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Swift Energy Co. (NYSE:SFY)

Q1 2012 Earnings Call

May 03, 2012 10:00 am ET

Executives

Paul Vincent - Director, Finance & IR

Terry Swift - Chairman & CEO

Alton Heckaman - EVP & CFO

Bruce Vincent - President & Secretary

Bob Banks - & COO

Analysts

Neal Dingmann - SunTrust

Gordon Douthat - Wells Fargo

Marcus Talbert - Canaccord

John Abbot - Pritchard Capital Partners

Noel Parks - Ladenburg Thalmann

Andrew Coleman - Raymond James

Operator

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

I would now like to turn the conference over to Mr. Paul Vincent, Director of Finance and Investor Relations. Please go ahead sir.

Paul Vincent

Good morning. I’m Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy’s first quarter 2012 earnings conference call. On today’s call, Terry Swift, Chairman and CEO, will provide an overview. Alton Heckaman, Executive Vice President and Chief Financial Officer, will review our financial results for the first quarter. Then Bruce Vincent, President, and Bob Banks, Executive Vice President and Chief Operating Officer, will provide an operational update.

Terry Swift will then summarize, before we open up the line for questions. Also present on the call is Jim Mitchell, Senior Vice President, Commercial Transactions and Land.

Before I turn it over to Terry, let me remind everyone that our presentation will contain forward-looking statements based on our current assumptions, estimates, and projections about us, our industry, and the current environment in which we operate. These statements involve risks and uncertainties detailed in our SEC reports to which we refer you along with cautionary statements contained in our press releases, and our actual results could differ materially. We expect our presentation to take approximately 25 to 30 minutes and have allowed additional time for questions.

Terry Swift

Thanks Paul and thank you everyone for joining the call today. The first quarter of 2012 was another strong quarter for Swift Energy Company. With minimal third-party related operational delays or downtime during the quarter, we were able to deliver production volumes at the high end of our expected range. We are on track to have record production in 2012 and expect crude oil and natural gas liquids to comprise approximately 55% of our daily production mix by year-end.

As we discussed in detail during our Analyst Investor Day in March we have already achieved significant cost savings in both our drilling and completion operations in South Texas. We believe we can realize further cost savings and operational efficiencies by deploying drilling and completion techniques that are only really suitable to a full-scale development mode operation.

On the service and midstream front since our Investor Day we have extended our dedicated fracture stimulation agreement for one year and at a reduced fixed rate and on terms we believe reflect the current market for these types of services. We are also in the final stages of securing firm transportation and processing capacity for natural gas production in La Salle County Texas further removing third-party uncertainty from our execution plans. While there is always risk in our business, we believe we have contractually secured a significant portion of the equipment services, transportation and processing we require to achieve our goals. With this accomplished our technical and operating personnel are spending more of their time on activity directly related to growing crude oil and natural gas liquids production volumes.

With natural gas prices persistently weak, we have managed to park in the acreage in South Texas that's perspective for dry natural gas production by fulfilling drilling obligations or by working with sophisticated landowners and mineral owners to appreciate the economic effect of low natural gas prices at this time. With this acreage parked, we are now exclusively focused on growing crude oil and natural gas liquids production in all our areas and can maintain this focus for several years should natural gas pricing remaining weak.

Operationally we resumed drilling operations during the first quarter in our Lake Washington Field in South Louisiana. We continue to find thick sections of pay sands in these wells that we drilled to date. Our most recent well the CM 422 encountered 226 feet of pay and is now flowing above 650 barrels of oil per day. This type of activity should continue throughout 2012 and increases of course our crude oil production in an area where we capture strong Gulf Coast crude oil premiums. In Central Louisiana we brought a company operated Austin Chalk will online in the Masters Creek Field.

The performance of this well has confirmed drainage and reservoir assumptions we have developed over the past several years. This proof-of-concept well sets up further opportunity on held by production in-field acreage in this area and additional leasing opportunities as well. West of Masters Creek in the Burr Ferry area our joint venture partner has resumed drilling activity late in the first quarter after moving two rigs into this area. Increased activity levels in this area are consistent with our expectations of an increase in crude oil and natural gas liquids production in the second half of the year.

Turning to our South Texas activity our drilling and completion programs continued to improve so much so that it is difficult to say which has got us more excited. The six drilling rigs we [tidied] 15 wells during the quarter in this area. One of these rigs is a walking rig and spent much of the quarter drilling for surface holes in our first pad well drilling operations.

Drilling days and costs continued to improve as we develop techniques and standards that reduce our non-productive time and eliminate projects inefficiencies. Our completion crew also continues to do a great job and is finding ways to also be more productive. During the first quarter, we fracture stimulated 188 stages which is a record for Swift Energy. We believe that our drilling activity to hold acreage diminishes and we concentrate going forward primarily on drilling acreage with the highest current returns, liquids and oil. We further will improve our cost and operational efficiencies in all these critical areas.

For the remainder of 2012 and into 2013 we will take a disciplined approach to growing our crude oil and natural gas liquids production. While we pre-funded this year's capital expenditures we are prepared to reduce activity levels to better balance our cash flows and capital expenditures should the economic external conditions of commodity pricing remain weak or further weaken. However with crude oil and natural gas liquids production accounting for 85% of our revenues in the first quarter and a recent increase in our borrowing base which takes us to 375 million, we believe we have the financial flexibility to pursue a more aggressive activity profile if the operational performance and cash flows as well as the commodity environment dictate.

With another strong quarter behind us and the expectations that we will achieve record production and yearend reserve levels this year we believe we represent a compelling opportunity to investors who are interested in participating in the growth potential of the Eagle Ford Shale and the almost tight sands.

And also value the strong cash flows associated with productive crude oil assets in Louisiana. This business always represents challenges or presents challenges and I am extremely encouraged by the way our folks have solved the problems over the past several years. We have a multi-year inventory of drilling projects unlike any of the company has seen before. We also have the people services and sales outlets to develop this inventory effectively. And as the past two quarters have demonstrated we are now executing in line with our expectations. And now I ask Alton to present our first quarter 2012 financial results.

Alton Heckaman

Hey thank you Terry and good morning everyone. As mentioned one clear highlight for the quarter was the increased production volumes, up 6% from a year ago and 4% from the fourth quarter 2011. During the quarter, natural gas prices continued their decline to lows not seen in close to a decade while oil prices continued to be a bright spot validating our strategic shift to our inventory of oil and liquids-rich projects. For the quarter oil and gas sales were $136 million, income from continuing operations was $3.6 million or $0.08 per diluted share. Cash flow before working capital changes came in for the quarter of $1.61 per diluted share and 1Q12 production was 2.8 million barrels of oil equivalent the high end of our quarterly guidance.

Crude oil prices were 14% higher than a year ago while natural gas prices actually decreased 43% resulting in an overall 11% decrease in our realized price per BOE 1Q12. As Terry mentioned will point out that for the first quarter 2012 approximately 85% of our oil and gas revenues were from crude oil and liquid sales.

With respect to our controllable costs and metrics and comparing them in the guidance, production costs came in at $10.44 per Boe above guidance due mainly to unscheduled work over and maintenance activities during the quarter. G&A came in at $4.25 below our quarterly guidance, DD&A was within guidance at $21.92, interest expense came in within guidance at $4.81 per barrel and production and ad Valorem taxes were above guidance at 9.5% of revenue as we trued up some prior period state severance tax credits.

However, our guidance remains 8% to 9% for the remainder of 2012. As previously mentioned, the net result was income for the quarter of $3.6 million or $0.08 per diluted shares below first quarter mean estimate. Our effective income tax rate for the quarter was 39.3% which was within our guidance. Cash flow before working capital changes for 1Q12 came in at $69 million or $1.61 per diluted share while EBITDA was $82 million for the quarter. As you know, our quarterly CapEx on a cash flow basis was $188 million. With our high pricing volatility, our hedging activity was minimal during the quarter. We have layered in some strong outflows subsequent to quarter-end.

Please see our website for a complete and current detail oil & gas hedging information. As of the end of the first quarter 2012, we had $127 million of cash on hand and no outstanding balance on our line of credit. And as Terry said in his intro, in connection with our regular semi-annual review, our borrowing base was raised to $375 million from $325 million effective May 1. We’re keeping the commitment amount at $300 million on which we pay standby fees. The depressed natural gas prices in the near term continued to pose a significant challenge to our sector. With our liquidity, our inventory of oil and liquid rich projects and approximately 85% of our revenue came in from oil and liquids production, we feel we are very well positioned to continue to execute our 2012 strategic plan.

As always we recruited additional financial and operational information in our press release, including guidance for the second quarter and full year 2012. And with that I will turn it over to Bruce Vincent for an overview of our operations.

Bruce Vincent

Thanks, Alton and good morning everyone, thanks for listening. Today, I will discuss the first quarter of 2012 activity including our production volumes, recent drilling results, activity in our core operating areas, and our plans for the second quarter and full year 2012. Bob Banks will then provide greater detail on some of the operational highlights of the quarter.

Beginning with production, Swift Energy’s production in the first quarter of 2012 totaled 2.8 million barrels oil equivalent or 16.79 billion cubic feet oil equivalent which was at the high end of our previously issued expected range. This is an increase of 6% over the first quarter of 2011 production of 2.65 million barrels oil equivalent and an increase of 4% from the 2.7 million barrels of oil equivalent that was produced in the fourth quarter of 2011.

Our first quarter drilling results, Swift Energy drilled 17 operated wells during the quarter. In South Texas, nine operated wells or development wells were drilled in the Eagle Ford Shale formation in South Texas. Two of these wells were drilled in McMullen County. Two were drilled in Webb County and five wells were drilled in LaSalle County. Five wells were also drilled to the Olmos formation in McMullen County. And Swift Energy Southeast Louisiana core area two wells were drilled in the Lake Washington field. We currently have six operating drilling rigs in our South Texas core area, two in Eagle Ford and Olmos wells. We also have one operated barge rig drilling our Southeast Louisiana area and two non-operated drilling rigs that are active in our Central Louisiana East Texas area.

I’ll review of our performance in each of our core operating areas for the quarter and then let Bob detail some of the highlights of this recent activity. In the Southeast Louisiana core area, which includes a Lake Washington and Bay de Chene fields, production during the first quarter averaged approximately 6,440 net barrels of oil equivalent per day or 38.6 million cubic feet equivalent per day, which was down 14% when compared to the fourth quarter of 2011 average net production for the same area. Lake Washington averaged 6,024 net barrels of oil equivalent per day at 36.1 million cubic feet equivalent per day, a decrease of 14% when compared to fourth quarter 2011 average daily volumes.

These declines were anticipated and result from limited prior period activity levels in the field. Activity levels have accelerated in Lake Washington recently and we expect production levels to remain relatively flat and potentially increase slightly as 2012 progresses. Bay de Chene sequential production decreased 9% to 487 net barrels of oil equivalent per day or 2.9 million cubic feet equivalent per day. The sequential decline is due to new drilling activity and natural declines.

In our South Texas core area, which includes our AWP, Sun TSH and lastly (inaudible) in Almos fields and AWP, Artesia Wells and Fasken Eagle Ford fields, first quarter 2012 production averaged 21,968 net barrels of oil equivalent per day or approximately 131.8 million cubic feet equivalent per day, a 15% increase in production when compared to fourth quarter 2011 production in the same area and a 48% over the first quarter 2011.

The sequential increase is primarily from newly completed wells bottom lined during the quarter. Please see our press release issued this morning for specific information on wells brought on line during the quarter. As outlined in our annual Investor Day in March, well performance continues to improve as we drilled longer laterals and improved our efficiencies. As a result of our improving efficiencies and lower cost, we now expect to have somewhat higher levels of activity in the second half of the year drilling more wells. This activity will accelerate our operational momentum heading into 2013 and since the year capital expenditure budget trend toward the higher end of our current expected range.

Bob will spend time discussing our Almos and Eagle Ford programs in greater detail. Central Louisiana, East Texas core area which includes our Brooklyn, Masters Creek, Burr Ferry and South Bearhead Creek fields contributed 1979 barrels of oil equivalent per day or approximately 1.9 million cubic feet equivalent per day our production in the first quarter of 2012. We brought one new operated well on line during the first quarter in this area and our joint venture partnership has resumed drilling operations in the Burr Ferry area with two rigs currently active. I will now turn the call over to Bob Banks to review operational highlights of the first quarter in a little more detail.

Bob Banks

Thank you, Bruce. At the Lake Washington Field during the quarter, we completed 10 wells and performed 26 production optimization projects which include sliding sleeve shift changes, gas lift enhancements and returning shunted wells to production during the quarter. As part of our capital program, we had a drilling rig active for the entire first quarter. This rig drilled two wells in the first quarter and has drilled two wells to-date in the second quarter. The first well of our 2012 program, the CM419 was drilled to a measured depth of 84-89 feet and encountered 60 feet of true vertical pay.

After completion, extraneous water entered into the productive interval and the well would now require a work over in the second quarter to shut off the water and return the well to production. The second well drilled during the quarter, the CM421 was drilled to a measured depth of 8,513 feet and encountered 255 feet of true vertical pay. The initial production rate at this well was 406 barrels of oil per day and 0.2 million cubic feet of gas per day with flowing tubing pressure of 250 psi on at 1,864 choke. Both of these wells have opened up additional drilling opportunity on the west side of the Lake Washington salt dome. Third well, the CM422 was just recently drilled and completed in the second quarter. Since wells located in the northeast portion of the field was drilled to a measured depth of 8573 feet and encountered 226 feet of true vertical pay. The initial production rate of this well was 654 barrels of oil per day and 0.1 million cubic feet of gas per day with slowing tubing pressure of 400 PSI on a 26/64 inch choke.

This will also sets up additional drilling inventory in this portion of the field. We may have mentioning that we are finding enormous amounts of pay at depth one could reasonably expect us they been develop decades ago. As a result, we see several years of development activity at hand for this truly remarkable asset.

We expect to keep at least one rig active in Lake Washington throughout the year as production in this field benefits from strong Gulf Coast crude oil pricing and generate strong cash margins.

As mentioned in our Central Louisiana East Texas area, we completed the Exxon Corp. 10-1 well in our Masters Creek Field and one in Parish during the quarter.

The initial production rates on this well were 836 barrels of oil per day and 5.4 million cubic feet of natural gas per day with flowing tubing pressure of 25/65 PSI on a 48/64 inch choke. This well was a proof of concept well drilled at an in-field location to a lateral length of 2,500 feet. The productivity of this well has proven this concept and increases our ability to down stays on our previously developed acreage units in this area.

As a result of this successful test we have begun evaluating and acquiring additional acreage in the area and are making plans to resume drilling operations in the future. We have been adding stuff to this asset team and are advancing discretionary initiatives such as side-tracking the GASRS20-1 well initially drilled last year. We are looking at enhancing production optimization and maintenance programs and we are accelerating our appraisal in the Wilcox acreage in Beauregard Parish.

Moving on to South Texas, 10 Eagle Ford horizontal wells and three Olmos horizontal wells were completed during the first quarter. We've published a table in our press release this morning with details of test results of all these wells.

Our well performance continues to improve overtime and we believe we are still making strides towards optimal well performance and cost efficiency. Our fracture stimulation crew which is operated by Weatherford International continues to demonstrate top-tier performance and has reduced non-productive time and increased the number of stages completed per day far beyond our most optimistic initial expectations when we entered into our contract.

Partially a result of this performance, we have extended our agreement with Weatherford International for another year. This agreement reflects a reduced fixed rate on more current economic terms from Swift Energy and ensures that the crew and equipment that has performed so well for us will remain working for us for the next 15 months.

As our completion efficiency improves evidenced by completing a 188 frac stages during the quarter, it has also been important to improve our drilling efficiency. With six rigs running during the quarter, we drilled 15 horizontal wells in South Texas. We have reduced both our drilling times and our costs significantly and we plan to continue building in these types of efficiencies into our operations for the foreseeable future.

As we've indicated previously, one of our rigs is a walking rig and is drilling a full well pad presently in our oil rich acreage in McMullen County. This rig is well ahead of schedule both on drilling days and cost. This type of operation doesn't just improve drilling times, we will also complete these four wells in fewer days and at less costs than we otherwise would if they were single well operations.

As we drill and complete our wells in closer proximity to one another, we are also collecting reservoir data which is supporting our belief that much of our acreage can be developed on 80 acre spacing. This is important for the validation of our inventory and for creating optimal development plans for each of our areas.

While most of our major transportation and service needs now under long term contracts and agreements, our operating organization is now able to focus larger portions of its time on drilling wells and growing our crude oil and NGL production volumes.

We are extremely focused on deliverability and execution. We are improving our processes, we are adding depth to all of our asset teams and we are really seeing the results of being balanced and focused across a diverse asset base.

As a result, we have a number of ongoing exciting projects in Lake Washington, Burr Ferry and South Texas and I’ll look forward to updating you on as we report our second quarter results later this summer.

With that, I thank you for your time this morning and I will turn it back to Terry to recap.

Terry Swift

Thanks Bob. Before we open the line for questions, I will summarize Swift Energy’s first quarter results and review some of the highlights from today's call.

First quarter production growth of 6% over first quarter 2011 production; increased activity levels in all three of our core areas; 15 wells drilled and 13 wells were completed during the first quarter in South Texas; we completed a 188 frac stages during the quarter in this area, a record performance for our frac crude.

We anticipate completing our first four wells drilled off of a single pattern during the second quarter; 85% of our revenue was derived from crude oil and natural gas liquids production and all of our remaining 2012 drilling activity is crude oil and natural gas liquid rich focused areas.

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

Question-and-Answer Session

Operator

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

Neal Dingmann - SunTrust

A couple of questions; first, you did talk about potentially rent up being in the South East Louisiana, I am just wondering Bruce or Terry just sort of general comments as far as how much more in the way of either work overs, new rigs etcetera could you add on and obviously to be what’s going on with the NGL prices and obviously still the premium LSS prices.

I was wondering just how much more you can continue and is that something we could potentially see maybe the budget refigured or even the budget taken up that is with all to potentially higher activity in later part of the year in that area?

Terry Swift

Well, it’s a good question Neal. I think obviously with oil pricing particular the HLS market was like Washington sales and tubing very attractive today along with the success that we’ve been having; we absolutely do have under consideration some additional activity at Lake Washington specifically probably at a minimal we’re going to keep that rig busy all year.

But we are considering accelerating or actually having some additional well activity at the Lake Washington and brining in the second rig to get that activity kind of accomplished this year. And we have not made a final decision on that, but that’s something under serious consideration and obviously that would uptick the capital budget spend in a little bit, but we would get the results from that particularly.

If we made that decisions there you take couple of months get ready the field in the second half activity production, we get lower production this year which is primarily get production momentum going into next year and it would have high quality HLS pricing crude oil. So it’s a good question because it’s certainly under consideration.

Neal Dingmann - SunTrust

And then moving back to just kind of looking at South Texas around some of the wells either in McMullen or Webb County; just Bruce wondering still on the frac design there; are you still expanding that, are you still kind of keeping that on par where you had last quarter. It look like the results were pretty stable versus the results you had laid last quarter? And then the second part of the question around that would be around takeaway in that area; it does appear like you solved most of those problems; can you just comment around that?

Bruce Vincent

Let me answer that Neal on the frac design, we are pretty much sticking with that design we talked about at our Analyst Day; it’s a hybrid design, (inaudible) with breakers.

In terms of performance of the wells you know on of the things we are doing is we are releasing our flow back cruise a lot earlier now I think we tried to get him off in about six days; to workout cost efficiencies. So you know some of the reports that we show you don’t quite get to the 20/64 inch choke setting, because we get our flow testers off early.

So we do track each one of our wells against our models; are the wells that we’re reporting in our press release today I think are pretty much in line with our models taking into account you know the choke settings, the frac stages and the lateral lengths things of that nature. And then the second part of your question again on the capacity we have all of our capacity taken care of really in the McMullen County area certainly out in the Webb County area. The last bit is in La Salle County. We are kind of in final throes of negotiations there for the firm takeaway and capacity. In the interim we are getting interruptible service there. But we really expect to have that all concluded this quarter.

Terry Swift

Yes the other thing I would add to that you know we talked about our ideal model being about 6000 foot legged lateral. In the La Salle County area where we are having an increased level of activity and it is an oilier area than we had originally thought it was. It's also a little shallower and so we are actually trying to, where the leasehold allows we are really trying to push the laterals out more like the 6700 feet. We think that will actually get us better performance.

Neal Dingmann - SunTrust

Okay and then last question I could maybe just Bruce either for you or for Alton, just more on kind of production taxes and LOE. I think LOE was up because of the workover. I was just wondering kind of for the remainder of this year, you know should we think about more you know that was closer to where they were in the first quarter or maybe where they were in the fourth quarter as far as just per BOE basis.

Alton Heckaman

You know both LOE and severance taxes. Neal we had some outliers in the first quarter that we talked about and will be described in the Q, but they were outliers and we are very comfortable with the guidance that we have presented here in the press release.

Bruce Vincent

If you look at the guidance I would add to that though at least on the LOE side we do have quite a bit of well activity planned that would be workover activity. One of the things we will probably get to at some point in time is in terms of the second-quarter guidance you know flat to slightly up. One of the reasons for that was actually April activity was below what we thought it would be and a lot of that had to do with well activity basically, going in and doing work on wells I think there were 12 wells in South Texas alone that were shut in for various periods of time doing workover activity. So you're going to see that expense, you see the short-term downturn from production but then you see the increase of production from the workover activity.

Operator

Your next question comes from the line of Gordon Douthat with Wells Fargo.

Gordon Douthat - Wells Fargo

First on the South Texas, what's the timing of that four well pad. You know how is the drilling looking there, when do you expect to bring that on and what's incorporated into the guidance there?

Bob Banks

The operation is going very efficiently. Of course I think as we discussed in our Analyst Day you know when you do the four-well pad like the we're doing you have to move the rig of before you bring the frac crew on and do the zipper frac operation that we showed you at Analyst Day. So the timing of all that really is kind of right at the end of second quarter kind of on the border between the end of second quarter to first quarter, when we will bring all of those wells on production all at once. And so that does kind of cut into you know second quarter versus third quarter oil production. So I think what we have planned is really kind of at the end of the second quarter going into the third quarter.

Terry Swift

As I recall there at the Analyst Day we did even get a question about the production being lumpy as a result of bad drilling and you will see that but that is a part of the reason for the significant higher ramp of crude oil in the third quarter.

Gordon Douthat - Wells Fargo

And then going forward how do you expect the pad drilling to kind of proceed, is everything going to be on pads or?

Bob Banks

No, no. Not everything will be on pads. We will be doing some more pads, but for the rest of this year the pads will be limited to two per pad not four per pad. So it will be a little less bumpy in terms of bringing on wells. I think by the time we get into next year you will start seeing us moving back to more and more pad drilling and going back to the four pad drilling but again some of the things we're trying to understand at this point is our drainage areas. We have to get those drainage areas set correctly so we can be very efficient on how to go about this pad drilling?

Gordon Douthat - Wells Fargo

Okay and then you mentioned the 80 acre spacing can you just remind me is that what you have based your location counts on at the Analyst Day?

Terry Swift

We did yeah. We did show you the 80 acres, most all of our drilling has being done on 160s. But we have shown you both 160 counts and 80 acre counts I think we showed you the 80 acre numbers at Analyst Day?

Bob Banks

And that's specific to the Eagle Ford, the almost (inaudible) are based on 160 acres basically yeah.

Gordon Douthat - Wells Fargo

Okay and then in Central Louisiana, East Texas, the Masters Creek look like a good result there. So what does that tell you, you mentioned you are looking for different additional acreage? What are you seeing as far as opportunities to go there and then you also mentioned accelerating a Wilcox test so just wondering if you could provide a little color there?

Alton Heckaman

Well on the infield concept basically most of all these units would fall into the 2000 acre spacing and what we did is we tested a down spacing with this Exxon Corp 10-1 well. So that basically that basically builds an automatic inventory of infield locations on our held by production acreage, but in addition to that there is activity out in the area. We do have an active leasing program in the area working the whole Austin Chalk trend in terms of a regional study that we are doing here through our exploration team. And so we have a fairly specific strategy in that regard.

With regard to the Wilcox down at South Bearhead Creek, we like that opportunity. We are planning a concept well, a proof of concept horizontal well in the Wilcox there. I don't imagine we will get that in before this year, but you will see us coming forward with plans to drill that proof-of-concept well before too long.

Gordon Douthat - Wells Fargo

Okay and then lastly from me just a follow-up as far as the inventory goes the Masters Creek had, do you care to quantify what the down spacing opportunities might add to your inventory there?

Alton Heckaman

Well I think we actually showed you some of that at the Analyst Day. I will put it into context to maybe 15 to 20 or 25 type infield opportunities.

Operator

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

Unidentified Analyst

My first question I guess is just it seems that the NGL mix in the full year guidance got bumped by a couple of percentage points, you just like to clarify what is driving that?

Terry Swift

What's driving it primarily is the shifts in focus from dry gas to liquid rich opportunities, both oil and NGLs. If you get it to a little more granular level than that, Artesia Wells as we've indicated before, turned out to be little more liquid, even gassy than the first one so that actually drive a little bit higher liquid activity.

One of the other things is the efficiencies we've talked about by shortening drilling times, getting them off the wells quicker, we are saving costs, but the other thing we are doing is saving time and we are not going to stop drilling, we are going to basically be able to move some wells we would have drilled next year into 2012.

So those cost savings basically accelerate activity from the next year into this year. Obviously, more well activity, you get better results. We've talked about drilling 6 to 10 wells in Lake Washington and we've been saying of late that more likely 10 than 6 and as I indicated earlier we have under consideration actually increasing that well activity as well and possibly bringing in a second ring.

All that contributes to higher liquid growth. I guess the other thing, looking at the other area that the Central Louisiana and East Texas area, we've mentioned that Anadarko rigs in the field and that activity is a little bit ahead of our originally planned schedule. So again that's going to also drive more liquid growth and gas growth.

Terry Swift

One other (inaudible) in the first quarter sort of looking at the trend there was a small portion of gas that we were not able to process in the first quarter, which is really a part of the explanation to why our NGL is on the low side of our guidance and why natural gas was above the high end.

Unidentified Analyst

I guess I was kind of focusing on what changed as just to prior guidance.

Bruce Vincent

Versus prior guidance, the NGL mix is just really tweaking the model going forward. So again its just kind of as you get in there.

Bob Banks

Yeah, and especially out in the LaSalle County area where we continue to drill some new wells, we are looking at those models very closely and we are adjusting those models all the time and so we are seeing good condensation, good NGL yields out there. So that's part of it as well and its partly related to how we intend to recover our NGLs from these contracts that are being negotiated.

Unidentified Analyst

I see and then just to clarify in terms of the second quarter guidance for oil production that's coming down a bit, I guess that's mainly driven by the work of person you referred then. When was (inaudible).

Terry Swift

Well, I think that’s certainly a part of it. When we actually look at the actual April production, oil production was actually lower, slightly lower in April than was in January and slightly lower than February and March and that's really due to the well activity that happens but when we see that declining again in May and June and much more so in the end that we will get to July and August.

Operator

The next question comes from the line of Marcus Talbert with Canaccord.

Marcus Talbert - Canaccord

I had just a couple of operational questions and then a one financial one if I could. I guess taking a look at the most recent Eagle Ford wells that you guys disclosed this morning in McMullen. It looks like, I guess, the initial productivity rates were a little bit softer than sort of some of these wells towards year end. I was thinking that it would make sense from a volumetric perspective as you look at some of the more oiler sections to the north but on average it looks like the liquids composition has maybe coming slightly? Is this just a function of what you are drilling across McMullen County on aggregate, if you had any more commitments in the central areas, I guess during the first quarter if you can just sort of talk to how these locations lay out geographically for me?

Bob Banks

Yeah, I’ll try to do that for you, Marcus. First of all, I guess, I would say, I won’t read too much into it. You know, some of those well they’re up in the SMR area. They are real heavy oil model or very, very strong wells. You will see in our press release that one of those wells only reach to 1264-inch choke setting and reason why we only taken that to 1264-inch its because we are experimenting with the restricted flow type model to see how that changes our decline profile in that very liquids area. And so but what we do as we equalize these against our models to try to make sure the performance overall is matching our models. So we drilled the two wells up in that real oil area. We drilled well we drilled four wells kind of down in the condensate window and then we drill three Almos wells which were kind of in that rich condensate window, McMullen County. One of the wells, one of the Almos wells only had eight stages associated with it for mechanical reason.

So there is a number of moving parts between what we done with choke settings, what we are doing what we are able to do with lateral links and stages and you know things of that nature, but that kind of gives you a general breakdown in McMullen County, where those three wells that we finished up out in Webb County in our gas acreage that we’re paying all of our acreage and those all look very strong. So overall we were very pleased with the way the performance is going and the way we are matching our models that we’ve been presenting to the industry.

Marcus Talbert - Canaccord

I guess it just present, I guess, Almos oil model back in March. Just as curious as to may be how these initial wells are stacking up against that curve, too?

Bob Banks

Yeah, like the SMR, our Almos model, I think they are stacking up quite well against our models. We are very pleased.

Marcus Talbert - Canaccord

And then may be just one for Alton, in terms of you know, sort of this spread that we are seeing for NGO realizations versus crude, do you have any thoughts to potentially hedging any of these volumes moving forward given the growth that you guys are looking at here and is there I guess a sufficient market for that in terms of depth of contracts and so forth, you could may be just highlight some color on that?

Alton Heckaman

We had those discussions; we have not done anything with respect to NGLs. As you know the guidance down is a percentage of crudes, a function of the ethane and propane markets that are out there. So we continue to look at that. We’ve guided what we think the market is going to give us going out in the remainder of 2012. I believe there probably is enough activity out there to do something but we have those discussions that we feel that’s in the best interest of the company and the shareholders and we will do that.

Operator

Your next question comes from the line of John Abbot with Pritchard Capital Partners

John Abbot - Pritchard Capital Partners

Just one quick question here on NGLs. Could you remind me what is the percentage make up of your NGLs right now? What is the percent of propane, isobutene, and how does that break out?

Bob Banks

I don't know that we’ve got a definitive specific mix and obviously from my area a little bit different but I think the last information I saw on some discussions we had is about 60% was ethane and propane. That's about as granular as I can get.

Operator

Your next question comes from the line of Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann

Just a couple of questions. I wanted to go back to Masters Creek for a minute; I was wondering the wells you’ve done, NGL wells that look encouraging. Were those or were any of those on that relatively new acreage you bought? And I want to say it’s around 10,000 acres or something that you added out there?

Bob Banks

No this is two different areas. The area we've been adding acreage is actually in our Burr Ferry area. That's to the west of Masters Creek. That's where we have two AMIs with an operator. This Masters Creek field we've operated for quite a long time. This was actually the first in field well that we've drilled at Masters Creek and so that's what has us excited about revitalizing the Masters Creek deal. The two rigs we mentioned to you that are being operating now in Burr Ferry are continuing all in that area where we’ve build our lease positions to the West.

Noel Parks - Ladenburg Thalmann

Okay, and that new acreage at Burr Ferry, is it also pretty largely developed at this point or does it have a lot of running room?

Bob Banks

Yeah, it has lots of running room. That's all new acreage positions, that's what we; I think we've tried to lay out some of those number of locations at our Analyst Day and what we think the resource potential is there.

Noel Parks - Ladenburg Thalmann

And sorry if you comment on this before, but you know as I have been saying to at different conference calls over the course of earnings season, I’ve heard at least four different public companies talk about monetizing either their entire Eagle Ford positions or you know part of the JV or something like that.

And so I assume there is quite a few data rulings out there in a lot of discussion. Have you heard anything in the last month or so that sort of changes either your idea of what areas of the play might work or just trade off between I guess pressure and oil and pressure in the condensate weighted gas windows and so forth. Have you heard anything that have you curious or anything anyone find things might be game changing or just give us any new ideas on the play?

Terry Swift

I’ll answer that or attempt to answer that question. But basically, the Eagle Ford is one of the premier plays in the United States particularly as it related to oil and NGLs and in such a vast play that clearly there is going to be different things happening and with so many operators in there I wouldn’t be surprised if you hearing different ideas.

But I really made to speak specifically the Swift Energy Company, we have now fully appraised our areas and we know where we need to focus and we are not looking at any kind of joint ventures or any kind of different monetization right now other than drilling up this inventory and focused on liquids and NGLs; we’ve got several years of liquids and NGLs drilling on our part and if we do get any of those kind of ideas and take any action in that direction we will certainly be talking to the market about it.

But right now we are focused on developing our inventory and in the areas that we work in; we are really not seeing operators knew much of anything other than focus on drilling. Now again it’s a big, big play area, so I wouldn’t be surprised if you’ve hurt a few things in some of the other areas.

Operator

(Operator Instructions) Your next question comes from the line of Andrew Coleman with Raymond James.

Andrew Coleman - Raymond James

You said at the Analyst Day that you had looked at the TMS that we are not overjoyed with that at the time (inaudible) with all the additional activity that’s having in place some of it appears to be kind of heading closer to your direction, have you changed your view at this point?

Terry Swift

No, I really wouldn’t say our view has changed so much, but I might clarify a little bit from the Analyst Day, you know the Tuscaloosa Marine Shale is a very interesting play; it’s a very, very early; a lot of operators are doing appraisals in different areas. We are in a unique situation; we’ve fee acreage, where we own the royalty involved there, so there is a lease expiration to choose. We also will have a very activeness we’ve discussed today; Austin Chalk play where we’re drilling out and so really it’s kind of a secondary kind of opportunity for us as our guys have looked at it, we clearly believe our Austin Chalk is the play that you are there and we will continue to watch the Tuscaloosa Marine Shale, but we don’t have any near term plans to do any testing or evaluation of it.

Andrew Coleman - Raymond James

And to clarify then two points, one on the Austin Chalk ,one on TMS, I guess, first would be, what's the separation approximately between the TMS and the Austin Chalk for you guys and then if I remember correctly you guys are targeting the upper piece of the Austin Chalk which has not been historically produced (inaudible)?

Terry Swift

Bob, you want to take that?

Bob Banks

Yeah, I think its about 200 feet separation something in that order of magnitude.

Andrew Coleman - Raymond James

And then for the Austin Chalk, there are two branches in that correct?

Bob Banks

Correct. Yeah there are two zones that are typically targeted and talked about in the Austin Chalk; different areas, we think work differently between those two zones. So what works in one area versus another area may be a little different.

Terry Swift

Yeah, let me clarify that a little bit, you go from Brooklyn over to Burr Ferry all the way over the Masters Creek, we are seeing variations in the upper chalk and the lower chalk or the A&B chalk and also as you go across the Edwards Reef System there we are seeing differences.

In terms of how we target, I at this point in time wouldn’t say that the upper and lower is the best necessarily across the play, but we are actually of the opinion that the frac recess are more important than upper or lower end of frac recess is what we are trying to find be they upper or lower.

Andrew Coleman - Raymond James

So as far as it’s been over say 10 to 12 years ago and you know when the play was being targeted pretty extensively as well, that they were looking specifically at more the upper versus lower?

Bob Banks

Yeah, it’s a tough question to ask because of the differences across the play geologically, but let it suffice to say that even if you target the upper versus the lower in some areas we think the upper might be separated from the lower, some ceiling factors, in other cases we are absolutely convinced they are not separated. So that complicates it further I am sure.

Andrew Coleman - Raymond James

I guess I will ask just one last question here try to, as I look at your kind of releases the last four quarters here what I noticed is that compared to guidance per year, if your guidance range is in both fourth quarter and in the first quarter, you guys can comment on the high side and outside the high side of guidance for gas NGLs and oil for each of those past two quarters. So should I just raise my forecast to the high side of your guidance, perhaps tapering off gas heading to the rest of the year, based on guidance based on that, the last couple of quarters?

Terry Swift

Andrew let me just tell you our philosophy. We aren't putting out our expectations. You know we try to create a range that we can beat it with that. And as things worked pretty much according to plan, we do hope to be on the high side.

But stuff happens, and so we account for that with the range and may more than likely some thing’s going to happen to keep you from being on the high side consistently quarter after quarter. But we work real hard though to try to hit the high side of guidance, but I think that midpoint is probably the better point putting some sort of a forecast or estimate that you might be using because stuff does happen and frustrates us, but it does; but rest assured what we are shooting for is the higher side, would love to be above it, but I am happy with the high side.

Operator

And at this time there are no further questions. Presenters you may continue with your presentation or closing remarks.

Terry Swift

Okay. Well, we would like to thank you for joining us today and we’ll look forward to executing throughout the next quarter here and getting back with better results. Thank you again.

Operator

Thank you. This concludes Swift Energy Company First Quarter Earnings Conference Call. You may now disconnect.

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