SilverBow Resources Inc (SBOW) 2007 Q4 法說會逐字稿

Good morning. I'm Marcita, and I will your conference operator today. At this time, I would like to welcome everyone to the Swift Energy Company 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 this over to you host, Scott Espenshade. Sir, you may begin your conference.

Good morning. I'm Scott Espenshade, Director of Corporate Development and Investor Relations. I would like to welcome everyone to Swift Energy's fourth quarter and full-year 2007 earnings conference call.. In today's call, Terry Swift, Chairman and CEO, will be provide an overview. Alton Heckaman, Executive Vice President and CFO, will review the financial results for the fourth quarter and full-year 2007 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 officers Bob Banks, Joe D'Amico and [Mike Kitterman]. 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. Our actual results could differ materially. We expect our presentation to take approximately 25 to 30 minutes and have allowed additional time for questions and answers. And now, I will turn it over to Terry.

Thank, Scott. First I would like to announce that after 20 years of service, Joe D'Amico intends to retire in May of this year. Swift Energy Company is very appreciative of Joe's service and his many contributions to Swift Energy Company. We will truly miss Joe and on behalf of the company we wish him the very best in his retirement. Mr. D'Amico will continue to serve as an executive vice president until his retirement date to ensure an orderly transition over the next several months.

I would also like to introduce Bob Banks and John Branca. Mr. Banks has been appointed Executive Vice President and Chief Operating Officer. Mr. Branca has been appointed Vice President- Exploration and Development. Both appointments are effective immediately. Bob and John have already contributed significantly to Swift's business and we expect additional contributions from them in the future. We are confident that Mr. Banks and Mr. Branca can provide additional leadership that will further enhance the value of the company and help take us to new heights of achievement.

Now, we are proud of the report that Swift Energy Company had another excellent year on our domestic operations. We should note that the strategic decisions were made to sell our New Zealand operations which had disappointing results in the past several years. This decision resulted in a one-time noncash earnings loss of $131 million. We are disappointed in the loss but definitely believe it to be an important strategic sale that will allow the company to focus on our continuing domestic operations. Our decision to sell New Zealand operations allows it to be treated as discontinued operations which means the future comparisons will be made with continuing operations which will exclude any New Zealand results. In to 2007, Swift Energy had income of $151 million from continuing operations, cash flow of $455 million from continuing operations, production of 10.6 million barrels of oil equivalent from continuing operations and domestic reserves at year end of 803 BCF equivalent. We replaced 245% of our domestic production at an all end funding and development costs to $27 per barrel of oil equivalent.

Lake Washington is currently the most exciting field that Swift Energy owns in its portfolio, and we expect that to be the crowned year of our portfolio for many years. However, we have been experiencing some growing pains in the field in the fourth quarter which is carried over into this quarter. As we continue to drill deeper wells, we're adding new high pressure flowing wells that have higher associated gas content into our facilities and production system. This system must also handle more mature production profiles. There are also more mature wells that usually produce larger volumes of water and require artificial [diluents] such as gas [fluid]. Combining these different pressure receives requires constant monitoring, rebalancing and in some cases new facilities, especially when new discoveries are brought into the overall production system.

The West Side facility expansion is on track and was key to aiding in this situation. The West Side facility will not only provide additional throughput capacity but just as importantly, it will allow us to help optimize the fuel for a better overall productivity. The West Side facility will also provide the platform space for pressure maintenance program at the Newport area. The reservoirs in the Newport area are generally not open to the basin and as a result have a weak water drive which means that these reservoirs can significantly benefit from pressure support. We plan to begin this process by pumping water into a down dip injection well in the second quarter to help maintain and increase production from the various Newport sands. We also see this potential for additional recovery in a number of other reservoirs in the field.

In the fourth quarter, we purchased three properties in South Texas which are operated out of the Cotula, Texas area. We will continue to refer to this as the Cotula area. We department two rigs busy there for the fourth quarter. We kept two weeks busy there for most of the fourth quarter and pleased with the results today. We believe this area will be very similar to our success in AWP Olmos field in the same almost geologic trend. This should be viewed as a strategic acquisition with excellent gas pricing and a predictable inventory of drilling opportunities. I should also note, as it relates to the New Zealand assets sale, this should close near quarter end and the proceeds would be applied to (inaudible). With last fall's 90-dollar plus oil prices and our acquisition, we decided to increase some of our activity. At the same time, weaker natural gas prices led to a moderating of day rates for land rigs.

We with expect this BTU disparity between the oil and gas to last for the majority of 2008. This situation has allowed us to ramp up to 13 rigs which are currently running. Over the long term, typical costs parallel energy price decks, and we believe that 1/3 of the long-term price deck will represent the cost recovery of the asset or the funding and development cost. Swift Energy will continue to monitor the cost side and take the appropriate actions to keep the company healthy.

Our 2008 plans call for production growth of 10% to 15% over our domestic production or continuing operations and reserve growth of 5% to 9% again over our continuing operations of our reserves. Based on our capital spending budget, which will be $425 million to $475 million. If oil prices stay close to or in the range of $90 for 2008 or if we have material exploration success, we are ready and prepared to increase our spending. We will again see the majority of our spending in South Louisiana region and with additional activity across our other quarries including South Texas.

Over the past several years, Swift Energy has been spending for significant growth opportunities in the future without facility and seismic investments. These investments should lead to lower future F and D cost as we bring forward the opportunities we see in our portfolio for 2008 and beyond. Swift Energy is committed to improving our capital efficiency metrics, that starts with our funding and development costs which we are focused on improving. With this in mind, Swift Energy begins the year with an effort to control and monitor the capital costs and delivering on our growth metrics. We continue to believe that Swift Energy strategy, our current property mix and earnings potential compared to our evaluation makes swift Energy one of the best risk-reward opportunities in the sector. We also continue to add personnel to our talented staff and give them the tools they need to perform for you, the shareholder. We have grown our staff at approximately 7% per year over the past ten years. This will continue to be a challenge for Swift and everyone else in this sector.

I look forward to our dialogue as Swift Energy's up and coming analyst investor meeting which we are hosting here in the wood lands less than a week away or Wednesday, February 20th. It is here that we intend to show case our 2008 plans and go into much greater detail than we can this morning. We are excited about 2008 and the opportunities it holds for Swift Energy Company. With that, I would like Alton to present the fourth quarter and 2007 financial results.

Thank you, Terry. Good morning, everyone. Swift Energy had a strong finish to another great year. As to the fourth quarter, revenues were $196.4 million, up 36% over 4Q '06. Net income from continuing operations was $52.7 million, up 54% and diluted EPS from continuing operations came in at $1.71 an increase of 52% compared to the fourth quarter 2006. While cash flow before working capital changes increased 20% per diluted share to $4.23. Domestic production increased 7% to 2.8 million barrels of oil equivalent. Crude oil prices remain strong and with approximately 69% of Swift's current production coming from crude oil and natural gas liquids, the current oil pricing environment continued to be favorable effect on Swift's financial results.

Swift's domestic average relies price on 4Q '07 increased 36% to $70.33 on a composite basis per BOE. As crude oil prices averaged over $89 per barrel compared to approximately $58 per barrel during the fourth quarter fourth quarter 2006. In addition to higher commodity, production increased that allowed Swift to increase its quarterly oil and gas revenues, 46% over the prior year. We continue to focus on our controllable per unit cost in metrics as Terry mentioned and as to the fourth quarter 2007, G&A came in at $3.11 per barrel which which was below our guidance, EBITDA for you that came in at $19.49 which was above guidance. Production costs came in at $7.56 per barrel, slightly above guidance. Production taxes increased on a BOE basis, primarily due to higher prices and increased production but actually decreased as a percentage of oil and gas revenue due to changes in Swift's production exhibition locations.

Finally, interest expense came in at $2.99 as we increased our line of credit borrowings during the fourth quarter to fund the South Texas property acquisition that Terry mentioned. We, therefore, realized the income from continuing operations for the quarter of $52.7 million which was $1.75 basic and $1.71 diluted, again bidding first call mainly as tonight. As Terry mentioned in the intro as we announced in last week's press release, we recorded a noncash discontinued operations charge of $131 million net of taxes during the fourth quarter 2007 for the sale of the major portion of our New Zealand assets. We still expect to realize total cash proceeds between $100 and $110 million, from the ultimate sale of all of our NZ assets and future additional remaining proceeds above the recorded $88 million will be reflected as a gain from discontinued operations upon the execution of the great months that is anticipated to be in place later this year.

All future results will reflect Swift's continuing operations which is almost entirely domestic and New Zealand results will be reclassified into discontinued operations for all past and present periods presented. Cash flow before working capital changes for 4Q '07 came in at $130 million or $4.23 per diluted share while EBITDA was $146 million or $4.75 per diluted share quarter or $4.75 per diluted share. Results for the full year of 2007 were also impressive. With record revenues driven primarily by higher production and higher commodity costs. Please see our earnings' press release and, of course, our subsequent Form 10K filing, The would get filed by the end of February for complete details.

CapEx the fourth quarter of $324 million which included our Cotula property acquisition in South Texas resulted in borrowings under the line of credit of $187 million at the end of the year 2007. Although we did access our bank line during the quarter to fund the acquisition activity with the New Zealand proceeds and available line, we still have plenty of liquidity and resources for any additional value adding strategic opportunities that avail themselves. With respect to Swift's hedging activity we have purchased natural gas for approximately 30% to 35% of our domestic production for first quarter 2008 at an average NYMEX strike price of $7.02 per MMbtu. Along with natural gas fluids for the second quarter covering approximately 40% to 44% of that quarters natural gas production at an average strike price of $7.45 per MMbtu. We have also purchased oil floors for approximately 40% to 43% of our first quarter 2008, domestic oil production at an average NYMEX strike price of $71.22 per barrel. Please see our web site for complete and current detailed hedging information.

And as always, we have included additional financial and operational information in our press release including the initial guidance for the first quarter and the full year 2008. This year was another great year for Swift Energy, but we are equally excited about what we see on the horizon for 2008 and beyond and with more of that I will turn it over to Bruce Vincent for an overview of our operations.

Thanks, Alton, and good morning, everybody. Today I want to discuss fourth quarter and full-year 2007 activity including production volumes, recent drilling results, activity in our core operating areas and unveil some plans for 2008. You may have noticed that Swift Energy began reporting our production and our per unit items on a barrel of oil equivalent basis. Since 74% of our 2007 production was crude oil, 66% and NGL is 8%, we felt this change was appropriate and decided year-end would be the time to make the change. I will include both oil and natural gas equivalents in today's review.

Growth production, Swift Energy's production from continuing operations during the fourth quarter of 2007 totaled 2.8 million barrels of oil equivalent or 16.75 billion cubic feet equivalent, an increase of 7% from the 2.6 million barrels of oil equivalent or 15.6 billion cubic feet produced produced in the same quarter of 2006. Sequential production from continuing operations increased 3% when comparing the fourth quarter 2007 to production in the most recent third quarter of 2007. From our discontinued operations, New Zealand production in the fourth quarter 2007 was 0.3 million barrels of oil equivalent or 1.8 billion cubic feet of growth. A decrease of 38% from production in the same quarter in 2006 due to the natural production declines. And no new drilling activity by Swift Energy in this region. Sequentially, this area also saw a decrease of 5% from production levels in the third quarter of 2007.

Fourth quarter 2007 domestic production, our continuing operations was essentially flat at 3.1 million barrels of oil equivalent or 18.6 billion cubic feet equivalent compared to the same quarter in 2006. Compared to the third quarter of 2007, fourth quarter 2007 total production increased 3% from 3 million barrels of oil equivalent or 18.2 billion cubic feet equivalent due to production increases from our new Cotula area fields. Swift Energy's year-end 2007 reserves consist of 133.8 million barrels of oil equivalent or 802.7 billion cubic feet equivalent of of domestic reserves and our discontinued operations in New Zealand had 16.3 million barrels of oil equivalent or 98.0 billion cubic feet equivalent of growth of reserves.

This compares to 2006 year-end reserve of 118.4 million barrels of oil equivalent or 710.5 billion cubic feet equivalent domestically and 17.7 million barrels of oil equivalent or 106.4 billion cubic feet equivalent in New Zealand. This is a 13% increase in reserves from our continuing operations domestically and an 8% decline in discontinued operations. Swift Energy's domestic reserves are 48% crude developed and are comprised 44% of crude oil, 43% natural gas and 13% of natural gas liquids. Swift Energy's 2007 domestic capital spending was $703.2 million which implies a domestic 2007 funding and development cost of $27 per BOE calculated according to industry standards.

Swift Energy's-year-end 2007 domestic crude reserves were valued at approximately $3.8 billion of present value discounted at 10% per year PB 10 compared to $2.4 billion for the company's 2006 year-end to domestic reserves. Domestic pricing for reserves and PB 10 calculations utilized $93.24 per barrel of crude oil and $6.65 per MCF equivalent for natural gas in 2007. This compares to $60.07 per barrel and $5.84 for MCF equivalent at year-end 2006. As for our drilling results, Swift Energy's successfully completed 25 of 27 wells in the fourth quarter of 2007. The company completed 24 of 26 development wells and was successful on one exploration well in the Bay de Chene area. Let me briefly review our activity in our core operating areas beginning with our largest area, South Louisiana.

Production during the fourth quarter of 2007 averaged approximately 20,700 net barrels of oil equivalent per day or 124 million cubic equivalent per day in the South Louisiana region which was a decrease of approximately 10% compared to our third quarter 2007 average production. The bulk of this quarters South Louisiana production, again came from the lake Washington field. Net to Swift of approximately 15, 900 barrels of oil equivalent per day or 95.5 billion cubic feet equivalent per day. In the company's South Louisiana region, Swift Energy successfully drilled one operated exploration well and one non-operated development well in the Bayou Sale area plus one service well which will be used for water ejection at the Newport area. Swift successfully drilled and completed an expiration well in the Bay de Chene area. The BDC Number U7 exploration well or our pie seize prospect was tested with production rates of up to 2.1 million cubic feet her day on a [10/64th inch choke was 6,085 pounds] going to deeper. This well is currently shut in and weighted on additional market outlets. Swift Energy is currently market constrained in the Bay de Chene area and we are pursuing alternative outlets.

The service well recently drilled, we'll begin our pressure maintenance project at the Newport area in Lake Washington in the next few weeks. We plan to inject water into two reservoirs to maintain pressure in two separate sands in aid of the ultimate recovery of the hydrocarbons that are in place in these reservoirs. While water injection will begin in the next weeks we do expect it will take a few months before we see the production response. This project is being undertaken by the West Side facility expansion which is still on track to be commissioned in the first half of this year. As a reminder with regard to pressure maintenance projects we've talked about this before, we previously disclosed our initial pressure maintenance project with the CM Number 222 well at Lake Washington.

The bottom hole CM 222 reservoir pressure has now returned to the original 2000 PSI from its depleting state of 700 PSI following water injection in the down dip CM 225 well. As recently as January 24, the CM 222 well tested at 982 barrels a day, but after a recent aciddization and clean up, the well tested as recently as February 10 at 1,975 barrels of oil per day. That's an indication the kind of response we get from pressure maintenance. Simulation indicates that we can increase the recovery factor of this particular fault block from around an original 27% to 45% or an additional 400 to 700,000 barrels of oil. In addition to these pressure maintenance projects, there may be additional recoveries available from tertiary projects. We haven't began working these issues yet.

In the Bay de Chene area, Swift Energy is reviewing alternatives to be able to market more natural gas. Our well results as well as our geologic work suggests that we will need significant additional take away capacity. Swift currently has a marketing constraint due to a limited market for natural gas on the existing pipeline system where we connect to. We are pursuing two alternatives for more capacity and additional optionality. First option we began is to build our own pipeline. This will take up to a year to complete. They were also pursuing another option with third party marketers with existing pipelines in place that may become available by the second half of this year.

Swift Energy currently has four operated and one non-operated rig working in this region. Additionally, we continue to work on our merge with the Bay de Chene across this region covering approximately 4,000 square miles. We now have the prestep. Depth migration was done at Lake Washington, Bay de Chene and Cote Blanche. And we're beginning to see the added value of these today. We now have an even better picture of sale set in them at interface as well as better imagining of the numerous faults and sand horizons. This will enable us to get further up dip and closer to the south sand blocks, but for other in Bayman areas such as Newport and develop potential substant place in this area. We have also completed the fast track PSDM work at Cote Blanche and are already using that to look for potential salt overhangs for additional up dip potential.

We will will be beginning PSDM reprocessing under [military] bay and (inaudible) data this year with the current merge data sets. All of our 3D acquisition and processing work should continue to bear fruit for many years and help improve our funding and development cost over time. We continue to be extremely excited about the glimpse of the future for Swift that we see from our seismic data and current interpretation as well as our drilling results. For instance, we have found additional newly productive CC series sands, those found in Newport area that we will continue to look to exploit in 2008. Additionally, we actually had two wells penetrate the salt in the Lake Washington area in 2007 providing positive encouragement. Neither of these wells were originally designed to be drilled below the salt so we had limited drilling capability with these well (inaudible) at these depths. But the results do lead us to believe that we will find higher pressures, sands and hydro carbons at these deeper intervals.

This will help us plan for and design a well to explore these deeper intervals either later this year or early in 2009. In the South Texas region, production in the fourth quarter 2007 averaged approximately 6,700-barrels of oil equivalent per day or 40 million cubic feet equivalent per day split between AWP Olmos area and the new Cotula area. In the fourth quarter, we successfully completed 13 development wells targeting the Olmos and AWP area. We have two rigs in the AWP field currently. In the new Cotula area, this is the [SNBDO] resources acquisition in October of last year, we drilled nine of 11 development wells. Drilling occurred predominantly in the Sand TSH field and also in the Briscoe ranch field. We currently have three rigs working in this area right now. The [Cote Blanche] region contributed approximately 2,600 barrels of oil equivalent per day or 15.6 million cubic feet equivalent per day in the third quarter of 2007.

Swift Energy completed four development wells in the fourth quarter in South Bearhead Creek in Beauregard Parish, Louisiana. We continue to have two rigs operating in the South Bearhead Creek area. This area is showing potential and we are pleased with the results today. During the expected sale of the New Zealand assets, we were pretty in it as discontinued operations in our financials. We expect the sale to origin then close in the March-April time frame and for the remainder of the assets to be sold later in 2008. The discontinued operations in New Zealand produced 1.8 billion cubic feet of equivalent in the fourth quarter of 2007. There are approximately 3,300-barrels of oil equivalent per day or about 20 million cubic feet equivalent per day for both the [Ton and the Roanoke] area. The fourth quarter decrease in production was primarily due to our lack of drilling activity in the area and natural declines. Thanks for your attention. I'm going to turn it back to Terry for a recap and then we will get into the questions and answers.

Thanks, Bruce. In summary, before we open it up for questions, Swift Energy company is pursuing opportunities and strategies to economically increase our reserves base and our valuation. To reiterate our 2007 results, in to 2007 our revenues from continuing operations increased by 19% to over $650 million. Income from continuing operations was up 1% and cash flow increased 12% to over $460 million. Strategic decisions were made in 2007 to sell our New Zealand assets which resulted in a one-time noncash loss of $131 million. The proceeds from the New Zealand sale which should close near quarter end will be applied to our bank line. Swift Energy still maintains a conservative balance sheet. Focusing on our continuing operations, domestic production was a record level of 10.6 million barrels of oil equivalent, a 12% increase. We expect to increase production by 10 to 15% in 2008 over 2007 levels.

Reserves for our continuing operations domestically were 133.6 million barrels of oil equivalent or 13% increase in reserves over 2006. We expect to increase reserves 5% to 9% over these 2007 levels. For the total company, we had record production of 72 BCF equivalent, a 3% increase and we replaced 216% of our total production in 2007 or 10% increase to 902 BCF equivalent. We have a portfolio of high impact opportunities in our South Louisiana exploration programs which are complimented with the significant South Texas gas portfolio which can deliver predictable growth and value. We are continuing to work our 3D seismic for additional oil and gas opportunities to spotlight the value of our reserves and production growth opportunities. We are encouraged by our progress in our core areas. We believe we have accumulated a valuable set is of properties, technologies and a highly skilled staff to bring value to all of our regions. Once again we are committed to improving the execution of our plan and delivering success for Swift Energy and its stakeholders in 2008. At this time we would like to begin the question and answer portion of our presentation.

(OPERATOR INSTRUCTIONS) Our first question comes from [Jason Wagler of Diamond Group].

Good morning, guys. Just curious, the 13 rigs, the four barge and nine [land], is that a pretty good run rate for the year?

Definitely for the first half. I mean as you know, we have historically used the discretionary spending wedge in our budget. Our strategy is to spend cash flow, we tend to be a little conservative on the front side in terms of what -- like the prices. That sort as well as historically, over the last several years we have been able to ramp up. Spending is removed throughout the year as we realize we have a higher price deck and higher realized cash flow. But that's a good run rate for the first half and if prices continue at the levels they are right now, probably a good run rate for the second half too but we just need to wait and see.

Great. And I guess just on those, the contract wise, is there anything that and on general because the 13, but are they, you know, well by well? Are they contracted for a certain period of time or anything?

All of our rig contracts are well by well at this point in time. The market is such that you don't need to do anything else.

Great. Thanks a lot.

And then, I guess the, the rigs in South Texas, I guess three are actually on Turkey, contracts are supposed to run rate but it is all well in the well.

Okay, cool. Thank you, guys.

Our next question comes from Brian Kuzma of JPMorgan.

Hi, good morning, guys.

Morning, Bryan.

Could you guys tell me just to confirm all of the guidance you got given the need for production and reserves, that's all organic?

That's all organic. We don't budget the acquisitions. We obviously look at acquisitions all the time, and target specific opportunities that are strategic in nature. Well, I would like to do it but we don't budget it. We focus on it a real bit and we head along on good grip for a real bit in 2008.

Okay. And do you guys know, like in your PB 10 calculation, what the total development costs was associated with like the 400 you guys have.

Of course, we run those numbers and they are up from prior, from the prior year, and I think, we think they're up in accordance with the trends that you've seen in the industry but we will actually report that in detail in the 10-K which will be filed later this month.

In two weeks.

Okay. And could you get into the specifics into what you guys are looking to do to control F&D costs in 2008?

Well, I can get into some of the specifics. We clearly have a very large inventory of probable and possible reserves, and balancing our drill bit toward the probable and possible, I think it's very important in controlling the all-in F&D costs. We spent a lot of money here in the past several years drilling development wells. It is true that we've got a large undeveloped inventory but we are cycling that inventory and as we cycle that inventory, the undeveloped reserves that you see today are very different than the undeveloped reserves that you saw last year or the year before. We keep adding those but we have got to access the probables and possibles in a more efficient manner, bring them forward because that gives you complete reserve growth relative to the capital expenditures, also we have been spending a lot on facilities and seismic. We have been building that base up strong, not that we are through doing seismic or facilities but as a percent of your overall budget, it is going down.

Just to re-emphasize, we have made a good, to give us a better picture and low you are our risk. As a consequence, particularly the PSDM particularly Lake Washington, we are getting much, much better clarity, much more accuracy in you a little bit, that does enable us to step back and take on what would have been perceived a year ago as a riskier project because of the picture we have. It also enables us to do the deeper exploration things.

Okay.

And I think you are going to be with us next week, we will definitely provide more color on it next week.

Okay. I have a couple more but I will hop back in line.

Thanks, Brian.

Our next question comes from [Gary Michele of Jefferies and Company].

Thanks. Good morning, guys.

Good Morning.

First question at Bay de Chene, you guys, mentioned you are looking at building your own pipeline, what is the cost of doing that?

We are building our own pipeline and we are also working to have other routes out. So we really believe there's enough opportunity in Bay de Chene that we need to have several markets and show you different ways out of the field . The pipeline that we have actually applied for the permit, received permit, with all the purchased pipe for. All in cost of that probably be about $10 to $15

Okay. And.

The [Side West] I might add that we are working with another, third party system owner about building an air connected to the current system and building another meter that will allow us to get more out quicker. But we think we are going to have enough potential in that field we want the optionality of two alternatives.

Can you tell us what our fourth quarter volumes were fourth quarter, what was the average fourth quarter from Bay de Chene?

Well, I don't know if we got that. I will tell you what, we can get that information within the call. We'll give it or we can provide it next week at the analyst meeting. It will definitely be an okay. It should be filed in two weeks.

The thing is I'm going to remind you and everyone else about Bay de Chene is where are the pipeline system that goes one place. It goes to the ConocoPhillips enhancement refinery but we are subject to whims of how much gas they can take and recently they have largely curtailed our gas deliveries a little bit which is the reason we are both looking for interconnect on that system to other outlets as well as build our own line.

Yeah just a little color on Bay de Chene, last year's Bay de Chene number was just a little over a half a million barrels of production equivalent. It is actually mostly gas. We really expect and some significant ramp up of that in 2008 and we have got the well bores already drilled to demonstrate that, the tests conduct canned to demonstrate that again we have development wells and probables in this field that we will be tapping, I am going to go ahead and step out and say we do believe Bay de Chene will be every bit as big in terms of volume as AWP or those types of fields. We see it going higher.

Okay. And my last question, Lake Washington production averaged just under 16,000 barrels, it had been averaging what looks like 18 to 20. Prior to getting the west side facility up and running should we expect it to continue averaging around 16,000?

Yeah, I would expect to continue that the average that until we get the West Side facility up and also the pressure maintenance project both underway and see the response o from that. Those are the two key things that make a big difference there.

Okay. That's all I had. Thanks.

Our next question come cans from Leo Mariani of RBC.

Yes. Can you give us an update at Lake Washington there on the construction plan on the West Side facility and give us a little more insight as opposed to what you think it will be, come on?

Well, actually everything is going pretty well. We have always said we don't have it in place by the end of the first half. I think that we would hope to begin the commissioning process probably by April and you know, once you, it doesn't, you don't just like buy a car and turn the ignition switch and all the sudden it is working. There is a commissioning process that takes, you know, a month or so and then it takes time to rebalance the system. One of the significant things that will help is with regard to the Newport production, the Newport production currently goes about three miles to the 212 platform in order to get it processed and out, the west side facility, it is closer to that. And so that will immediately help, but once we get the Newport production, we need to rebalance the older production that's going into to 212 and the main part of the field. But we expect to have it fully operational by the first half of this year.

Okay. Could you give us a little bit more in terms of visibility on the near-term exploration program, I guess obviously you had one success here in the fourth quarter. Joining us and be drilled right now. I think you'd see it in the next several months here.

There's a lot of things being drilled but in terms of high profile, high impact wells, we are really not focusing ourselves or the market on that. We have got a pretty regular look at the deeper sections in Lake Washington. As we have been drilling in Lake Washington we have taken the opportunity to go deeper on numerous of our wells and by that I mean all into the series, the CC series and we have finding more new accumulations at these deeper depths. We have noted that in the presentation today. We do see those as significant in the continual growth of Lake Washington but a few of these wells as we mentioned we found them in strategic positions to take them through what we call salt wings or what we call the weld and going through the salt wings or the weld, we got some strap tests and some strategic places within our seismic data where we were able to get through the well and find sands, get through salt wing find sands, find hydro carbon but we didn't have enough mechanical ability to nor did we want to go further for safety reasons. So, We have designed this year at least one deeper test where we are supposed to go deeper with a much more robust drilling design. That will happen probably the second half of the year. That's a big impact well. We won't focus on it to, in that sense but it is a big impact well. In Bay de Chene we have an opportunity there at a pretty large target that has been put together, again late flesh the year a second quarter we will make a decision on third quarter we could be spending something large in Bay de Chene. And as we look across our seismic area we do see scenarios in the seismic data (inaudible) we may be active in recent programs. Because one of the advantages is that we have these core areas where we do see very significant opportunities from both above the salt and sub salt, but also for example, we have a shot or prospect that's between Lake Washington, Bay de Chene. That keys off of (inaudible). Remember we had a success before that. But we are not queueing them up one by one presentation. We will show more of that in terms of the analyst meeting in terms of showing seismics and the mapping in a much greater fuel for where these are. Yes, as we have talked about before, and the full strategy revolving around the 3D technology, the merged data said, the top-migrated data, the depth-migrated data. You are taking it into a much higher quality and you are creating a picture that nobody has seen before, create a new geography. And as we both go deeper or there's other opportunity, but as we continue to drill within this data set and further recalibrate the data set, we crystallize a much better picture than anyone has ever been able to see before. That's not just true at Lake Washington, it is true throughout the data set.

Okay. Also, I wanted to see if you guys had any recent activity or expect to do anything in some of those fields you acquired from BP in late 2006, Jeanerette Island, Horseshoe Bayou, Bayou Penchant. I'm just trying to get sense of what's been going on there?

Absolutely. We've had some drilling activity in Bayou Sale and Horseshoe Bayou, these are some nice areas. We've had some activity over in Jeanerette. In terms of again, the 3D it takes time to fully integrate the low board data sets with the 3D, newly processed 3D data sets that we have. We are doing that and making great progress. I think we will show you again at the analyst meeting how the different stages of process tag we have our data sets in. We are in a well over in what we call [St. Mary's]. well, over in Horseshoe Bayou. That's a pretty important work force. We're pretty pleased with the results for the coming end year. We will report more on that in the next several weeks, it is a deeper well. We have I believe 20% in that well. We also have a fault block in contested fault block in Bayou Sale that we are building. Going over, a new location that we're excited about. Going over to Jeanerette, we've identified some designs in the general field that we also see as bypassed or areas that have some good pressure left in them in what has been a very significant producing field.

Okay. Thanks a lot for the color.

Thanks, Leo.

Your next question comes from Todd Swanson of Third Point.

You mentioned the ratio for domestic reserves is 48%. What's that for domestic spoil domestic gas?

That's a good question and that will certainly be detailed out in the 10-K. We can have that also at the analyst meeting. We don't have that in front of us right now.

Okay. How about that on Lake Washington you have mentioned the focus this year will be on converting pad? What does it cost to drill and complete a development well there and what's a dry hole cost for a development well?

Actually, I want to clarify your statement. The focus this year in Lake Washington is more on converting probable than possible and not so much on pud. But you know, many actually will be able to clarify a lot of answer or give people color on it to come to me next week. Many of the wells we drill have a pud component and exploration component. We often try to design the well for such that it does intersect fault blocks if made may be you know prove undeveloped locations, but also designed to go deeper to target problem possible location so you occasions so you can have them, a combination of things in a particular well born, but the principle focus in Lake Washington of our program there is really to try to focus on the problem of possible conversion.

Okay. Can you giver us a sense of what wells cost there, just some sort of range or guidance?

The well costs is ranges significantly depend on the depth. They depend on the well track whether it is straight or can curved but generally it is $275 a feet approximately.

$275 a foot?

Yeah.

Okay. Thank you.

Our next question comes from [Greg Boblan] of Freeman Billings.

Good morning, gentlemen.

Morning.

I noticed that you guys are forecasting a jump in crude oil volumes after the press quarters. Can you just talk a bit how are to the plans ever year, especially with regard to the West Side expansion and water injection project?

We obviously are, got a very detailed approach to each field and our increase in production is not attributable to just Lake Washington. We have mentioned Bay de Chene. We're protecting the area where we're drilling wells and we're doing some marketing outlet work that should help us increase production from Bay de Chene. We got a fairly robust program down in South Texas with our Cotula area, a newly acquired property as well as (inaudible) where we will both maintain some of the field production there but also increase production on some of the acreage that we have down there undeveloped wells as well as probable reserves. In the Lake Washington area, I think we've noted that there's two aspects of Lake Washington that we've put into our production forecast. One is the insulation of the West Side facility that you give us additional capacity and additional flexibility so that we can optimize some of the different types of crude oil, strings that we have, the gas strings as well as some of the higher pressure wells going into that. But at the same time bringing that facility in we will be able to better utilize some of the older facilities for some of the mature production that has suffered some, some set back due to the higher pressure wells pushing them up in a temporary way. We also have our injection project, our pressure maintenance project, so they're going on. They were candid and had both the West Side facility and the opening up of expansion back in the older facilities. So that's the plan and that's what we are going to make happen.

One other one, in the release earlier this month on the year-end reserves, you mentioned a little down time at Lake Washington associated with change up for pressure maintenance. I was wondering if you can talk about the rational behind changing episodes versus tension out back or something.

Well, in pressure maintenance you can't have gas evolved out of solution in the reservoir itself. When that gas down in the reservoir evolves out it tends to go, travel up dip. You can have what is called a secondary gas cap form and that gas cap kind of like the fizz in a Coke bot bottle is your energy. You really don't want to let all of your energy out because if it is left in that position it can help push the oil out which is the primary product we're trying to get out. So as we saw some wells in the Newport area become more gassy particularly the up dip wells it made good reservoir. It seems to choke back on some of that gas, not produce it now so that we can save the fizz in the Coke bottle. It helped get the oil out.

But is there a reason why you actually had to physically change out the chokes as opposed to just using these existing ones to pinch the West Side.

No, that's just mechanical thing. In some case you have adjustable chokes where you go out there and you just adjust the chokes. In other cases, you have what's called a positive displacement type of choke where you actually -- let us use terminology in the business.

You say change the choke. It doesn't mean you go in there and change one from the other, you are just changing the size or adjusting the size over it.

Okay. Thanks.

Our next question comes from Jeff Robertson of Lehman Brothers.

Thanks. I apologize, ma'am, pardon this on the conference call but, Bruce can you talk a little bit about the reserve editions and also the revisions on both natural and gas and where those came from and on oil, what the negative revision related to and also where you added oil reserves?.

Well, yes. I don't have all of that at detail in front of me but the net effective revision was pretty neutral, but as you know, those revisions come across the set of properties, some are positive, some are negative even within fields like Lake Washington in particular where you probably have 100 fault blocks or more. You could have some that have a negative revision, some that have a positive revision. We didn't see any significant revisions positive or negative jumped out because there is any concern or alarm. There's nothing beneath that, like I said, it really is a cause for concern. For the specifics, I would have get the reserve report out and look at each of the field and even within the field like I said underneath it, understand which fault blocks we're talking about and I would say a lot more, the detail would be on the 10-K. It should be filed at about two weeks.where you added reserve, gas reserves?

And even though you do have some negative revisions and positive revisions. Still, a very small percentage as it relates to what was replaced.

Can you all talk where you added reserves, where you added gas reserves?

Where we added gas reserves? Well, clearly we added gas reserves in South Texas with the acquisition of that well.

But excluding the acquisition.

Where we added gas reserves in the Bay de Chene area? Jeanerette area? I am trying to pull the numbers out and get them in front of us. Yes, all I have MCFE equivalent if front of me. We will have to get that detail out in the 10-K as well as the analyst presentation next week.

Okay. Thank you.

Thank you.

Our next question comes from Brian Kuzma of JPMorgan.

He's back.

I am back from where I'm... I told you I would be back. When you guys look at Lake Washington and let's say into 2009, should we be expecting production to be back above that or close to that 20,000-barrel a day level you guys were at last year?

I heard 2009. Well, obviously we challenge ourselves here and you know, you really can't be above what you see. It's to be about what you intend to do. We intend to fill these facilities at Lake Washington. We are now building enough additional capacity and in particular, it should be noted on the West Side that we have got additional craft expansion space with this new facility to double its capacity in the future. We are set on doing that. Our goal is to bring the production up higher than the level that is it has seen in the past. That's our internal goal, that's our [Chene Bar] and I certainly hope to be sitting here in 2009 telling you that it has happened.

Okay. And then just to clarify Bay de Chene, there's two options you listed you are pursuing both of these options then.

Correct. Yes.

Okay. And the earliest you could see an expansion and would be able start party option by the middle of 2008?

That's correct. That is moving forward. Just one, we want to have optionality. Two, we don't want to be dependent on a third party if somebody doesn't come through with what they're planning to do. We think they will, and that will give us increased outlet certainly by the second half. If not, maybe a little before but we are, let's just say July 1st right now.

And do you know how much additional capacity that would be?

It would be significant, more than we could produce, the capacity would be.

Okay. And then, who else did you took down below the salt wells? How deep did those go?

They're approximately 16,000 feet.

16,000 feet.

Okay. And how much would it cost to design a well that would produce from that depth?

Well, we don't actually have the actual design yet but we approximate -- approximately $15,000, an additional string of casing.

Yes, I will comment on that just a little bit more. There are several different prospects that we are seeing that one might characterize as sub salt. And it depends on how you want to go through them. There are some of them that look like you might have to go through a very, very large amount of salt and those would probably be more expensive than what we are talking about here. But there's also some where it kind of prefer to use like more like salt wind. They're sections of salt you go through and then there's some others that look like you might actually be able to be out more and drill directionally under the salt.

We'll show some of that at the analyst presentation next week. Each of those has a different cost profile and risk profile to it, a different target size too.

Okay and then in South Texas, you had a couple of unsuccessful development while on these new properties. What have you seen over there? Have you found any type of limits where you know it is not going to work and what is like your typical well economics you are expecting on this new acreage?

Well, we haven't found any limits that have given us any concern. It is just like in AWP, we drilled 500 wells as your case have been hit, a fault you're going to hit, a thinner section or lower permeability section is not going to economical. It's not going to complete it. In a worst scale, you'll do a lot of work there, but we got a large acreage position. We are really excited about it. We think it will just going to turn into an acre-top property just like AWP has been for the last 20 years for us.

Okay. So we'll still be using like $250 million per well? For AURs.

Yes, that's probably a good number to use.

Yeah, but.

Yeah, it is a much higher liquid content down there that's about 1300 or so.

It is like 1300 BTUs, I think. If you get a much higher liquid content which certainly helps with the economics.

Okay. And then, just real quick, on the, on South Louisiana, you guys didn't drill that many wells in the second half of the year. I mean as you look out into 2008, I mean you have three rigs running right now. I mean, are you guys going to have to get a lot more aggressive out there to spend $300 million or like how many wells would that equate to do you think?

A lot of that, South Louisiana is not a simple area where you drill a well at the same depth they cost the same amount of money, as you go deeper they take longer but they cost more but they returns are better. You know, we think we have a good program set for the year, clearly front end loaded based upon our current budget, but we do, you know, we, inside our gut we do think prices are going to be above our budgeted price deck and we think we will have early opportunity to increase our spending and we got a program that's certainly an inventory to do that.

Yes, I will comment on that also, again going back to Lake Washington. The deeper wells that we drilled in Lake Washington are clearly more expensive and have taken longer to drill, therefore, when you put one of these bigger rigs on there, you don't get many wells out of it. But at the same time, one of our more recent wells we tested it over 2,000-barrels a day, brand you horizon, not a horizon that we have at the very beginning of the year, so dip is on 2,000-barrel a day type of test which if you were drilling more of the shallow wells which historically we were doing, where you might drill four or five wells in the same time frame with the same amount of money, you might only be looking at 200, 300-barrels. So you are looking at eight or nine times the production from these deeper wells. Once you finally get them on screen compared to the shallow wells and you're looking at probably four or five times the cost.

Yes, that's rig that we mentioned that nonoperating well in the same area as Parish, the Horseshoe Bayou area. That's the rig that we had working for us. We moved it over to the nonoperating well. The operated use of that rig coming back to us in probably two to three weeks. So, we think, like I said we have a good program to accomplish what we need to do this year. We got some upside in it. We got room and the inventory to increase that. We think the rig availability is out there as well.

Okay. So, is it seven wells you guys drilled in the second half of the year in South Louisiana? A lot of those were -- you were still doing other activities in deeper wells that maybe won't come on line until the first quarter or was it actually like a conscious reduction inactivity?

It wasn't an unconscious reduction or inactivity. Some of it just get carried over. You got the number while you're drilling on 1,231 so you don't really count a well in a quarter until it gets completed.

Yeah, okay. All right, guys, thanks.

Thanks, Bryan.

Thanks.

At this time, there appear to be no further questions.

Well, great. Thanks everybody for listening and for those of you that will be with us next week, we look forward to spending more time with you and we think it will be a great opportunity to get a lot more color on what we are doing. We are pretty excited about it and looking forward to showing it off next week. Thanks again. .

Thank you, this does conclude today's teleconference. You may now disconnect.