SilverBow Resources Inc (SBOW) 2008 Q2 法說會逐字稿

Good morning, Ladies and Gentlemen. I will be your conference Operator today. At this time, I'd like to welcome everyone to the Swift Energy Company second quarter 2008 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers remarks, there will be a question and answer period. (OPERATOR INSTRUCTIONS) Thank you.

It is now my pleasure to turn the floor over to your host, Paul Vincent, Manager of Investor Relations. Sir, you may begin your conference.

Good morning. I'm Paul Vincent, Manager of Investor Relations. I'd like to welcome everyone to Swift Energy second quarter 2008 earnings conference call. In 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 the 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 and 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 have allowed additional time for questions.

Thanks, Paul. Thank you again for joining this morning's conference call. The second quarter of 2008 were the best financial quarter in Swift Energy's 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 has 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 prices for granted, as recent volatility in the commodity and equity markets have demonstrated prices can change very quickly. We believe that companies who operate with a longer term approach and outlook will be best positioned to be the successful companies 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 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 2008 to the second quarter 2008 increased 5%, in line with our earlier guidance. These increases resulted from improved performance in our South Texas area at our Bay de Chene area, Horseshoe Bayou and Southbury Creek fields. While we certainly did improve production in several areas we experienced some disappointing delays in our Lake Washington field operations. The 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 will 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're 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 continued to experience natural declines and higher water coke from our older, more mature wells which places additional volume loads on our low pressure bulk system gathering lines and three phase production systems. To further complicate this situation as we place our newer and deeper wells on production, we observe higher operating pressures and higher gas to oil ratios. These newer, high pressure, high gas content wells crowd out the older wells effectively competing for the existing space at our bulk gathering lines. Additionally some of the deeper wells producing in the Newport area are not supported by a strong water drive. Without downdip water injection to stabilize and 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 these pressure and 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 of up to 2000 barrels of water per day in the first pressure maintenance well. The Company has operating plans under way to increase this amount to over 8,000 barrels of water per day in additional injection wells. We're 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 reduce 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 events that occurred in the second quarter.

In Lake Washington the West Side facility has been fully commissioned and oil is now being processed by this facility. We currently have six rigs contracted in this area of of 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 salt model. We also completed our seismic core pressure prediction project. This has allowed us to increase our confidence as we begin to drill some of the deeper and higher impact wells in this area of South Louisiana. For example, we are currently drilling our Shasta prospect and preparing to drill our Teton and West Newport prospects. A full inventory of deeper and higher impact tests will be underway this year and carry over into 2009 drilling activities.

At South Louisiana we continue to drill deeper impactful well targets identified through our 3D seismic library. This includes developing and planning a subsalt exploratory test most likely early next year. In South Texas, we have begun a seismic acquisition 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 actively 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 existing 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 forward projects which will allow us to resume production and reserve growth in our 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're currently taking, there should be no doubt for the level of committment by Swift Energy Company and how its committment extends to its assets and shareholders. With that I'll ask Alton to present the second quarter financial results.

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. 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 at $2.66, an increase of 166% while cash flow before working capital changes increased 71% per diluted share to $5.88. Production increased as Terry said 4% to 2.7 million barrels of oil equivalent. Crude oil prices remain strong and with approximately two-thirds of Swifts current production coming from crude oil and natural liquids, the current oil pricing environment obviously continued to have a very favorable effect on Swifts financial results. Swifts domestic average realized price in 2Q '08 increased over 60% to just under $98 per barrel of oil equivalent as crude oil prices almost doubled from the prior year level to average over $125 per barrel, allowing Swift to increase 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 barrel which was in line with our guidance. DD&A per unit came in at $21.26 which was above our guidance. Production costs came in at $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 a percentage of oil and gas revenues due to the changes in Swifts production mix and location. And finally, interest expense decreased to $3.06 per barrel was slightly above guidance primarily due to the previously announced 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 $184 million or $5.88 per diluted share while EBITDA was $197 million for the quarter or $6.28 per diluted share. CapEx for the second quarter totaled $143 million and 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 $124 million under our line at quarter end, we still have plenty of liquidity and resources available for any additional all 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 at 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.

Thanks, Alton and good morning everyone. Today, I will discuss second quarter 2008 activity, including our production volumes, recent drilling results, activity in our core operating 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 development 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 approximately13,937 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 2215 net barrels of oil equivalent per day. At the Lake Washington field in Plaquemines Parish, Louisiana, activity levels have been high and we've drilled very good wells. Unfortunately due to the back pressure constraints in the system that Terry referred to and the delayed timing of the pressure maintenance project at Newport, we have not seen much change in our field wide production. The West Side facility has been fully commissioned and 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 higher pressures and targeting additional drilling activities in areas that won't be as impacted by the current higher pressure reading.

Swift Energy drilled eight successful development wells in the second quarter. These wells ranged in depths from 5672 feet to 17,005 feet and encountered true vertical net pay ranging from 61 feet to 399 feet. As an example of the constraints caused by back pressures during the quarter, several of these wells were brought on and tested during June at a combined daily rate of approximately 3,000 barrels of oil equivalent per day; however our daily production over this period only increased by 1800 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 these bottlenecks in our gathering system and in early third quarter we installed an additional gathering line to the Newport area to reduce back pressure on the older wells.

Ongoing activity in Lake Washington will largely focus on intermediate horizons and particular F through K sand and West Side exploration activity where we believe we can add reserves and develop production that will not be impacted as much by the system back pressure we're currently experiencing. In Bay de Chene, the previously announced increase in export capacity has positioned 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 equivalent per day. The BDC VUB 150 was completed and is producing 1200 barrels of oil equivalent per day. The BDC Number 142 was completed and is producing 1,000 barrels of oil equivalent per day and the BDC UC Number 7 was recompleted during the third quarter and is currently being placed on production.

We currently have six barge rigs contracted in this area , four are operated in Lake Washington with two in Bay de Chene. We expect to drill 10 to 15 additional wells in Lake Washington this year and three to five more wells at Bay de Chene. In our South Texas area, which includes our Katula area and AWP field, second quarter 2008 production averaged 7454 barrels of oil equivalent per day. In the second quarter we successfully completed nine of 10 development wells in the AWP area and five of six development wells in the Katula area. The 2008 drilling program at AWP includes another 10 to 12 (inaudible) 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 Katula area and will drill 10 to 15 more wells for the year in that area which will include the addition of another rig in the fourth quarter.

In the Lafayette North area which we previously referred to as Toledo Bend, this area contributed 2825 barrels of oil equivalent per day of production in the second quarter of 2008. A production enhancement program is under way in our Brooklyn field in the counties of Jasper and Newton in Texas and Masters Creek Field in Vernon and Repeats Parish in 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 at South Bearhead Creek resulted in a 13% increase in production in this area when compared to the first quarter of 2008 levels and a 27% production increase when compared to the second quarter 2007 production in this area.

In Lafayette South area, which is comprised of Horseshoe Bayou, Bayou Sally, Jeneret, Cote Blanche Island, and Bayou Pinchella production averaged approximately 2879 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 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 Sally 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, and of particular importance, Swift Energy Company is also in the process of executing a strategic 3D 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's currently being drilled closer to our High Allen area. Swifts working interest participation in these prospects is 50% and 25% respectively. The Company also intends to drill two additional high potential prospects in the third and fourth quarters of 2008. One will be a 12,000 to 15,000 foot test in the West Side area of Lake Washington, while the other will be a 15,000 foot test in our Teton prospect in the Bay de Chene area. All of these prospects have potential reserve sizes 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 some time during the first half of 2009. Thanks for your attention and I'm going to turn it back to Terry for a

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 remained focused on our reserves and production growth. We're 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 had strong financial results in the second quarter 2008. Our revenues increased 68% to 2 million -- 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 $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 the 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 10.8 to 11.2 million barrels of oil equivalent. We're 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 are building a large seismic library adding additional acreage and expanding our drilling efforts in the Almost and Edwards formations. Our higher impact exploration and drilling efforts are well under way in South Louisiana. Additionally, production capacity constraints being removed from Lake Washington and Bay de Chene should help set the stage for further production growth in both those fields. Finally, our conservative management, financial and hedging philosophies have positioned us well to continue our dual approach of growing through drilling and acquisitions. At this time we would like to begin the question and answer portion of our presentation.

Thank you. (OPERATOR INSTRUCTIONS) Our first question is coming from Neal Dingmann from Dahlman Rose. Please go ahead.

Good morning guys.

How you doing?

Good. A few questions. First, on the Lake Washington with the higher decline in water type is that now something you can remedy or what will sort of be the near term or longer term steps? It sounds like you talked about a few of those, just wondering if we look after the end of this year are there other things you can can do to remedy that or the input other systems on or what exactly could you do there?

Well, first of all, every field has got natural declines and 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 actually keep their production up more stable until water breaks through and then the issue becomes how do you handle the water and in a lot of places we've actually got 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. And 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 planning well ahead for.

We do have some pressure decline or depletion decline type reservoirs out there. Newport is turning out to be a reservoir that doesn't have strong water drive and in that respect, until we get the pressure maintenance project up to a water injection level that would be closer to the 8,000 barrels a day, we have had 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 have to get increases 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. We've been staying away from adding these 50 or 100 barrel a day type wells because of these construction constraints. There's just not 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 have a whole bailiwick of that. Bruce mentioned a little earlier that we also have the Case Sands and the other sands in the second half of the year, we're focused on those. Those should be a water drive reservoir and come in without the kinds of declines that will be typical of non-water drive reservoirs.

And also without the pressure that you get added when you have the gas production along with the oil that we're experiencing and the pressure depletion reservoirs.

Sure. So is it fair to say a couple of those, Bruce, that you'd mentioned the deeper plays there are looking as good if not better than you all would anticipate?

I would tell you that we're really excited about some of the deeper plays there, both what we referred to as our West Newport prospect in Lake Washington and that's not a subsalt play but we've done extensive mapping on the West Side. Our seismic model is continually refined obviously as we continue to drill wells. We've been spending a tremendous amount of time quite frankly on the salt model so that we can design a subsalt test. We're pretty excited about the prospectivity down there but we want to get it right. It's a deep well and it will be expensive and we want to be sure we target it in the best way possible but we're definitely planning to drill that well and it will probably be in the first half. We're just continuing to do some technical work to be sure we drill it in the right spot and the best way possible with the best design.

Okay, and then last question. On the Lake Washington, Bay de Chene prospects you mentioned , how soon would you know or I guess I know it's early to speculate but how soon would you know how good those are looking in order to really get after

Well, see, there's a series of them. Two of our exploration prospects that we mentioned are currently drilling. One is actually between Lake Washington and Bay de Chene. It's not located in either field, and we would hope to finish that drilling activity in the third quarter, but then based upon what you find 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 the High Allen area that's actually onshore and that should also finish drilling in the third quarter. We actually have an interesting exploration well that's drilling in the Bay de Chene 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 Teton prospect to spud possibly late 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'll have a pretty reasonable idea of what you have there. Same thing with Lake Washington. We would expect to spud that West Lake Washington in probably the late third quarter also to try to finish it up this year.

Perfect. All right, thanks, guys.

Thank you. Our next question comes from Nicholas Pope with JPMorgan. Please go ahead.

Good morning guys.

Good morning.

I was hoping to clarify something you had given out on the production numbers. For Lake Washington and Bay de Chene, can you go over those numbers again, I was -- and also, I guess to you have total like South Louisiana as well?

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

But the number I was looking at though like you said Lake Washington, did you say 84 million today?

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

Okay. Thanks. And also, I was curious with, I guess as you're seeing some of the growth trajectory it seems like it's a little slower than expected with some of these constraints. Do you have any concerns about reserves in Lake Washington, like some of the proved undeveloped reserves. Is there any concerns there?

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

Yes, what I would add to that that while the complication that you you get from having so many different wells out there and the fact that so many different wells have so many different types of flow regimes, 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 fault blocks, a lot of different reservoirs. I don't think any one well out there is really very material in that regard.

Okay. That's all I had. Thanks, guys.

Sure.

Thank you. Our next question is coming from Gary Nuschler with Jefferies & Company. Please go ahead.

Thanks, good morning.

Good morning.

Speaking of reserves, earlier this year, you projected that you could grow reserves 5 to 9% for the year. We're at the halfway mark. Is that still the target?

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 will be forced lower into that range but we currently are putting plans in place. We currently are looking at some activities in South Texas that we can expand our drilling and do some things there. I'm optimistic that we can stay in that range.

Okay, so you can still hit at least the low end of the range even without success in the exploratory process?

Yes, 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.

Okay, and then my next question, last quarter you'd mentioned you were targeting or looking at the Edwards trend over in South Texas. You 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 field will you do it in and whatnot?

Well, we've got a couple of opportunities in South Texas. We've positioned ourselves almost from the Rio Grande in the Edwards trend all the way over to the Almost field in McMullen County and we've got Edwards opportunity all across that whole retrend where our acreage currently exists as well as our seismic databases that we've built. We have, 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 Katula area as well and we've got some areas that we're leasing on, so definitely you'll see one this year, but you may see us come out with a couple others that will go across the year or early 2009.

Okay. That's all I had. Thank you.

Thanks, Gary.

Thank you. Our next question is coming from Leo Mariani with RBC. Please go ahead.

Good morning here, guys.

Hi, Leo.

A couple questions on some of your exploration prospects here. You talked about the subsalt prospect, you're going to drill in the first half of '09. Can you give us an indication of what a well like that could cost you guys and what type of target you guys may be targeting?

I'll take a shot at it. Again, we have to speak in ranges and even when we speak in ranges we have to put some risk and some caveats on it, but we're definitely looking at going through the subsalt and Lake Washington. We've got two possibilities. One is we could go through a very very thick section of salt and get very much under the dome but we've also got, and it's 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 size 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 are seeing today, that's probably the best guess we can give you. In terms of size, it would be well over 100 Bcf equivalent, probably an oil prospect and if I had to put a range on it , it would probably be between 100 and 200 Bcf type

Okay. I guess the similar question on the Shasta prospect that you guys are hoping to drill here pretty soon as well.

Yes, I'll take a stab at Shasta. Shasta is actually currently drilling. It's one of the ones you referred to that's in between Bay de Chene and Lake Washington and we have a 50% interest in it. We are the Operator of of that well and we're always hesitant to put sizes on it because these numbers are generally unrisked and people throw a lot of reserve numbers around, but that prospect is at least a 50 plus Bcf unrisked gross prospect. And we would hope to have that finished drilling during the third quarter.

Okay, and what -- do you have an estimated cost on that as well?

I'm sure we do.

Yes, it's in the neighborhood of about $15 million.

About a $15 million well. And that's going on 17,000 feet.

18.

Okay. Just a question on your CapEx increases as well for the year. Do you have any indication of sort of how much of that may be cost related and how much of that is for increased activity on your part?

Well, I guess to begin with, we've always talked about how we like to spend our cash flow and we start out with a conservative spending number because we don't know what prices care going to do during the year and as prices are 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 caused really is what I would term as additional activity as opposed to just cost increases out there.

Okay. Thanks a lot, guys.

Thank you.

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

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

I think in the -- this is Alton. I think in the Q, we drilled down, to use your term, into those costs a little bit but the primary delta on this quarter versus the guidance we had provided relates to some workover activity, so we had a minimal amount in our guidance relative to some workover initiatives versus the actual cost that came in and I think both first quarter and second quarter that's the primary change that we had versus guidance, and obviously, that can be a good thing from a standpoint of locking some future revenues that weren't otherwise there.

And that workover activity is probably broken down into two primary areas. One is positive result things we're proactively doing to try to stimulate additional production but we also had a couple of saltwater disposal wells that we needed to go in and work on to improve the saltwater disposal capabilities, so there's some of both on that workover number.

Okay, very good. And going forward as you look at the guidance obviously, you don't plan on the workovers continuing to trickle over but given the increase in water injection, et cetera, how much confidence do you have in the numbers here as we look out and it sounds like you're stepping up activity, you got a new gathering system going in. Do you feel very good about that [9 to 950] range?

Yes. I think we feel pretty good about that. That includes obviously our planned workover, what it doesn'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 go fix it. I think we have had a number of our saltwater disposal wells we've worked over in the first and second quarter so we really don't think that's a repetitive thing, some of the saltwater disposal injection wells, at Lake Washington because some newly drilled wells too so I think we feel pretty good about that number as best you can.

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 the full amount of that 1800 barrels a day of deferred production? If so what do you think the timing would be for that? Is it going to just come on ratably over the balance of the year? Will it be pushed out to 2009?

Yes. I think the example that Bruce gave where we had the seven wells, tested them and didn't see all that test oil get to the export, now that's a good example of the type of pent-up capacity that is behind the system due to the constraints that we have out there. I do think that that kind of pent-up capacity when you get the constraints removed, you haven't lost it. It comes back towards year-end or early 2009, we really should see Lake Washington significantly regaining its growth cycle. We're not just focused on that 1800 barrels. In fact that kind of gets, just becomes a part of a much greater allocation. We want to get Lake Washington back where it's on a complete growth cycle and to do that, we've got to get these bulk lines turned into high pressure and low pressure systems out there. And so I mean, the short answer is yes, we expect it back. The long answer is we expect a lot more than that, and while the gathering line additions are going to help, it's really the refresh you're it of these Newport reservoirs that will make the substantial difference.

Very good. Can you give us an idea of what volumes in West Side facility is processing versus what volumes Legacy facility is processing?

West Side I think is about 4600 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.

And 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.

Well , 6700, we can get those break

And all of those numbers that Bob referred to is on a gross basis, not a net basis.

Sure. Very good. I appreciate your time.

Sure.

Thank you.

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

Hi, good morning. Sorry if I missed this. Do you guys expect to keep 100% of the subsalt prospect?

That depends. There are really as I mentioned two different types of prospects out there. There's one where you're going through the full core of the salt and those are some of the higher costs, higher risk, higher targets, but we also have Lake Washington kind of has a salt ledge on the fringe where they're still expensive wells. We could be looking at 20 million to $25 million on the top side and be looking at up to 200 Bcf type targets. That kind of a prospect we might sell down a small amount and a more passive type of player but the deeper targets, we may bring in a significant industry partner type. What we're trying to do is make sure we fully get all of our processing of the seismic, our salt model is completed such that we look at the full inventory. I believe there's at least three different subsalt targets in Lake Washington that we could be looking at.

Okay, great. And you mentioned an expectation for an exit rate for Lake Washington, you're post the gathering issues or even a rate that we could expect in the first quarter or first half of '09?

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

Yes, I would guide you 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's going to be how we drive our planning, if not to exceed that because it is one of our horses, it's where we've got a lot of opportunities, so though you hear us be conservative about the near term and how these things will get worked out, our drive is going to be for Lake Washington to return to significant growth relative to our strategic plan.

Yes. And that's both going to come from the pressure maintenance project and the facility infrastructure we're putting in place but also some of this new drilling that they're planning on.

Okay, great. Thank you.

Thank you. Our final question is coming from Andrew Coleman from Union Bank of Switzerland. Please go ahead.

Hi, good morning, guys. Got the full name in today. It's amazing. A couple questions on Lake Washington and start off with I was doing some comparison with the State data that's now put out there, what's the net revenue and interest on Lake Washington approximately?

Well, it's obviously mixed because we have a number of different leases. It's probably in the 78, 79 net revenue interest. We've got some that are in the low 80s and some that are on 75 so probably 78 to 79. It really can vary a little bit, just depends upon allocations and stuff.

Okay, so the implication is then that production here for the quarter was probably flat then through all three months?

I'd have to look, but probably about right.

Okay. And then--?

It's variable during that period of time.

Oh, sure. And as I think about the water r injection pieces here, correct me if I'm wrong, but the injection that's happening at Lake Washington that's just straight down dip water injection of these radio faults here and I assume that because you're offshoring good KV, so you're keeping good support here in Lake Washington and then at Newport, you should still have good KV, but I guess there's an issue that maybe because the flood is younger, you haven't kind of overcome the -- or you haven't injected enough water to match the amount of offtake that you've taken from that portion of the deal; is that correct?

I'm sorry, did you say KV? Were you talking about vertical permeability?

Yes, because you're injecting the water straight into the bottom of the zone and just trying to float that oil to the top, right?

Yes, we're currently injecting down dip and we've got a dual injector where it's going into two different zones and the composite injection into those two zones is about 2000 barrels of water a day. One zone taking the dominant amount, but we've got actually about five major reservoirs over there in the Newport area, and a couple of not so major ones and so we really need pressure maintenance and I know 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're pushing fast to get to 8,000 barrels a day. That's going to take more injection points.

Okay, so the goal then is to reiterate as you have taken about 4600 barrels a day. You're injecting to offset that about 2000 barrels of water. You're trying to get that to about twice the volume, or twice the offtake rate to try to catch up and close that volume gap and then sustain it?

Yes, when you talk about volume, you know exactly what we're talking about. We got to catch up and repressurize.

Are you seeing any issues with the water compatibility? is it all formation water or are you using sea water right now? Is that kind of impeding the injection process or is it really you don't have enough wells?

We don't produce very much water at all from these Newport zones.

We don't see a compatibility problem with the water that's being injected. We just are not getting enough in the ground. We just have a single injection point in each of the two sands. We clearly need more injection points so we get more water in the ground. It's not really a compatibility problem at this point in time.

We've drilled two purpose water source wells very close to Newport that are both good water producers. It's clean water, all of the compatibility studies look good , so we don't think we is have any water compatibility

Okay, and then so do you think then, is it a faulting issue out in Newport or?

No. It's just the reverse of a PI, a well can only take so much water, and where this one injector is way down dip, it needs to, the sands aren't as thick as up dip where you got some really big juicy oil sands and so we just need more injectors.

Okay, fair enough. Maybe later you are going to put a halt plot in one of your presentations?

A what?

An old spot reservoir. Moving on here since I've already taken my time on Lake Washington but looking at again the AWP and Katula, it looks like production has been declining there since really January. Is that accurate? I know Texas State data is not all the most timely, but I guess how do you see that changing going through the year? It had been growing pretty nicely in the back half of last year and what's the timing of an Edwards test?

Yes, it's obviously the tight gas sands that they all have higher declines up front when you're drilling new wells and there were quite a lot of new wells being drilled right as we took the Escondito purchase last year and turned them into our Katula operation. That activity did slow down a little bit but we're reinstituting our drilling activity so we should see new wells coming in with new flush production, but that is the nature. Once you've got a big active drilling going on in the tight gas sands you get a big flush and it declines but then you stabilize it and much more comfortable rates. AWP has been doing that for 10, 15 years.

Okay.

And also in the Katula 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. We have a plan to remedy that now.

Okay. All right, good and last two questions then. At Southbury Head Creek and Jasper County, how deep do you hold the rights out there?

I think that varies between leases. I know a number of leases we have all depths. There are some leases that go down to the base of the Wilcox. One of the things that we've been able to do there actually is drilling a little deeper on some of the wells and actually discover some additional stringers in the Wilcox sand that weren't known to be productive before. We actually had to reform a unit which we successfully did just fairly recently that allowed us to go back into those particular wells and 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's anything in the lease hold that's restricting us in terms of our development of that area.

Okay. And then I guess do you feel comfortable looking at I guess all of the assets more from an aggregate oil versus gas from an F&D perspective that you'll replace reserves off both oil and gas respectively or do you think there will be another more gas heavy year, kind of like last year?

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

Sorry if I could squeeze one last one and I'll get out of the way, and that's sorry, I got a laundry list.

No, good questions.

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

You guys have mentioned the first quarter, you guys were kicking around the idea of doing more on the facility side and the West Side could be expanded. I guess bear in mind with guidance coming down, CapEx going up, I guess want to see what the results are here through the year but are you still considering doubling down out in the (inaudible) facilities play?

Absolutely. No change in that. I think what you're referring to is on our West Side facilities, we put platform space out there to be able to double that and we've already instituted actions to double that capacity out there. Is that the question?

Yes.

And we're staying with that.

Okay, all right, well good luck getting that water on the ground. It will get everybody happy.

It will.

That's a first. Thanks, Andrew.

Thank you.

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

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

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