SilverBow Resources Inc (SBOW) 2010 Q4 法說會逐字稿

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 speaker's 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.

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.

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, multi-stage fracturing activity in the Eagle Ford shale and Olmos tight gas sand in South Texas, and horizontal drilling in the Austin Chalk in Central Louisiana and East Texas.

We've made a commitment to be a top-tier organization. In 2010, we drilled 52 wells, 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 and high rate production gains in the Austin Chalk, and we secured long-term gathering, transportation and processing for 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 towards 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 incidents and lead to a measurable improvement in our overall SHE performance.

On the drilling side, we have 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 have also added and high graded to 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've mentioned, we've successfully entered into long-term service agreements that have helped us reduce our uncompleted well backlog from 12 in the fall, to 3 today and we have 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 have 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 have 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 for the quarter, which include six operated Eagle Ford wells, six operated Olmos wells, and one non-operated Eagle Ford well being fracture stimulated. We've also brought three operated Eagle Ford wells, two non-operated Eagle Ford wells and one Olmos well on line 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 re-completion 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 and 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 a gross production basis. Swiss 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 has taken 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.

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 and revenue growth over the third quarter. It solidified our overall financial position with a very successful November stock offering. Our production was up 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 edging effects, were $116 million, a 1% increased from 4Q 2009, and a 9% increase from 3Q 2010. Our income from continuing operations was $10.3 million or $0.25 per diluted share, down from 4Q 2009, 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 2010 production, while down slightly from a year ago levels, was up 5% from 3Q 2010 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 our 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 2010, as compared to the prior year.

We continue to vigilantly focus on our cost and metrics, as Terry said. Production costs came in within our 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 this ever-tightening and competitive environment.

DD&A came in at $20.35 per Boe, just above guidance, as sector-wide capital project costs continue to increase. Interest expense is within guidance at $3.95 per barrel and production in ad valorem taxes came in near the low end of our guidance at 10.2% of revenue. The result was income from continuing operations for 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 nonrecurring small adjustment to deferred state income taxes.

Cash flow before working capital changes for 4Q 2010 came in at $66 million, or as I said, $1.65 per diluted share. EBITDA was $71 million for the quarter and clearly CapEx on a cash flow basis with $125 million as we consciously accelerated our successful South Texas initiatives.

While gas prices have been very volatile, we have continued to lock in price-forward 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 at an average NYMEX strike 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's 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.

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 of 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 of 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 crew and 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 efficiencies.

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.

For 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 LaSalle County.

The Company has three rigs capable of drilling horizontal wells in the 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, at Blackman Parish, Louisiana, three development wells were drilled; one well was completed and two wells were plugged and abandoned during the fourth quarter. Three re-completions were performed during the quarter, resulting in an average production increase of 183 gross barrels of oil equivalent per day per completion.

In addition to drilling and re-completion activity, 12 field optimization projects were carried out, resulting in an average production increase of 75 barrels of oil equivalent per day per project. One drilling rig and one re-completion rig are currently operating in Lake Washington. I will briefly review our activity in each of our core operating areas for this quarter, and Bob will detail the highlights of our more recent activity.

In the South Texas core area, which includes the AWP, Sun TSH, Briscoe Ranch, Las Tiendas, and Fasken fields, fourth-quarter 2010 production averaged 9,968 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 levels of 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 our Olmos 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 reduced activity and natural declines.

Bey-de-Chene's sequential production decreased 13% to 1,830 net barrels of oil equivalent per day, or about 11 million cubic feet equivalent per day. This 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 field, drilling an exploitation test.

The Central Louisiana/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. Of 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 Perish, 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 area 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 will turn it over to Bob and let him review the operational highlights of the fourth quarter.

Thanks, Bruce. At our Lake Washington field, we drilled three wells during the quarter, completing one and P&A-ing two. These wells were the final wells drilled in our 2010 Shallow and Alto Shallow drilling campaign. Even though this program had mixed results in 2010, we did complete 8 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 spotted a 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 -- Central 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 re-enter and further develop mature fields in the Austin Chalk.

One non-operated exploration well, the Gas RS 18-1, 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 3,264 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, 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 Olmos wells, and one joint venture Eagle Ford well were fracture stimulated during the fourth quarter. We have 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 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 were 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 low 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 initial production declines and higher initial pressures and EURs.

Our engineers continually calibrate our well 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. Additionally, we have continued to refine our completion techniques, our fluids, 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 crew and 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 and one joint venture well. While 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 analyzed 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 have put into securing drilling, completion coil tubing services, accessing our infrastructure and market outlets, building the water handling infrastructure, and securing oil country tubular goods in critical equipment, just to name a few things, will allow us to minimize the effects of service shortages, transportation constraints, oil field 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 appoint 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 will turn it back to Terry to recap.

Thanks, Bob. Before we open the line for questions, I will 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.

To date, 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 area and this joint venture will see an increase in activity in 2011. Similar results to the first 2 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 would like to begin the question-and-answer portion of our presentation.

(Operator Instructions)

Your first question comes from the line of Neil Dingmann with SunTrust.

(Technical difficulty) in more particular levels in Louisiana around Lake Washington and the Brookeland area. Just wondering, as you look at this year what type of decline you are trying to forecast in your (inaudible), in your expectations, both around Lake Washington, Brookeland, and will you continue to add some injectors etc. to try to keep that production from depleting as quick?

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 Brookeland as well as Lake Washington. When we are looking at the Austin Chalk, we are real excited about that area in Burr Ferry in between Brookeland and Masters Creek. It does have good implications for some of our Brookeland and Masters Creek production, so we are, certainly, looking at that area, and Burr Ferry is 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% type range for initial decline.

Moving to south Louisiana and Lake Washington, we have been in a mode there where we have been doing a lot of re-completions. As we noted to our investors, a lot of the wells that have been drilled in Lake Washington have lots of behind pipe zones. And we have taken advantage of that over the years to change sliding sleeves and come up the hole. And, really, it's best to talk about declines on a fuel wide basis, not an individual well basis, because a lot of these zones are small zones. They might produce a couple of years, five years, and then you move up the hole, so an individual well can have a pretty interesting decline profile.

I will turn it over to Bob to comment further on that.

Yes, I think 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 wells and tests, and we think that there is a lot more potential beneath Lake Washington than we have been able to tap into so far. So in a success case model, we would actually see production growing maybe a little bit towards 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, and don't have any of that exploration success, we could see maybe a decline of 10% to 12% to 15% without the kind of success that we are planning for.

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. And, let it suffice to say right now that the 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 complements coming from these other areas that we will detail at the analyst meeting.

And so it does include some deeper success in that production estimate?

No, no.

No.

Got it. Got it.

Did I hear you right? Was it on the Eagle Ford that you let a rig go for 30 days as a catch up because you are running ahead, or could you maybe give a little more color around that for the 30 days that you let up this quarter?

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 frac'ed. Then we got the dedicated crew from Weatherford in the fourth quarter, and I guess we would say that it has probably outperformed our expectation 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 re-balance it out.

So, we are taking actions now to pick up a spudder 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 drill to fracture to on line efficiencies.

Okay.

So even with the rigs you have planned now, with that stepped up frac'ed completion schedule, you still will be right on schedule, then?

Yes.

Got it, got it. Okay.

Last one, if I could. You mentioned -- just wondering when you break down the 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 the extended lateral lengths that you are seeing on some and then you mentioned some of the processes that are seeing higher IP rates.

I guess two questions, there. Are you seeing the improved rates now here this quarter in both of those plays, and how similar are the lengths and techniques between the two plays?

Well, I think we are using pretty similar techniques between the Eagle Ford and the Olmos. As we have always said, we kind of broke our development into a number of phases. The first phase being an evaluation and data capture phase, the second phase being an appraisal and efficiency phase.

Basically, what we were trying to do during those periods is get the subsurface data; get our baseline models on lateral lengths, on stage 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 refinements, number one. But, secondly, we believe with the contracted arrangements we currently have and the well performance that we have seen on wells we have tested, taking our lateral lengths from anywhere in the 3,500-foot to 4,200-foot range, which were kind of our baselines for both of the formations, to where we are now moving up as high as 6,000 feet in lateral length going from 11 to 12 stages of frac to as high as 17 stages of frac, that those economics and well performance appear to be more optimal.

That is what we are doing. We have also changed a bit of our frac design. Our early frac designs were more geared around slick water frac, pumping large volumes of water. We have now gone 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 bauxite 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 stimulation designs in both of these. And, I guess what I can leave you with is the combination of extra lateral lengths and the change in some of our design is showing us better performance.

Great, guys. Thanks for all the color.

Thanks.

Your next question comes from the line of [Cowell Rose] with RBC.

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

Welcome.

I was just wondering quickly on your new CapEx, is that increase a result of just higher costs or increased drilling? What is driving that?

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

Plus, the spudder rig, plus drilling the longer laterals and the longer completions brings more capital into the program.

Okay, great.

So you are still expecting kind of $6 million to $7 million on the Eagle Ford well costs, or is that creeping up slightly with the new laterals?

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.

Okay, great.

And then, just quickly jumping over to Eagle Ford, I was wondering if you guys could break out that LaSalle County exploration well, just IP rates and the oil gas split on that?

Yes, let us get it real quick.

Yes. That well is our [cardon] well. We IP'd that at 4.2 million cubic feet a day and 134 barrels of oil per day. That doesn't include any NGLs.

I believe that is also in the state records.

And that should be in the records, yes.

Great. I appreciate it, guys. Thanks.

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

Thanks. Good morning.

Just curious -- I guess I was a little surprised at how much you had 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 the AWP area for the majority of 2011, or what is the thought on the split between all the various areas?

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 fair to say that we have been working on a lot of marketing agreements, transportation agreements, things of that nature. You did see us bounce around a little bit. We really wanted to get Fasken 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, so you did see us move over there to the Fasken area to secure more of our acreage, get that all buttoned up.

We are working -- and we've got the market agreements, the transportation agreements all in place there, so you won't see as much activity over there next year as you will over in AWP. The artesian wells area, we've still got some marketing outlet 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 Olmos. That is where the lion's share of our activity is in 2011 as it relates to the Eagle Ford and that is where some really great results have come also in the gas condensate window for the Eagle Ford. So we are real bullish about that area. We will give you lots of detail at the analyst meeting.

The other comment I would make, Michael, is that, strategically what we have been trying to do is to evaluate, delineate 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.

Okay, great. Appreciate the color and look forward to the analyst day.

I guess on the topic of midstream, but over in the Austin Chalk, how long until the facility constraints are alleviated in the various different areas? Also if you could, what rates are the two Burr Ferry wells currently producing at?

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 market. As we noted in our press release, those wells were drilled I think seven miles apart, so we have been doing appraisal, and -- 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 for before we get real aggressive. We've got a joint venture partner there who's the operator of that area. 2011, I think will be an appraisal year, whereas 2010 was more of an exploratory year in those assets.

The facilities constraint really aren't with Swift. They are really with the midstream player that we are, basically, selling the product to.

Yes. It's -- the midstream does have a number of line pressure issues. We've been working with them very carefully trying to get those resolved, so the rates of those wells, currently, are cut back. Each well's right in around $4 million to $5 million a day, 400 barrels 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 date. We talk about this every week at our operating meetings, but we do need some help from the midstream side, and they are working on it.

Okay.

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

Well, the Brookeland area is a shallower area that is 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 barrel-type wells, and nice complement of associated gas depletion drive.

You move all the way over to Masters Creek and you get into some real horses. You get deeper. Some of those wells approach 2 million barrels equivalent over there, mostly oil and lots of water. A typical well would come in well over 1,000, 2,000 barrels of oil per day and could have that much or twice that much water.

Burr Ferry is 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 we are early into what we are doing there; it is -- I would say we are now 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 1,000 to 2,000 feet deeper than your typical Brookeland well, maybe 1,000 feet shallower than your typical Masters Creek well.

Okay, that's helpful. Thanks very much. See you in March.

Thanks.

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

Good morning, guys.

Hey, Adam.

I will try to avoid making you defer answers until next week. First of all, on pricing, do your deferential assumptions in your guidance take into account what is currently going on, or are you being more conservative than historical?

Well, no, they do take into account what's going on. Obviously, we can't predict the future with regard to that, but it is certainly important to note that our Louisiana oil production is getting either the LLS or HLS pricing. The coastal stuff, the Lake Washington and the like, is really priced against the heavy Louisiana light crude oil, and the Austin Chalk production is really getting the Louisiana-like pricing, which I checked this morning; they were actually running $117 and $117.75, so it's more correlated to Brent pricing plus a little premium because of the transportation issues. It is certainly not WTI.

That leads me to the next question. With prices and differentials where they are, do you think about hedging at some point, either pricing or differentials?

Well, yes. The answer 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 a purchaser at specific price or a specific spread tied to that particular market.

And then -- but you can hedge against WTI, whether it is through the use of floors or whether it's through the use of swaps, but then you would have to contractually agree with your purchasers with regard to the differential and the role as it relates to the different pricing mechanisms. Of course, the other thing to remember when we talk about swaps a lot of that production is in the coastal area, and so we clearly want to be concerned about putting swaps in place in at least that production.

So, in terms of potentially putting in some floors -- ?

Oh, absolutely, yes.

The thing you find with the crude oil markets, though, is you just can't go very go very far out with floors. 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 floors as far out as we can get them at reasonable prices.

Okay.

Lastly, with this capital budget, it looks like you are going to have somewhat of a cash flow gap. Could you talk a little bit about what your thoughts are on funding that?

Yes. Well, of course, remember we are starting the year with quite a bit of cash in the bank from the equity offering, and obviously, we don't know exactly what pricing is going to be. We build our budget around a couple of things. One is there is always a discretionary component to the budget. That is the first thing to go if we're not going to meet our cash flow objectives. Secondly, one of the things we are going to be looking at this year is possible disposition of non strategic assets. That would also fill the gap. Then, of course, the third thing, we think our balance sheet certainly could support some borrowing and a line of credit if we needed to go into that. I think in the end we are going to continue to manage the Company as we have historically, always trying to maintain low leverage, yet high liquidity.

Is there a magnitude or a framework on a potential asset sale?

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 are actually going to get something done until you do it. But, we'll do our best to -- I know you were trying not to do this, Adam, but we'll do our best to give you a little more color on that in a couple of weeks.

Great. Okay. Thanks.

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

Good morning, guys.

Morning.

A few questions for you. Again, with the Eagle Ford, could you comment on the non-operated well you completed during the fourth quarter, specifically did it have a liquids component to it?

Yes. That would be JV 2H refrac. Yes, it did have a nice liquids component to it. [Glade] on that well was about 8.4 million about 134 barrels of oil a day.

Nice.

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

Yes. The second well, I think that well came in under $6 million, so we did pretty good on the efficiency. We changed it around and drilled a single lateral on that well, and we did not have near the mechanical issues that we had on the first well, so we think that's more an indicative number of go-forward Austin Chalk drilling in the Burr Ferry area.

In terms of the EUR -- is very early data, but we see them pretty similar to the Masters Creek type wells, as Terry alluded to, so we are thinking from an EUR perspective, we ought to be able to do 1.5 million barrels or better from some of these wells.

Great.

And then, thinking about this second well that you guys drilled, could you offer any color on its delineation implications?

You are talking Burr Ferry?

That is correct.

Yes. Well, there's plenty. The second well was seven miles from the first well, and this is a pretty large acreage position, so I think clearly, we -- the program was designed 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 an infield development drilling-type program.

Okay.

And then, maybe sliding over to the Brookeland field, do you have any preliminary thoughts on your first operated and JV wells?

Well, we want to get them all in line before we get too far along. I think we'll talk a little bit more about that at the analyst meeting, but I would hesitate to talk much about those until we flow test them.

Sure. That's fair. Well, thanks, guys, for all your color.

Thanks, Derrick.

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

Yes. Hey, good morning. I had a question about any preliminary thoughts on decline rates from the Austin Chalk production and ultimate EURs on the wells.

Well, I think, I was just talking about that a little bit, but in terms of the EURs, we think it's very similar to the Master Creek type wells, from what we're seeing so far, so we would expect EURs of 1.5 million barrels or more maybe if it all hangs in there the way we think it is. The pressures that we are 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 bucking high line pressure and that's why our rates are down around 400 barrels or 500 barrels a day instead of 1,000 barrels a day.

Okay. Got it.

How much production would you say is curtailed currently because of different constraints?

I think right now, down in the well -- in the AW -- let's, let's --

I think -- we really are working on the various constraints that we have, and we have found in South Texas, there have been some [de-high] issues, some compression issues. As you are well aware, the winter was -- 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 some certain excess capacity at this point.

Now, Bob did mention in the Austin Chalk over in Burr Ferry that we are cutting back -- holding those back because of some high pressure constraints -- probably a good thing to produce those wells the way they are right now. Even if those constraints come off, we might not open the wells up that quickly. Same thing down in South Texas to the extent that we've got most of our constraints open, we're managing this production and not reaching for the moon in terms of opening up chokes, so even if we get a little bit more latitude over in the Fasken or AWP area, we're not likely to go reach for that real quick. So, I would not want to say that there's pent up, held back production at this point.

Okay. Got it.

And, I guess, Terry is the goal to keep the uncompleted well in [Tempori] around I think you said it was three wells? Is that where it is going to stay?

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'd be a little high, a little low.

Right. Got it. Thanks very much.

Thanks, Ray.

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

Good morning, guys. I've got a couple of questions for you here.

One, do you have a proved developed PV-10 number?

We certainly probably have that number, but we don't have it available to us. I don't think we've disclosed that in the past, Brian.

Yes, 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.

Okay.

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

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

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

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

Yes, 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 the realty owner, so we are looking for our acreage to be developed.

And the lateral length, when you're running the single lateral, are you able to run it as long as a lateral length in the reservoir?

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

Okay.

Hey, Brian, on your question about crude developed PB 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.

All right.

And your CapEx, the run rate you have in 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?

Let's make sure we've got the question right. You seem to think our CapEx is stepping down. Brain, again, I think at the -- Thursday, March 10 is our analyst day, we are going to be talking about that. Remember that the current guidance of $430 million to $480 million, 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. Again, depending on events and success, 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.

I see. And then, the back half of the year, you'll be able to ramp up, keep the same run rate going?

Based on success and activity.

Okay. That's it for me. Thanks, guys.

Thank you, Brian.

Thanks, Brian.

(Operator Instructions)

Your next question comes from a line of with Biju Perincheril with Jefferies.

Hi, good morning.

A couple of questions. I'm sorry if you've answered this already. The 91 barrels of negative oil reserves, is that mostly Lake Washington area, and what drove that?

Some of it is Lake Washington, but also the FCC put some guidance out there about the five [yields] going forward. We looked at all of that. We'll look at some of the reserves that have been on the books for a 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 then the other portion would be some re-mapping. And results from our shallow 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 pure FCC definition.

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

Okay.

Can you tell me I guess how many part locations -- how many barrels of part reserves you have at Lake Washington?

I don't have that number with me.

I think we will be prepared with that information at the meeting.

Okay.

And then this deeper objective or the deeper wells that you'll be drilling there, those will also be oil targets?

Yes. They will be oil targets or they will be gas with very high liquid components.

Okay.

And then, with prices where they are, especially the Louisiana prices, what opportunity do you have to accelerate activities there, even from the shallower drilling. If my understanding is right, you had quite a bit of locations there remaining. Is there an opportunity to go forward activities there?

Yes. 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 those differentials, we are talking about that every day.

Yes. 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. You've got multiple objectives that you are looking at.

The same thing is true even in the Austin Chalk. You're doing some evaluation, delineation, and earning acreage. Lake Washington, much of that is held by production. Clearly, as oil prices move closer to $120, that can certainly change your thinking a little bit. It also gives you more cash flow to add something without taking away.

Got it.

And then Eagle Ford, I 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?

Again, I think we will be going through that. Actually, I think that the K that we filed today will give you a little more granular information on that, and that we will fill in any of the gaps there at the analyst meeting.

Okay. I will wait for that.

One last question. For Burr Ferry field how many more wells do you plan to build there this year?

Yes. 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.

Okay.

And those are going to be more [step out] drilling from those first two wells?

Yes. They are going to be very much appraisal-oriented wells.

Got it. Okay. Thank you very much.

Thank you.

Thank you.

And your next question comes from the line of James Pfizer with 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 the 2011 to supplement your organic opportunities?

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

Okay. Sounds good. Thank you.

Thank you.

(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.

Okay. Once again, we would 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 10, which is a Thursday, here in Houston, so thank you again for joining us.

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