SilverBow Resources, Inc.
Q2 2008 Earnings Call Transcript

Published: 7 Aug 2008

[Operator:]

Good morning ladies and gentlemen, my name is Sharon and I will be your conference operator today. At this time I would like to welcome everyone to the Swift Energy Company Second Quarter 2008 Earnings conference Call. (Operator instructions) It is now my pleasure to turn the floor over to your host Paul Vincent, Manager of Investor Relations. Sir you may begin you conference.

[Paul Vincent:]

Good morning I am Paul Vincent, Manager of Investor Relations. I’d like to welcome everyone to Swift Energy’s Second Quarter 2008 Earnings Conference Call. On today’s call Terry Swift, Chairman and CEO will provide an overview. Alton Heckaman, EVP and CFO will review the financial results for the first quarter and then Bruce Vincent; President will provide an operational update. Terry Swift will then summarize before we open it up to questions. Also present on today’s call are Bob Banks, EVP and COO and Jim Mitchell, SVP-Commercial Transactions and Land. Before I turn it over to Terry, let me remind everyone that our presentation will contain forward-looking statements based on our current assumptions, estimates and projections about us, our industry in the current environment in which we operate. These statements involve risks and uncertainties detailed in our SEC reports and our actual results could differ materially. We expect our presentation to take approximately 25 to 30 minutes and allow additional time for questions.

[Terry Swift:]

Thanks Paul. Thank you again for joining this morning’s conference call. The second quarter of 2008 was the best financial quarter in Swift Energy history. The company received a 62% higher aggregate price for its oil and natural gas during the second quarter of 2008 when compared to the second quarter of 2007. This is resulted in Swift Energy’s income from continuing operations increasing 173% year-over-year and cash flow before working capital changes from continuing operations rising 71% year-over-year. We don’t take these higher oil and natural gas process for granted, as recent volatility in the commodity and equity market has demonstrated process can change very quickly. We believe the companies how operate with a longer-term approach and outlook will be best positioned to be the successful company’s in the energy business and deliver consistent long-term results. With this in mind, our strategic operating plans are to grow production on average in excess of 7% per year and to grow reserves on average in excess of 5% per year. Swift Energy’s 2008 second quarter production increased 4% year-over-year. Production from the first quarter of 2008 to the second quarter of 2008 increased 5% inline with our earlier guidance. These increases resulted from improved performance in our South Texas area and our Bay De Chene area, Horseshoe Bayou and South Bearhead Creek fields while we certainly did improved production in several areas we experienced some disappointing delays in our Lake Washington field operations. More specifically, we’ve experienced certain operational delays, which have impacted our production for the remainder of this year. As a result of these operating challenges, which we’ll explain further in this conference call we are lowering our full-year production guidance to a range of 10.8 to 11.2 million barrels of oil equivalent. Although this is a short-term disappointment, we are confident that the work plans and programs that we have in place will allow us to meet or exceed our strategic production growth targets for 2009. At Lake Washington, we’ve continued to experience natural declines and higher water cut from our over more mature wells, which places additional volumes loads on our low pressure BOLT system gathering lines and three space production systems. To further complicate this situation as we placed our newer and deeper wells on production we observed higher operating pressures and higher gas to oil ratios. These newer high pressure, high gas content wells, crowd out the over wells effectively competing for the existing space in our BOLT gathering lines. Additionally, some of the deeper wells producing in the Newport area are not supported by strong water drives. Without down tip water injection to stabilize an increased reservoir pressure these wells produce lesser amounts of oil and greater amounts of gas. In response the company deemed it appropriate to reduce the choke size of several wells in the Newport area to manage theses pressure in gas volume issues. While the Newport pressure maintenance water injection project was commenced during the quarter, the required water injection volumes however had not been achieved yet. We have currently demonstrated Newport water injection levels about to 2,000 barrels of water per day in the first pressure maintenance flow. The company has operating plans underway to increase this amount to over 8,000 barrels of water per day in additional injection wells. We are also installing additional gathering lines, which are designed to provide operating flexibility in the gathering system. These lines will be used to segregate newer wells from older wells and to reduce the back pressure of the system. The first additional line is being installed between Newport and the West Side facility, which is expected to be operational in the third quarter. Additional lines will be installed later this year. We anticipate that pressure maintenance activities planned for 2008, together with the West Side infrastructure enhancements will reduce the production constraints experienced in the first half of 2008 and reduced the competition for space on the current gathering system. Swift Energy has spent the past several years building an extensive regional operating portfolio in South Louisiana and South Texas and continues to have an exceptional inventory to work with. I’ll briefly mention some of these more significant projects and the events that occurred in the second quarter. In Lake Washington the Westside facility has been fully commissioned and oil is now being process by this facility. We currently have six rigs contracted in this area South Louisiana, four operating in Lake Washington and two in Bay De Chene. Also in Lake Washington and Bay De Chene we completed our 3D seismic depth migration of the merged data sets with an updated sale model. We also completed our seismic four pressure projection project. This is allowed us to increase our confidence as we begin to drill some of the deeper and higher impact wells in this area in South Louisiana. For example, we are currently drilling our Shasta prospect and preparing to drill our Keeton and West Newport prospects. A fully inventory of deeper and higher impact test will be underway this year and carryover in 2009 drilling activities. In South Louisiana we continue to drill deeper and tackful well targets identified through our 3D seismic collaborates. This includes developing and planning a sub-salt exploratory test most likely early next year. In South Texas we have began a seismic acquisitions strategy in conjunction with acquiring deep mineral rights over a large part of our AWP field. We have a plan to have three to four rigs activity drilling in South Texas for the remainder of this year. We believe the strategy we’ve employed successfully in South Louisiana of using seismic imaging to identify opportunities deeper and exciting production can be successfully added in South Texas as well. As a result of increased activity levels and higher estimated full-year cash flows we are raising our 2008 full-year capital spending budget to the range of $525 million to $575 million from an earlier range of $475 million to $525 million. This increase is necessary to bring four projects, which will allow us to resume production and reserve growth in Lake Washington field and accelerate production growth in the rest of our portfolio. It isn’t always easy to take the steps that will maximize future growth as well as shareholder value, but as demonstrated by the steps we are currently taking, there should be no doubt for the level of commitment by Swift Energy Company and how its commitment extends to its assets and shareholders. With that, I’ll ask Alton to present the second quarter financial results.

[Alton Heckaman:]

Thank you Terry and good morning everyone. As Terry said Swift Energy had a great second quarter, the best financial quarter in the company’s long history. To reiterate some of the financial highlights for the quarter, revenues were a record $263 million up 68% over 2Q ’07, net income was $83 million up 173% and diluted EPS came in a $2.66 and an increase of a 166%, while cash flow before working capital changes increased 71% per diluted share the $5.88. Production increase as Terry said 4% to $2.7 million barrels of oil equivalent. Cured oil prices remain strong and with approximately two-thirds of Swift’s current production coming from crude oil and natural liquids, the current oil-pricing environment obviously continued to have a very favorable effect on Swift’s financial results. Swift’s domestic average realized price in 2Q ’08 increased over 60% to just under $98 per barrels of oil equivalent, as crude oil prices almost doubled from the prior-year level to average over $125 per barrel allowing Swift to increases its quarterly oil and gas revenues 68% over 2Q ’07. We continue to focus on our controllable per unit cost and metrics, as for the second quarter of 2008 G&A came in at $3.82 per barrels, which was inline with our guidance. DD&A per unit came in at $21.26, which was above our guidance. Production costs came in $10.61 per barrel also above our guidance as discussed in today’s earnings press release. Production taxes increased on a BOE basis primarily due to higher prices, but actually decreased as the percentage of oil and gas revenues due to the changes in Swift’s production mix and location, and finally interest expense decreased to $3.06 per barrel, was slightly above guidance primarily due to the previously announce delayed closing of our New Zealand sale. We therefore realized income from continuing operations for the quarter of $83 million which is $2.72 basic and $2.66 diluted, well above the first call mean estimate. Cash flow before working capital changes for 2Q ’08 came in at a $184 million or $5.88 per diluted share, while EBITDA was a $197 million for the quarter or $6.28 per diluted share. CapEx for the second quarter totaled $143 million. With this free cash flow and proceeds from the sale of the New Zealand assets we reduced borrowings under our bank line by almost $100 million during the quarter. Although we still had borrowings of a $124 million under our line at quarter end, we still have plenty of liquidity and resources available for any additional value adding strategic opportunities that may come along. With respect to Swift’s hedging activity and as discussed in detail in our press release, during the last 90-days we’ve purchased additional natural gas and crude oil floors for the third and fourth quarters of 2008 is very attractive strike prices. Please see our website for complete and current detailed hedging information and finally as always we’ve included additional financial and operational information in our press release including guidance for the third quarter and full-year 2008, and with that I’ll turn it over to Bruce Vincent, for an overview of our operations.

[Bruce Vincent:]

Thanks Alton and good morning everyone. Today, I will discuss second quarter 2008 activity, including our production volumes, recent drilling results, activity in our cooperating areas and our plans for the rest of 2008. Beginning with production, Swift Energy’s production from continuing operations during the second quarter of 2008 totaled 2.69 million barrels of oil equivalent or 16.16 billion cubic feet equivalent, an increase of 4% over the 2.59 million barrels of oil equivalent produced in the same quarter of 2007. As guided during our last quarterly conference call, sequential production increased 5% when comparing the second quarter of 2008 to production in the first quarter of 2008. Now for our drilling results, Swift Energy completed 25 of 27 wells in the second quarter of 2008, all of which were developed wells for a success rate of 93%. One of these wells was a non-operated well, which Swift had a small interest in. I will briefly review our activity in each of our core operating areas beginning with our Lake Washington area, which includes the Lake Washington field and Bay De Chene Field. Production during the second quarter of 2008 averaged approximately 16,152 net barrels of oil equivalent per day or 97 million cubic feet equivalent per day in this area, essentially flat when compared to our first quarter 2008 average net production from the same area. Lake Washington averaged approximately 13,937 net barrels of oil equivalent per day or 84 million cubic feet equivalent per day, a 3% decrease when compared to the first quarter 2008 volumes. While Bay De Chene sequential production grew 24% to 2,215 net barrels of oil equivalent per day. At the Lake Washington field in Plaquemines Parish in Louisiana activity levels have been high and we have drilled some very good wells. Unfortunately due to the back pressure constrains in the system (inaudible) and the delayed timing of the pressure maintenance project at Newport, we have not seeing much change in our field wide production. The Westside facility has been fully commissioned and the oil is being processed by this facility. We will continue to work diligently to optimize production in the field by successfully implementing the pressure maintenance program in multiple sands in the Newport area, adding gathering lines in the system to help offset the higher pressures and targeting additional drilling activities in areas that won’t be as impacted by the current higher pressure region. Swift Energy drilled eight successful development wells in the second quarter, these wells ranged in-depth from 5,672 feet to 17,005 feet and encountered true vertical net pay ranging from 61 to 399 feet. As an example of the constraints caused by back pressures during the quarter, seven of these wells were brought on and tested during June and a combined total weight of approximately 3000 barrels of oil equivalent per day. However, our daily production over this period only increased by 1,800 barrels of oil equivalent per day. We believe this discrepancy was caused by a reduction in production from the older wells in the field due to an increase in the gathering system pressure caused by the new wells. We have been working to reduce this bottlenecking in our gather system and in early third quarter we’ve installed an additional gathering line to the Newport area to reduce back pressure on the older wells. Ongoing activity in Lake Washington will largely focused on intermediate horizons in particularly after clay sand and West Side exploration activity that we believe we can average and develop production that will not be impacted as much by the system back pressure we are currently experiencing. In Bay De Chene, the previously announced increase in export capacity has position the company to increase production in this area during the remainder of 2008. During the second quarter the BDC VUB number 152 was drilled and completed and is currently producing 350 barrels of oil per day. The BDC VUB 150 was completed and is producing 1,200 barrels of oil per day. The BDC 142 was completed and is producing 1,000 barrels of oil per day and the BDC UC 7 was re-completed during the third quarter and is currently being placed on production. We currently has 6 barge rigs contracted in this area, four our operating Lake Washington with two in Bay De Chene. We expect to drill 10 to 15 additional wells in Lake Washington in this year and 3 to 5 more wells Bay De Chene. In our South Texas area, which includes our Cotulla area and AWP field, second quarter 2008 production averaged 7454 barrels of oil per day. In the second quarter we successfully completed nine or 10 development wells in the AWP area and five of six development wells in the Cotulla area. The 2008 drilled program in AWP includes another 10 to 12 Olmos wells and includes plans to drill a well to the Edwards formation in the AWP area during the second half of the year. We have one rig in the Cotulla area and will drill 10 to 15 more wells for the year net area, which well include the addition of another rig in the fourth quarter. In the Lafayette North area which we’ve previously referred to as Toledo Bend, this area contributed 2,825 barrels of oil equivalent per day of production in the second quarter of 2008. A production enhancement program is underway in our Brooklyn field in the counties of Jasper and Newton. In Texas, the Masters Creek field, in Bearhead the Rapides and Louisiana, and South Bearhead Creek field in Beauregard Parish. This program should allow us to grow our base production from existing wells. This program and production from the new wells brought online in South Bearhead Creek resulted in a 13% increase in production in this area when compared to first quarter 2008 levels and a 27% production increase when compared to second quarter 2007 production in this area. In the Lafayette South area which is comprised of Horseshoe Bayou, Bayou Sally, Jeanerette, Cote Blanche Island and Bayou Bijou, production averaged approximately 2,879 barrels of oil equivalent per day or 17.3 million cubic feet equivalent per day, during the second quarter an increase of 40% when compared to the first quarter production in this area. In Cote Blanche Island, an exploration well drilled during the first quarter of 2008 was completed and is currently producing over 300 barrels of oil equivalent per day with flowing tubing pressure of 1600 psi. There are two additional zones above the current producing zone that will be completed and produced in this well. In Bayou Sale we are currently drilling one well, which is expected to be finished drilling during the third quarter. Swift Energy currently has one rig operating in this region. Lastly in a particular importance, Swift Energy Company is also in a process of executing a strategic 3-D based South Louisiana exploration program during the second half of 2008. The Company is currently drilling as operator, one high potential 18,000 foot prospect, which we call Shasta in the Lake Washington, Bay De Chene area and is also participating as non-operator in one 16,000 foot prospect that is currently being drilled closer to our High Island area. Swift’s working interest participation in these prospects is 50% and 25% respectively. The Company also intends to drill two additional high potential prospects in the 3 and 4 quarters of 2008. One will be a 12,000 to 15,000 foot test in the Westside area of Lake Washington, while the other will be a 15,000 foot test Chichon prospect in the Bay De Chene area. All of these prospects have potential reserve size in excess of 50 bcf equivalent. Swift maintains a 100% working interest in both of these prospects. Further, the Company is now carrying out the work necessary to design and plan a very high impact 18,000 to 20,000 foot sub-salt test in the Lake Washington area for drilling sometime during the first half of 2009. Thanks for your attention and I’m going to turn it back to Terry to recap.

[Terry Swift:]

Thanks Bruce. Before we open the line for questions, I want to summarize Swift Energy’s second quarter results and 2008 planned activity. During the second half we remain focused on our reserves and production growth. We are also working to protect our margins by managing our drilling and operating cost. To review some of the highlights from this morning, first Swift Energy Company have strong financial results in the second quarter of 2008. Our revenues increased 68% to $262.7 million. Income from continuing operations was $83.2 million or $2.66 per diluted share and cash flow before working capital changes was a $184.4 million or $5.88 per diluted share. In the second quarter of 2008 we had production of 2.69 million barrels of oil equivalent for quarter, a 4% increase over the second quarter of 2007. Due to operating challenges in Lake Washington, we are lowering our full-year guidance to a range of 10.8million to 11.2 million barrels of oil equivalent. We are continuing to drill deeper and higher impact prospects. Swift Energy has developed a large inventory of lower risk development opportunities as well. In South Texas we were building a large seismic library adding additional acreage in expanding our drilling efforts in the almost and Edwards formations. Our higher impact exploration and drilling efforts are well underway in South Louisiana. Additionally, production capacity constraints being removed from Lake Washington and Bay De Chene should helps set the stage for further production growth in both those fields. Finally, our conservative management, financial and hedging philosophies had positioned us well to continue our dual approach of drilling 10 acquisitions. At this time, we’d like to begin the question-and-answer portion of our presentation.

[Operator:]

(Operator instructions) Our first question is coming from Neal Dingmann, from Dahlman Rose. Please go ahead.

[Neal Dingmann:]

Good morning guys.

[Terry Swift:]

Hi Neal how are you doing?

[Neal Dingmann:]

I had few questions, first on the delayed Lake Washington with the higher decline in water size. Is that now something you can remedy or what would be sort of the nearer-term or longer-term steps, it sounds like you’ve talking about a few of those. I was just wondering if we look after the end of this year are there other things you can do to revenue that or put other systems on, or what exactly could you do there?

[Bruce Vincent:]

Well first of all, every field is got natural decline. In Lake Washington we’ve got a different basket of decline types. We do have wells that are very strong water drive and although they have declines they’re actually keep their production up more stable into a water breakthrough, and then the issue becomes kind of you handle the water. In a lot of cases we’ve actually go wells shut in, that have high water cuts and we do have plans to add those wells back into the system as we get these line problems fixed out there. In the West Side for example we did add considerable space in terms of our water separation capability out there, so that’s something we’ve been finding well ahead for, we do have some pressure decline or depletion decline type reservoirs out there in Newport turning out to be reservoir that doesn’t have strong water drive and in that respect until we get the pressure maintenance project up to water injection level that will be closer to the 8,000 barrels a day. We have found higher declines out there than we would have anticipated. With the higher injection rates and greater stabilizing of reservoir pressure we expect those declines to actually reverse out as we pressure back to the reservoir. We want to increase from that reservoir and then we do have some smaller projects in the field where we’ve got a lot of development opportunities of the small wells and we’ve been stand away from adding these 50 or 100 barrel day type wells because of these construction constraints. There just now been a reason to drill those right now, but as you sort out all of the infrastructure problems we can get back on that; we’ve got a hole available for that, Bruce mentioned a little earlier that we also have the K-sands and other sands the Li-sands and the second half of the year we are focused on those, those are opt to be a water drop reservoirs and come in without the kind of declines that will be typical of non-water drawing reservoirs. Terry Swift And also without the pressure, but you could add it when you have the gas production along with the oil that we are experiencing in the pressure replacement reservoirs.

[Neal Dingmann:]

So is it fair, so a couple of those Bruce that you had mentioned, the deeper place area are looking as good it’s not better than what we had anticipating?

[Bruce Vincent:]

I would say that we are really excited about some of the deeper place they, both this what we’ve referred to is our West Newport prospect in Lake Washington and that’s amount of sub-salt play, but we’ve done extensive mapping on the West Side, our seismic model is continually refined obviously as we continue to drill our wells. We’ve been spending a tremendous amount of time quite frankly on the salt model, so that we can design a sub-salt test. We are pretty excited about prospect activity down there, but we wanted to get it right, it’s a deep well a little bit expensive and we wanted to be sure that we targeted the best way possible, but we will definitely planned to go out well and probably in the first half or discontinue to do some technical work to be sure that we drilled in the right spot in the best way possible with the best design.

[Neal Dingmann:]

Okay and then last question was on the Lake Washington, they have the same prospects you mentioned. I know it’s sort of early to sort of speculate, but how soon would you know how good those are looking in order to really get after those?

[Bruce Vincent:]

Well, see there’s a series and two of our expiration prospects that we mentioned are currently drilling. One is actually between Lake Washington and Bay de Chen and is not located in either field and we would hope to finish that drilling activity in the third quarter, but then based upon what you’re finding you have to go through a testing process and we’re pretty excited about that and then there’s another one that’s over in Ohio and is actually onshore, that should also finish here in the third quarter. We actually have interest in expiration wells drilling in the Bay de Chen right now. It's not quite of the size that we referred to when we talked about the 50 Bcf plus but we expect the Bijon prospect to spread possibly like third quarter but it should get finished this year. We’ve got a pretty good seismic model there, so I think based upon when you get that well drilled you have a pretty reasonable idea of what you have there, the same thing with Lake Washington and we would expect to spread that West Lake Washington probably later quarter. I’ll say we’ll try to finish it up this year.

[Neal Dingmann:]

Perfect, alright thanks guys.

[Operator:]

Thank you. Our next question is coming from Nicholas Pope with J.P. Morgan; please go ahead.

[Nicholas Pope:]

Good morning guys.

[Bruce Vincent:]

Hey, good morning.

[Nicholas Pope:]

I was hoping something you’d given out here on the production numbers. For Lake Washington and Bay de Chene, can you go over those numbers again? And then also I guess, so you have the total like South Louisiana as well?

[Bruce Vincent:]

Yes, actually the 10-Q will detail all of that regional information. We expect to get that filed by the end today. That breaks out all of these queries; net oil and gas sales volumes for the ’08 quarter and the ’07 comparable period.

[Nicholas Pope:]

The number I was looking at though, you said Lake Washington did you say $84 million a day?

[Bruce Vincent:]

$84 million at cubic feet equivalent per day is what it averaged during the second quarter.

[Nicholas Pope:]

Okay, thanks and also I guess you’ve seen some of the growth trajectory, it seems like it’s a little smaller than expected with some of these constrains. Do you have any concerns about reserves in Lake Washington? I guess like some of the approved and developed reserves, is there any concern there?

[Bruce Vincent:]

No, we don’t have any concerns there at all, it’s really just a timing issue. We got an expectation that we could get more water in the ground quicker and that hadn’t happened and it’s probably going to take longer to get the water in the ground and pressure up these particular reservoirs, because at this point in time we certainly do not have any concerns that I’m aware of with regard to pub reserves in Lake Washington.

[Bruce Vincent:]

Yes, I want to add to that that well, the complication that you get from having so many different wells out there and the fact that so many different wells have so many different types of flows; we’ve got high water-cut wells, we’ve got high gas-cut wells, we’ve got high sulfur wells, we’ve got high pressure wells, low pressure wells, but those complications actually create a diversity out there. We have literally, I forget how many, but 80 different major sands out there and the reserves are spread over a lot of different slat block and lot of different reservoirs. I don’t think any one well out there is really very materially in that regard.

[Nicholas Pope:]

Okay. That was all I had. Thanks guys.

[Operator:]

Our next question is coming from Gary Nuschler with Jefferies & Company; please go ahead.

[Gary Nuschler:]

Thanks good morning. Speaking of reserves; earlier this year you projected that you can grow reserves 5% to 9% for the year. We’re at the half way mark, is that still the target?

[Bruce Vincent:]

We have a strategic objective to grow reserves on average year-over-year 5% to 10%. This particular year we’ve been guiding in the 5% to 9% range roughly. I think given the current outlook as we see everything, we’d be of course lower into that range, but we currently are putting plans in place, we’re currently looking at some activities in South Texas that we can expand our drilling and do some things there. I’m optimistic that we can still be in that range.

[Gary Nuschler:]

Okay, so you could still hit at least the low end of the range even with out success in the previous Boe/d prospects.

[Bruce Vincent:]

Yes, all of our plans are showing that we’ll still be in the range and obviously we need to do a good job there and this is a great time to be doing it. So, the 5% to 9% range is still a good range, though we’re presently at the low end of that.

[Gary Nuschler:]

Okay and then my next question, last quarter you had mentioned you were targeting or looking at the Edwards trend over in South Texas. You even said you were going to drill a well in the back half of this year. Can you provide some details there? Are you going to do it on your own? Which well are you going to do and in what height?

[Bruce Vincent:]

We’ve got a couple of opportunities in South Texas. We positioned our self almost from the Real Grande in the Edwards and almost trend all the way over to the Olmos field in McMullen County and we’ve got Edwards opportunity across that whole reef trend where our acreage currently exists as well as our seismic databases that we built. I’d say our most likely candidate is going to be in the AWP area, but we’ve got some opportunities for some Edwards test over in the Cotulla area as well and we got some areas that we’re releasing on, so definitely you’ll see one this year, but you may see this come out with a couple of others that will go across the year and early 2009.

[Gary Nuschler:]

Okay, that’s all I had. Thank you.

[Bruce Vincent:]

Thanks Gary.

[Operator:]

Thank you, our next question is coming from Leo Mariani with RBC; please go ahead.

[Leo Mariani:]

Hi, good morning guys?

[Bruce Vincent:]

Hi, Leo.

[Leo Mariani:]

A couple of questions on some of your expiration prospects here. You talked about the sub-salt prospects that you’re going to drill in the first half of ’09, can you give us any indication of what a well like that could cost you guys and what type of target you guys maybe targeting from the reserve side?

[Bruce Vincent:]

I’ll take a shot at it. Again we have to speak in ranges and even though we speak in ranges we have put some risk and some caveats on it, but we’re definitely looking at going through the sub-salt in Lake Washington. We’ve got two possibilities; one is we can go through in very, very thick section of salt and get very much under the down and its important to note we’ve got more than one sub-salt opportunity in Lake Washington that we’re looking at. Lake Washington does not have to our knowledge one big prospect under it, but several very nice sized prospects under it. If we go through the main core of the salt, that would be a very, very expensive well. It would probably be in the $25 million to $35 million range, that’s a very rough estimate, giving drilling costs that we’re seeing here today, that’s probably the best guess we can give you. In terms of size it would be well over a 100 bcf equivalent; probably an oil prospect and if I had to put a range on it, it would probably be between a 100 bcf and 200 bcf type target.

[Leo Mariani:]

Okay, I guess two more questions on the Chester prospect that you guys are hoping to drill pretty soon here as well?

[Bruce Vincent:]

Yes I’ll take a stab at Chester. Chester is actually currently drilling, its one of the one things we referred to that’s between Bay de Chene and Lake Washington and we have a 50% interest in it, we already operator of that well and we obviously don’t want to put some sizes on it because these numbers are generally under risk and people throw a lot of reserve numbers around but that prospect is at least a 50 plus Bcf un-risk gross prospect and we would hope to have that finished drilling during the third quarter.

[Leo Mariani:]

Okay and what do you estimate the cost is on that well?

[Bruce Vincent:]

Yes, I think that’s nearly about a $15 million well. That can go on, but I can tell you in advance to be about 18.

[Leo Mariani:]

Okay, just a question on your CapEx increase as well for the year; do you have any indication of sort of how much of that maybe cost related and how much of that is going to be for increased activity in your core?

[Bruce Vincent:]

Well, I guess to begin with, we’ve always talked about how we like to spend our cash flow and we started out with a conservative spending number, but we don’t know what prices are going to do during the year. As prices have obviously picked up this year and our outlook for cash flow is up we can easily see ourselves cash flowing up to $575 million and so we want to increase our cap spending accordingly. We’ve got this wonderful depth of inventory to do that. I think most of that cost really is what I would term as additional activity as opposed to just cost increases out there.

[Leo Mariani:]

Okay, thanks a lot guys.

[Bruce Vincent:]

Thank you.

[Operator:]

Thank you. Our next question is from Curtis Trimble with Natixis; please go ahead.

[Curtis Trimble:]

Sure thank you, good morning. Drilling down a little bit on the cost side if you will, can you kind of compose both in magnitude and source the over heads with regard to guidance for the second quarter and then the actual 1061 on the operating costs that you guys reported?

[Alton Heckaman:]

This is Alton. I think in the Q we drilled down an easier term into those costs a little bit, but the primary delta on this quarter versus the guidance we have provided relates to some work-over activity. So, we had a minimal amount in our guidance relative to some work-over initiatives versus the actual cost that came in and I think both the first quarter and second quarter, that’s the primary change that we have versus the guidance and obviously that can be a good thing from a standpoint of unlocking some future revenues that weren’t otherwise there. So, the network of our activity is probably broken down into two primary areas. One is the positive result things we’re proactively doing to try to stimulate additional production. We also have a couple of saltwater disposal wells that we needed to go in and work on to improve the saltwater disposal capability, so some of both in that work-over number.

[Curtis Trimble:]

Okay, very good and going forward as you look at the guidance, obviously you don’t plan on the work-overs continuing to trickle over, but given the increase in water injection etc, how much confidence do you have in the numbers here? As we look out it sounds like you stepping up activity, you got to be gathering system going in; do you feel very good about that 9 to 9.50 range?

[Bruce Vincent:]

Yes, I think we feel pretty good about. As you know that includes obviously our planned work-overs, what it don’t include is the stuff that happens. You can always budget an estimated amount, but when stuff happens you have to deal with it and you go to fix it. I think we have had a number of our salt water disposable wells. We worked over in the first and second quarter and so we really don’t think that that’s a repetitive thing. Some of the salt water disposable injection wells; it’s like Lake Washington because there are some newly drilled wells too. So, I think we feel pretty good about that number as best as you can.

[Curtis Trimble:]

Very good and regarding expectations for the new gathering systems going in around Lake Washington and the Newport area, do you think you’ll be able to recover that full amount of that 1,800 barrels a day of deferred production; if so what do you think the timing would be for that, is that going to just come on ratably over the balance of the year, will it be pushed out to 2009?

[Bruce Vincent:]

Yes, I think the example that Bruce gave where we had the seven wells tested and didn’t see all of that test oil get to the export, that’s a good example of the type of picked up capacity that is behind the system due to the constraints that we have out there. I do think that that kind of thin our capacity. When you get constraints removed you haven’t lost it, it comes back both year end or early 2009. We really should see the Lake Washington significantly regaining its growth cycle. We are not just focused on that 1,800 barrels in fact that kind of just becomes a part of the much greater allocation. We want to get Lake Washington back were it’s on a complete growth cycle and to do that we’ve got to get these bald plans turned into high pressure and low pressure systems out there. I mean the short answer is, yes we expect it back; the long answer is we expect a lot more than that.

[Bruce Vincent:]

And while the gathering line of additions are going to help, it’s really the re-pressurization of these Newport reservoirs that will make the substantial differences.

[Curtis Trimble:]

Very good. Can you give us an idea of what volumes the Westside facility is processing versus what volumes that legacy facility is processing?

[Alton Heckaman:]

Westside I think it’s about 4,600 barrels of oil a day, currently is what we’ve taken through that and we’re rated to take 10,000 barrels a day through that facility.

[Terry Swift:]

I guess gross production in Lake Washington in terms of oil production is about 14,000 so, the remainder of that would be in the other three platforms.

[Alton Heckaman:]

We can get the break outs..

[Terry Swift:]

And all those number that Bob referred to you is on a gross basis not the net basis.

[Curtis Trimble:]

Sure, very good I appreciate your time.

[Operator:]

Thank you. Our next question is from Tom Nowak from Merrill Lynch. Please go ahead.

[Tom Nowak:]

Sorry, if I missed this, do you guys expect to keep a 100% of the sub salt prospects?

[Terry Swift:]

That depends, there are really as I mentioned two different types of prospects out there is one, where going through the full core of the salt those were sum with the higher cost, higher risk, higher target, but we also have Lake Washington in kind of has a salt ledge on the French where they are still expensive wells. We could be looking at $20 – $25 million of the top side, and if be looking it up to 200 Bcf types targets. That kind of a prospect we might sell down a small amount but more passive type of player, but the deeper targets we may bring a significant industry partner type. What we are trying to do is make sure that we fully get all of our processing of the seismic our salt models completed such that we look at the four inventories I believe there is at least three difference sub-salt targets in Lake Washington that we could be looking at.

[Tom Nowak:]

Okay great and did you mentioned an expectation for you not exit rate for Lake Washington once you are posted the gathering issues or even a rate that we could expect in the first quarter of first half ’09.

[Robert Banks:]

I don’t think we’ve gotten that far out. I thin w are assuming on the kind of downside case through the rest of this year with Lake Washington not to be able to help hold flat at 14,000 gross barrels a day. It's so dependent upon the timing particularly of the re-pressurization of the Newport reservoirs and that not going to just happen one day. We had seen some response from the injection so that we know we have the right idea. It will take some time and as its pressurizing itself you will se it pick up in the oil production and that will be gradual tell you get more and more other.

[Alton Heckaman:]

Yeah, I would gauge this way so that you understand how our minds are thinking, our strategic production growth rate year-over-year average is in the 7% to 12% range and for Lake Washington itself we would expect to be at the high end of that range that going to be how we drive our planning it is not to exceed that because it is one of our horses, its where we’ve got a lot of opportunities. So, you hear us to be conservative about the near-term and how these things will get worked out. Our drivers are going to be for Lake Washington to return to some significant gross relative to our strategic plan and that’s both going to come from the pressure maintenance project and the facility infrastructure we are putting in place, but also some of this new drilling that we are planning on.

[Tom Nowak:]

Okay great. Thank you.

[Operator:]

Thank you, our final question is coming from Andrew Coleman [ph] from Union Bank of Switzerland [ph]. Please go ahead.

[Andrew Coleman:]

Hi, good morning guys. Can you talk about how do places like Lake Washington sort of operate those, gave some comparisons with the today’s data that’s where put there, what’s the net revenue interest at Lake Washington approximately? Terry Swift Well, it’s obviously mix as we have a number of different leases, it’s probably in that 78, 79 our net revenue interest. We’ve got some that are in the low 80’s and then some at around 75, so probably 78 to 79. It really does, can vary a little bit depended upon the allocation and stuff.

[Andrew Coleman:]

Okay, so the implication is in that production here, and for quarter it was probably flat end though all three months?

[Terry Swift:]

I’d have to look but probably about right.

[Andrew Coleman:]

Okay and then…

[Terry Swift:]

Variable during that period of time, but…

[Andrew Coleman:]

And as I think about the water injection pieces here, correct me if I am wrong, but the injection that’s happening at Lake Washington that’s just straight down-dip water injection of these radio fault test and I assume that depends, you off-shoring out good KV, o, you are kipping good support here in Lake Washington and then at Newport. You should start good KV, but I guess there is an issue that maybe because of the flood is younger you haven’t kind of overcome the or you haven’t injected enough water to match the same amount of oil that you’ve taken from that portion of deals, is that correct?

[Terry Swift:]

I’m sorry did you say KV, are your talking about vertical permeability.

[Andrew Coleman:]

Yes, you’re injecting the water straight into the bottom of the zone and just time will float that oil to the top, correct?

[Terry Swift:]

Yes, we’re currently injecting down-dip and we’ve got dual injector where it’s going to two different zones and the composite injection into those two zones is about 2000 barrels of water a day. One zone taking with the dominant amount, but this is a, we’ve got actually about five major reservoirs over there in the Newport area and a couple of not so major ones, so we really need pressure maintenance in at least two or three of them and we need to get up to about 10,000 barrels of water a day over the longer-term in the short-term, we are pushing fast to get 8000 barrels a day. That’s going to take more injection points.

[Andrew Coleman:]

Okay so to goal is to reiterate, as you are up-taking 4,600 barrels a day you are injecting to offset that about 2000 barrels of water you’re currently get that to about twice the par volume for twice the off-take rates your trying to catch up and closing that floor volume down?

[Bruce Vincent:]

Yes, when you talk about floor volume, you know exactly what we’re talking about, yeah, we’ve got to ketchup and re-pressurize.

[Andrew Coleman:]

Are you seeing any issues where if the water compatibility is at all formation of water, you are using seawater right now, is that kind of impeding into the injection process or the equivalent you just all have enough wells?

[Terry Swift:]

We don’t really produce very much water at all from these Newport zones we don’t see any compatibility problem with the water that’s been injected. We are just not given up in the ground. We just have the single injection point in each of the two sands. We certainly need more injection points so we get more water in the ground, not really a compatibility problem at this point.

[Bruce Vincent:]

We’ve drill to water source well it’s very close to Newport, so they are both getting water produced there, its clean water all the compatibility studies look good. So, we don’t think we have any water compatibility issues.

[Andrew Coleman:]

You think then it’s a faulting issues out in Newport or?

[Terry Swift:]

No, it is just the reversal of the PI, a well can take only so much water and were just one injector is way down deep that it needs to, the sands are as thick as up-dip where you got some really big juicy oil sands and so we just need more injectors?

[Andrew Coleman:]

Okay, fair enough and I guess may be later you can put a whole plot in one of your presentation. Moving on here, I’m so sorry to take so much time on Lake Washington but looking at again the AWP and Cotulla looks like production has been declining since the January. Is that accurate, I know Texas State data is not all the most timely but I guess how you see that changing going through the year, because it had been going pretty nicely in the back half of last year and what’s the timing of an Edwards test?

[Terry Swift:]

It’s obviously the tight gas sands, they all have higher declines upfront when you’re drilling new wells, and there were a quite a lot of new wells being drilled, right as we took the Escondido purchased last year and turned it into our Katula operation. That activity did slowdown a little bit, but we are reinstituting our drilling activity. So, we should new wells coming in with new flush production, but that is the nature once you've got a big active kind of drilling going on tight gas ends, you get a big flush and it declines below number but then you stabilize much more comfortable, AWPs being doing that for 10-15 years.

[Bruce Vincent:]

Also in the Cotulla area, some of those wells when we acquired them had no tubing in them, they were produced through 4.5 inch so, we need to run some tubing out there, some of the wells are loading out there. We have a plan to remedy that now.

[Andrew Coleman:]

Last two questions then as our South Bearhead Creek, the newer ones Jasper County. How deep you hold the rights out there?

[Terry Swift:]

I think that varies between leases, I know a number of leases we have all depths, but there are some leases that go down into the base of the Wilcox. The one of thing that we’ve been able to do there actually is drill a little deeper on some of the wells and actually discovered some additional stringers in the Wilcox sand, that weren’t know to be productive before. We actually had to reform a unit, which we successfully did. Just fairly recently they allowed us to go back into those particular wells and in place the deeper zones on production. So, we’re pretty excited about that area, obviously you can look at the numbers we’ve been able to grow production from that area, at this point in time based on my knowledge, I don’t think there is anything in the leasehold, that’s restricting us in terms of our development in that area.

[Andrew Coleman:]

And then I guess, you feel comfortable looking at I guess all the assets more are from an aggregate oil versus gas that’s something has the perspective that yield replace reserves are offering both offered both oil and gas respectively or do you think it will be another little more gas heavy year , kind of last year?

[Terry Swift:]

I think as you relate to just this year, you could see it be a little bit more gas heavy. We’ve got some excellent results coming out of Bay De Chene and there is fair amount of gas where as I noted South Texas we’re turning with a bit harder for the rest of the year, so that’s gas and Lake Washington we were actually trying to deal with the gas and we’re trying to pitch it back in places. It's going to be a more gas a year, but the forward plans we’re clearly there to get more oil out of Lake Washington as well as South Bearhead Creek field some of these other areas.

[Andrew Coleman:]

Okay and I’m sorry, if I squeezed one last one and then I’ll get out of way that’s, sorry I just got longer then –

[Terry Swift:]

I don't think that there is anybody behind you. Andrew, so take your time.

[Andrew Coleman:]

You guy have mentioned in the first quarter some, you guys are picking around the idea of drilling more on the facility side, is on the Westside side could be expanded. I guess bear in mind that with guidance coming down, CapEx still going up, I guess want to fell what the results are here through the year, but are you still considering of putting, I guess drilling down, how that perform facilities plan?

[Terry Swift:]

Absolutely, no change there, I think you’re referring to is on our Westside facilities we put platform space out there to be able to double that and we’ve already institute actions to double that capacity up there. Is up that the question?

[Andrew Coleman:]

Yes.

[Terry Swift:]

And we’re stand with that.

[Andrew Coleman:]

Okay, well good luck getting that water o the ground that’s going to make everybody happy.

[Terry Swift:]

Thanks Andrew

[Operator:]

Thank you. At this time I’d like to turn the floor back over to your host for any further comments.

[Paul Vincent:]

We just want to thank everybody for listening and we appreciate your support and certainly available for further conversation as needed. Thank you.

[Operator:]

Thank you. This concludes today’s Swift Energy Company conference call. You may now disconnect and have a good day.