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Swift Energy Company (NYSE:SFY)

Q4 2011 Earnings Conference Call

February 23, 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 – EVP & COO

Analysts

Neal Dingmann – SunTrust Robinson Humphrey

Leo Mariani – RBC Capital Markets

Dan Morrison – Global Hunter Securities

Michael Hall – Robert W. Baird

Marcus Talbert – Canaccord Genuity

Ray Deacon – Brean Murray, Carret & Co.

Noel Parks – Ladenburg Thalmann

Justin [ph] – RBC Capital Markets

Gordon Beck [ph] –Wells Fargo Securities

Operator

Good morning. My name is Dona, and I’ll be your conference operator today. At this time I would like to welcome everyone to the Swift Energy Company 2011 Fourth Quarter and Full Year Earnings Conference Call and Web cast. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator instructions)

Thank you, Mr. Paul Vincent. You may begin you conference sir.

Paul Vincent

Good morning. I’m Paul Vincent, Director of Finance and Investor Relations. Welcome to Swift Energy’s fourth quarter 2011 earnings conference call. On today’s call, Terry Swift, Chairman and CEO, will provide an overview. Alton Heckaman, Executive Vice President and Chief Financial Officer, will review our financial results for the fourth quarter. Then Bruce Vincent, and Bob Banks, 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 today’s call is Jim Mitchell, Senior Vice President, Commercial Transactions and Land; and Steven Tomberlin, Senior Vice President, Resource Development & Engineering.

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

Okay. Thank you, Paul. I appreciate that introduction. And I appreciate everyone joining us for our conference call today. Swift Energy Company has entered 2012 with exceptional operational momentum and financial strength. We expect this year to be one of the best years in the history of the company in terms of physical performance.

It is important to point out some of the more significant accomplishments of last year, 2011, and at the same time we need to discuss today some of the challenges and opportunities in front of us for 2012. Production [ph] last year realized a growth of 26%, driven by activity and results in South Texas, and resulted in 45% higher cash flows in 2011, relative to 2010.

We expect to follow-up this performance with record production levels in 2012. Reserve growth of 20% established a new record for year-end proved reserves of 160 million barrels of oil equivalent. During 2011, we have witnessed an increasingly lower natural gas pricing environment and a very healthy crude oil market. I want to emphasize that the company has significant liquids and oil opportunities in front of it, and we are driven to grow liquids in virtually everything we are doing. We have been doing that. We are going to continue to focus in that direction and fortunately we have got a great inventory to do that.

At the same time, I want to emphasize that last year we did finish up some gas projects, got ourselves in a very healthy position in terms of our future relative to gas, and I like to use the word parked. We were able to get ourselves in a position where we parked numerous leasehold in areas where we had gas opportunities. We don’t have to drill those going forward. Those will stay in our inventory of future unbooked opportunities because they are parked at this time as we focus on liquids.

I also want to emphasize that not all natural gas is created equal. It is important for investors to know that the way we look at natural gas, there is associated gas. That gas comes from our oil world. It is actually a very good thing. It is part of our reserve base. Associated gas helps provide broad mechanisms and gets a lot of natural gas liquids as we produce our oil. We also have wet gas. That is generally a pretty good thing too, because as we process that we get a lot of NGLs out of those reserves.

And finally, we do have some dry gas that proportionate when compared to our peers, we have a very small amount of dry gas. Just want to emphasize, not all gas is created equal. This year, we will be strategically focused on liquids as I have mentioned, rich liquids, in fact. And our near-term drilling obligations are absolutely focused on highest quality perspective acreage as it relates to liquids. We will get into that in our presentation today.

We have also pre-funded our 2012 liquids directed budget by issuing $250 million of long-term debt. In addition to this offering, we maintained an undrawn bank borrowing base with a commitment level of $300 million. This financial position allows us to further focus on our oil and liquids rich opportunities, which accounted for 81% of our 2011 revenues.

While the natural gas market remains weak, we will stay very focused and we believe we will be very strong in terms of liquids activity, and our liquids cash flow. One of our goals this year is to return the balance between our capital expenditures and our cash flows. Should gas prices remain weak, we have positioned ourselves where we can reduce activity in spending from our current levels to achieve this goal by year-end.

We have structured our commitments and work programs so that we have flexibility in all the things that we are doing to maintain a strong financial position and balance sheet. Operationally in 2011, we drilled and completed 38 horizontal wells in South Texas. With our acreage further appraised as a result of all this activity, we are able to focus our current activity on our highest return projects. We will discuss today some of the results we have and some of the activity going forward.

In central Louisiana, we expanded our meaningful [ph] joint-venture area with Anadarko in the Austin Chalk, and also resumed drilling Austin Chalk wells on our acreage. We also resumed drilling operations in Lake Washington, drilling two important prospects, each of which were successful, and have brought up additional opportunities we wish to exploit in 2012.

In October, we divested non-strategic onshore Louisiana assets for $53.5 million, further focusing our organization on the more strategic assets and opportunities in our other three core areas. Structurally, we have made important marketing commitments in South Texas, which will allow much of our liquids rich production to be gathered, processed, transported and processed under very favorable commercial terms for many years to come.

We also took additional steps to increase control of our supply chain, and now are sourcing much of our propane, as well as managing more of the logistics involved in our growing South Texas operation. This highlights two of the initiatives that are designed to make us more efficient, more effective in our execution and to bring down cost. Focusing on the fourth quarter of 2011, Bruce and Bob will discuss all of our fourth quarter activity in detail a bit later, but I would like to highlight a few of the achievements first.

The 12 gross wells we completed in South Texas during the quarter pushed the average daily production to 29,338 barrels of oil equivalent per day, a 6% increase over the third quarter and a 24% increase over fourth quarter 2010. Our end of the year exit rate of 31,200 barrels of oil equivalent per day represents an increase of approximately 16% of our 2010 daily exit rate.

This production growth achievement has naturally been adjusted for the strategic property divestitures that we had last year. By the end of the fourth quarter, we had six drilling rigs active in South Texas, which should ensure a steady inventory of wells for our dedicated frac crude to complete during 2012.

Operated drilling results in our central Louisiana area have encouraged us in that we have a material opportunity set in the Austin Chalk drilling prospects outside of our large nonoperated position. We will be focused on the Austin Chalk and the oil and liquids aspect of this project area throughout 2012.

We have also resumed drilling operations in Lake Washington during the fourth quarter. Drilling results, combined with our recompletion of production optimization work should flatten production declines in the field. This is extremely important as we currently realize strong Gulf Coast pricing premiums on crude oil sales in this field relative to NYMEX levels.

Looking ahead, as more of our acreage in South Texas is earned, and we further remove external uncertainties through the long-term agreements and commitments, our results will continue to improve. This can best be seen in our production growth guidance for 2012 of 14% to 20% growth, and our reserve growth guidance of 10% to 15% for 2012. This year, we will transition our operations towards full development of our highest value acreage and take steps to significantly reduced cost. This will be accomplished by utilizing multi-well drilling pads, simultaneous completion operations, or what is referred to zipper fracs, and further realizing efficiencies in our supply chain.

With oil and liquids rich focused activity throughout our portfolio this year; we are prepared to weather a prolonged period of weak natural gas prices, and expect to have an exceptional year.

And now I will ask Alton to present our fourth quarter 2011 financial results.

Alton Heckaman

Thank you Terry and good morning everyone. The fourth quarter was another successful quarter for Swift Energy. Our production increased 24% from the fourth quarter of 2010. Coupled with higher oil prices we posted strong financial results.

Oil and gas sales were $156 million, a 35% increase from 4Q ’10. Income from continuing operations was $20.7 million or $0.48 per diluted share, up from $0.25 in 4Q ’10. Cash flow before working capital changes came in for the quarter at $2.33 per diluted share and 4Q ‘11 production was up 24% from the prior year at 2.7 million barrels of oil equivalent, at the high end of our quarterly guidance.

Crude oil prices were 31% higher than fourth quarter 2010 levels, while natural gas prices decreased slightly, with an overall 9% increase in our realized price per Boe in 4Q ’11. I should point out that for the fourth quarter of 2011 approximately 83% of our oil and gas revenues were from crude oil and liquid sales.

As to our controllable cost to metrics compared to guidance, production cost came in at $9.82 per Boe, slightly above guidance for reasons that we will talk to you about today. G&A came in at $4.70 on the high side of guidance, DD&A was within guidance at $21.52, interest expense came in at $3.75 per barrel, above guidance due to the debt offering in November, and production in ad valorem taxes were slightly below guidance at 8.5% of revenue.

As previously mentioned, the net result was income from continuing operations for the quarter of $20.7 million, $0.48 per diluted share, well above the first column mean estimate. Our effective income tax rate for the quarter was 38% just above guidance due to a slight increase in the effective state tax rate. Cash flow before working capital changes for 4Q ’11 came in at $99 million or $2.33 per diluted share, while EBITDA was $103 million for the quarter. Quarterly CapEx on a cash flow basis was $137 million.

Compared to last quarter, production was up 6%. This production growth combined with strong oil prices resulted in a 22% increase in net income from 3Q11. And for the full year 2011 production was up 26%, while income from continuing operations increased 82%. With the high price and volatility, our hedging activity was minimal during the quarter. As always, please see our website for complete and current detail of oil and gas hedging information.

As previously announced, we’ve closed on the sale of certain non-strategic assets in October for about $50 million in net cash proceeds. The buyer also assumed approximately $28 million of PV asset retirement obligations related to these properties. And as Terry mentioned, in November, we completed a very successful debt offering of $250 million senior notes due 2022. The net proceeds will be used to prefund our 2012 capital expenditures in excess of internally generated cash flows.

As of the end of the fourth quarter 2011, we had no outstanding balance on our line of credit and had $252 million of cash on hand. With the debt offering in November and the receipt of the disposition proceeds in October we have a very strong liquidity position. Also, as Terry mentioned, suppressed natural gas in the near term pose a significant challenge to our sector. But with our year-end liquidity, our strong liquids component inventory of projects, and more than 80% of our revenues coming from oil and liquids production, we are well positioned to execute our 2012 strategic plans.

As always we’ve included additional financial and operational information in our press release, including guidance for the first quarter and full year 2012.

And with that I’ll turn it over to Bruce Vincent for an over view of our operations.

Bruce Vincent

Thanks Alton, and good morning everyone and thanks for listening in. Today, I will discuss fourth quarter 2011 activity including our production volumes, our recent drilling results, activity in our core operating areas, and our plans for the first quarter and full year of 2012. Bob Banks will then provide greater detail on the operational highlights for the quarter.

Beginning with production, Swift Energy’s production during the fourth quarter of 2011 totaled 2.7 million barrels of oil equivalent, which was at the high end of our previously stated guidance range. This was an increase of 24% over fourth quarter 2010 production of 2.18 million barrels of oil equivalent, and an increase of 6% from the 2.54 million barrels of oil equivalent produced in the third quarter of 2011.

As the natural gas market has deteriorated dramatically since (inaudible), we have reduced our planned activity, and where possible opted to replace projects with higher percentage of expected natural gas production, with projects that yield more oil and natural gas liquids production. This will result in slightly lower full year production than previously expected, but much better cash returns, and much better project economics.

2012, we expect our production to grow 14% to 20% over last year’s level, and our production mix will be roughly 50% crude oil and natural gas liquids, and 50% natural gas at the end of the year.

For our fourth quarter drilling results, Swift Energy drilled 12 operated wells and participated in 2 non-operating wells during the quarter. In South Texas, 8 operated horizontal development wells were drilled to the Eagle Ford shale formation in South Texas. Three wells were drilled in McMullen County, three wells were drilled in Webb County and two wells were drilled in LaSalle County. Three operated wells were also drilled to the Olmos formation in McMullen County, and the two non-operated wells were drilled in the Eagle Ford shale in McMullen County.

With Swift Energy’s Central Louisiana and East Texas core area, one operated well was drilled in Austin Chalk formation in the Masters Creek field in Burr Ferry. We now have six operated drilling rigs in our South Texas core area, drilling Eagle Ford and Olmos wells. We also have one operated barge rig in drilling in our south-east Louisiana area.

I will review our performance in each of our core operating areas for this quarter, and let Bob provide detail of the highlights of the most recent activity. Again with the Southeast Louisiana core area, which includes Lake Washington and Bay de Chene fields, production during the quarter approximated 7505 net barrels of oil equivalent per day in this area. That is down 12% when compared to the third quarter of 2011 average net production from the same area.

Lake Washington averaged approximately 6,969 net barrels of oil equivalent per day, an increase of 10% when compared to the third quarter of 2011 average daily volumes. Bay de Chene sequential production decreased 29% to 536 net barrels of oil 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 [ph] fields, and AWP future wells, and Fasken Eagle Ford fields, third quarter 2011 production averaged 19,083 net barrels of oil equivalent per day, a 21% increase in production when compared to the third quarter 2011 productions in the same area, and a 91% increase over fourth quarter 2010. This sequential increase was primarily for newly completed wells brought online during the quarter. In addition, our ongoing production optimization efforts and the uninterrupted operation of a third-party natural gas gathering and transportation system in Webb County.

Please see our press release issued this morning for specific information on wells brought online during the quarter, as well as wells brought online to date in 2012. This type of productivity is consistent with our expectations for this area. As Terry mentioned, we believe there is room to improve in this performance, while reducing operational costs at the same time. Bob will spend great deal of more time discussing our Olmos and our Eagle Ford programs.

The Central Louisiana, East Texas core area, which includes our Brooklyn, Masters Creek, Burr Ferry and South Ferry Creek deals, contributed 2339 barrels of oil equivalent per day of production in the fourth quarter 2011. We are bringing a new operated well online late in the first quarter in this area, and expect our joint venture partner to resume drilling operations in the Burr Ferry area later in the first quarter, early in the second quarter.

I’ll now turn the call over to Bob Banks to review operational highlights of the fourth quarter.

Bob Banks

Thank you Bruce. Before discussing our operational achievements, I like to make a few comments about our 2011 year-end proved reserves. Considering today’s market environment, I believe it is important to consider these reserve numbers relative to the phase of hydrocarbon that they are found in.

Of our total reserves, dry natural gas reserves only account for 21% of our reserves volume, while oil and liquids rich associated gas account for 79% of our volume. We see a similar break down in reviewing our PUD reserves by hydrocarbon plays. Dry natural gas reserves account for 26% of our PUD volumes, while oil and liquids rich associated gas reserves comprise about 74% of our PUD volume.

With approximately 80% of the reserve volumes comprised of crude oil and liquids rich associated gas, Swift Energy is clearly levered to these products. Moving on now to our activity, at the Lake Washington Field, we completed 10 wells and formed six production optimization projects during the quarter. The re-completions we performed averaged an initial production response of approximately 171 gross barrels of oil equivalent per day. Our production optimization projects, which include sliding sleeve shift changes, gas lift enhancements and returning shut-in wells to production, averaged an initial production response of 99 gross barrels of oil equivalent per day.

Recognizing the opportunity to realize strong crude oil pricing for Gulf Coast markets, we moved the barge rig into the field late in the fourth quarter. This rig has drilled one well, and is currently drilling a second. We expect this rig to be active for much of the year, drilling shallow to intermediate depth oil wells. The first well of this program, the CM 419, was drilled to a measured depth of 8,489 feet and encountered 87 feet of true vertical pay. This well will be tested upon completion of a flow line installation.

The second well of this program, the CM 421, is currently drilling and has encountered 227 feet of true vertical pay through both open hole and cased hole logs. Strategically, these two wells are located on the west side of the Lake Washington [ph], where we now see additional opportunity based on these preliminary results.

Lake Washington continues to generate strong free cash flow, and we intend to manage production at flat to slightly declining levels for the foreseeable future through a low-risk, shallow to intermediate drilling program.

In our Central Louisiana, East Texas area, we completed the GASRS 20-1 well in the Burr Ferry area in Vernon Parish. This well encountered large quantities of hydrocarbons during drilling operation, and tested at rates consistent with recent results in the area for a short period of time. As we discussed on our last quarterly call, we did encounter mechanical difficulties during the initial cleanup of this well. Unfortunately, several attempts to repair this malfunction were unsuccessful, making it impossible to produce commercial quantities of hydrocarbons. We do expect to sidetrack this well in the future.

We also drilled a well in our Masters Creek field during the fourth quarter. This well, the Exxon Corp. 10-1 was recently completed and tested at rates of 836 barrels of oil per day, and 5.4 MMcf of natural gas per day, with flowing tubing pressure of 2,565 psi on a 48/64 inch choke. This well also produced significant volumes of water during this preliminary test and will not be completely cleaned up until it is connected to production facilities. It is also important to tell that we only drilled approximately 2,500 feet of lateral, or 50%, of what we had planned. However, we encountered 21 fracture sets during drilling, and pressures that responded well during this initial testing. This well is an inter [ph] location, which is testing drainage and reservoir assumptions and could have implications for us. We are extremely encouraged by these preliminary results.

At our South Bear Head Creek field in Beauregard Parish, we continue to evaluate the well cost, and expect to test this area with a horizontal well later in 2012 or early 2013. Moving on to South Texas, we drilled nine Eagle Ford horizontal wells and Olmos three horizontal wells that were completed during the fourth quarter. So for in the first quarter, six of Eagle Ford horizontal wells and one Olmos horizontal well has been completed.

We have published two tables in our press release this morning that detail the test results of all these wells. One item to note is that for a number of our wells and our liquids rich acreage, we are experimenting with restricted settings to measure the longer term effect of these settings on well performance. Our activity and performance in this area continue to ramp up as evidenced by our production growth.

We are now averaging 65 frac stages per month, and believe this will further improve as we move towards pad development and deploying the zipper fracs. This is important to note as we expect to realize crude oil cost savings of at least $500,000 per well, through these efficiencies. Additionally, we are now sourcing certain propanes directly from a manufacturer, and managing the delivery of this propane ourselves, which is reaching our pro-well consumable and transportation cost.

As a result of improving frac fleet efficiency, we added 6 drilling rigs to this area during the fourth quarter to ensure that we had sufficient inventory in wells to keep up with our frac spread in crude. We are now in an exciting position as we move to a full-scale development program in South Texas. With much of the evaluation and appraisal work necessary to determine the value of our acreage behind this, we expect to significantly reduce cost and improve performance across all of our South Texas operations.

We are moving more towards multi-well pad drilling, allowing us to become more efficient by batch drilling our surface holes, shortening the time for rig blues, and carrying out simultaneous completion operations. Along with the other cost reduction and supply chain initiatives, this will allow us to reduce cost and improve cost across all of our operating areas.

For the remainder of the year and beyond, we have the flexibility now to concentrate our drilling efforts in the liquids rich area of the Eagle Ford and Olmos trends, while retaining an option to drill dry gas acreage in the future. I believe the value proposition we offer investors, coupled with our current production mix and oil and liquid rich project inventory offer an exceptional opportunity in today’s environment.

As Bruce and I just discussed, we began 2012 with strong operational momentum, and this momentum is coupled with the financial strength and flexibility Alton discussed, I am confident we are going to have a great year in 2012.

Thanks for your attention this morning, and I will turn it back to Terry to do a recap.

Terry Swift

Thanks Bob. Before we open the lines for questions, I will summarize Swift Energy’s fourth quarter results, and review some of the highlights from today’s call. Fourth quarter production growth of 24% over fourth quarter 2010 production. Our 2012 capital expenditures are pre-funded by our projected cash flows and cash on hand at the end of 2011.

Twelve gross wells were completed during the fourth quarter, and we are now completing on average 65 frac stages per month. This will improve as we move to pad drilling. We began our drilling program in our Lake Washington Field in Southeast Louisiana, which will add premium priced oil production. A successful Masters Creek concept well opens up a mature asset for further development.

We anticipate our Burr Ferry joint-venture partner will resume drilling activity in Vernon Parish this quarter. Our production will grow in 2012 14% to 20%, and will be approximately 50% crude oil and natural gas liquids at year-end.

With that, we would 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 Robinson Humphrey

Hi, good morning gentlemen. Good color. Say, maybe Bruce or Terry, first question just kind of dialing in little bit on the new business, Bruce, I understand what you are saying, I guess, about sort of the realignment and looking at maybe drilling some of the wells. I guess what I was looking at is just looking at the exit rate the 31,000 is up about 7% from your fourth quarter average, yet the new guidance is about 14% to 20%. I’m just kind of trying to walk through how you see gas production flowing from the end of the year if you are at 31,000 to kind of work into that new guidance, kind of what your assumptions are around that?

Bruce Vincent

Well, if you look at the activity that we had in the fourth quarter, or I guess at the very beginning of this year, a number of those wells were drilled down in the Fasken area. We now have – I guess, we have one well drilling right now. With the completion of that, we have now earned all that acreage down there. So the entire shift of the capital is going to go to liquids rich play.

So we got probably a higher than normal level of gas production today then you will have towards the end of the year certainly in that mix. The growth has been coming in the liquids production as you move through the year, and you will see gas actually drop down a little bit for the year.

Neal Dingmann – SunTrust Robinson Humphrey

Got it. And then just looking at you know, some of the recent wells on the release today, you know, looking I guess McMullen almost, are those expectations that kind of on a going rate like when I look at the Discher, the EF 3H, around the 645 oil. Just if you could comment, you know, maybe Bruce around sort of expectations or what when you kind of model out, how you see either these Eagle Ford or Olmos wells in McMullen, or even in Webb, what type of, I guess, if you kind, maybe just help me kind of think about what type of type curves you are thinking about for these wells through this year?

Terry Swift

Yes, I will make a couple of comments and turn it over to Bob for additional color. But one of the things that is important that people recognize with Swift is we standardize our reporting on our rate [ph]. And we’re also really holding wells jump back in the beginning. So we’re not opening them up to get nice IP rates, we are not picking the best rate during a period of time. We try to standardize that really for our purposes, so we can benchmark one well to the next.

It is important for people to really look ultimately at decline curves and EURs to see how they hold up against original IP rate, because IP rates can be all across the board and in our view, they in and of themselves are unimportant, to talk to me more about [ph] your decline and the EUR. So that is kind of a general comment.

But we have had models, and we have shown some of that to you in terms of the different areas that we are drilling, and we are going to give you a lot more color on that in a couple of weeks at our analyst day, March 15. Bob, do you have some more comments you want to make?

Bob Banks

Yes, I will just reiterate, our models that we have put out there for everyone are EUR models, and type curve models. Just to try to summarize, (inaudible) oil, we see about 395 MBoe. In our north AWP high yield condensate area, we see about 615 MBoe. In our central AWP and Artesia wells area, we see about 1.15 MBoe. Down at Fasken and the dry gas, we see about 1.67 MBoe, and then AWP dry gas is a little less than that, but again as Bruce said, all of our focus now that we have held the Fasken acreage, and we have an option on the AWP acreage is to work through those first 3 EUR models, and do all of our drilling in those areas.

Neal Dingmann – SunTrust Robinson Humphrey

Got it. And then last one if I could guys. Just, it looks you mentioned in the press release about having the one rig on Lake Washington rest of the year, just kind of your thoughts on Lake Washington and the rest of that South East et cetera. In the guidance, what is your thoughts on sort of the production for you know, the year, just at general level, you know, Bruce, maybe for you or Bob, just kind of how you are seeing that play out for the remainder of the year?

Bruce Vincent

Well, you know, drilling up that Lake Washington, if left it is going to decline, and we have seen that where we have significantly reduced activity to focus in other areas. So one of the things we have done now is really bring activity back to the field. You’ve got to drill wells to make that happen. I think the intent is to have enough activity in the field to kind of resume it to more of a flat level of production to mitigate that decline. And that is the overall objective of that program.

We started out with 4 to 6 wells. Now we think we’re going to do 5 to 10. You have seen from the information we put out today that the first two are really looking pretty good. So we’re actually pretty excited about that program, you know, and really hope to do better than implied out in our guidance. But we are going to see how we will get it.

Neal Dingmann – SunTrust Robinson Humphrey

Great comments. Thanks Bruce.

Bruce Vincent

Thanks Neal.

Operator

Your next question comes from the line of Leo Mariani with RBC.

Leo Mariani – RBC Capital Markets

Hi guys. Could you sort of address the infrastructure situation in kind of each of your areas in South Texas situated, and kind of what your form of transport is some of those areas, and your plans to acquire more form of transport?

Terry Swift

Sure. Bob Banks will take that.

Bob Banks

Yes. Obviously, down at Fasken ranch, we have firmed up all of that transport capacity. In fact, we even have a dual option now down there. So we are well situated. As we move up to into AWP, we announced that South Cross deal. We have also recently done another deal kind of up in our liquids rich area with DCP. So we believe we have taken care of all of our needs for transportation and processing in that area.

And then, out in the LaSalle County, Artesia Wells area, we are currently moving all of our product. We are in discussions with two transportation processing companies. We expect to have firm capacity there. That is not interrupting us at all at this point. So that is progressing very nicely. That is probably our last area to get tightened up. But all of these, you know, contracts are confidential.

We do have confidentiality agreements around them, but we have made significant progress in the past few months to getting all of our transportation and processing needs taken care of.

Leo Mariani – RBC Capital Markets

Okay, great. And I guess just jumping over to the Austin Chalk, you guys talked about your JV partner Anadarko putting a rig over there in the second quarter. How many wells do you guys have scheduled in the Austin Chalk this year?

Terry Swift

We have 4 to 6 in there, and you know, we believe that our partner is going to start up here maybe even by the end of this quarter.

Alton Heckaman

Yes, we had hope that the activity would have started really in January. It has been pushed back a little further like had some other needs where they have taken the rig to that is one of the reasons that is built into the production guidance. It is just a shift in that production to a little bit later in the year.

Leo Mariani – RBC Capital Markets

All right. And I guess you guys talked about some well cost savings, you anticipate here in South Texas. Could you give us kind of what your current well costs are in Eagle Ford and the Olmos and just clarify whether or not you have assumed that kind of $500,000 odd savings you are talking about in those numbers, yes, or no?

Alton Heckaman

Yes, I think, what we’re going to do at our analyst day, we’re going to lay this out in much greater detail, and show you the trade-offs that we are working. Obviously, as we start moving to the pad drilling, the zipper fracs, we are going to lay all that out for you in great detail, and kind of reconcile for you what our well costs are coming in at.

So if you wouldn’t mind, I would like to hold that detail analysis, because there is lots to talk about on what we have done probably since last analyst day in moving those costs down.

Terry Swift

But we put out that our well costs are running $8.5 million to $9.5 million, and you know, obviously, the things we are working on, we’re hopefully actually bringing that down to the lower end of the range, and maybe even below that.

Leo Mariani – RBC Capital Markets

Okay. And in terms of your Olmos well, it looks like, I guess it has much higher sort of NGL [ph] cut on some of your wells this quarter, maybe if you could talk about what you think is driving that?

Terry Swift

Well, that is the area we are targeting. We are definitely moving in a direction that we – we understand the Olmos very, very well. We are doing that by design. That is where we are placing our wells, and I think that is what you are going to see throughout this year, us targeting both the Olmos and the Eagle Ford where it is more liquid rich.

Bruce Vincent

I think it is important for people to understand about the Olmos is the Olmos is present across our acreage, and everywhere it is present is liquid rich. It may have different amounts of free condensate production with high btu, and so we can actually focus Olmos activity in areas, where maybe the Eagle Ford might be dry gas, and still preserve the acreage over time.

So one of the things that we have been trying to do is push off any acreage obligations in the dry gas areas, maybe as far out as 2015 to give us plenty of time for the gas market to correct itself.

Leo Mariani – RBC Capital Markets

All right. Thanks guys.

Terry Swift

Thanks Leo.

Operator

Your next question comes from the line of Dan Morrison with Global Hunter.

Dan Morrison - Global Hunter Securities

Good morning. Thanks.

Terry Swift

Hi Dan.

Dan Morrison - Global Hunter Securities

Can I get you to elaborate a little bit on that infill well [ph] at Masters Creek and kind of some of the implications there?

Terry Swift

Yes. Well, I think we did lay out in the last analyst day, we have been talking a little bit about. We did test an infill concept. Most of the wells in the Austin Chalk, in that particular area we drilled around 2000 acre of units. We are really, with the first well of testing a downs facing concept. And that is partly why we cut the well short at 2500 feet.

We were targeting a very specific zone to hedge our bets to make sure we could stay into the virgin reservoir pressure. We encountered a tremendous number of fractures, more than we really anticipated. And so, yes, this definitely sets up the opportunity as a proof of concept well. Again we have got to test this well for a while. We need to get it hooked up. It is not totally cleaned up yet. You know, a lot of mud went into the well. That is not all back yet.

But as we evaluate some of the test performance and well performance from that well, we believe that sets up a down spacing program on our acreage, moving it down spacing from the 2000 acres.

Bruce Vincent

You know, the well at Masters Creek were generally drilled on 2000 acres spacing units, which is a very, very large spacing unit. We have always felt the opportunity was there, we are finally getting back to testing that concept.

Dan Morrison - Global Hunter Securities

Great. Thanks. I had one more quick one on when we look at the Anadarko finally back up in their program, what kind of assumptions go into your guidance with respect to activity in the short play generally?

Terry Swift

Well, of course, that is one of the hardest thing to forecast is timing of somebody else.

Dan Morrison - Global Hunter Securities

Correct.

Terry Swift

And then that actually hurt us last year, and hurt us really in the beginning of this year as well. So we have actually had a number of conversations with them [ph] recently, and do believe that our heads are together in terms of the program. And so we think that the timing that we factored in those are a little more reliable than it was last year.

They are having a lot of success in the Chalk, in some of their other stuff, and they really want to get to this particular area. We think it is a very good area, particularly in this marketplace, obviously with crude oil and natural gas so far apart in terms of the value. So we have made assumptions and we hope that they will stick to that.

Dan Morrison - Global Hunter Securities

So, just to finalize…

Terry Swift

We will lay out the specific timeline of that at the Analyst Day in terms of the wells, and when we expect to be drilling them. But we do expect the rig back in the field, you know, sometime in late March. It could be early April, something like that, and then it will actually stay in the field, move from well to well.

Dan Morrison - Global Hunter Securities

Okay. Thank you very much.

Operator

Your next question comes from the line of Michael Hall with Robert W. Baird.

Michael Hall - Robert W. Baird

Hi, good morning.

Terry Swift

Hi Michael.

Michael Hall - Robert W. Baird

Just a couple of quick follow-ups I guess, one on the Gulf Coast, you kind of got toward it, but just curious what is kind of the underlying decline there. I mean, your sequential declines are relatively meaningful in both Lake Washington and (inaudible). I know you are fighting those with the barge rig and what not, but just kind of curious, what the kind of assumed decline is in the 2012 outlook?

Terry Swift

Well, yes, I mean, we do try to break that down. The pure decline without any of the remediation work we do. We are always doing sliding sleeve changes, we are always doing gas lift optimization. And so that fights that pure decline. But that has become such a normal part of our operation that we look at our declines based on the maintenance program that we have.

We have such a number of wells there in infrastructure, it gives us a lot of capability to manage that decline. You know, without doing that type of work, we are probably around 50% decline. So that is what we are mitigating on a weekly basis, on a monthly basis. We have lots and lots of opportunities to mitigate that.

Alton Heckaman

That is really a number that is worth focusing too much on because of all the behind pipe things that are type that have already had significant capital applied to them, all of the sliding sleeves, all of the other. So I don’t know that that is a meaningful number. But if you look at the individual Gulf Coast well, it will come on, it will stay flat for a little while, and then it will go into that type of decline. But that individual well may have 3, 4, 5 zones in it. You just keep re-completing some of that back up.

Terry Swift

Yes. You got to be careful if you are not trying to look at the decline rate, or the life expectancy of a particular zone. We will need to look at the well bore itself, and really a well might be a 5 year expected life, the well bore maybe 15 to 20.

Michael Hall - Robert W. Baird

Got you. Certainly still plenty of life left it seems. I guess I’m trying to also understand is at what point does it become, or if at all or ever does the asset become less meaningful as it relates to the corporate total to the extent you might?

Terry Swift

I think the way to answer that and again we point you to our analyst meeting, because we are going to be divulging a lot of our drilling operation plans, some of our three-year plans in fact. We do see enough additional opportunity in Lake Washington that it could actually have some production growth in the three-year plan. Again it goes back (inaudible) sands, which are the deeper horizons. We are not really drilling those in quantity right now. We are staying more conservative, but clearly with a little bit of help on the west side, which as we have noted today we got two new wells over there that have opened up some new areas.

We could just keep drilling and again I want to point out that when we drill one of these wells, they are really single target wells. So as you hear us say, we’re going to put a barge [ph] there, and stay there for the year. We will be drilling a lot of conservative zones. We will be drilling some puds, but we will be drilling deeper and hitting these (inaudible) sands in some perspective ways. Again, we think we can actually grow production with success there.

Bruce Vincent

It seems like many times when we drill these wells, like the two last year, and actually the two this year, as you drill them, you discover stuff and you find more around it. So it is not just the well that you targeted, but you actually played [ph] around the discovery you just made.

Terry Swift

And just to elaborate on that, the CM 419, we had 4 individual pay sands in there. So, while we open up production from one pay sand, we have three others waiting to be completed.

Michael Hall - Robert W. Baird

Got you.

Bruce Vincent

Sometimes give way to that well bore to move up it. But other times we have gone in and drilled an acceleration well for the shallower zones to produce it earlier.

Michael Hall - Robert W. Baird

Okay. I guess the other thing, and I guess on the Eagle Ford, I’m just curious, remind me, if a contract rolls over this summer, I am just curious what your thoughts are and maybe direction of the contracted costs on that?

Terry Swift

Well, we are heading into that right now. Yes, the contract expires around the first of June. We are in very serious negotiations over access to a frac spreading crew. We study the market forces very well. We know that there is horse power on the market. We think we are in a much better position to obtain even more favorable terms now than we were two years ago.

Michael Hall - Robert W. Baird

Got you. Very good. Thanks guys.

Operator

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

Marcus Talbert – Canaccord Genuity

Hi gentlemen. Good morning.

Terry Swift

Hi Marcus.

Bruce Vincent

Hi.

Marcus Talbert – Canaccord Genuity

Bob, I think you had touched on the progression you had made with the completions in Eagle Ford and being able to do 65 or so stages per month. Could you quantify or maybe provide a little bit more color in terms of how much more efficient you can get with the pad drilling in place, and then has anything really changed in terms of the intensity of these completions from what you laid out at last year’s analyst day?

Bob Banks

Yes. The first part, let me try to address that. When we go to pad drilling, and we set up the potential for zipper fracing, there are several things we can do in that environment. One, we can move that rig very efficiently to drill, batch drill surface hole, and we can move that rig back to drill you know the curve and the lateral.

The other thing we can do is become very efficient with the way we use our wire line services, as well as our fracing services. And we are going to show you an illustration of what we are doing right now on one of our leases at the analyst day. But we think there are about another 30% to 50% efficiency savings by fully utilizing your wire line crew between two wells, and fully utilizing fracing crew between two wells.

In the past, and in a conventional sense, what we do is we, you know, have the wire line crew out there. They do their thing, and then they stand down and wait for the fracing crew. And then the fracing crew stands down and the wire line crew comes back and does their thing. So what you can do by working from the pad and doing these two wells simultaneously is you can reduce all that downtime. We think that downtime efficiency is about another 30% to 50%. And that translates into money.

Bruce Vincent

It is possible to bring like the cost of these wells down really about $1 million, 0.5 million on the drilling side and about 0.5 million on the fracing side.

Terry Swift

Yes, I think I would add to that real quickly here that what we have been talking about is efficiencies that we are trying to build into the operation, particularly in the execution or design referrals. But we are also seeing a little bit softer vendor market

out there, and we’re working that as hard as we are working the efficiency side.

Marcus Talbert – Canaccord Genuity

Okay. And in terms of the intensity of the completion, has anything changed this year as you tested an increasing number of wells

from what you had forecast at last year’s analyst day?

Terry Swift

In terms of intensity, in terms of number of well?

Marcus Talbert – Canaccord Genuity

Number of stages on a per well account?

Terry Swift

No, I mean, we are experimenting some. We have cut some things out of wells. We have experimented a little bit with the size of fit [ph], things of that nature, but the spacing, we’re still kind of in that 300, 350 foot spacing on our fractures. We have done a lot more micro seismic work. So we are looking at how efficient we are with these fracs.

And we have been doing some experimenting with some higher strength profits. And we are collecting that data now to try to develop a better understanding of well performance based upon those higher strength profits.

Marcus Talbert – Canaccord Genuity

Okay, thanks very much. And maybe just one last one from me. You know, given how you sort of laid out the intention for the capital program this year being very liquids oriented, and I just – you know some of these efficiencies that you should pick up throughout the year, how should we think about the mobilization of these rigs in the Eagle Ford play itself, thinking that if you’ll need four rigs in northern McMullen county, you know, with these programs in place, is there kind of an average that we should think about where these rigs will be allocated over the course of the year?

Terry Swift

Well I think, yes, I think it is fair to say you will see those rigs allocated really out in our Artesia Wells, LaSalle County area, probably on average two rigs out there with a remainder being kind of in that North AWP area over McMullen County in the liquids rich area probably a couple of rigs over there on average. So there will be pretty equal distribution between our LaSalle County and our McMullen County liquids rich acreage.

Marcus Talbert – Canaccord Genuity

Okay, thanks very much for the color.

Operator

Your next question comes from the line of Ray Deacon with Brean Murray.

Ray Deacon - Brean Murray, Carret & Co.

Yes, I had a question about your PV 10, and maybe what kind of mechanics went into this year's number versus last year. I was just expecting a bigger increase with the oil prices up so much year-over-year?

Terry Swift

Yes, I'll take that. You know, the PV 10 they have changed how we’ve computed, we're now using a 12 month average that looks back. So, you know, some pluses and some minuses in terms of the gas prices. We all know that has been going down so those averages are going down that brings the PV 10 down in that regard.

Oil on the other hand has been going up more recently, so that tends to bring it up, but I'd like to point out two things relative to PV 10 really comparing last year to this year, again last year we also used that 12 month formula, but I think it is important to note on the oil side all the big run up we've seen in oil, particularly on this pricing differential that we get, that's not factored into that number. That just didn't come through and certainly it has to be there for a long time.

We saw this happen briefly last year, where I think with the beginning of the year we saw some really nice blow out in this difference between Brent and West Texas Intermediate types of pricing, and again we're seeing some really strong prices there. That doesn't factor into it. I also want to point out that particularly in the gas market, your gas reserves and I think this is true across the whole industry, are more sensitive in terms of the margin that you're looking at, and just if you look at the cash margin on your gas you know, your PV 10 can go down, but the reserves still be there but the margin will go down faster than the actual gross cost would, but the reverse is true.

You know, prices start moving up. That margin will open up, the PV 10 will go up faster than the actual price will go up. So two things to point out there, and also a final comment when you're looking at value, you know, we really don't put a number out there on the probable values, and last year particularly as we move to second half of the year we really were focusing on doing more liquids rich projects. We've got a lot of good data. As Bob noted we're now in a position where we are focusing ourselves on those areas that are very, very liquids rich. So right now we are really focused on cash flow and not growing the PV 10 at this point.

Alton Heckaman

The development cost, which are a big part of that PV 10 are as they are today. They don't incorporate all of these things that you expect to do regarding the cost.

Ray Deacon - Brean Murray, Carret & Co.

Right, okay. Got it. And I'm just – I thought that if you just looked at oil and liquids on the wells you drilled this quarter and the Eagle Ford. There was a pretty significant tick up versus last quarter, almost 50% in that IP rate I guess is, I guess how would you – is that an indication of better EURs that type curves could be moving up I guess.

Terry Swift

Well, again I want to emphasize that as we did all of our drilling really in 2010 and early 2011, we're doing a lot of delineating, appraising, and we now know where the best of the best is. So particularly when we say we are more liquids directed we are actually zeroing in on the more liquids areas, the better areas, and as Bob noted we're doing some of these new techniques and we think some of these design techniques you're not just trying to lower cost you're trying to improve the result that you're getting out there. So, Bob you want to add to that?

Bob Banks

Yes, no I think it is showing that we are holding in on our completion techniques. We have a great team that isn't afraid to test new ideas and challenge our assumptions on our completion designs, and I think you will see us continuing to improve our EURs. A lot is very dependent on the length of lateral as we’ve talked about before you know, we have tried to go to longer laterals. We can’t always drill to 6000 foot laterals. Lot of times we’re down around 5000 foot, but I would expect that before too long you will see the results of some of the changes we've made, some of the higher strength profits, and I think we will be prepared to talk to you about maybe we can do better from our existing models by some of these changes.

Terry Swift

And I think one final comment there is we want emphasize, we think we've got some of the best acreage in the trend as you look at our peers, you look on trend, you look at the geology. Clearly we said that you know, we got some good gas acreage. We part or put that in a position where we could come back to it later. We are now very aggressively moving towards our liquids and oil acreage, and we believe that some of the good acreages out there we are very pleased to have these opportunities in front of us.

Ray Deacon - Brean Murray, Carret & Co.

Great, well thanks, and just one last one if I can. Could you talk about that growth rate and how it will vary between oil and gas and NGLs and maybe any comment you got on NGL prices and thoughts there? Thanks.

Terry Swift

Yes, I think as we’ve kind of hinted around this morning I think throughout the year and what we will show at the Analyst Day, we’ll see the liquids go up. Coming in the first quarter you know, as we mentioned we’ve earned all of our Fasken acreage. We are finishing up some of our obligations drilling there.

So that gas production is coming in. So early in the year you will see a little bit more gas mix, as we start moving through the year and completely move our rigs away from the gas areas, you're going to see the liquids mix climb pretty consistently from second to fourth quarters and then Bruce, you may want to comment on the NGL markets. We've had a lot of discussion on that lately.

Bruce Vincent

Well, I think as everybody probably knows, I mean, the components pricing particularly for ethane has softened a little bit, but when you know downstream at the petrochemical industry they're doing a lot of expansion in ethylene cracking. Because of this projected significant increase in volume, so we think that that fall off particularly in ethane is temporary, and it's like all of the other dislocations we've seen whether it is the crude oil market or in the liquids market it is just temporary dislocations as a result of infrastructure constraints. There are being planned and will get worked out. So I think over the long run we actually feel pretty good about the liquids out in terms of pricing.

Ray Deacon - Brean Murray, Carret & Co.

Great. Thank you.

Operator

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

Noel Parks – Ladenburg Thalmann

Good morning.

Terry Swift

Good morning Noel.

Noel Parks – Ladenburg Thalmann

Just a couple of things, and sorry if you touched on this already, but I had heard from another operator in the Eagle Ford that on the cost side on the efficiency [ph] that rig day rates were looking sort of flat to down for renewals and contracts. Is that also what you've been seeing?

Terry Swift

Yes, I think that's a fair comment. I think we're seeing similar things and we have a very active procurement supply chain group. We negotiate quite hard with all of our major service providers and we see a real willingness from them to talk to us about ways of lowering cost. Yes, we are seeing a willingness there of our major providers to have meaningful discussions with us.

Noel Parks – Ladenburg Thalmann

Great. When did you start seeing that willingness come in?

Terry Swift

Well, you know, we test that every time we come up for a negotiation, and the way we have our rig contracts, and stagger those, so that we're not leveraged to any one period of time. So we're testing that every time we are coming up for a renewal and as we mentioned on the frac side we’re testing that very hard right now.

Alton Heckaman

Yes, I think the only way to really find that out when you really entering into a new contract and you could have these discussions and everybody is going to still negotiate it until you finalize up. So you know, we haven’t renewed a contract in the immediate past future that we're beginning to enter into conversations with people about going forward, and so we are seeing that impact of what you're talking about.

Noel Parks – Ladenburg Thalmann

Great, that's an encouraging. Another question I just want to move over to Lake Washington for a second. The first jelly ball [ph] was the success sort of first half of last year if I remember right, do you know in the new reserve numbers, what sort of reserves we are getting assigned to that?

Alton Heckaman

I don't have that right here in front of me now.

Bruce Vincent

The specific well reserve numbers at any of them, but that's an area that definitely has a significant future development. I think we would have to get what the reserve group says exactly. I mean, I don't remember of the top of my head. I'm sure Bob does.

Bob Banks

Yes, those are the exceptional wells. So we have keyed off of some wells on the south and southeast area that historically have produced anywhere from 0.5 million to 1 million barrels of each down in that area. That doesn't say anything about what Jelly Bowl itself was, but definitely a good area to be in and as Bruce said we really don't put individual wells out there, and even if we did, it is important to note that Jelly Bowl had some offset and additional opportunities that it set up both in the existing fault block and some other fault blocks. So even if we guess your number, it really wouldn't be an indicative of what discovery itself means to us.

Noel Parks – Ladenburg Thalmann

Got it, but it is safe to say it at least…

Terry Swift

Absolutely.

Alton Heckaman

That would be correct, yes.

Bruce Vincent

We are looking at drilling another well there later this year. So it’s absolutely.

Noel Parks – Ladenburg Thalmann

Great, and then just questions on a couple of plays that other folks are working now there and if you have any thoughts are any updates, one being customs in Marine Shale. You know, always something that gets brought up and then also if you have any more thoughts on the sub salt like in reaction to what Mac brand has been establishing. I think in the past you guys might have talked about your glory of prospects as maybe having some more potential.

Terry Swift

Let me hit that first one on the salt. You know, the sub salt is the Air Force. We’ve got HBP acreage and we're excited about that future opportunity, but this is not the time for us to be – sitting our risk dollars here. We've got a deep inventory of liquids rich opportunities, where we thought we can get on cash flows and our margins and so that's where we are focused right now. We're not giving up those opportunities in the deep (inaudible) over there.

Really probably not appropriate to talk about some of those other folks where that is their strategy. They’d developed that strategy. We wish them well and certainly is very important to that strategy. It may help us understand our areas better. It might derisk our areas. So we’ve got that on the back burner, but certainly are focused on our liquids rich activities both in the oil and Lake Washington and that area, the Austin chalk and Central Louisiana as well as all the activities of South Texas.

Speaking more specifically about these other plays, we keep a group of folks working in these plays. We do a lot of geology. We understand the trends. We've got acreage that could benefit from success in the marine shale. It is not part of our strategy right now, but again we would not let go that acreage and if we see something happen near and around us you can bet you that we will expand our position accordingly as we see any proof of that play materializing, but right now that's not part of our near-term strategy.

Noel Parks – Ladenburg Thalmann

Thanks. That's all I had.

Terry Swift

Thanks Noel.

Operator

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

Justin - RBC Capital Markets

Hi this is Justin [ph] for Adam. Couple of questions on the reserve revision, in the oils and liquids, could you elaborate on why and where that revision came from?

Terry Swift

Could you speak up a little bit, we are having a hard time hearing you?

Justin - RBC Capital Markets

Yes, can you hear me now?

Terry Swift

Yes, that is better.

Justin - RBC Capital Markets

Okay. First question is on the negative reserve revisions for oil and liquids, could you give some context on where those where, and maybe what caused them?

Alton Heckaman

I really think, we will give you a little quick view [ph] here, but again at our analyst meeting, we will be kind of diving into all of the year’s results, and what they mean going forward. As we noted, we did look hard at any of our wet gas in South Texas or things that really might not be the things that we wanted to focus on going forward.

As you are aware, you got this five-year rule, where if management isn’t going to focus on it, and you let it come off the book, and there were some vertical types of things that we adjusted downward were in favor of new opportunities that are liquids rich, and we’re really going to be putting the capital. Some of that was in South Texas in the Sun TSH, all vertical wells and things like that.

And then in the – in terms of dried gas things, we really focus hard on making sure that our plan going forward is going to be the same, or not exactly the same, but very, very close to how that books out. And you know, we’re going to be doing horizontal wells. So, we take some vertical wells out basically.

Justin - RBC Capital Markets

Okay. And on the increase in price, is that related to the change in strategy in what you guys are looking at during the next five years?

Terry Swift

It is certainly reflective of that strategy. But a lot of that has to do with where the puds are in relationship with the wells that we drilled this year. So we are able to add the puds.

Justin - RBC Capital Markets

Okay. Two questions on CapEx, do you guys provide a break down by regions, or what portion of CapEx will be…

Alton Heckaman

We will at our analyst day. We will provide quite a bit more detail, more than just a breakdown by region, but more specifics about where within the region also.

Justin - RBC Capital Markets

Okay. And then one last quick one, is there a gas price level that you guys think might trigger your assumed cash rate down?

Alton Heckaman

Well, that is an iterative process, because we have to template oil prices as well. Clearly when you look out into this year with a declining futures curve, if you look back at the last 12 months, you expect to see the gas price under the SEC requirement go down. But, you know, I don’t know what oil is going to do, and also it varies depending on what reserves we book at that time.

I think that is a flat curve. Everybody in the industry as we move through this year, particularly get a worst case gas scenario.

Justin - RBC Capital Markets

Quite good. Thanks a lot guys. I appreciate it.

Operator

Your final question comes from the line of Gordon Beck [ph] with Wells Fargo.

Gordon Beck - Wells Fargo Securities

Good morning guys.

Terry Swift

Good morning.

Alton Heckaman

Hi.

Gordon Beck - Wells Fargo Securities

My question has to do with kind of your product split in your reserves. A little bit more gas this year than historically, probably some of that has to do with what you have been doing at Fasken. I’m just curious as you kind of, you know, is it safe to assume that you direct your activity to liquids related areas that you will kind of return to a more historical production mix in your reserve profile going forward?

Alton Heckaman

Yes, I think that is a correct assumption. I think really if you know, Fasken was an unusual area and in fact if we could earn 640 spacing, it was actually the best Eagle Ford section in terms of rock leasing in South Texas, very prolific wells. And so we drilled it up. And get a lot of the puds down there. We now own that acreage. So, unless the gas market takes off, which I don’t expect it to, you are not going to see any additional drilling down there, the drilling instead will be in always liquid rich plays, you know. Another thing that has happened to us for instance in our (inaudible) well as we started getting more activity there, that has turned out more liquids rich area than we originally thought. So that is another plus that has happened.

Gordon Beck - Wells Fargo Securities

In how many locations did you book at Fasken?

Alton Heckaman

I would have to check with our reserve guys. I don’t have that at the top of my head.

Gordon Beck - Wells Fargo Securities

And then one final question from me, you mentioned 19,000 barrels a day roughly in South Texas, maybe…

Alton Heckaman

That is what I said.

Gordon Beck - Wells Fargo Securities

Yes. I’m just wondering if you could provide a split between various areas?

Terry Swift

The K that we will be filing today will have a little more granular activity there, and probably at the analyst meeting we will be able to expand that a little bit.

Gordon Beck - Wells Fargo Securities

Okay. All right. Thank you very much.

Terry Swift

The K will be filed this afternoon.

Gordon Beck - Wells Fargo Securities

All right. Thanks.

Terry Swift

Thank you. Thanks Gordon.

Operator

If there are no further questions, I would now turn the floor back over to the presenters for any closing remarks.

Terry Swift

We would like to thank everyone for joining us today. We look forward to 2012, and we will report back to you next quarter. Thank you again.

Alton Heckaman

Thanks for listening.

Operator

This concludes today’s Swift Energy Company 2011 fourth quarter earnings conference call. You may now disconnect.

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