SilverBow Resources Inc (SBOW) 2012 Q1 法說會逐字稿

Good morning, my name is Felicia and I will 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 Winston, Director of Finance and Investor Relations. Please go ahead sir.

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 Finance 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 the call 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. The statements involve risks and uncertainties detailed in our SEC reports, to which we refer you, along with cautionary statements contained in our press releases, and our actual results could differ materially. We expect our presentation to take approximately 25 to 30 minutes and have allowed additional time for questions.

Thanks, Paul, and thank you, 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've 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 sages 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's 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've managed to park any 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 who 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 remain 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 have drilled to date. Our most recent well, the CM 422, encountered 226 feet of pay, and is now flowing about 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 well online in the Masters Creek field. The performance of this well has confirmed drainage and reservoir assumptions we've 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 continue to improve, so much so that it's difficult to say which has got us more excited. With six drilling rigs we TD'd 15 wells during the quarter in this area. One of these rigs is a walking rate and spent much of the quarter drilling four surface holes in our first pad well drilling operations. Drilling days and costs continue to improve as we develop techniques and standards that reduce our non-productive time and eliminate project 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 as our drilling activity -- 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 an 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 year-end 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'm extremely encouraged by the way our folks have solved the problems over the last few years. We have a multi-year inventory of drilling projects, unlike any 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'll ask Alton to present our first-quarter 2012 financial results.

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 been 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 products.

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 at $1.61 per diluted share, and 1Q 2012 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 in 1Q 2012. As Terry mentioned, we'll point out that for the first-quarter 2012, approximately 85% of our oil and gas revenues were from crude oil and liquids sales.

With respect to our controllable cost and metrics and comparing them to guidance, production costs came in at $10.44 per BOE, above guidance, due mainly to unscheduled workover 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 share, below First Call mean estimate. Our effective income tax rate for the quarter were 39.3%, which was within our guidance. Cash flow before working capital changes from 1Q 2012 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 the high pricing volatility, our hedging activity was minimal during the quarter. We have, however, layered in some strong oil floor subsequent to quarter end. Please see our website for a complete and current detailed oil and 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 semiannual review, our borrowing base was raised to $375 million from $325 million effective May 1st. We're keeping the commitment amount at $300 million, on which we pay standby fees.

Depressed natural gas prices in the near term continue to pose a significant challenge to our sector, but with our liquidity, our inventory of oil and liquid-rich projects, and approximately 85% of our revenue coming from oil and liquids production, we feel we are very well positioned to continue to execute our 2012 strategic plans. As always, we've included additional financial and operational information in our press release, including guidance for the second-quarter and full-year 2012.

And with that, I'll turn it over to Bruce Vincent for an overview of our operations.

Thanks, Alton, and good morning, everyone, thanks for listening.

Today I will discuss the first-quarter 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 during the first quarter of 2012 totaled 2.8 million barrels of oil equivalent, or 16.79 million cubic feet equivalent, which was at the high end of our previously-issued expected range. This is an increase of 6% over the first-quarter 2011 production of 2.65 million barrels of 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. For our first-quarter drilling results, Swift Energy drilled 17 operated wells during the quarter.

In South Texas, nine operated horizontal 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 La Salle County. Five wells were also drilled to the Olmos formation in McMullen County. In Swift Energy's Southeast Louisiana care area two wells were drilled in the Lake Washington field. We currently have six operated drilling rigs in our South Texas core area drilling Eagle Ford and Olmos wells. We also have one operated barge rig drilling in our Southeast Louisiana area, and then two non-operated drilling rigs that are active in our Central Louisiana/East Texas area.

I will review 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 the 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 2011 average net production for the same area.

Lake Washington averaged 6,024 net barrels of oil equivalent per day, or 36.1 cubic feet equivalent per day, a decrease of 14% when compared with 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's sequential production decreased 9% to 487 net barrels of oil equivalent per day, or 2.9 million cubic feet equivalent per day. This sequential decline is due to no new drilling activity and natural declines.

In our South Texas core area, which includes our AWP, Sun TSH and Las Tiendas Olmos fields, and AWP artesian 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 with fourth-quarter 2011 production in the same area, and a 48% over the first quarter of 2011. This sequential increase is primarily from newly completed wells brought online during the quarter. Please see our press release issued this morning shows for specific information on wells brought online during the quarter.

As outlined in our annual investor day in March, well performance continues to improve as we drill longer laterals and improve 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 should see our capital expenditure budget trend toward the higher end of our current expected range. Bob will spend time discussing our Olmos and Eagle Ford programs in greater detail.

The Central Louisiana/East Texas core area, which includes our Brookeland, Masters Creek, Burr Ferry, and South Bearhead Creek fields contributed 1,979 barrels of oil equivalent per day, or approximately 11.9 million cubic feet equivalent per day, of production in the first quarter of 2012. We brought one new operated well online during the first quarter in this area and our joint venture partner has resumed drilling operations in the Burr Ferry area with two rigs currently active.

I'll now turn the call over to Bob Banks to review the operational highlights of the fourth quarter and -- or first quarter in a little more detail.

Thank you, Bruce.

At the Lake Washington field, during the quarter we completed 10 wells and performed 26 production optimization projects, which includes sliding sleeve shift changes, gas lift enhancements, and returning shut-in 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 CM 419, was drilled to a measured depth of 8,489 feet and encountered 60 feet of true vertical pay. After completion, extraneous water entered into the productive interval and the well will now require workover in the second quarter to shut off the water and return the well to production.

The second well drilled during the quarter, the CM 421, was drilled to a measured depth of 8,513 feet, and encountered 255 feet of true vertical pay. The initial production rate of 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 an 18/64" choke. Both of these wells have opened up additional drilling opportunity on the west side of the Lake Washington salt dome.

A third well, the CM 422, was just recently drilled and completed in the second quarter. And this well, located in the northeast portion of the field, was drilled to a measured depth of 8,573 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 flowing tubing pressure of 400 psi on a 26/64" choke. This well also sets up additional drilling inventory in this portion of the field.

It merits mentioning that we are finding enormous amounts of pay at depths one could reasonably expect us to have been developed decades ago. As a result, we see several years of development activity ahead 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 generates 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 in Vernon Parish during the quarter. The initial production rates of 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 2,565 psi on a 48/64" choke. This well was proof of concept well drilled at an infill location to lateral length of 2,500 feet. The productivity of this well has proven this concept and increases our ability to downspace 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 the future. We've been adding staff to this asset team and are advancing discretionary initiatives, such as sidetracking the gas RS 20-1 well initially drilled last year, we're looking enhanced -- enhancing production optimization and maintenance programs, and we're accelerating our appraisal of the Wilcox acreage in Beauregard Parish.

Moving on to South Texas, ten 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 that details the test results of all these wells. Our well performance continues to improve over time, and we believe we are still making strides toward optimal well performance and cost efficiency. Our fracture stimulations crew, which is operated by Weatherford International, continues to demonstrate top-tier performance and has reduced nonproductive time and increased the number of stages completed per day far beyond our most optimistic initial expectations when we entered into our contract.

Partially result of this performance, we've extended our agreement with Weatherford International for another year. This agreement reflects a reduced fixed rate on more current economic terms for 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 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 cost significantly and we plan to continue building in these types of efficiencies into our operations for the foreseeable future.

As we have indicated previously, one of our rigs is a walking rig and is drilling a four-well pad presently in our oil-rich acreage in northern 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 and fewer days and at less cost 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 that 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'll turn it back to Terry to recap.

Thanks, Bob.

Before we open the line for questions, I'll summarize Swift Energy's first-quarter results and review some of the highlights from today's call. First-quarter production growth of 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 fourth quarter in South Texas -- first quarter in South Texas. We completed 188 frac stages during the quarter in this area, record performance for our frac crew. We anticipate completing our first four wells drilled off of a single pad during the second quarter. 85% of our revenue was derived from crude oil and natural gas liquids production. All of our remaining 2012 drilling activity is crude oil and natural gas liquid-rich focused areas.

With that, we like to be in the question-and-answer portion of our presentation.

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

Morning, guys. A couple of questions. First, you did talk about potentially ramping the Southeast Louisiana, I'm just wondering, Bruce or Terry, just general comments, as far as how much more in the way of either workovers, new rigs, et cetera, could you add? Obviously, to me, with what's going on with the NGL prices, and, obviously, still the premium LSS prices, was wondering just how much for you can continue, and is that something we could potentially see, maybe the budget rejiggered, or even the budget taken up as a result of potentially-higher activity in the later part of the year in that area?

That is a good question, Neal. Obviously, with oil pricing, particularly the HLS market, which Lake Washington sells into being 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 minimum, we're going to keep that rig busy all year. But, we are considering accelerating or actually adding some additional well activity to Lake Washington and bringing in a second rig to get that activity accomplished this year.

We've not made it a final decision on that, but that's something under serious consideration and, obviously, that would uptick the capital budget spending a little bit. But we would get results from that, particularly if you made that decision today. It'd take a couple months to get the rig in the fields, so it would be second-half activity production. You'd get a little bit of production this year, but you'd primarily get production momentum going into next year, and it would be high-quality HLS pricing crude oil. It's a good question, because certainly under consideration.

Okay. Moving back to -- just looking at South Texas around some of the wells either in McMullen or Webb County. Bruce, wondering still on the frac design there, are you still expanding that, or are you still keeping that on par with where you had it last quarter? It looked like the results were pretty stable versus the results you had late last quarter. Then, the second part of the question around that would be on the take away in that area. It does sound like you -- it does appear like you solved most of those problems, if you could just comment on that?

That me answer that, Neal.

On the frac design, we're pretty much sticking with that design that we talked about at our analyst day. It's a hybrid design, a guar gel with breakers. In terms of performance of the wells, one of the things we are doing is, we're releasing our flow back crews a lot earlier, now. I think we try to get them off in about six days to, again, work our cost efficiency.

Some of the reports that we show you don't quite get to a 20/64" choke setting, because we get our flow testers off early. We do track each one of our wells against our models. All the wells that we're reporting in our press release today, I think are pretty much in line with our models, taking into account the choke settings, the frac stages, and the lateral links, things of that nature.

The second part of your question, again, on the capacity. Yes, 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're in the final throes of negotiations there for the firm takeaway in capacity.

In the interim, we are getting interruptible service there, but we really expect to have that all concluded this quarter. Yes, the other thing I would add to that, we talked about our ideal model being about a 6,000-foot legged lateral. In the La Salle County area, where we're having an increased level of activity and is an oilier area that we had originally thought it was, it's also a little shallower, and so we're actually trying to -- where the leasehold allows it, we're really trying to push the lateral down more like to 6,700 feet. We think that will actually get us better performance.

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

On 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're very comfortable with the guidance that we've presented here in the press release.

Yes, 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'll probably get to at some point in time is, in terms the second-quarter guidance is 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.

Great color. Thanks, Bruce.

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

Thank you, good morning. First on South Texas. What's the timing of that four-well pad, how's the drilling looking there, when do expect to bring that on, what's incorporated in the guidance there?

Yes, the operation's going very efficiently. Of course, I think as we discussed in our analyst day, when you do the four-well pad like we're doing, you have to move that rig off before you bring the frac crew on and do the zipper frac operation that we showed you at analyst day. The timing of all that really is right at the end of second quarter, 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. That does cut into second quarter versus third quarter oil production. I think what we have planned, is really at the end of the second quarter going into the third quarter.

As I recall during 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 part of the reason for the significant higher ramp of crude oil in the third quarter.

Then going forward, how do you expect the pad drilling to proceed? Is everything going to be on pads?

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'll be a little less bumpy in terms of bringing on wells. I think, by the time we get into next year you'll start seeing us move 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 we go about this pad drilling.

Okay. And then you mentioned 80-acre spacing, can you just remind me? Is that what you based your location counts on at the analyst day?

We did. Yes, we did show you the 80 acres. Most all of our drilling has been done on 160s, but not we have shown you both 160 counts and 80-acre counts. I think we showed you the 80-acre numbers at analyst day.

And that's specific to Eagle Ford. The Olmos [multiple speakers] on 160-acre spacing.

Okay. And then in Central Louisiana/East Texas at Masters Creek looked like a good result. What does that tell you? You mentioned you're looking for different -- additional acreage, what are you seeing as far as opportunities go there? And then you also mentioned accelerating a Wilcox test, so just wondering if you provide a little color there?

On the infill concept, basically, most all of these units are formed on 2,000-acre spacing, and what we did is we tested a down spacing with this Exxon Corp. 10-1 well, so that basically builds an automatic inventory of infill 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 the regional study that we're doing here through our exploration team. 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, proof of concept horizontal well in the Wilcox there. I don't imagine we'll get that in before this year, but you'll see us coming forward with plans to drill that proof of concept well before too long.

Okay, and then lastly for me just a follow up. As far as the inventory goes at Masters Creek do you care to quantify what the downspacing opportunities might add to your inventory there?

Well, I think we actually showed you some of that at analyst day. I'd put it into context of maybe 15 to 20 or 25 type infill opportunities.

All right. Thank you very much.

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

Good morning, thank you for taking my call. My first question is just, it seems that the NGL mix in the full-year guidance got bumped up by a couple of percentage points, I would just like to clarify what is driving that?

Well, what's driving the primarily is the shift in focus from dry gas to liquid-rich opportunities, both oil and NGL's. If you get into a little more granular level than that, Artesia wells, as we've indicated before, turned out to be a little more liquidy than gassy than we first thought, so that activity is actually driving a little bit higher liquid activity. One of other things is the efficiencies we've talked about, by shortening drilling times, getting them off the wells quicker, we're saving cost, but the other thing you're doing is saving time, and we're not going to just stop drilling, we're going to basically be able to move some wells that we would've drilled next year into 2012. So, those cost savings, basically, accelerate activity from the next year into this year. Obviously, the more well activity you get the better results.

We've talked about drilling six-to-10 wells in Lake Washington and we've been saying of late it's more likely 10 than six. And as I indicated earlier, we have under consideration to actually increasing that well activity, as well, and possibly bringing in a second rig. All that contributes to higher liquid growth. I guess the other thing, looking at the other area, the Central Louisiana/East Texas area, we mentioned that Anadarko has two 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 than gas growth.

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

I guess I was focusing on what changed versus the prior guidance.

Versus prior guidance, the NGL mix. It's just really tweaking the model going forward.

As you get in there and --

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

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 workovers in the Eagle Ford, and what else was there driving that?

I think that is certainly part of it. When we actually look at the actual April production, oil production was actually lower -- slightly lower in April than it was in January and certainly lower than February and March, and that's really due to the well activity that happens. But we see that climbing again in May and June and much more so when we get too July and August, though.

That's all I have. Thank you.

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

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

Yes, I'll try to do that for you, Marcus. First of all, I guess, I would say, I wouldn't read too much into it. Some of those wells up in our SMR area that are the real heavy oil model are very, very strong wells. You'll see in our press release that one of those wells only reached a 12/64"choke setting. The reason why we've only taken that to a 12/64" is because we're experimenting with a restricted flow-type model to see how that changes our decline profile in that very liquids area.

But what we do is, we equalize these against our models to try to make sure that the performance overall is matching our models. We drilled two wells up in that real oil area, we drilled four wells down in the condensate window, and then we drilled three Olmos wells, which were kind of in that rich condensate window of McMullen County. One of the wells -- one of the Olmos wells only had eight stages associated with it for mechanical reasons. So there's a number of moving parts between what we're doing with choke settings, what we're doing -- what we're able to do with the lateral links and stages and things of that nature.

But, that kind of gives you a general breakdown of McMullen County. There were those three wells that we finished up out in Webb County in our gas acreage that retained all of our acreage and those all look very strong. So overall, we're very pleased with the way the performance is going and the way we're matching our models that we've been presenting to the industry.

Okay, great. I guess, you did present the new Olmos oil model back in March, just curious as to how these initial wells are stacking up against that curve, too?

Like the SMR Olmos model, I think they're stacking up quite well against our models. We're very pleased.

Okay, great. And then maybe just one for Alton. In terms of this spread that we're seeing for NGL 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 a sufficient market for that in terms of depth of contracts and so forth? If you could maybe just highlight some color that?

We have had those discussions, we have not done anything with respect NGLs. As you know, the guidance down as a percent of crudes, a function of the ethane and propane markets that are out there. We continue to look at that. We've guided what we think the market's going to give us going out for the remainder of 2012. I believe there probably is enough activity out there to do something, but we have those discussions and if feel that it's in the best interests of the Company and shareholders then we'll do that.

Okay. Well, great, guys, that's all I had. I appreciate it.

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

Good morning, thanks for taking my question. Just one quick question her on NGL's. Could you remind me what is the percentage makeup of your NGLs right now? What is the percent propane, isobutane, how does that break out?

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

All right, I appreciated it, guys. Thank you're much.

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

Good morning. Just a couple questions. I wanted to go back to Masters Creek for a minute. I was wondering, the wells you've done, the infill wells that look encouraging, were any of those on that relatively-new acreage you bought? I want to say was about 10,000 acres or something that you added out there.

No, 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 infill well that we've drilled at Masters Creek, and so that's what has us excited about revitalizing the Masters Creek field. The two rigs that we mentioned to you that are being operated now in Burr Ferry are continuing on in that area where we built our lease position to the west.

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?

It has lots of running room. That is all new acreage position and that's what we -- I think we tried to lay out some of those number of locations at our analyst day and what we think the resource potential is there.

Okay. Sorry if you commented on this before, but as I've been listening to 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 part of a JV or something like that. So, assume that there's quite a few data rooms out there and a lot of discussion, have you heard anything in the last month or so that changes either your idea of what areas of the play might work, or just trade off between pressure in the oil window and better pressure in the condensate and gas windows and so forth. Have you heard anything that has you curious, or anything you -- anyone's found that you think might be game changing, or give us any new ideas on the play?

I will answer that -- or I'll attempt to answer that question. But basically, the Eagle Ford is one of the premier plays in the United States, particularly as it relates to oil and NGLs, and it's such a vast play that clearly there's going to be different things happening, and there's so many operators in there I wouldn't be surprised if you're hearing different ideas. But I really need to speak specifically to Swift Energy Company. We have now fully appraised our areas and we know where we need to focus, and we're not looking at any kind of joint ventures or any kind of different monetization right now, other than drilling up this inventory and doing it focused on liquids and NGLs.

We've several years of liquids and NGL drilling on our part, and if we do get any of those kind of ideas and take any action in that direction, we'll certainly be talking to the Market about it. But right now we're focused on developing our inventory and in the areas that we work in we're really not seeing operators do 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 heard a few things in some of the other areas.

Thanks a lot. That's it for me.

(Operator Instructions)

Your next question comes from the line of Andrew Coleman with Raymond James.

Good morning, folks, sorry (multiple speakers) here to the call, but you'd said at the analyst day that you had looked at the TMS, but were not overjoyed with it at the time. I think I'm paraphrasing, but with all the additional activity that's had in the play some of it appears to be heading closer to your direction. Have you had any change to your view at this point?

No. I really wouldn't say our view has changed so much, but I might clarify a little bit from the analyst day. The Tuscaloosa Marine shale is a very interesting play. It's very, very early. A lot of operators are doing appraisals in different areas. We're in a unique situation. We've got fee acreage where we own the royalty in a lot of that, so there's no lease expiration issues.

We also have a very active, as we have discussed today, Austin Chalk play where we're drilling out. So really, it's kind of a secondary or lagniappe kind of opportunity for us. As our guys have looked at it we clearly believe our Austin Chalk is the play du jour there, and we'll continue to watch the Tuscaloosa Marine shale, but we don't have any near-term plans to do any testing or evaluation of it.

Okay. To clarify, then, two points, one on Austin Chalk, one on TMS. First would be, what's the separation, approximately, from the TMS and the Austin Chalk for you guys? And then if I remember correctly, you guys are targeting, is it, the upper piece of the Austin Chalk, which has not been historically produced as the lower one?

Bob, you want to take that?

Yes, it's about 200 feet separation, something in that order of magnitude.

Okay. Then, for the Austin Chalk, there are two benches in that, correct?

Correct. 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 are, versus another area may be a little bit different.

Yes, let me clarify that a little bit. You go from Brookeland over to Burr Ferry, all the way to Masters Creek, we're seeing variations in the upper chalk and the lower chalk, or the A and B chalk, and also as you go across the Edwards Reef system there we're seeing differences. In terms of how we target, I, at this point, wouldn't say that the upper or the lower is the best, necessarily, across the play. But, we're actually of the opinion that the fracture sets are more important than upper or lower, and those fracture sets as what we're trying to find, be they upper or lower.

Okay. It's not as if, then, over 10, 12 years ago when the play was being targeted pretty extensively, as well, that they were looking specifically at more the upper versus the lower?

Yes, it's a tough question to ask because of the differences across the play geologically. But let us suffice to say that even if you target the upper versus the lower, in some areas, we think the upper may be separated from the lower, some ceiling factors. In other cases, we're absolutely convinced they are not separated.

Okay.

That complicates it's further, I'm sure.

Fair enough, clear as mud, right? (laughter) If I could -- I guess I'll throw one last question here, try to -- as I look at your releases the last four quarters here, what I notice is that compared to guidance for your -- if your guidance range is in both fourth quarter and in the first quarter, you guys have come in on the high side and outside the high side of guidance for gas, NGLs, and oil, for each of the past two quarters. Should I just raise my forecast to the high side of guidance, perhaps tapering off gas heading to the rest of the year, based on the guidance based on that last couple quarters?

Andrew, let me just tell you our philosophy around putting our expectations. We tried to create a range that we can be within, and if things work 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 more than likely, something's going to happen to keep you from being on the high side consistently, quarter-after-quarter.

We work real hard, though, to try to hit the high side of guidance, but I think that midpoint is probably the better point to put in some sort of forecast or estimate that you might be using. Because stuff does happen, and it frustrates us, but it does. But rest assured, what we're shooting for is the high side. Love to be above it, but I'm be happy when we have the high side.

Okay, great. Well, I appreciate that and nice quarter.

At this time there know further questions. Presenters, you may proceed with your presentation or closing remarks.

We'd like to thank you for joining us today and we look forward to executing throughout the next quarter here and getting back with you with our results. Thank you again.

Thank you. This concludes today's Swift Energy Company first-quarter earning conference call. You may now disconnect.