SilverBow Resources Inc (SBOW) 2011 Q4 法說會逐字稿

Good morning. My name is Dawn and I will 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 webcast. 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 your conference, sir.

Good morning. I am 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, 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 Steve Tomberlin, Senior Vice President Resource Development and 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.

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 an 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.

Full-year production 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 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 go liquids in virtually everything we're doing, we've been doing that, we're going to continue to focus 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, park. We were able to get ourselves in a position where we parked numerous leaseholds 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 wells.

It is actually a very good thing; it is part of our reserve base. That associated gas help provide drive mechanisms and gets a lot of natural gas liquids as we produce our oil. We also have wet gas. That's generally a pretty good thing to because as we process that we get a lot of NGLs out of those reserves. And finally we do have some dry gas, but proportionate and 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've mentioned, rich liquids in fact. And our near term drilling obligations are absolutely focused on our highest quality perspective acreage as it relates to liquids. We will get into that in our presentation today. We have also prefunded our 2012 liquids-directed budget by issuing $250 million of long-term debt. In addition to this offering we maintain 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 bleak, we will stay very focused and we believe we will be very strong in terms of our liquids activity and our liquid 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 and spending from our current levels to achieve this goal by year end. We structure 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 that today and some of the results we had and some of the activity going forward. In central Louisiana, we expanded our meaningful 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 for us to explore into 2012.

In October we divested non strategic on-shore 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 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 own proppant, 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 costs.

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% over our 2010 daily exit rate. This production growth achievement has naturally been adjusted for the strategic property divestiture's that we had last year. By the end of the fourth quarter we had 6 drilling rigs active in South Texas which should ensure a steady inventory of wells for our dedicated frac crew to complete during 2012. Operating 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 non operating position. We will be focused on the Austin Chalk and the oil and liquids aspect of this project area throughout 2012. We also resumed drilling operations in Lake Washington during the fourth quarter. Drilling results combined with our recompletion and 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 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 reduce cost. This will be accomplished by utilizing multi-well drilling pads, simultaneous completion operations or what's referred to as 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.

Thank you Terry and good morning everyone. 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 liquids sales.

As to our controllable cost and metrics compared to guidance, production costs 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 and 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 call 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 stronger oil prices resulted in a 22% increase in net income up from 3Q '11. And for the full-year 2011, production was up 26% while income from continuing operations increased 82%. With the high pricing volatility our hedging activity was minimal during the quarter. As always please see our website for complete and current detailed oil and gas hedging information. As previously announced, we 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, the pressed natural gas prices 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 have 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 overview of our operations.

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 2012. Bob Banks will then provide greater detail on the operational highlights of 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 the fall, we have reviewed our planned activity and, where possible, opted to replace projects with higher percentages 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 to 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. 3 wells were drilled in McMullen County, 3 wells drilled in Webb County, and 2 wells were drilled in La Salle County. 3 operated wells were also drilled to the Almonds formation in McMullen County and the 2 non-operated wells were drilled to the Eagle Ford Shale in McMullen County. In Swift Energy's Central Louisiana and East Texas core area, 1 operated well was drilled to the Austin Chalk formation in the Masters Creek Field in Vernon Parish. We now have 6 operated drilling rigs in our South Texas core area drilling Eagle Ford and Olmos wells We also have 1 operated barge rig drilling in our Southeast Louisiana area.

I will review our performance in each of our core operating areas for this quarter and then let Bob provide detail of the highlights of the most recent activity. To begin with, in the Southeast Louisiana core area, which includes Lake Washington and Bay de Chene Fields, production during the quarter averaged approximately 7,505 net barrels of oil equivalent per day in this area. That is down 12% when compared to the third quarter 2011 average net production from the same area. Lake Washington averaged approximately 6,969 net barrels of oil equivalent per day, a decrease 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 Olmos Fields, and AWP, Artesia Wells, and Fasken Eagle Ford fields, fourth 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 production in this same area, and a 91% increase over fourth quarter 2010. This sequential increase is primarily from 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 the wells brought online in 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 a great deal more time discussing our Olmos and Eagle Ford programs. The central Louisiana/East Texas core area which includes our Brookeland, Masters Creek, Burr Ferry and South Bearhead Creek, contributed 2,339 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 or early in the second quarter.

I will now turn the call over to Bob Banks to review operational highlights for the fourth quarter.

Thank you Bruce. Before discussing our operational achievements, I would 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're 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 volumes. We see a similar breakdown when reviewing our PUD reserves by hydrocarbon phase. 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 volumes. With approximately 80% of our 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 recompleted 10 wells and performed 6 production optimization projects during the quarter. The recompletions 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 from Gulf Coast markets, we moved a 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 with 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 dome 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 a GASRS 20-1 well in that Burr Ferry area in Vernon Parish. This well encountered large quantities of hydrocarbons during drilling operations 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 hydrocarbon. We do expect to side track 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 million cubic feet of natural gas per day, with flowing tubing pressure of 2,565 PSI on a 4864-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 note that we only drilled approximately 2500 feet of lateral, or 50% of what we had planned. However, we encountered 21 fracture sets during drilling and pressures had responded well during this initial testing. This well is an infill location which is testing drainage and reservoir assumptions and could have field-wide implications for us. We are extremely encouraged by these preliminary results.

At our South Bearhead Creek field in Beauregard Parish we continue to evaluate the Wilcox and expect to test this area with a horizontal well later in 2012 or early 2013. Moving on to South Texas, we drilled 9 Eagle Ford horizontal wells and 3 Olmos horizontal wells that were completed during the fourth quarter. So far in the first quarter, 6 Eagle Ford horizontal wells and 1 Olmos horizontal well have 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 in our liquids-rich acreage, we are experimenting with restricted choke settings to measure the longer-term effect of these settings on well performance. Our activity and production in this area continue to ramp up as evidenced by production growth. We are now averaging 65 frac stages per month and believe this will further improve as we move towards pad development and employed zipper fracs. This is important to note as we expect to realize per- well cost savings of at least $500,000 per well through these efficiencies.

Additionally, we are now sourcing certain proppants directly from a manufacturer and managing the delivery of this proppant ourselves which is reducing our per-well consumable and transportation costs. As a result of improving frac fleet efficiency we added a sixth drilling rig to this area during the fourth quarter to ensure that we have sufficient inventory of wells to keep up with our frac spread and crew. 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 us, we expect to significantly reduce cost and improve performance across all of our South Texas operations. We are moving towards more multi-well pad drilling, allowing us to become more efficient by batch drilling our surface holes, shortening the time for rig moves and carrying out simultaneous completion operations. Along with the other cost reduction and supply-chain initiatives, this will allow us to reduce costs and improve performance 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 and acreage in the future. I believe the value proposition we offer investors coupled with our current production mix and oil and liquids rich project inventory offer an exceptional opportunity in today's environment. As Bruce and I just discussed we began 2012 with strong operational momentum. When 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. I will turn it back to Terry to do a recap.

Thanks, Bob. Before we open the line for questions, I'll 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. 12 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 have began a drilling program in our Lake Washington field in Southeast Louisiana which will add premium-priced oil production. The 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'd like to begin the question-and-answer portion of our presentation.

(Operator Instructions)

Neal Dingmann, SunTrust.

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

If you look at the activity there we had in the fourth quarter, really just the very beginning of this year, a number of those wells were drilled down in the Fasken area. We now have -- I guess there's one well drilling right now. With the completion of that, we've now earned all that acreage down there. So the entire shift of the capital is going to go to liquids-rich plays. So you've got a higher-than-normal level of gas production today than you will have towards the end of the year, certainly that mix. The growth is going to come in the liquids production as we move through the year and you will see gas actually drop down a little bit through the year.

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

I will make a couple of comments and turn it over to Bob for some color. One of the things that is important for people to recognize with Swift is we've standardized our reporting on our IP rates and we are also really holding wells choked back in the beginning. So we are not opening them up to get nice IP rates; we're not picking the best rate during a period of time. We've tried to standardize that really for our purposes so we can benchmark one well to the next.

It's important for people to really look ultimately at decline curves and EURs to see how they hold up against original IP rates. The IP rates can be all across the board and in our view they, in and of themselves, are not important. It is ultimately more about your decline curve and your EUR. So that's a general comment. But we've had models and we have shown some of that to you in terms of the different areas that we are drilling in and were going to give you a lot more color on that in a couple of weeks at our analyst day on March 15. Bob, do you have some more comments you want to make?

Yes, I would just reiterate. Our models that we have put out there for everyone, our EUR models and our type-curve of models just to try to summarize. North AWP oil, we see about 395 MBOE and 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 in 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 three EUR models and do all of our drilling in those areas.

Got it. And last one, if I could guys, you mentioned in the press release about having one rig on Lake Washington the rest of the year. Just your thoughts on Lake Washington and the rest of that southeast Bay de Chene, et cetera, in the guidance, what your thoughts are on production for the year, just a general level. Bruce, maybe for you or Bob, just how you're seeing that play out for the remainder of the year.

One of the things generally about Lake Washington, if left to its own devices it's going to decline. We have seen that where we've 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 have to drill wells to make that happen. I think the intent is to have enough activity in the field to resume it to more of a flat level of production that can mitigate that decline. And that's the overall objective of the program. We started out with 4 to 6 wells and now we think are going to do5 to 10. You've seen from the information that we put out today the first two are really looking pretty good. So, we're actually pretty excited about that program and really hope to do better than laid out in our guidance but we just need to see how the year goes.

Great comments. Thanks Bruce.

Thanks, Neil.

Leo Mariani, RBC.

Hello guys. Could you address the infrastructure situation in each of your areas in South Texas? Particularly interested in what your form transport is in some of those areas and your plans to acquire more form transport?

Obviously, down at Fasken Ranch, we've firmed up all that transport capacity. In fact, we even have a dual option down there. So we are well situated. As we move up into AWP, we announced that Southcross deal. We have also recently done another deal up in our liquids rich area with DCP. We believe we have taken care of all of our needs for transportation and processing in that area. And then out in the La Salle 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's not interrupting us at all at this point, so that's progressing very nicely. That's probably our last area to get tightened up. But all of these contracts are confidential. We do have confidentiality agreements around them. We have made significant progress the past few months in getting all of our transportation and processing needs taken care of.

That's great. Jumping over to the Austin Chalk, you talked about [Ujadie] Park, Anadarko, putting a rig over there in the second quarter. How many wells do you guys have scheduled in the Austin Chalk this year?

We have four to six in there. We believe that our partner is going to start up here maybe even by the end of this quarter.

We had hoped that the activity would've started really in January and it has just been pushed back a little further. They had some other needs where they have taken the rig to. That's one of the reasons it's built into the production guidance is just a shift in that production to a little bit later in the year.

All right. You guys talked about some well cost savings you anticipate here in South Texas. Can you give us what your current well costs are in the Eagle Ford and the Olmos, and clarify as to whether or not you have assumed that $500,000 savings you were talking about in those numbers yet, or no?

What were going to do at our analyst day is 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're going to lay all that out for you in great detail and reconcile for you what our well costs are coming in at. So, if you wouldn't mind, I'd like to hold that detail analysis because there's lots to talk about on what we've done probably since last analyst day in moving those costs down.

But we have put out that our well costs are running $8.5 million to $9.5 million and obviously the things we're working on will hopefully actually bring that down, so at the lower end of the range or maybe even below that.

Okay. And in terms of your Olmos Wells, it looks like you had a much higher oil and NGL cut on some of your wells this quarter. Maybe you could talk about what you think is driving that.

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

The other thing that is important for people to understand about the Olmos is the Olmos is present across our acreage and everywhere it is present it is liquid rich. It may have different amounts of free condensate with the production but it's 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 we've 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.

Okay, thanks guys.

Thanks, Leo.

Dan Morrison, Global Hunter.

Good morning, thanks. Could I get you to elaborate a little bit on that infill well at Masters Creek and some of the implications there?

Yes, as I think we did lay out at our last analyst day, we've been talking a little bit about, we did test an infill concept. Most of the wells in the Austin Chalk and that particular area were drilled on 2,000 acre units. We're really, with this first well, testing a down-spacing concept, and that's partly why we cut the wells short at 2,500 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 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 to test this well for a while; we need to get it hooked up. It is not totally cleaned up yet; a lot of mud went into the well, that's not all back yet. But as we evaluated some of the test performance and well performance from that well, we believe that sets up a down-spacing program on our acreage, moving to down spacing from the 2,000 acres.

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

Great, thanks. One more quick one. When we look at the Anadarko firing back up in their program, what kind of assumptions go into your guidance with respect to activity in the Chalk clay generally?

That's one of the hardest things to forecast is timing of somebody else.

Correct.

And that actually hurt us last year, and hurt us really in the beginning of this year as well. So we actually have had a number of conversations with them, in fact, had a lengthy meeting with them recently, and do believe that our heads are together in terms of the program and we think that the timing that we factored in there is a little more reliable than it was last year. They are having a lot of success in the Chalk and some of their other stuff that. 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 their value. So we have made assumptions, and we hope they will stick to that.

Just to finalize the --

(multiple speakers) 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 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.

Perfect. Thank you very much.

Michael Hall, Robert W. Baird.

Hello, good morning. Just a couple of quick follow-ups, I guess. Number one, on the Gulf Coast, you got towards it, but just curious, what is the underlying decline there? Your sequential declines are relatively meaningful in both Lake Washington and Bay de Chene. I know you're fighting those with the barge rig and whatnot, but just curious what the assumed decline is in the 2012 outlook.

Yes, we do try to break that down. The pure decline without any of the remediation work we do, we're always doing sliding sleeve changes, we're always doing gas lift optimization, and so that fights that pure decline. But that's 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 and infrastructure, it gives us a lot of capability to manage that decline. Without doing that type of work, we're probably around 50% declined. That's what we are mitigating on a weekly basis, a monthly basis. We have a lots and lots of opportunity there to mitigate that.

That's not really a number that is worth focusing too much on because of all the behind-pipe things that are there, that have already had significant capital applied to them, all the sliding sleeves, all the other -- so I don't know that that's a meaningful number. But if you look at an individual Gulf Coast well that, it will come on, it will stay flat for a little while, and then it will go in to that type of decline. But that individual well may have three, four, five zones in it that then you just keep recompleting and coming back up.

So, you've got to be careful that you're not trying to look at the decline rate or the life expectancy of a particular zone. You really need to look at the well bore itself. And while a zone might be a five-year expected life, the well bore may be 15 to 20.

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

I think the way to answer that, and again we point you to our analyst meeting because we're 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 a three-year plan. Again, it goes back into getting into the Li and CC sands which are the deeper horizons -- we're 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've noted today we've 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 rarely single target wells. As you hear us say we are going to put a barge rig out there and stay there for the year, we will be drilling a lot of conservative zones and we will be drilling some PUD, but we will be drilling deeper and hitting these Li and CC sands in some prospective ways. Again, we think we can actually grow production with some success there.

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 find more around it. So it's not just the well that you targeted, but it you actually create additional opportunities around the discovery you just made.

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

Got you. (multiple speakers)

Sometimes, you'll wait for that well bore to move up it, but other times we've gone in and drilled an acceleration well in the shallower zones to produce it earlier.

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

We are heavy into that right now. The contract expires around 1 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 horsepower on the market. We think we're in a much better position to obtain even more favorable terms now than we were two years ago.

Got you. Very good. Thanks guys.

Thanks, Michael.

Marcus Talbert, Canaccord.

Hello gentlemen, good morning. Bob, I think you had touched on the progression you've 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?

Yes, the first part, let me try to address that. When we go to pad drilling and we set up the potential for zipper fracking, there's 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 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 fracking services. And we're 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 your fracking crew between two wells.

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

It's possible to bring the cost of these wells down really about $1 million, $0.5 million on the drilling side and about $0.5 million on the fracking side.

Yes, I think I would add to that real quickly here that what we've been talking about is efficiencies that we are trying to build into the operation particularly in the execution or design [details], but we are also seeing a little bit softer vendor market out there and we are working that as hard as we are working the efficiency side.

Okay. And in terms of the intensity of the completions, has anything changed this year as you tested an increasing number of wells from what you had put forth at last year's analyst day?

In terms of -- intensity in terms of number of wells?

Number of stages on a per well -- (multiple speakers)

No. We are experimenting some and we have cut some things out of wells. We have experimented a little bit with the size of proppant, things of that nature. But the spacing, we are still in that 300, 350 foot spacing on our fractures. We've done a lot more microseismic work, so we are looking at how efficient we are with these fracs. And we have been doing some experimenting with some higher strength proppants. And we are collecting that data now to try to develop a better understanding of well performance based upon those higher strength proppants.

Okay. Thanks very much. Maybe just one last one for me. Given how you laid out the intention for the capital program this year been very liquids oriented, and I guess 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 don't need four rigs in northern McMullen County with these four rigs in place. Is there an average that we should think about where these rigs will be allocated over the course of the year?

I think it's fair to say you will see those rigs allocated really out in our Artesia Wells, La Salle County area. Probably on average two rigs out there, with the remainder being in that north AWP area over in 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 La Salle County and our McMullen County liquids rich acreage.

Okay. Thanks very much for the color.

Ray Deacon, Brean Murray

Yes, I had a question about your PV10 and maybe what kind of mechanics went into this year's number versus last year. I was expecting a bigger increase with oil prices up so much year-over-year.

Yes, I will take that. The PV10, that changed how we compute it. We are now using a 12-month average that looks back, so some pluses and some minuses. In terms of the gas prices we all know that's been going down, so those averages are going down. That brings the PV10 down in that regard. Oil on the other hand, has been going up more recently here so that tends to bring it up.

But I'd like to point out two things relative to PV10, really comparing last year to this year. Again last year we also used that 12-month formula, but I think it's 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 doesn't come through and certainly it would have to be there for a long time. We saw this happen briefly last year, I think with the beginning of the year, we saw some really nice blowout in this difference between Brent and West Texas Intermediate types of pricing. And again we are 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 as you look at a cash margin on your gas, your PV10 can go down, but the reserves will still be there. But the margin would go down faster than the actual gross price would. But the reverse is true. When those prices start moving up, that margin will open up, the PV10 will go up faster than the actual price will go up. Two things to point out there.

Also, final comment, when you're looking at value, we really don't put a number out there on the probable values. And last year particularly as we moved the 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 are 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 PV10 at this point in time. (multiple speakers)

Development costs which are big part of that PV10 are as they are today. They don't incorporate all these things we expect to do to drive the cost down.

Right. Okay, got it. If you just looked at oil and liquids on the wells you drilled this quarter in the Eagle Ford, there was a pretty significant tick up versus last quarter, almost 50% in that IP rate I guess. Is that an indication of better EURs, that type curves could be moving up I guess?

I want to emphasize that as we did all of our drilling really in 2010 and early 2011, we were doing a lot of delineating, appraising and we now know where the best of the best is. 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 are 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 results that you are getting out there. Bob, do you want to add to that?

I think it is showing that we are honing 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 the lateral as we've talked about before. We have tried to go to longer laterals. We can't always drill the 6,000 foot laterals. A lot of times we are down around 5,000 feet.

But I expect that before too long, we will see the results of some of the changes we have made, some of the higher strength proppants. 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.

And I think one final comment there is, we want to 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 have said that we've got some good gas acreage. We have parked or put that in a position where we can 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 acreage that's out there -- we're very pleased to have these opportunities in front of us.

Great. Well, thanks. Last one, if I can. Could you talk about that growth rate and how it will vary between oil, gas, and NGLs? Any comments you got on NGL prices and thoughts there? Thanks.

Yes, I think as we have hinted around this morning, I think throughout the year, and what we will show at the analyst day, we will see the liquids go up. Coming in the first quarter, as we mentioned, we [learned] all of our Fasken acreage, we're finishing up some of our obligation 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 gassy areas, you're going to see the liquids mix climb pretty consistently from second to fourth quarters. Bruce, you may want to comment on the NGL markets. We have had a lot of discussion on that lately.

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

Great. Thank you.

Noel Parks, Ladenburg Thalmann

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

Yes, I think that's a fair comment. We are 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 for our major providers to have meaningful discussions with us.

Great. About when did you start seeing that willingness come in?

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

I think the only way you really find that is when you are really entering into a new contract. You can have these discussions and everybody's going to still be negotiating until you finalizing something. So we haven't renewed a contract in the immediate past feature but we are beginning to enter into conversations with people about going forward. So we are seeing that impact of what you're talking about.

Great. That's encouraging. Another question, I wanted to move over to Lake Washington for a second. The first Jelly Bowl well you had, the success, the first half of last year if I remember right, do you know from the reserve numbers, what sort of reserves wound up getting assigned to that?

I don't have that right here in front of me, no.

We don't publish specific well reserve numbers in any event, but that's an area that definitely has significant future development. I think we would have to get with a reserve group to see exactly -- I don't remember off the top of my head. I'm sure Bob doesn't.

Those are exceptional wells. We have keyed off of some wells on that south and southeast area that historically have produced anywhere from a 0.5 million to 1 million barrels apiece 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's important to note that Jelly Bowl had some offset and additional opportunities that had set up both in the existing fault block and some other fault blocks. So even if we gave you a number it really wouldn't be indicative of what the discovery itself means to us.

Got it. But it's safe to say it at least met, if not exceeded your predrill expectations?

Absolutely.

That would be correct.

We are looking at drilling another well there later this year, so absolutely.

Great. And then just questions on a couple of plays that other folks are working out there, and if you have any thoughts or any update. One being, Tuscaloosa Marine Shale, always something that gets brought up. And then also, if you have any more thoughts on the subsalt, in reaction to what [Matt Brand's] been establishing. I think in the past you guys might have talked about your Gloria prospect as maybe having similar potential?

Let me hit that first one on the subsalt. The subsalt is there for us. We have HBP acreage and we are excited about that future opportunity but this is not the time for us to be putting dollars there. We've got a deep inventory of liquids rich opportunities where we know we can get our cash flows and our margins and so that's where we are focused right now. We are not giving up those opportunities in the deep Myocene over there. Really probably not appropriate to talk about some of those other folks, where that is their strategy. They have developed that strategy -- we wish them well and certainly as they employ that strategy it may help us to understand our areas better; it may derisk our areas.

So we've got that on the back burner but certainly are focused on our liquids rich activity both in the oil and Lake Washington in that area, the Austin Chalk and central Louisiana as well as all the activity in South Texas. Speaking more specifically about these other plays, we keep a group of folks working these plays. We do a lot of geology; we understand the trends; we've got acreage of that could benefit from success in the Marine Shale. It's not part of our strategy right now, but again, we are not letting go of that acreage. If we see something happen near and around this you can bet 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.

Thanks, that's all I had.

Thanks, Noel.

Adam Light, RBC Capital Markets.

Hello this is Justin Schleifer on for Adam. First question is on the negative reserve revisions for oil and liquids. Could you give some context on where those were and maybe what caused them?

I really think we could give you a little 3,000-foot view here, but again at our analyst meeting we will be 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 we wanted to focus on going forward. As you are aware, you have this five-year rule where if management isn't going to focus on it and drill it, then you let it come off the book. And there were some vertical types of things that we adjusted downward. We are in favor of new opportunities that are liquids rich and where we're really going to be putting the capital. Some of that was in South Texas in that Sun TSH, old vertical wells and things like that. And then, in terms of dry 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 we are going to be doing horizontal wells, so we take some of the vertical wells out basically.

Okay. And on the increase in PUDs, is that related, just a change in strategy and what you are looking to drill the next five years?

It is certainly reflective of that strategy but a lot of that has to do with where the PUDs are in relationship to the wells that we drilled this year, so we were able to add the PUDs.

Okay. Thanks. Two questions on CapEx. Do you guys provide a breakdown by region, or what portion of CapEx would be -- (multiple speakers)

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

And then one last quick one, is there a gas price level that you think might trigger a fueling test write down?

That's an iterative process because you have to tell me what oil price is, as well. Clearly when you look out into this year with the declining futures curve and look back at your last 12 months, you expect to see the gas price under the SEC requirement go down, but I don't know what oil is going to do a lot of it also varies dependant on what reserves we book at the time. I think that is a threat for everybody in the industry as we move through this year, particularly if you get a worst-case gas scenario.

All right, great. Thanks a lot guys. I appreciate it.

Gordon [Dubat], Wells Fargo.

Good morning guys. My question has to do with your product split and your reserves. A little bit more gassy this year than historically, probably some of that has to do with what you been doing at Fasken. I'm just curious -- is it safe to assume as you direct your activity to liquid-rated areas that you will return to a more historical production mix in your reserve profile going forward?

Yes, I think that's a correct assumption. I think really -- Fasken was an unusual area in the fact that we could earn 640-acre spacing; it was actually the best Eagle Ford section in terms of rock we've seen in South Texas. Very prolific wells. So we drilled it up, so you get a lot of the PUDs down there, now our net acres. Unless the gas market takes off, which I don't expect it to, we're not going to see any additional drilling down there. The drilling instead will be in all these liquid-rich plays. Another thing that's happened to us, for instance in Artesia Wells, as we've started getting more activity there that's turned out to be even a more liquids rich area than we originally thought. So that's another plus that's happened.

How may locations it did you book at Fasken?

I would have to check with our reserve guys, I don't have that off the top of my head.

And then one final question from me. You mentioned 19,000 barrels a day roughly in South Texas. Maybe -- (multiple speakers)

That's correct.

Yes, I'm just wondering if you could provide a split between various areas.

(multiple speakers) -- we will have a little more granular activity, that and probably at the analyst meeting we will be able to expand that a little bit.

Okay. Thank you very much.

[Our K] will be filed this afternoon.

All right, thanks.

Thanks Gordon.

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

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.

Thanks for listening.

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