averaged approximately 27,000 barrels of oil equivalent per day. We expect to grow full-year production by 25 to 30% over 2010 levels.

A second Austin Chalk joint venture well in Louisiana has tested and is producing at high rates. This really – this joint venture will see an increase in activity in 2011. Similar results to the first two wells in this area could lead to significant increases in drilling production and reserves in the years to come. Our crude oil production is levered to Louisiana crude oil pricing, and we are benefiting from recent increases in these pricing levels.

With that summary, 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.

Neal Dingmann – SunTrust

Production guidance in more particular like Louisiana or unlike Washington and the Brookeland area. Just wondering kind of as you look at this year, what type of decline – you’re trying to forecast and you have hoped in your expectation both around Lake Washington and Brookeland, and will you continue to add some injectors etcetera to trying to keep that production from depleting as quick?

Terry Swift

Well, while the guys are trying to get an answer for you – this is Terry Swift – I thought I’d speak up. First of all, when we look at the Austin Chalk area from Brookeland over to Masters Creek and then come down to south Louisiana, these are entirely different provinces, different kinds of production. I heard the question, properly, I heard you mention Brooklyn as well as Lake Washington. And when we are looking at the Austin Chalk, we are real excited about that area in Burr Ferry between Brooklyn and Masters Creek. It does have good implications for some of our Brooklyn and Masters Creek production, so we are certainly, looking at that area in Burr Ferry as an area where we can increase production.

Now, as you increase production by drilling wells, obviously, in that area, the natural declines there are higher declines. They are not as high as Shale wells, but Austin Chalk wells, naturally, have a pretty high initial decline in the 50% tight range for initial decline.

Moving to South Louisiana and Lake Washington. We have been in a mold there where we have been doing a lot of recompletions as we noted during our investors. A lot of the wells that we drilled in like Washington have lots of behind pipe zones. We have taken advantage of that over the years to change sliding sleeves (ph) and come up the whole, and really it’s best to talk about declines on a fuel wide basis, not individual well basis because a lot of these zones are small zones that might produce a couple of year, five years, and then you move up the hall. So an individual well can have a pretty interesting decline profile. I will turn to Bob for further comment on that.

Robert Banks

Generally in southeast Louisiana, we have about three models working. One model does assume some of this deeper success. As I mentioned, we are going to drill some deeper extension well and tests and we think that there is a lot more potential beneath Lake Washington then we have been able to tap into so far. So in a success case model, we had actually see production growing maybe a little bit toward the end of the year. We won’t be drilling those tests until closer to the second half of the year. In the case where we are just doing our production optimization work, doing our bread and butter activity, we don’t have any of that exploration success we can see maybe a decline of 10 to 12 or 15% without the kind of success that we are planning for.

Terry Swift

You are going to hear us say this several times in the Q&A, I’m sure, but we do have an analyst meeting coming up shortly where we will get into the details of our 2011 plan by field, by area, by activity. Let it suffice to say right now that was 25 to 30% production growth that we are guiding for 2011 it has a large impact coming from South Texas, but there are some nice compliments coming from these other areas that we will detail at the analyst meeting.

Neal Dingmann – SunTrust

And this sure does include some deeper success in that production estimate?

Paul Vincent

No, no.

Terry Swift

No.

Neal Dingmann – SunTrust

Got it. And then over, did I hear you right on the Eagle Ford that you left a rig Gulf for 30 days kind of as a catch up because you are running ahead, or could you maybe give a little more color around that for the 30 day that you let off this quarter?

Robert Banks

No, it is not the drilling rigs. In fact, what happened – our drilling efficiencies were so far ahead of our completion efficiencies last year that we built up quite an inventory of wells ready to be flat. We got a dedicated crew from Weatherford in the fourth quarter, and I guess it has probably outperformed our expectations to where the efficiencies ramped up so rapidly we withered away that inventory of wells to the point now where we actually have to step up our drilling activity to rebalance it out. So we are taking actions now to pick up a spinner rig and to do some more things to try to get our drilling efficiencies up even further. And we thought the prudent thing to do was to take 30 days on the frac crew, let that go back to our service provider for 30 days, that way we don’t have to pay the fixed fees for that spread until we get a little more inventory out ahead of us. And by taking this 30 day break that will let us balance out the rest of the year where we can be very efficient with our drilled frac online efficiencies.

Neal Dingmann – SunTrust

Okay. So even with a rig you have planned now, would that stepped up frac completion schedule, or will you still be on schedule there?

Terry Swift

Yes.

Neal Dingmann – SunTrust

Got it, got it. Okay. And then last one, if I could. You mentioned, just kind of wondering when you break down Olmos versus the Eagle Ford well results, or I guess what I am asking is the completion technique. How different are we talking? You mentioned kind of the extended latter a link that you are seeing on some and then you mentioned some of the processes that are seeing higher IP rates. I guess, two question there, are you seeing that the improved rates now here this quarter in both of those plays, and how similar are the links and so the techniques between the two plays?

Terry Swift

Well, yeah, I think we are using pretty similar techniques between the Eagle Ford and Olmos. And as we have always said, we kind of built our development into a number of phases. The first phase being in evaluation and data capture phase, the second phase being an appraisal and efficiency phase. And basically, what we were trying to do during those periods is get the subsurface data, get our baseline models or lateral links onstage spacing, on profit mixes. Compare well results against those baseline models to see how we are doing.

So what we have learned through that process is some refinement, number one, but, secondly, we believe with the contracting arrangements we currently have and the well performance that we have seen on wells we have tested, taking our lateral links from anywhere in the 3500-foot to 4200-foot range, which will kind of our baseline for both the formations, to where we are now moving up besides 6000 feet in lateral links going from 11 to 12 stages of frac to as high as 17 stages of frac, but those economics and well performance appear to be more optimal.

And so that is what we are doing. We have also changed a bit of our frac design. Our early frac designs were more geared around split water fracs, pumping large volumes of water. We have now moved more to a hybrid type of design where we are pumping the mix of water and gel. We are changing around some of our profit mixes from different sand sizes to also even putting some box in one well. In a joint venture area we are experimenting a little with our partner on a Schlumberger frac technique, so we are trying different fracture stimulation designs in both of these. And I guess, what I can leave you with is the combination of extra lateral length and the change in some of our design is showing us better performance.

Neal Dingmann – SunTrust

Great, guys. Thanks for all the color.

Terry Swift

Thanks.

Operator

Your next question comes from the line of (inaudible) with RBC.

Unidentified Analyst

Hey, guys. Long time listener and first time caller.

Terry Swift

Really, welcome.

Unidentified Analyst

I – just wondering quickly on your new CapEx, is that increase result of just higher costs or increased drilling, what’s driving that?

Alton Heckaman

It’s a predominantly – there is a little bit of higher cost in there, but it’s predominantly some additional activity. Bob mentioned that we were going to add this sputter rig back in, and that wasn’t in our original CapEx.

Robert Banks

Well, plus this – sputter rig and plus drilling the longer laterals and longer completions brings more capital into the program.

Unidentified Analyst

Okay, great. So you guys still expecting kind of 6 to 7 million on the yield per well cost, is that kind of creeping up slightly with the new laterals?

Alton Heckaman

Well, it’s creeping up – it’s going to creep up with the extended laterals. Obviously, when we go from 4,000-foot laterals to 6,000 foot laterals and go from 10 or 11 stages to 17 stages, the costs definitely go up. Now, we are going to show you at the analyst meeting the economics of all of this and why we believe in what we are doing now.

Unidentified Analyst

Okay, great. And then just quickly jumping over to Eagle Ford, I was wondering if you guys could break out that La Salle County exploration well, just kind of IP rates and oil, gas split on that.

Terry Swift

Yeah, we can and let’s get it real quick.

Bruce Vincent

Yeah, that well is our Carden well. We were out at 4.2 cubic feet a day and 134 barrels of oil per day and that doesn’t include any NGLs.

Alton Heckaman

I believe that’s also in the state records.

Terry Swift

And that should be in the records, yeah.

Unidentified Analyst

Okay. Great, I appreciate it guys. Thanks.

Terry Swift

Thanks.

Bruce Vincent

Thanks.

Alton Heckaman

Thanks

Operator

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

Michael Hall – Wells Fargo

Thanks. Good morning.

Terry Swift

Good morning, Michael.

Michael Hall – Wells Fargo

Just curious. I guess I was a little surprised at how much you’ve been moving around within the Counties of South Texas and the Eagle Ford program. As you are trying to increase, the backlog, if you will, or increase your inventory for your dedicated frac crew. Are you going to stay in kind of the AWP area for the majority of 2011, or I guess, what’s the thought on the split between all the various areas?

Robert Banks

Well, this is going to sound like a little bit of a copout, but at the analyst meeting we are going to give you a lot of detail that gets right down to that. But at this point, I think it’s clear to say that we’ve been working on a lot of marketing agreements, transportation agreements, things of that nature and you did see us bounce around a little bit. We really wanted to get fast and up and running and we were very, very pleased with the rock that we saw over there. Even with gas prices being down, gas can be a great investment when you’ve got good rock and good results. And so you did see us move over there to the FASCON acre to secure more of our acreage, get that all buttoned up.

We are working – and we’ve got the market agreements, transportation agreements all in place there. So you won’t see as much activity over there next year as you will over in AWP. At the artesian wells area, we’ve still got some marketing outlook things we are working on that we hope to bring that forward to you guys in the next couple of quarters. We will be giving you a lot of detail on that. But at the Analyst Meeting we are going to be showing you a lot about AWP, both the oil for the Eagle Ford and the gas condensate on the almost. That is where the lion share of our activity is in 2011 as relates to Eagle Ford. And that’s where some really good results have come. Also in the gas condensate window, so we are really bullish about that area. We will give you lots of detail at the Analyst Meeting.

Terry Swift

The other comment I would make Michael is that, strategically what we have been trying to do is to evaluate, and alleviate our entire acreage position. And in the process, really de-risk it. I think Bob made a comment earlier about how we significantly de-risk a lot of our acreage position. We understand it now. And that really will allow us to go forward with a more efficient development.

Michael Hall – Wells Fargo

Okay, great. I appreciate the color and look forward to the Analyst Day. I guess on the topic of midstream over in the Austin Chalk, how long until the facility constraints are alleviated in the various different areas? And then also if you could, what rates are the two wells currently producing at?

Terry Swift

We will have to get back with you on the current rates of those wells, but at present, I don’t believe we really have any marketing constraints in that area. Both the wells are producing. They are getting the markets. As we noted in our press release, we drilled I think 7 miles of part, so we have been doing appraisal. And you know, we are going to give it measured results at this point. We do believe that we can grow production in that area. We’ve got a big acreage position in that area. There are some marketing things we need to work forward before we get real aggressive. We’ve got a joint venture partner there who is the operator of that area. 2011 I think will be an appraisal year, whereas 2010 was more of an exploratory year in those assets.

Michael Hall – Wells Fargo

Yeah, the facilities’ constraints really aren’t with Swift they are really with the midstream player that we are, basically, selling the product to?

Robert Banks

Yeah. The midstream does have a number of line pressure issues. We’ve been working with them very carefully trying to get those resolved. So those rates of those wells currently, our cut back. Each well write in around 4 to 5 million a day, 400 to 500 barrels of oil per day. Pressures are holding very flat, very steady. We like what we are seeing on the pressures, but we do have to alleviate some of that midstream line pressure issue. And I hesitate to give you a day. We talk about this every week in our operating meetings, but we do need some help from the midstream side, and they are working on it.

Michael Hall – Wells Fargo

Okay. And then one more, if I may, can you remind me of the kind of variation of geology between Brookeland and Burr Ferry in particular what we would think about oil and gas splits?

Bruce Vincent

Well, the Brookeland area is a shallower area that’s more of a depletion drive reservoir. We don’t have much water over there.

Typically, we have had smaller oil wells that would be 250,000 barrels, 350,000 types wells, and nice complement of associated gas, depletion drive. We move all the way over to Masters Creek and we get into some real horses. You get deeper. Some of those wells approached 2 million barrels equivalent over there, mostly oil and lots of water. A typical well would come in well over a 1000 to 2000 barrels of oil a day and could have that much or twice that much water.

Bearhead kind of in between more of a Masters Creek type of model in terms of the water that’s coming with it. As we noted early in what we are doing there, it’s a – I would say we are at the point where we need to go into appraisal. We have definitely attacked some Austin Chalk zones that are highly fractured, high pressure, lots of water, lots of temperature, probably a 1000 to 2000 feet deeper than your typical Brooklyn well, maybe a thousand feet shallower than the typical Masters Creek well.

Michael Hall – Wells Fargo

Okay. That’s helpful. Thanks very much.

Terry Swift

Thanks.

Michael Hall – Wells Fargo

I’ll see you in March.

Terry Swift

Okay.

Operator

Your next question comes from the line of Adam (inaudible) with RBC Capital Markets.

Adam (ph)

Good morning, guys.

Terry Swift

Hey, Adam.

Adam (ph)

I will try to avoid making you do for answers until next week. First of all on pricing. Do your differential assumptions and your guidance take into account what’s currently going on, or you’re doing more conservative than historical?

Alton Heckaman

Well, no, they do take into account what’s going on. Obviously, we can’t predict the future with regards to that, but it’s certainly important to note that our Louisiana oil production is getting either the LLS or HLS pricing.

The coastal stuff, Lake Washington alike is really prized against heavy Louisiana light crude oil. The Austin Chalk production is really getting the Louisiana like pricing, which I check this morning, they were actually running 117 and 117 and 75, so it’s more correlated to grant pricing plus a little premium, because of the transportation issues and certainly not WTI.

Adam (ph)

That leads me to the next question of prices and differentials probably are. Did you think about hedging at some point either pricing or differentials?

Alton Heckaman

Well, you know, yes the simple is yes. You really – LLS and HLS don’t have a market that you can go and do a swap in. You would actually have to contractually agree with the purchaser and a specific price or a specific spread tied to that particular market.

And then – but you can hedge against WTI, whether it is sort of use of lower, whether it use of swaps. But then you would have to contractually agree with your purchasers with regards to the differential and the role as it relates to the different pricing mechanisms.

And of course, the other thing to remember when we talk about swaps along that production is in the coastal area, and so we clearly want to be concerned about putting swaps in place and lease that production.

Adam (ph)

So in terms of potentially putting in some floors...

Alton Heckaman

The thing you find with the crude oil markets though as you just can’t go very far out with force. We look at them all the time. In fact, we were looking at them yesterday. So I think you could expect us to continue to do what we’ve done in the past, which would be in strong strengthening markets like this, try to layer on the floor as far out as we can get them at reasonable prices.

Adam (ph)

Okay. Lastly, with its capital budget, it looks like you are going to have somewhat of a cash flow CapEx. Could you talk a little bit about what your thoughts are funding them?

Alton Heckaman

Yeah. Well, of course – we’re starting the year with quite a bit of cash in the bank from the equity offering. Obviously, we don’t know exactly what pricing is going to be. We build our budget around a couple things. One is there is always a discretionary component to the budget. That’s the first thing to go with we’re not going to meet our cash flow objectives. Secondly, one of the things we’re going to be looking at this year is possible disposition of nonstrategic assets that would also fill the gap. And of course the third thing, we think our balance sheet certainly could afford some borrowing a lot of credit if we needed to go into that. So I think in the end we’re going to continue to manage the company we have historically, always trying to maintain low leverage yet high liquidity.

Adam (ph)

Is there a magnitude or framework on potential asset sale?

Terry Swift

Well, we’re still in the process of trying to decide exactly what we might target for dispositions. They would certainly be non-strategic assets and of course you never know you’re actually going to get something done till you do it. But we’ll do our best, I know you’ll try not to do this, Adam, but we’ll do our best to give you little more color on that in a couple weeks.

Adam (ph)

Right. Okay. Thanks.

Operator

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

Derrick Whitfield – Canaccord

Good morning, guys.

Terry Swift

Good morning.

Alton Heckaman

Morning, Derrick.

Derrick Whitfield – Canaccord

Two question for you, and getting with the Eagle Ford, could you comment on the non-operating well you completed there in the fourth quarter, specifically did you have a liquids component to it?

Alton Heckaman

Yeah, the JV – that was the JV 2-H we frac, yeah did have nice liquids component to it, right on that well was about 8.4 million about 134 wells of oil a day.

Derrick Whitfield – Canaccord

Right. And then moving over to the Austin Chalk trend, could you comment on the complete well cost of your second Burr Ferry and EUR if possible that you guys are selling to you first well?

Alton Heckaman

Yeah, I mean, the second well I think that well came in under $6 million, so we did pretty good on the efficiency. We kind of changed it around and drilled single moderate along that well and we did not have near mechanical issues that we have on the first well. So we think that’s more indicative number of go forward Austin Chalk drilling in the Burr Ferry area. In terms of the EURs very early data, that we see them pretty similar to the Masters Creek type wells as Terry alluded to. So you know, we’re thinking from a EUR perspective we ought to be able to do 1.5 barrels or better from of these wells.

Derrick Whitfield – Canaccord

Great. And then maybe thinking of this second well that you guys drilled, could you offer any color or implications?

Alton Heckaman

You’re talking Burr Ferry.

Derrick Whitfield – Canaccord

Yeah, that is correct.

Terry Swift

Yeah, that was funny. The second well was seven miles from the first well. And this was a pretty large acreage position. So I think clearly we – the program was design to take two portions on opposite ends of this acreage position drill exploratory wells get our data and now what we are doing is developing an appraisal strategy to further delineate that acreage position. And then from that we would move into more of in-field development drilling type program.

Derrick Whitfield – Canaccord

Okay. And then maybe slide number to the Brookeland field, do you have any preliminary thoughts on your first operated in JV well.

Robert Banks

We want to get them online before we get too far long. I think we will talk a little bit more about that at the analyst meeting. But I’d hesitate to talk much those until we flow test them.

Derrick Whitfield – Canaccord

Sure, that’s fair. Thanks guys for all of your color.

Terry Swift

Thank you, Eric.

Alton Heckaman

Thanks, Eric.

Operator

Your next question comes from the line of Ray Deacon of Pritchard Capital.

Ray Deacon – Pritchard Capital

Hey, good morning. I had a question about – any preliminary thoughts on the decline rates of Austin Chalk production and sort of ultimately EURs on the wells.

Terry Swift

I think I will just time out that a little bit. In terms of the EUR we think is very similar to the Masters Creek type wells from what we are seeing so far. So we would expect EURs remain at half barrels or more maybe if at all hangs in there the way we think it is. The pressures that we’re seeing so far we have some line pressure we’re bucking up against right now. So the pressures of the wells right now are actually very flat, very steady. So we can’t calculate for you a good decline at this point because we are Bakken high line pressure and that’s our rates are going around 400, 500 barrels a day instead of a 1000 barrels a day.

Ray Deacon – Pritchard Capital

Okay. Got it. And how much production would you say is curtailed currently because of different constraints?

Terry Swift

I think right now down in the well in the AW – let’s go to south...

Bruce Vincent

I think we really are working on the various constraints that we have and we have found in South Texas there have been some the high issues and compression issues, as you’re well aware of the winter we really had some hard shocks of cold weather that created some issues.

We do have a little bit of bottleneck but I would hesitate to say that we have certain excess capacity at this point. Now Bob mentioned in the Austin Chalk over in Brookeland that we are cut back holding those back because of some higher pressure constraints.

Probably a good thing to produce those well for where they are right now, even if those constraints come off it might not open the wells up like quickly. Same thing down in South Texas, to the extent that we’ve got most of the well, our constraints open we’re managing this production and not reaching for the moon in terms of opening up Chalk.

So even if we get a little bit more latitude over in the we’re not likely to go reach for that real quick. So I would not want to say that there is pent-up held back production at this point.

Ray Deacon – Pritchard Capital

Okay, got it. And I guess, Terry, is the goal to kind of keep the uncompleted well inventory around, I think, you said, it was three wells, so does that – is that kind of where it’s going to stay.

Terry Swift

Yes, I would love to have it at zero and be at perfect harmony with the world, but three to five wells is probably where you want to be expecting it. And every now and then you will be a little high, a little low.

Ray Deacon – Pritchard Capital

Right. Got it. Hey, thanks very much.

Terry Swift

Thanks Ray.

Operator

Your next question comes from the line of Brian Kuzma with Weiss Multi-Strategy.

Brian Kuzma – Weiss Multi-Strategy

Hey, good morning, guys.

Terry Swift

Hey, good morning.

Brian Kuzma – Weiss Multi-Strategy

I’ve got a couple questions for you here. One, do you have the proved developed PV-10 number? May be...

Alton Heckaman

We certainly probably have that number, but we don’t have it available to us. And I don’t think we disclose that in the past, Brian.

Terry Swift

Yeah, we have it, obviously, but I think to get any color and detail, we are really going to have to go to the analyst meeting.

Brian Kuzma – Weiss Multi-Strategy

Okay. And then I wanted to ask, I think you said this earlier but I missed it. What’s the average net revenue interest on your Austin Chalk well?

Alton Heckaman

The two that we’ve talked about in a joint venture area, the work interest is around 50% and the net revenue, which is around 60%, slightly over that.

Robert Banks

Yeah, that’s on the second well. The first one we didn’t have the same net revenue.

Brian Kuzma – Weiss Multi-Strategy

Yeah.

Bruce Vincent

But most of the acreage position we do employ the fee mineral position. So in addition to our working interest position, so...

Terry Swift

Yeah, and that’s a good point that you bring up, because we are really wearing two hats out there. We are a working interest partner, and we definitely are working with our joint venture operator to get the best wells we can, but we are also royalty in there, so we are looking for our acreage to be developed.

Brian Kuzma – Weiss Multi-Strategy

And the lateral life when you run into single lateral, are you able to run it as long as lateral link in the reservoir?

Jim Mitchell

Yes, I think that lateral link on the single lateral, I think we got about 5,000 feet or so, something like that. That’s pretty much what we were designed to do.

Brian Kuzma – Weiss Multi-Strategy

Okay.

Robert Banks

Hey, Brian, on your question about proved developed PV-10, that will be disclosed in our 10-K that we will be filing today, so you will be able to get the number right out of there.

Brian Kuzma – Weiss Multi-Strategy

All right. And your CapEx, the run rate you having Q4 and Q1, it looks like it’s going to step down for the rest of the year. And I am curious, what’s driving that?

Alton Heckaman

Let’s make sure we’ve got the question right. You seem to think our CapEx is stepping down.

Terry Swift

Brian, again, I think, as Thursday, March 10th is our Analyst Day, we are going to be talking about that. Remember that the current guides of 430 to 480, as Bruce mentioned, we’ve got a lot of discretion in there. We’ve got some other activity that we are going to be talking about at the analyst meeting as far as a full complement there. So I think – and from the standpoint of right now, we’ve got two rigs under contract for the full year, and one rig that runs through the middle of the year, and, again, depending on events and success, we will dictate the full year, so we are a little bit front end loaded, but we hope to get the momentum and accelerated going throughout the year.

Brian Kuzma – Weiss Multi-Strategy

And on the back half of the year, you’ll be able to ramp-up, keep the same kind of run rate going question not.

Terry Swift

Yeah. Based on success and.

Brian Kuzma – Weiss Multi-Strategy

Okay. That’s it for me. Thanks, guys.

Terry Swift

Thank you, Brian.

Alton Heckaman

Thanks, Brian.

Operator

(Operator Instructions) Your next question comes from a line of (inaudible) with Jefferies.

Unidentified Analyst

Hi, good morning. A couple of questions. I’m sorry, if you’ve answered this already. The 99 barrels of negative oil, is that most the Lake Washington area, and what drove that?

Robert Banks

Some of its Lake Washington, but also you know the FCC put some guidance out there about the five yields going forward. We kind of looked at all of that. We’ll looked at some of the reserves that have been on the books for little while. And we actually took a proactive decision to remove some reserves from the proven category and move them into the probable category, only because they have been on our books a little longer than most. So that would be a good portion of that number, and any other portion would be some remapping and results from our shower drilling really altered some of our interpretation to where we have moved some of those proven reserves into more of a probable category now under your SBC definition.

Terry Swift

I hate to be redundant, but we will be giving you a little more color on this at the Analyst Meeting.

Unidentified Analyst

Okay. Can you tell me I guess how many part locations, how many barrels of part reserves you have that Lake Washington?

Terry Swift

I don’t have that much – I think we will be prepared with that kind of information at the meeting.

Unidentified Analyst

Okay. And then this deeper objective. Those will also be oil targets?

Robert Banks

Yeah. But they will be oil targets or they will be gas with very high liquid components.

Unidentified Analyst

Okay. And then what the prices where they are, especially for the Louisiana prices, what opportunity do you have to accelerate equity they are, even from a consolidate drilling. If my understanding is right, you had quite a bit of fluctuations there remaining optimistic there?

Terry Swift

Yeah. I think they’re very well could be. We are, obviously, trying to balance out our budgets and work programs and commitments on rigs and capital, but, believe me, with all these differentials, we are talking about that every day.

Alton Heckaman

Yeah. We were actually talking about that just the other day, but I think you got to remember one of the reasons we’ve reduced activity in Lake Washington is in large part because we are trying to both evaluate the land and earn the acreage in South Texas. So you’ve got multiple objectives that you’re looking at.

The same thing is true for analysis and talk. You’re doing some evaluation and earning acreage. And at Lake Washington, much of that is held by production. So, clearly, as oil prices move closer to 120, that can certainly change your thinking a little bit. And it also gives you more cash flow to add something without taking away.

Unidentified Analyst

Got it. And then can Eagle Ford – I’d hope I don’t have to wait for the analyst meeting, but can you give us how many locations you’ve booked now or how much reserves booked?

Terry Swift

Again, I think, we’ll be going through that. And actually, I think the K that we filed today will give you a little bit more granular information on that, and then we’ll feel in any gaps there at the analyst meeting.

Unidentified Analyst

Okay. I’ll wait for the K then. One last question. In South Burr Ferry field, how many more wells do you plan to drill there this year?

Bruce Vincent

I think, in Burr Ferry, we have about three wells planned. As you mentioned, if those are successful, then we can always step up that activity as well.

Unidentified Analyst

Okay. And those are going to be more, say, far (ph) drilling from the first two wells?

Terry Swift

Yeah. They are going to be very much appraisal oriented wells.

Unidentified Analyst

Got it. Okay. Thank you very much.

Alton Heckaman

Thank you.

Terry Swift

Thank you.

Operator

And your next question comes from the line of James Pfeiffer with Wells Fargo Securities.

James Pfeiffer – Wells Fargo Securities

Hi. Good morning. Just wondering if you guys are seeing anything interesting on the acquisition front and whether that could be meaningful at all to you in 2011 to supplement your organic opportunities?

Terry Swift

Well, we’ll certainly look at acquisitions, but it’s not really a real high priority for us. But if something interesting came along, we would look hard at it. I would have to tell you that right now I wouldn’t expect a significant add from an acquisition in 2011. Not that that couldn’t change, but we’re just really very focused on what we’re doing with the drill bit and can accomplish a lot if we just execute those plans.

James Pfeiffer – Wells Fargo Securities

Okay. Sounds good. Thank you.

Terry Swift

Thank you.

Operator

(Operator Instructions). And there are no further questions at this time. I would now like to turn the floor back over to management for any closing remarks.

Terry Swift

Okay. Once again, we just want to thank you for joining us today. And we want to remind you that Swift energy will host a meeting with financial analysts on March the 10th, which is a Thursday here in Houston. So thank you, again, for joining us.

Operator

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

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