SilverBow Resources, Inc.
Q4 2007 Earnings Call Transcript

Published: 19 Feb 2008

[Operator:]

Good morning. My name is Marchita, and I'll be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy Company conference call. (Operator Instructions) It is now my pleasure to turn the floor over to your host, Mr. Scott Espenshade. Sir, you may begin your conference.

[Scott Espenshade:]

Good morning. I'm Scott Espenshade, Director of Corporate Development and Investor Relations. I'd like to welcome everyone to Swift Energy's fourth quarter and full year 2007 Earnings Call. In today's call, Terry Swift, Chairman and CEO will 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 today and have allowed additional time for questions and answers. And now, I'll turn it over to Terry.

[Terry Swift:]

Thanks, Scott. First, I would like to announce that after twenty 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'd 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 the new heights of achievement. While 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 non-cash 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 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 finding 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 it to be the crowned jewel 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 lifts such as gas lift. Combining these different pressure regimes requires constant monitoring, rebalancing, in some cases new facilities, especially when new discoveries are brought into the overall production system. The Westside facility expansion is on track and was key to aiding in this situation. The Westside facility will not only provide additional throughput capacity but just as importantly, it will allow us to help optimize the fuel for better overall productivity. The Westside 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 very 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 Cotula, Texas area. We'll continue to refer to this as the Cotula area. We kept two rigs 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 the AWP Olmos field in 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 relates to the New Zealand asset sale, this should close near quarter end and the proceeds will be applied to our bank line. With last fall's $90 plus oil prices and our acquisition, we decided to increase some of our activity. At the same time weaker natural gas process led to a moderating of day rates for land rigs. We expect this Btu disparity between 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 one-third of a long-term price deck will represent the cost recovery of the asset or the finding 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 reserved 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 the South Louisiana region and with additional activity across our other core areas including South Texas. Over the past several years Swift Energy has been spending for significant growth opportunities in the future with our facility and seismic investments. These investments should lead to lower future F&D costs, as we bring forward the opportunities that we see in our portfolio for 2008 and beyond. Swift Energy is committed to improving our capital efficiency metrics that starts with our finding 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 our 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 talent and 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 the sector. I look forward to our dialog at Swift Energy's up and coming Analyst Investor meeting which we are hosting here in the Woodlands less than a week away on Wednesday February 20th. It is here that we intend to showcase our 2008 plans and go into much greater details 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.

[Alton Heckaman:]

Thank you, Terry, and 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% at 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 very favorable effect on Swift's financial results. Swift's domestic average realized price in 4Q '07 increased 36% to $70 and 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 2006. In addition to higher commodity prices, production increases 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 was below our guidance. DD&A per unit 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 mix and locations. An 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 income from continuing operations for the quarter of $52.7 million which a $1.75 basic and $1.71 diluted, again bidding First Call mean estimate. As Terry mentioned in the intro and as we announced in last week's press release, we recorded a non-cash 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 of between $100 million and $110 million from the ultimate sale of all of our NZ assets and any future additional remaining proceeds above the recorded $88 million will be reflected as a gain from discontinued operations upon the execution of agreements that's 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 would 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 for the 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 prices. Please see our earnings press release and, of course, our subsequent Form 10-K filing that would get filed by the end of February for complete details. CapEx for the fourth quarter of $324 million which included Cotula property acquisition in South Texas resulted in borrowings under our 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 the available lines, we still have plenty of liquidity and resources for any additional value adding strategic opportunities that avail themselves. With respect to the Swift's hedging activity, we have purchased natural gas floors 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 floors for the second quarter covering approximately 40% to 44% of that quarter's natural gas production at an average strike price of $7.45 per MMBtu. We've 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 website 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. We are excited about what we see on the horizon for 2008 and beyond. And with more on that, I will turn it over to Bruce Vincent for an overview of our operations.

[Bruce Vincent:]

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 of our plans for 2008. You may have noticed that Swift Energy began reporting our production in 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. Regard to 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 equivalent 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 equivalent, 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 Cotulla 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 domestic reserves and our discontinued operations in New Zealand at 16.3 million barrels of oil equivalent or 98.0 billion cubic feet equivalent 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 our discontinued operations. Swift Energy's domestic reserves are 48% proved developed and are comprised 44% of crude oil, 43% of natural gas and 13% of natural gas liquids. Swift Energy's 2007 domestic capital spending was $703.2 million which implies a domestic 2007 finding and development cost of $27 per BOE calculated according to industry standards. Swift Energy's year end 2007 domestic proved reserves were valued at approximately $3.8 billion of present value discounted at 10% per year (PV-10) compared to $2.4 billion for the company's 2006 yearend domestic reserves. Domestic pricing for reserves and PV-10 calculation utilized $93.24 per barrel for crude oil and $6.65 per Mcf equivalent for natural gas in 2007 as compares to $60.7 per barrel and $5.84 per Mcf equivalent at year end 2006. As for our drilling results, Swift Energy successfully completed 25 of 27 wells in the fourth quarter of 2007. The company completed 24 or 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 feet 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 quarter's 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 million 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 injection at the Newport area. Swift successfully drilled and completed an exploration well in the Bay de Chene area. The BDC #U7 exploration well or Pisces prospect was tested with production rates of up to 2.1 million cubic feet per day on a 10/64 inch choke with 6085 pounds flowing tubing pressure. This well is currently shut-in and waiting on additional market outlets. Swift Energy is currently market constrained in the Bay de Chene area and we're pursuing alternative outlets. The service well recently drilled will begin our pressure maintenance project at the Newport area at Lake Washington in the next few weeks. We plan to inject water into two reservoirs to maintain pressure in two separate sands in aid in the ultimate recovery of the hydrocarbons that are in place in these reservoirs. While water injection will begin in the next few weeks, we do expect it will take a few months before we see the production response. This project has been undertaken with the Westside 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've previously disclosed our initial pressure maintenance project with the CM #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. Recently as January 24, the CM #222 well tested at 982 barrels a day. But after a recent acidization and clean-up, the well tested as recently as February 10, at 1,975 barrels of oil per day. That's an indication of the kind of response we get for 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 400,000 to 700,000 barrels of oil. In addition to these pressure maintenance projects, there may be additional recoveries available from tertiary projects but we haven't begun working these issues yet. In the Bay de Chene areas, Swift Energy is reviewing alternatives to be able to market more natural gas. Our well reserves as well as our geologic work suggest that we will need significant additional takeaway capacity. Swift currently has a marketing constraint due to a limited market for natural gas on the existing pipeline system that we connected. We are pursuing currently two alternatives for more capacity and additional optionality. First option we have begun is to build our own pipeline. This would take up to a year to complete. While we are 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 merged 3-D data set [that crosses] region covering approximately 4000 square miles. We now have the pre-stack depth migration work done at Lake Washington, Bay de Chene and Cote Blanche Island and are beginning to see the added value of these new data. We now have an even better picture of the salt-sediment interface as well as better imaging of the numerous faults and sand horizons. This will enable us to get further up-dip and closer to the salt and some [fault] blocks, look for other Embayment areas such as Newport and develop potential subsalt place in this area. We have also recently completed the fast track PSDM work at Cote Blanche Island and are already using that to look for potential salt overhangs for additional up-dip potential. We will be beginning the PSDM reprocessing of the Barataria bay and (inaudible) this year with the current merged data sets. All of our 3-D acquisition in processing work should continue to bear fruit for many years and help improve our finding 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 our 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 was originally designed to be drilled below the salt so we had limited drilling capability with these well bores at these depths. But the results do lead us to believe that we will find higher pressures, sands and hydrocarbons 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 6700 barrels of oil equivalent per day or 40 million cubic feet equivalent per day split between the AWP Olmos area and the new Cotula area. In the fourth quarter, we successfully completed 13 development wells targeting the Olmos sand in the AWP area. We have two rigs in the AWP field currently. In the new Cotula area, this is the Escondido Resources acquisition in October of last year. We drilled 9 of 11 development wells, drilling occurred predominantly in the Sun TSH field and also in the Briscoe Ranch field. We currently have three rigs working in this area now. The Toledo Bend region contributed approximately 2600 barrels of oil equivalent per day or 15.6 million cubic feet equivalent per day of production 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 operated in the South Bearhead Creek area. This area is showing potential and we're pleased with the results today. Due to the expected sales of New Zealand assets, we are treating it as discontinued operations in our financials. We expect the sale to Origin to close in the March-April timeframe 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 equivalent in the fourth quarter of 2007. There are approximately 3300 barrels of oil equivalent per day or about 20 million cubic feet equivalent per day for both the (inaudible). 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 recap and then we'll get into the questions and answers.

[Terry Swift:]

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 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 non-cash 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 at 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 a 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 have replaced 216% of our total production in 2007 or a 10% increase to 902 Bcf equivalent. We have a portfolio of high impact opportunities in our South Louisiana exploration programs which are now complemented with a significant South Texas gas portfolio which can deliver predictable growth and value. We are continuing to work our 3-D seismic for additional oil and gas opportunities to spotlight the value of our reserves and our production growth opportunities. We are encouraged by our progress in our core areas. We believe we have accumulated a valuable set 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 strategic 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:]

(Operator Instructions) Our first question comes from [Jason Wagler] of Dahlman Rose.

[Jason Wagler:]

Good morning, guys. Just curious the 13 rigs, the 4 barges and then the 9 land rigs, is that a pretty good run rate for the year?

[Terry Swift:]

Yes, 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, tend to be a little conservative on the front side in terms of what the outlook for prices are that served as well as historically over the last several years, we have been able to ramp up spending as we move throughout the year as we realize we are going to have a higher price deck and higher realized cash flow. But that is a good run rate for the first half. And if prices continue at the levels are at right now, probably good run rate for the second half too. But we just need to wait and see.

[Jason Wagler:]

Great. And I guess just on those, the contract-wise is there anything, in general because obviously the 13, are they well by well or are they contracted for certain period of time or anything?

[Terry Swift:]

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.

[Jason Wagler:]

Great. Thanks a lot.

[Terry Swift:]

Yeah. And then I guess the rigs in South Texas, I guess three of them are actually on turnkey contracts as opposed to day rate but it is all well to well.

[Jason Wagler:]

Okay, great. Thank you, guys.

[Operator:]

Our next question comes from Brian Kuzma of JPMorgan.

[Brian Kuzma:]

Hey, good morning guys.

[Bruce Vincent:]

Good morning, Brian.

[Terry Swift:]

Good morning, Brian.

[Alton Heckaman:]

Good morning, Brian.

[Brian Kuzma:]

Could you guys tell me just to confirm all of that guidance you have got given in your production of reserves, that is all organic?

[Terry Swift:]

That is all organic. We don't budget acquisitions. We obviously look at acquisitions all the time and target specific opportunities that are strategic in nature. Probably we would like to do one, but we don't budget it. We are focused on a drill bit that a little bit and we are going to deliver good growth from the drill bit in 2008.

[Brian Kuzma:]

Okay. Do you guys know like in your PV-10 calculation with the total development cost was associated with like the 400 PUDS you guys have?

[Terry Swift:]

Of course, we run those numbers and they are up from prior year and 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 our 10-K which will be filed later this month.

[Alton Heckaman:]

In two weeks.

[Brian Kuzma:]

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

[Alton Heckaman:]

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 towards the probable and possible, I think is 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 even 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 quite 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's going down.

[Terry Swift:]

Yeah, the other part of that, just to reemphasize, we've been making a big investment on the quality of our data to give us a better picture in lower order risk and as a consequent, particularly with the PSDM work in particularly in Lake Washington, we are getting much, much better clarity, much more accuracy with a drill bit, that does enable us to step back and take on what would have been perceived a year ago as a riskier project by lowering the risk because of the picture that we developed. It also enables us to do some of the deeper exploration things.

[Brian Kuzma:]

Okay.

[Terry Swift:]

And I think you're going to be with us next week, we'll definitely going to provide a lot more color on it next week.

[Brian Kuzma:]

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

[Terry Swift:]

Okay. Thanks, Brian.

[Operator:]

Our next question comes from [Garry Nuschler] of Jefferies & Company.

[Garry Nuschler:]

Thanks. Good morning guys.

[Terry Swift:]

Good morning.

[Garry Nuschler:]

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

[Alton Heckaman:]

We're building our own pipeline and we're also working to have other routes out. So we really believe that there is enough opportunity in Bay de Chene that we need to have several markets and several different ways out in the field. The pipeline that we've actually applied for the permit, received permit, we've already purchased pipe for, all in-cost for that probably about $10 million to $15 million.

[Garry Nuschler:]

Okay.

[Terry Swift:]

The same went down, I might add that we're working with another third-party system owner about building an interconnect to the current system and building another meter that will allow us to get more route quicker, so we think we're going to have enough potential in that field, we want the optionality of two alternatives.

[Garry Nuschler:]

Okay. Can you tell us what were fourth quarter volumes average or what was the average fourth quarter from Bay de Chene?

[Terry Swift:]

I don’t know whether we got that. I tell you 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 in 8-K which should be filed in two weeks.

[Garry Nuschler:]

Okay.

[Alton Heckaman:]

And I'm going to remind you and everyone else about Bay de Chene is we where are the pipeline system that goes one place, it goes to the ConocoPhillips Alliance Refinery but we are subject to whims of how much gas they can take and recently they've actually curtailed our gas deliveries a little bit, which is a reason we're both looking for an interconnect on that system to other outlets as well as build their own line.

[Terry Swift:]

Yeah, just a little bit of color on Bay de Chene. Last year's Bay de Chene number was just a little over 0.5 million barrels of production equivalent. It's actually mostly gas. We really expect some significant ramp up of that in 2008. We have got the well bores out in drill to demonstrate that, the tests are already conducted to demonstrate that and again we have got development wells and probables in this field that we will be tapping. I am going to go ahead and step out and say that we do believe Bay de Chene would be ever bit as big as in terms of volume as AWP or those types of fields. We see it going higher.

[Garry Nuschler:]

Okay. And my last question, Lake Washington production averaged just under 16,000 barrels. It had been averaging about looks like 18 to 20, prior to getting the Westside facility up and running, should we expect that they continue averaging around 16,000?

[Terry Swift:]

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

[Garry Nuschler:]

Okay, go ahead. Thanks.

[Operator:]

Our next question comes from Leo Mariani of RBC.

[Leo Mariani:]

Thanks. Can you give us an update at Lake Washington there on the construction plans in the Westside facility and give us little more insight as opposed to when you think it is going to come on?

[Alton Heckaman:]

Actually, everything is going pretty well. We have always said that we'd hope to have it in place by the end of the first half. We would hope to begin the commissioning process probably by April and you just don't buy a car and turn it into an ignition switch and all of a sudden it is working. There is a commissioning process that takes a month or so and then it takes time to kind of rebalance the system. One other significant things that that will help with regard to the Newport production, the Newport production currently goes about 3 miles to the 212 platform in order to get it processed out. Westside facility, it is a lot closer to that. And so that will immediately help, but once we get the Newport production flowing to the Westside we need to rebalance the older production that is going in to 212, 6700 and CM3 over the other main part of the field. But we expect to have it fully operational by the end of this first half of this year.

[Leo Mariani:]

Okay. Could you give us a little bit more in terms of visibility on the near-term exploration program. I guess obviously you guys had one success here in the fourth quarter. Is there anything that has been drilled right now? Anything you see in the next several months here?

[Terry Swift:]

Well, there is a lot of things being drilled right now. But in terms of high profile, high impact wells we are really not focusing ourselves on the market on that. We have got a pretty regular look at the deeper sections in Lake Washington and 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 [LI series], the [Kaysen series], the CC series. And we are finding more new accumulations at these deeper depths, we have noted that in the presentation, 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 where we could take them through what we call either salt wings or what we call the wells. And going through the salt wings or the wells, we have got some strap tests. And some strategic places within our seismic data cube where we were able to actually get through the well, find sands, get through salt wings, find sands, find hydro carbon but we didn't have enough mechanical ability nor did we want to go further for safety reasons. So, we've actually designed this year at least one deeper test where we are purposed 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. We won't focus on it to in that sense but it is a big impact well. In Bay de Chene we've got an opportunity there at a pretty large target that's been put together. Again later in the year that 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 some areas that in our seismic data cube where we may be active in leasing programs. Because one of the advantages is that we have these core areas where we do see very significant opportunities for both above the salt and subsalt, but also for example, we have Chester prospect that's between Lake Washington, Bay de Chene it kind of keys off of Bondi area where we had success before that. So you are going to see more of these kinds of high impact opportunities but we're not queuing them up one by one for presentation. We will show more of that at the analyst meeting in terms of showing seismic, some of the mapping and a much greater fuel for where these are.

[Bruce Vincent:]

As we've talked about before, and the whole strategy revolving around the 3D technology, the merged data set, the time-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, you're creating new geography. And as we both go deeper where there is other opportunity, but as we continue to drill within this data set and further re-calibrate the data set, we crystallize a much better picture than anyone has ever been able to see before and that's not just true at Lake Washington or Bay de Chen, it is true throughout the data set.

[Leo Mariani:]

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

[Terry Swift:]

Absolutely, we've had some drilling activity in Bayou Sale and Horseshoe Bayou, these are some nice areas. We have had some activity over in Jeanerette. In terms of again the 3-D, it does take time to fully integrate the well bore data sets with the 3-D, newly processed 3-D data sets that we have, we're doing that, we're making great progress. I think we'll show again at the Analyst Meeting the different stage of processing that we have our data sets in, we're in a well over what we call St. Mary's well over in Horseshoe Bayou, that's a pretty important well for us. We are pretty pleased with the results that are coming in there. We'll report more on that in the next several weeks. It's a deeper well. We have bit of 20% in that well. We also have a fault block, untested fault block in Bayou Sale that we're drilling, that's a new location that we're excited about. And going over to Jeanerette, we've identified some zones in the Jeanerette field that we also see by cast or areas that have some good pressure left in them and what has been a very significant producing field.

[Leo Mariani:]

Okay. Thanks a lot for the color.

[Terry Swift:]

Thanks Leo.

[Bruce Vincent:]

Thanks Leo.

[Operator:]

Our next question comes from Todd Swanson of Third Point.

[Todd Swanson:]

You mentioned the proved develop ratio for domestic reserves is 48%, what's that for domestic oil and then domestic gas?

[Bruce Vincent:]

I think we have it in front of us.

[Terry Swift:]

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 the information right now.

[Todd Swanson:]

Okay. How about then on Lake Washington, you've mentioned lot of the focus this year will be on converting PUD. What is the cost to draw and complete a development well there and then what's the dry hole cost for a development well?

[Terry Swift:]

Well, actually I want to clarify your statement, the focus issue this year at Lake Washington is going to be much more on converting probables and possibles to prove not so much on PUD. But, many actually will be able to clarify lot of this or give people color on to come to me next week. Many of the wells we drill have a PUD component and an exploration component to them and we also try to design the well or such that it does intersect some fault blocks it may be proven on developed occasions but also design it go deeper to target probable abd possible locations. So you can have a combination of things and in particular well bore but the principal focus in Lake Washington of our program there is really to try to focus on the probable and possible conversion.

[Todd Swanson:]

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

[Terry Swift:]

The well costs ranges significantly depend on the depth. They depend upon the well track, whether it is a straight hole or a curved well. But generally it is running about $275 a PUD approximately.

[Todd Swanson:]

$275 a PUD?

[Terry Swift:]

Yeah.

[Todd Swanson:]

Okay, thank you.

[Operator:]

Our next question comes from [Greg Bolden] of Friedman and Billings.

[Greg Bolden:]

Good morning, gentlemen.

[Terry Swift:]

Good morning.

[Greg Bolden:]

Now that you guys are forecasting a jump in crude oil volumes after the first quarter, can just talk a bit about how that is going to play out through the year especially in regards to the Westside expansion and the water injection projects?

[Terry Swift:]

Yeah, we obviously have 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 in particular an area where we are drilling wells and we are doing some marketing outlook work that should again help us increase production from Bay de Chene. We have got a fairly robust program down in South Texas with our Cotulla area, our newly acquired properties as well as AWB, where we will be 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 have noted that there is two aspects at Lake Washington that we put in to our production forecast. One is the installation of the Westside facility that should give us additional capacity and additional flexibility so that we can optimize some of the different types of crude oil streams that we have, the gas streams as well as some of the higher pressure wells that go in to 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 setback rather due to the higher pressure wells pushing them out in a temporary way. We also have our injection projects, our pressure maintenance projects that are going on. They work hand in hand with both the Westside facility and the opening up of expansion back in the older facility. So that is the plan and that is what we are going to make out.

[Greg Bolden:]

Thanks. One another one and the release you guys put out earlier this month on the year end reserves, you mentioned a little bit of downtime at Lake Washington associated with choke change up for pressure maintenance. Wondered if you could talk a little bit about the rationale behind changing up a chokes versus pinching the back or something?

[Terry Swift:]

Well, in pressure maintenance you can 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's called a secondary gas cap form and that gas cap kind of like the fizz in a Coke bottle is your energy and you really don't want to let all of your energy out because it can also, 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 of our wells in the Newport area become more gassy, particularly the up dip wells it made good reservoir sense to choke back on some of that gas, not produce it now so that we can save the fizz in the Coke bottle that it helped get the oil out.

[Greg Bolden:]

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 well pack?

[Terry Swift:]

That's just a 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 -- that's just terminology in the business.

[Bruce Vincent:]

You say change the choke, it doesn't mean you necessary go in there and change one for the value, you are just changing the sizes or adjusting the size over it.

[Greg Bolden:]

Okay, great. Thanks.

[Operator:]

Our next question comes from Jeff Robertson of Lehman Brothers.

[Jeff Robertson:]

Thanks. I apologize, I may have missed part of this on the conference call but Bruce, can you talk a little bit about the reserve additions and also the revisions on both natural gas and where those came from and on oil what the negative revision related to and also where you added oil reserves?

[Terry Swift:]

Well, I don't have all that detail in front of me. Jeff, but the net effective revisions was pretty neutral, but as you know those come across the set of properties, some are positive, some are negative even within fields like Washington in particular where you probably got a 100 different 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 that jumped out and caused us any concern or alarm. There is nothing beneath that, like I said, it really is a cause for concern. The specifics, I'd have to get the reserve report out and look at each of the field and then within the field like I said underneath it, understand which fault blocks we're talking about. And I would say lot more that detail would be in the 10-K that should be filed in about two weeks.

[Jeff Robertson:]

And we need to know that even though you do have some negative revisions and positive revisions, these are still very percentages as relates to the whole reserve base. Can you all talk where you added reserves? Where you added gas reserves?

[Terry Swift:]

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

[Jeff Robertson:]

Excluding the acquisition?

[Terry Swift:]

We added gas reserves in the Bay De Chen area, Jeanerette area, trying to pull the numbers out and getting them out in front us.

[Bruce Vincent:]

That just Mcfe.

[Terry Swift:]

Yeah, we've got Mcfe equivalent in front of me. We'll have to get that detail out in the 10-K as well as in the analyst presentation next week.

[Jeff Robertson:]

Okay, thank you.

[Terry Swift:]

Thank you.

[Operator:]

Our next question comes from Brian Kuzma of JPMorgan.

[Terry Swift:]

He is back.

[Brian Kuzma:]

I told you I'd be back. When you guys look at Lake Washington and let's say in the 2009. Should we be expecting production to be back above or close to the 20,000 barrel a day level you guys were at last?

[Terry Swift:]

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

[Brian Kuzma:]

Okay. And then just to clarify at Bay de Chene, there is two options you listed. You are pursuing both of those options.

[Terry Swift:]

Right, yes.

[Brian Kuzma:]

Okay. And the earliest you could see an expansion would be with this third party option by the middle of 2008?

[Terry Swift:]

That's correct and that's moving forward as just one, we want to have optionality. Two, we don’t want to be dependent upon a third party or somebody done completely come through with what they said they are planning to do. We think they will and that will give us increased outlet certainly by the second half if not may be a little before but let's assume, July 1 right now.

[Brian Kuzma:]

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

[Terry Swift:]

It would be significant. It would be more than we could produce the capacity we are going for.

[Brian Kuzma:]

Okay. And then on wells that you took down below the South wells, how deep did those go?

[Terry Swift:]

They are approximately 16,000 feet.

[Brian Kuzma:]

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

[Terry Swift:]

Well we don't actually have the actual design yet, but approximately $15 million. It is going to require an additional string of casing.

[Bruce Vincent:]

Yeah, I will comment on that just a little bit more, there are several different prospects that we are seeing that one might characterize as subsalt 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 will probably be more expensive than what we are talking about here. But there is also some where we are really kind of referring to these more like salt wing, their intersections of salt you go through and then there is some others that look like you might actually be able to be out bored and drill directionally under the salt. We will show some of that at the analyst presentation next week. Each of those has a different cost profile and risk profile to it. And different, different target sizes too.

[Brian Kuzma:]

Okay. And then in South Texas, I mean you had a couple unsuccessful development wells on these new properties, I mean what are seeing 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 that you are expecting on this new acreage?

[Terry Swift:]

Well, we haven't found any limits to give us any concern I mean it is just like an AWP where we drill 500 wells as you occasionally you are going to hit a falter, you are going to hit an intersection or a lower permeability section that is not going to be economic, you are not going to complete it. We are still doing a lot of work there. But we have got a larger acreage position, we are real excited about it. We think that that is going to turn in to an anchor top property just like AWP has been for the last twenty years for us.

[Brian Kuzma:]

Okay. And should we still be using like 215 million per well for EURs.

[Terry Swift:]

Yeah. That's probably a good number to use.

[Brian Kuzma:]

Did you get higher liquid?

[Terry Swift:]

Yeah, there is much a higher liquid content down there, it's about 1300 or so, yeah it's like 1300 BTUs, I think. If you get a much higher liquid content, which certainly helps with the economics.

[Brian Kuzma:]

Okay. And then just real quick on the 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 got three rigs running right now, 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?

[Terry Swift:]

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

[Bruce Vincent:]

Yeah, I'll comment on that also, again going back to Lake Washington in particular, the deeper wells that we drilled in Lake Washington are clearly more expensive and they take longer to drill, therefore, when you put one of these bigger rigs on there, you don't get as many wells out of it. But at the same time one of our more recent wells, we tested it over 2000 barrels a day, brand new horizon, not a horizon that we had at the very beginning of the year, so deeper zone, 2000 barrels 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 barrels, 300 barrels. So you're looking at eight or nine times to production from these deeper wells, once you finally get on-stream compared to the shallow wells and you're looking at probably four, five time of cost.

[Terry Swift:]

Yeah, the rig that we mentioned the non-operating well in the same area as Parish, the Horseshoe Bayou area, that's a rig that we had working for us. We moved it over to the non-operated well and that rigs coming back to us in probably two to three weeks. So, we think we got a good program to accomplish what we need to do this year. We got some upside in it; we got room in the inventory to increase that. We think the rig availability is out there as well.

[Brian Kuzma:]

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

[Terry Swift:]

It wasn't a conscious reduction in activity and some of that just carried over. You got the number of wells that we're drilling on 12, 31, so you don’t really count a well in a quarter until it gets completed.

[Brian Kuzma:]

Yeah. Okay. I got it, thanks.

[Terry Swift:]

Thanks, Brian.

[Bruce Vincent:]

Thanks.

[Operator:]

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

[Scott Espenshade:]

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. We think it would be great opportunity to get a lot more color on what we're doing. We're pretty excited about it and looking forward to showing it off next week. Thanks again.

[Operator:]

Thanks you. This does conclude today's teleconference. You may now disconnect.