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Swift Energy Company (NYSE:SFY)

Q4 2008 Earnings Call Transcript

February 19, 2009 10:00 am ET

Executives

Paul Vincent – Manager of Investor Relations

Terry E. Swift – Chief Executive Officer

Alton D. Heckaman, Jr. – Executive Vice President and Chief Financial Officer

Bruce H. Vincent – President & Secretary

Robert J. Banks – Executive Vice President and Chief Operating Officer

Mike Kitterman – Senior Vice President of Operations

Analyst

Adam Leight – Credit Suisse

Andrew Coleman – UBS

Leo Mariani – RBC Capital Markets

Curtis Trimble – Natixis Bleichroeder

Jeffrey Robertson – Barclays Capital

Operator

Good morning. My name is [Angelia] and I will be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy’s fourth quarter 2008 year-end and earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions) Thank you. Mr. Vincent, you may begin your conference.

Paul Vincent

Thank you, good morning. I am Paul Vincent, Manager of Investor Relations. I would like to welcome everyone to Swift Energy's fourth quarter and full year 2008 earnings conference call. In today's call, Terry Swift, Chairman and CEO, will provide an overview. Alton Heckaman, EVP and CFO will review the financial results for the fourth quarter. And then Bruce Vincent, President, and Bob Banks, EVP and COO will provide an operational update. Terry Swift will then summarize before we open it up for questions. Also present on the call are Mike Kitterman, Senior Vice President of Operations.

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 operates. These statements involve risks and uncertainties detailed in our SEC reports to which we refer you along with cautionary statements contained in our press releases. And our actual results could differ materially. We expect our presentation to take approximately 25 to 30 minutes and have allowed additional time for questions.

Terry Swift

Thanks Paul. Thank you again for joining this morning's conference call. Before we comment on the fourth quarter, it's important to know to our shareholders and the investment community participating on the call that we are clearly in a time of worldwide uncertainty. Despite earlier efforts by the federal government to rescue some of our largest financial institutions, we continue to see significant need for financial support from the government.

Global equity and commodity markets continue to be very volatile. Unfortunately, during 2008, Swift and other Gulf Coast oil and gas producers also dealt with two major hurricanes, Gustav and Ike. And the time since our last quarterly conference call, crude oil and natural gas prices have continued to deteriorate as global economic results and forecast have continued to weaken.

Hydrocarbon pricing has fallen from peak season in summer of 2008 much more quickly than in previous downturns, which we witnessed over the past 25 years. The steep decline in prices is exerted increased stress levels on our business. The Contango oil market and the resulting surplus crude oil industries are in our judgment creating greater than normal downward pressure on oil and gas asset evaluations.

Unfortunately, Swift Energy has ended 2008, with a significant non-cash write-down due to dramatic drop in oil and gas prices. During our 29-history we've observed many pricing downturns and as a result have always employed a conservative financial strategy of low leverage and high liquidity.

We've also observed that drilling and completion costs have increased faster than oil prices over the past 10 years. And while our cost have begun to retreat recently, we don’t believe they're anywhere near the levels required for the industry to resume recent activity levels. In fact, the domestic rig count is still decreasing weekly and will probably not bottom out for several more months. All that said drilling and completion costs are still trending downward.

We view price risk management as a necessary component of our business. We try to protect our activity by purchasing floors or put options on oil and natural gas prices during a given quarter. We take a disciplined approach to purchasing these floors during the periods of rising oil and gas prices with the hope that we not ever collect on. However, in the event of the precipitous decline in commodity pricing, these floors do provide us with revenue and time to conclude our current operations during the given period and adjust our operating budget to market conditions. Unfortunately as a result of the recent price declines, the fourth quarter saw and collected over $28 million from the oil and gas natural gas floors that we have in place.

As I mentioned earlier, low leverage and higher liquidity have always been a major component of our financial strategy. We ended the year with approximately $181 million drawn on our bank line. Our bank facility has borrowing base of $400 million, and a commitment amount of $350 million. Alton will give further comments on our bank line in his financial presentation.

We have taken significant steps during late 2008 and early 2009 to reduce our spending levels and an effort to preserve our liquidity. Major initiatives related to cost reduction include releasing all rigs that we had operating during the fourth quarter of 2008, and adjusting our operations and facility usage levels, which will reduce lease operating expense by approximately $25 million in 2009 or 23%. We have also made significant moves to reduce gross general and administrative expenses and expect to reduce these expenses in 2009 by approximately $10 million, or 24%.

Although 2008 ended on a different note than it began, I must mention that during the year Swift Energy did generate record revenues, cash flows and income from continuing operations after adjusting for the effects of a write-down of oil and gas properties.

Operationally, as we’ll discuss in today's call, we have several projects to report on which have us very excited. The success of the State Lease 18669 #1 exploration well at the Shasta prospect in our Southeast Louisiana core area was very encouraging for exploration activity in this area. This well is an excellent example of the projects we are developing from our large regional 3D datasets in Southeast Louisiana.

We won't be able to speak about reserve implications of precise recovery expectations of this prospect until we've completed more sustained testing and observed longer-term well performance. But initial indications are that this is in fact a very large discovery and as potentially size of 30 to 50 bcf equivalent wells. This discovery also helps us to asses the risk associated with other prospects in the immediate area and it leaves us very excited about other activities we've ongoing there.

Including the recent Shasta discovery, the Company currently has 3,000 to 5,000 net barrels of oil equivalent per day of shut-in production awaiting pipeline construction or facilities repairs in the general Bay de Chene area.

Our exploration-drilling program will remain curtailed until market conditions improve, but we will continue to develop and mature sizable exploration projects from within our databases and datasets and increase the quality and quantity of our inventory of projects.

In the AWP field, in our South Texas core area, we drilled our first horizontal well in the Olmos formation. The Robert Bracken 33H well recently was completed with a nine-stage simultaneous hydraulic fracture enhancement. This is the first horizontal well of this type that we drilled in the Olmos formation and almost 20 years of drilling activity in the field.

This well is located in the southern portion of the field, and we believe it will result in an extension of the productive limits of AWP. We are pleased with the initial performance of this well and we will drill at least three additional horizontal wells in 2009 in locations designed to extend the fields.

Over the course of 2009, we will report on implications of the use of this technology. Not only in AWP, but throughout all of the approximately 120,000 acres we view as perspective to Olmos development. We have also analyzed the potential that both existing and recently acquired acreage has for the Eagleford Shale formation, another productive horizon found in our operating area.

This analysis leads us to believe that as of the day, we have approximately 45,000 acres, which maybe perspective in this play. We will drill at least one vertical well in 2009 to test this formation on our acreage. It is during times and great uncertainty and fear that experience and discipline are rewarded, is our job to be prudent custodians of assets and capital provided to us by stakeholders.

Although, we have the ability to borrow additional funds under our bank line, we will only utilize that ability to find the critical projects, which will create long-term value. There could be no mistake and this downturn is severe and if current conditions persist, we are prepared to curtail activity even further and expect year-over-year production and reserve declines in 2009 to allow for the longer-term growth.

Our short-term goals resolve and revolve around positioning Swift Energy Company not only to endure these difficult times, but remerge a stronger more efficient company.

With that I will ask Alton to present the fourth quarter 2008 and 2008 financial results.

Alton Heckaman, Jr.

Thanks, Terry and good morning everyone. The oil and gas sector indeed is experiencing extreme volatility. Swift Energy's financial results for the fourth quarter reflect its volatility. Revenues were $145.4 million, a 26% decrease from 4Q '07. These revenues include $28.8 million recorded as other revenues, the vast majority of which is price risk gains from our oil and natural gas floors that we had in place.

As Terry mentioned, $754 million non-cash full cost ceiling write-down was recorded during the quarter, as low oil and gas prices at year-end 2008, significantly reduced our PV-10. The write-down was approximately $473 million after-tax. Excluding this non-cash write-down, income from continuing operations was $20.6 million, or $0.66 per diluted share beating First Call Mean Estimates.

Cash flow before working capital changes decreased 35% per diluted share to $2.73 and 4Q '08 production decreased 12%, to $2.5 million barrels of oil equivalent following the result of the 2008 hurricane events.

Both crude oil and natural gas prices decline from both sequential and prior year quarterly levels. Swift's average realized price in 4Q '08 decreased 33%, $47.28 per Boe due primarily to crude oil prices declining to an average of just under $59 per barrel compared to approximately $89 per barrel during the fourth quarter 2007, resulting in a decrease in our quarterly oil and gas revenues of 41% when compared to the prior year.

We continue to focus on our controllable per unit cost and metrics, especially given recent pricing volatility and the downturn in the industry. For the fourth quarter, G&A came in at $3.39 per barrel below our guidance, as we reduced annual incentive awards in 4Q '08 inline with the final 2008 financial and operational results.

DD&A per unit came in at $24.45 per barrel, higher than guidance primarily due to year-end reserves coming in lower than expected, due to the pricing and technical revisions that will be further discussed.

Production cost came in below guidance, $10.10 per barrel and the interest expense decreased slightly to $2.93 per barrel, which was to the high-end of our guidance. Productions taxes actually came in below our guidance as a percentage of revenue mainly due to the production mix for the quarter.

As previously noted the company recorded $754 million pre-tax non-cash reduction in the carrying value of oil and gas properties, the result of a full cost ceiling test impairment in the fourth quarter.

The full cost ceiling test is a quarterly test based on SEC commission rules for companies that follow the full cost method of accounting. Reserve was a loss from continuing operations for the quarter. a $452.5 million or $14.66 loss per share both basic and diluted. Excluding the non-cash write-down, as I mentioned our income from continuing operations was $20.6 million, or $0.66 per diluted share.

As I am sure most of you are aware in December 2008 the SEC issued some new rules, which were effective for financial statements issued on or after January 1, 2010, which changed the accounting and disclosure requirements surrounding oil and gas reserves, intended to modernize and update the oil and gas disclosure requirement and align them with current industry practices and adapt to changing in technology.

As we indicated in our press release, the company would have used considerably higher crude oil and natural gas prices both accounting, impairment test, as well as calculating the PV-10 value and these new rules been in effect a year earlier.

Cash flow before working capital changes came in at $85 million, or $2.73 per diluted share. Our EBITDA was $101 million for the quarter. Fourth quarter CapEx was $155 million.

Given the recent global credit crisis and the effect on the financial market, let me spend a moment to highlight with solid financial position and discuss a few of our cost containment initiatives that Terry mentioned in the introduction.

Swift's debt-to-cap ratio was 49% at year-end 2008 even after the non-cash write-down of oil and gas properties, which highlights our conservative leverage strategy and our conscious historical decision to basically maintain our CapEx within cash flow. Our two senior notes outstanding had very good interest rates and are well aligned with our long-term assets.

As mentioned earlier, before we expect 2009 will be a difficult operating environment and we will require greater discipline and emphasis on reducing costs across the enterprise, which we have already begun.

Our first step in this initiative was reduction in our workforce that we implemented during the first quarter of 2009. Although a very difficult decision it was one we felt like we had to make.

Reduction and headcount that we have made will reduce G&A cost going forward, although the effect on 1Q '09 will be minimal given the severance and other associated costs. We’ve also implemented other cost saving initiatives in the G&A area, that will have an impact going forward and that's reflected in our guidance. We are also looking closely at our CapEx and our operating expenses and we have identified several cost saving opportunities in all of our core operating areas. We also were working very closely with our vendors for additional cost savings for goods and contract services.

With respect to our $500 million bank line facility, with our 10-member bank group that currently runs through October 2011, as Terry mentioned, our borrowing base was reaffirmed at $400 million in November and we continue to maintain the commitment amount of $350 million.

Swift had an outstanding balance underline of $181 million at year-end 2008, with the rollover of year-end cost into '09 and the lower hydrocarbon pricing environment, our drawdowns have decreased. But our current cash forecast do not anticipate our drawdowns exceeding $250 million at any point during 2009. We therefore feel our liquidity and resources are very solid and available to weather these difficult financial times.

We continue to maintain a conservative financial discipline, and have a 2009 budget that enables us to live within our means with limited drawdowns on our line of credit. I should note that the recent affirmation of our lines speaks to our solid bank group. We continually monitor and review the creditworthiness of the banks that fund our credit facility and thus far our bank liquidity has not been impacted.

Swift also continues to closely monitor our customers, from our joint interest owners to the purchasers of our oil and natural gas. Our stringent process for evaluating the creditworthiness of people would owe us money has resulted in a stellar record for minimal historical credit losses.

Given the downturn in the industry, this is an even more critical process we are keenly focused on. We believe that risk of these unsecured receivables is mitigated by the size, reputation, and the nature of the companies to which we extend credit. And certain customers will also obtain letters of credit, parent company guarantees if applicable and other collateral as considered necessary to reduce our risk of loss.

And as the Swift 4Q '08 hedging activity as mentioned earlier, we have significant gain of $28.8 million from our hedges in the fourth quarter, however, recent downward pricing volatility has not allowed the Swift to currently enter into any 2009 hedges. Our website remains the best source for complete and current detailed ongoing hedging activity. And as always, we’ve included additional financial and operational information in our press release including the initial guidance for the first quarter and full year 2009.

These are indeed difficult times in our world and in our sector. I think Swift is well positioned financially to take advantage of any opportunities that seem to present themselves during periods of uncertainty and adversity. We continue to be up to the challenge.

And with that, I will turn it over to Bruce Vincent for an overview of our operations.

Bruce Vincent

Thanks, Alton and good morning everyone. Today, I will discuss fourth quarter of 2009 activity including our production volumes, year-end results, recent drilling results, activity in our core operating areas and our plans for the rest of the 2009.

And then we are going to have Bob to provide a little more detail on the Shasta discovery and the horizontal wells in AWP, two of our recent projects that we're pretty excited about.

Beginning with production note, Swift Energy's production from continuing operations during the fourth quarter of 2008 totaled 2.47 million barrels of oil equivalent, or 14.8 billion cubic feet equivalent, a decrease of 12% from the 2.7 million barrels of oil equivalent or 16.2 billion cubic feet equivalent, produced in the same quarter of 2007.

As previously disclosed approximately 300,000 barrels of oil equivalent of production was shut-in during the quarter as we continue to recovery from Hurricanes Gustav and Ike.

Sequential production increased 6%, when comparing the fourth quarter of 2008 production to production in the third quarter of 2008.

Now for our reserves, Swift Energy's year-end 2008 reserves consist of 116.4 million barrel of oil equivalent, or 698.6 bcfe. This is a 13% reduction from 2007 year-end reserves of 133.8 million barrels of oil equivalent or 802.7 bcfe. Of these reserves, 53% were proved developed compared to 47% of reserves classified as proved developed at year-end 2007.

While Swift Energy has not historically released probable and possible reserves in the past, we believe that given the release of the new disclosure rules, now would be a good time. The company estimates that at year-end 2008, it had 51.1 million barrels of oil equivalent of probable reserves, and 68.9 million barrels of oil equivalent of possible reserves.

These probable and possible reserves do not incorporate any amounts or acreage acquired subsequent to 12/31. 75% of the total downward technical revisions and 98% of the net downward technical revisions is discoveries and extensions plus technical revisions occurred in Cote Blanche Island and Horseshoe Bayou, Bayou Sally. I'm sure there will be more questions on our reserve and we will discuss our 2008 proved, probable and possible reserves in great detail during the Annual Analyst Investor Day, which will be hosted in Houston next Thursday, February 26.

Swift Energy's year-end 2008 proved reserves were valued at approximately $1.4 billion of present value discounted at 10% PV-10 compared to $3.8 billion of the companies 2007 million reserves from continuing operations. Pricing for reserves and PV-10 calculations utilize $44.09 per barrel for crude oil, and $4.96 per Mcfe for natural gas in 2008, compared to $93.24 per barrel of oil and $6.65 per Mcfe at year-end 2007.

Moving to our drilling reserves, Swift Energy completed 29 of 32 development wells in the fourth quarter of 2008, a completion rate of 91%. I will briefly review our activity in each of our core areas. Beginning with our Southeast Louisiana core area, which includes the Lake Washington and Bay de Chene fields and that also incorporate the Shasta prospect, which lies between those two fields.

Production during the fourth quarter of 2008 averaged approximately 13,447 net barrels of oil equivalent or 81 million cubic feet equivalent per day in this area, an increase of 6% when compared to our third quarter 2008 average net production from the same area. This is primarily due to increased production from Lake Washington as no shut-ins related to the storms or weather occurred in this field during that quarter.

Lake Washington averaged approximately 13,027 net barrels of oil equivalent per day, or 78 million cubic feet equivalent per day, a 27% increase when compared to third quarter of 2008 volumes.

The Bay De Chene sequential production decreased 82% to 420 net barrels of oil equivalent per day as production remain completely shut-in for most of the quarter. At the end of November, high-pressure gas sales resumed in Bay de Chene, but all volumes remained shut-in until further repairs can be completed. The field is currently averaging approximately $13.2 million cubic feet equivalent of production per day.

Oil production is expected to be resumed by midyear in the third quarter. In total we estimate 3000 to 5000 barrels of oil equivalent per day of production net are currently shut-in in this field and our recent Shasta discovery.

At the Lake Washington field is Plaquemines Parish Louisiana, five wells were drilled during the quarter. Facilities construction and upgrades in the Bay de Chene field commenced during the fourth quarter allowing for high-pressure gas production to resume.

Production and processing equipment is being ordered and will be installed during the first half of 2009 on a large concrete barge, similar to the one the Company used to build its Westside facility in Lake Washington. Once constructed, this equipment will set approximately 18 feet above water, which should reduce the risk of catastrophic damage from hurricanes and severe storms in the future. The Company expects Bay de Chene production to be at or above pre-storm levels once these new facilities have been fully commissioned.

In Bay de Chene during the fourth quarter, the BDC VUC #9 well was drilled to 14,809 feet and encountered 78 feet of net pay in one zone. This well tested with production rates up to 4.8 million cubic feet per day of gas on a 23/64th inch choke with 1,750 pounds of flowing tubing pressure and is now currently producing to sales. We have also tested the first well drilled at the Shasta prospect and in a few minutes Bob will speak about those results in more detail.

Although the current operating environment is challenging, additional, high impact exploration activity will continue in 2009 if market conditions allow. Further the company continues to carryout the work necessary to resign and plan an 18,000 to 20,000 feet sub-salt test in the Lake Washington area. The timing of which is also depended on the more favorable commodity and operating environment as well as continue to develop and enhance our inventory of future projects.

Swift Energy maintains a substantial inventory well on the drilling projects, but currently has zero rigs operating. The Company intends to commence its 2009 drilling program once oil field drilling and service cost actively reflect the current operating and pricing environment. In our South Texas core area, which includes our AWP field, Sun TSH, Briscoe Ranch, and Las Tiendas fourth quarter 2008 production add us 8,226 barrels of oil equivalent per day, and 49 million cubic feet of oil per day. A 12% increase in production when compared to third quarter of 2008 production in the same area.

During the fourth quarter we completed 12 of 12 development wells in the AWP area, 5 of 7 development wells in the Briscoe Ranch field, and 4 of 5 development wells in the Sun TSH field. The highlight of the fourth quarter in this area was the drilling and subsequent completion during the first quarter of 2009. The first horizontal well Swift has drilled in the Olmos formation.

Bob will provide some more color on this in just a few minutes. The Central Louisiana/East Texas core area, which we have previously referred to as Toledo Bend contributed 2,719 barrels of oil equivalent per day of production in the fourth quarter of 2008. One well was drilled in South Perry Creek during the fourth quarter.

In our South Louisiana core area, which is comprised of Horseshoe Bayou, Bayou Sally and Jeanerette, Cote Blanche and Bayou Bijou, production averaged approximately 2090 barrels of oil equivalent per day or 12.5 million cubic feet equivalent per day. During the fourth quarter an increase of 6% when compared to third quarter production in this area primarily as a result of operations been uninterrupted by hurricane.

I will now turn it over to Bob Banks to review some of the more notable activity during the quarter.

Robert Banks

Thanks Bruce. First the previously announced discovery well at the Shasta prospect in the company's Southeast Louisiana core area was tested during the fourth quarter. The well tested at a rate of 11 million cubic feet of gas per day and 739 barrels of oil per day at 11,279 psi on a 14/64 inch choke. Due to the distance of this discovery from production facilities, further delineation will not occur until later in 2009 after a pipeline has been built to the Company’s Westside facility in its Lake Washington field. The pipeline will be approximately 8 miles long and will be completed during the first half of 2009.

Moving to the AWP field, as Terry and Bruce have talked about located in the Company’s South Texas core area, the Company drilled the R Bracken 33H well in the southern portion of the field to a measured depth of 14,322 feet. This includes a horizontal lateral leg of 3,530 feet in the Olmos formation. A nine stage simultaneous hydraulic fracture enhancement was performed while completing this well during the first quarter of '09.

Peak test rates of 10.4 million cubic feet equivalent per day were achieved on a 36/64 inch choke with flowing tubing pressure of 2,725 psi after fracture enhancement and it is now flowing to sales at a sustained rate of 6.3 million cubic feet equivalent per day on a 32/64 inch choke with flowing tubing pressure of 1,880 psi. The R Bracken 33H is expected to recover between 3 and 5 billion cubic feet of natural gas.

As this was the first well of this type that the company has drilled in this formation, the final well cost was approximately $9 million to drilling complete. By eliminating certain procedures and realizing both costs and operational efficiencies, we expect to be able to drill similar wells in the area in the future for approximately $7 million.

At least three additional horizontal wells are planned in the Olmos sands as part of the Swift Energy’s 2009 capital program. The results of these wells will be used and to determine the extent to which this type of drilling and completion technology will be applicable for the Olmos formation in the AWP and Sun TSH fields as well as for the additional acreage which the Company has recently acquired in the area.

Further analysis of the R Bracken 33H well will be conducted to determine the effectiveness of the multistage fracture enhancements, the decline rates associated with the reservoir and potential implications on future reserves bookings. The Company has acquired 16,203 net acres since year-end 2008 and we now have approximately 120,000 acres leased in South Texas, which maybe prospective for further Olmos development.

During 2009, Swift Energy will also drill a well to test the potential of the Eagleford Shale formation and the Company currently has 45,000 acres leased in the area, which make it prospective for this formation. And lease and acreage acquired in early 2009 in the area, is also prospective for this formation.

Thanks for your attention this morning. I will turn it back to Terry to recap.

Terry Swift

Thanks Bob. Before we open up the line for questions, I want to summarize Swift Energy's fourth quarter results in 2009 planned activity to review some of the highlights from this morning’s call. Swift Energy is monitoring economic and operational environments in the real time. We maintained frequent dialogue with our bank group and believe we have ample liquidity to weather the current downturn.

Although, we did have a significant non-cash write-down, we also had strong financial results in the fourth quarter of 2008 with revenues of $145.4 million, income from continuing operation was $20.6 million, or $0.66 per diluted share before the ceiling test adjustment of our oil and gas properties and cash flow of the full working capital changes was $85.3 million, or $2.73 per diluted share.

We expect to get our Shasta discovery on production by midyear, additional development will be conducted as market conditions improved. This is a great discovery, which will help us to analyze and develop other prospects in the area, including the recent Shasta discovery the company currently has between 3000 to 5000 net barrels of oil equivalent per day, shut-in production awaiting pipeline, construction, and facility repairs in the Bay de Chene area.

Our first horizontal wells in Olmos sand has performed as the high-end of our expectations. As a result, we will be moving forward additional horizontal wells in this area and also evaluating the Eagleford Shale in our operating area. If these wells proved to be successful, we expect very possible positive results to both our production and reserved numbers for 2009.

Next Thursday, February 26 we will host an Analyst Investor Day here in Houston. At this meeting, we'll review our 2008 operational and financial performance and detailed our 2009 plans and guidance

Lastly, we've have been through pricing downturns in the past. We believe that we have the experienced people and assets to emerge from this downturn in a better position relative to our competition.

At this time, we would like to begin the question and answer portion of our presentation.

Question-and-Answer Session

Operator

(Operator Instructions). Our first question is from the line of Adam Leight.

Adam Leight – Credit Suisse

Hi, good morning.

Paul Vincent

Good morning Adam, How are you?

Adam Leight – Credit Suisse

I'm well. Thank you. Can you give us an idea you sort referenced it, and maybe I missed it, but price related revision versus technical revisions, first of all?

Paul Vincent

We are going to go over that in the meeting next week and I think that’s really better place to do that, we do have an idea of that. And we are going to detail in the presentation next Thursday.

Adam Leight – Credit Suisse

Okay, how about on the CapEx side, either for '08 how much of that was drilling versus acreage and facilities in the ’09 number. Particularly given the reduction and the indication that you are differing drilling and spending, how much of that is infrastructure? And how would you expect the quarterly progression of capital spending to proceed?

Paul Vincent

The question relates to how much of the ’09 projected budget is drilling versus infrastructure?

Adam Leight – Credit Suisse

Yeah, that will do. And then timing?

Paul Vincent

Again, we're going to lay all that out next week. And I think its really better for us to be able to lay all that out and talk about it much more detail and try to do it over the call?

Robert Banks

Yeah, I think we can add to that, though that 2009, we focus very much on recompletions, fracture treatment enhancements. We also have a lot of shut-in production where we we're spending the money either through pipelines or through facility upgrades to get that production on. It's very meaningful to us. We ended the year with quite a lot of activity and lot of completion going on there. Some of that money flows over into 2009 finishing up those completions. We do have development well drilling that will continue in the South Texas. We also have a couple of delineation type wells that we'll be drilling, but we really backed off of the exploratory component. So we'll get you those details, but I think it is very clear to say that it's a very low risk leveraging of our capital in 2009.

Paul Vincent

Yeah, I think, just to give you some rough estimate for ’09 of the budget drilling is probably going to be in the 45% plus or minus range and facilities infrastructures 15 to 16%.

Adam Leight – Credit Suisse

Okay. And on the ‘08 numbers, can you sort of give the same sort of proportional breakdown?

Paul Vincent

Yeah the ’08 numbers the drilling component of the capital budget was 69% and the facilities infrastructure was just short of 8%, then acquisitions was about 7%.

Adam Leight – Credit Suisse

All right, given the number of successful wells you drilled compared to the amount of extensions and discoveries, is there something that you can provide a little bit more color on where there a fewer offsets and PUD adds, with a lower utilized for well?

Paul Vincent

Yeah, Adam I'll take a short of that, again we're going to have a lot more detail, lot more individuals participating at the Analyst Meeting next week. And we ought to be able to give you maps and charts at that time, but it’s very clear that during 2008 we would definitely looking at a $100 [plus directly], really $75 to $100, and we looking a gas project in the $7 to $10 range, and acquiring additional acreage down in South Texas in particular and we did have a pretty aggressive attempt going on. We had already instituted this horizontal activity. We did believe in that former pricing environment, we were going to add some nice reserves as a result of that. Now, obviously the price fell out from under us, as it did a lot of our peers, and we found ourselves at year-end not adding those reserves. So when you make that comparison a year-end '08 to year-end of ’07 there are a bunch of price related revisions downward that really are intra-year and that they don’t see in the recent year. We'll get into that at the Investor Analyst Meeting. It’s very clear that when we look at drilling cost, the day rates, the cost of pipe, the cost of completions, it was very, very high as the fourth quarter compared to where prices had fallen. So we judged it very, very prudent to just back off on all future drilling until these day rates and these steel prices came in line with the current pricing environment that we see.

Terry Swift

And the reserve determination, we have to use the costs as they are, where we fully expect the cost to come down pretty significantly, assuming the environment stays what it is. But for year-end reserve determination, you had to use the costs that were in place at the time. So that's going to cause price revisions or change the economics on the number of reserve potential areas.

Adam Leight – Credit Suisse

One last attempt, as you have been in discussions with your banks, in case I missed something, is there a price level that would imply a reduction in your borrowing base to a point where your commitment level, it would be below your current commitment level, and potentially constrained?

Paul Vincent

Probably is, but we don't see that. We've been in number of conversation with our bank, particularly our agent bank, and they are all talking to people who they see will have problems with the spring borrowing base redeterminations. They are not having that conversation with us. So that gives you one signal in terms from their perspective. But secondly I might point out that we have not collateralized along with all of our assets. And in last call we actually discussed with them what additional capacity we had. We did discuss that if we would have provided additional collateral. So we believe not only that we have the capacity and the borrowing base of $400 million. But we also believe there are additional assets that could support our borrowing base if necessary. We're really not at all concerned about our spring borrowing base redetermination.

Terry Swift

Yeah, I think I will add what Bruce said, at midyear last year, there were lots of folks increasing their borrowing basis, and we took a very conservative posture and did not increase that borrowing base, although we feel very confident we had material room to increase it. And I think because you never saw the increase to that level, you may not have the same comfort that we have. But we've got some comfort here.

Adam Leight – Credit Suisse

Okay thanks I'll give up the floor.

Operator

Our next question is from the line of Andrew Coleman.

Andrew Coleman – UBS

Hi, how are doing? I had a couple of questions just looking at the Olmos oil and gas field Bracken, I think, can you just described that how you cased that, and was that Packers Plus or was it a [Metaliner]?

Robert Banks

This was a Halliburton system. These were the Delta Stim Sleeve system they are expandable packer that swell up and isolate each individual zone.

Andrew Coleman – UBS

Okay. And was that a 4.5 inch liner that you guys had in there?

Robert Banks

Yeah, its 4.5 inch, that’s correct.

Andrew Coleman – UBS

Okay. So, can you give any comment as well on I guess moving over to Lake Washington, on the water injection facilities are moving along, I guess you guys are looking to convert another six wells, I think.

Robert Banks

Yeah Andrew, we're going to address that really quite heavily at the Analyst Meeting. We've actually engaged with the group that’s in very high-end Petrophysical Analysis with U.S. as well as some internal reservoir modeling. And basically what we're finding in the [Newport] much more complicated than we had originally modeled. And we have kind of a whole course of action moving a way out fully at the Analyst Meeting here next Thursday.

Terry Swift

Well, I like to add on that. We continue to wait on approval of permits in the state, many, many months ago, five to six months ago.

Andrew Coleman – UBS

Okay.

Robert Banks

Without the permits, we can't begin additional activity to get more water in the ground.

Terry Swift

Yeah I will add, one more comment to that we are injecting I believe about 1500 barrels a day. So there is some pressure maintenance going on. However, as I've gotten out and run this additional work and preparation for additional pressure maintenance, we had been very focused on optimizing where you put the water and where you going to get your best results, and then optimizing that that moves in sliding sleeves around, and I don't want to take the wind out of the sails, but at the Analyst Meeting I think they are going to show you that that in some respects, they should stabilized there. We gotten some more oil than we had anticipated we'll give you details on that. So we want to be very careful on that immediately start injecting into some of these finger or there's multiple sands where we still have some good oil production, which is more optimized. Let’s show you that next week.

Andrew Coleman – UBS

Okay. Then I didn’t know if you said earlier, but could you give a breakdown on the PUDs in terms of oil and gas. It wasn't in the release there.

Terry Swift

I don't have that with me.

Andrew Coleman – UBS

Okay.

Terry Swift

I don’t have a percentage is [gap on PUD]. We can get that and have that next week in the call.

Andrew Coleman – UBS

Okay. And then the last two questions one is, what do you think your or can you give an idea on base decline rate across, say, Lake Washington or, say, South Texas? I'm going to guess that Lake Washington and South Louisiana is in the 35% and the Olmos sand maybe is 25%. Is that fair?

Terry Swift

It’s a mixed bag as you would imagine in Lake Washington they are clearly close to the [drilling] types of wells that give you a nice flush production and they're declining in there in excess of 35% when you get those types of wells. In the Newport area, we're seeing stabilization of decline, so I'll tell you it's less than 35% at this time. Although when we get the pressure maintenance and we expect some uptick in that. So actually it's a mixture across Lake Washington I just have to see it as a best number, probably around 30% right now. But that’s without an aggressive behind pipe recompletion program or without the pressure maintenance. And so as we now focus on those items, we believe that we can do better than that.

Andrew Coleman – UBS

Okay. And stepping to the South Texas stuff one more time, do you think that as you add more horizontal wells that this would adjust your I guess, refrac potential on some of those wells, or is it just a, in shortest answer it's a way to save on the drilling costs and having to put something verticals down?

Robert Banks

Obviously the first well we considered it to be quite a success. But we did want some micro seismic technology and nearby observation wells to try to help us determine, how best to fracture stimulate these horizontal wells. We're drawing a number of conclusions from that. Overall we think we can actually do better on some of our fracture design and the way, we stimulate these wells. But that's really not part of the reference that I made to lowering some of the costs down to the $7 million range. So we think, we have a combination of cost reduction and potential to enhance the way we stimulate these wells.

Terry Swift

Yes, it’s a combination of clearly reduced drilling costs, but also improvement of performance. I mean, if you look at the nine-stage frac I think you are drilling nine-wells, obviously costs less to drill one more well in those nine vertical wells. But in a vertical well you are going to encounter maybe 30 to 40 feet of sand, and that’s what you're going to frac and these horizontal multi-stage fracs, we're fracing the surface area about a 300 feet long like that’s what we did in this job. We think we maybe extend that to 350 feet. So we are actually fracing in much larger area at that particular point than you did in the verticals wells, which we believe will end up giving us better recoveries out of those particular fract area.

Robert Banks

Yeah I think just to add to that historically the fields add a lot of different types of results in the early days. We were up north in the much higher quality sand. As we progressed out through the South we got into thinner sands, Shalier sands but never found the order. We did actually in some cases we find thicker sands driven to South. Then Shalier it's a very vast accumulation of gas that may in fact have something familiar to face these change will go from fairly high quality sand to very Shaley, but all these gassy sand. As we came to the fringe limits of this field it was not uncommon to get a quarter of $1 million a day or 0.5 million a day from a vertical frac. From a one-stage vertical frac, a 0.25 million of day to 0.5 million. And so here we're looking at initial results from a higher technology approach that's certainly two, maybe three times the rate that you would expect per stage. So we still got a lot to learn, but initially it's come back in very strong. We're very excited about it.

Andrew Coleman – UBS

Okay, thank you.

Robert Banks

Thanks Andrew.

Operator

(Operator Instructions). Our next question is from the line of Mariani.

Leo Mariani – RBC Capital Markets

Yeah, good morning, how are you guys?

Robert Banks

Hi, Leo.

Leo Mariani – RBC Capital Markets

My question here relates to your guidance. I noticed that your first quarter of '09 oil production is off pretty significantly kind of in that 24% to 25% range in terms of sequential decline. I'm trying to get my arms around what's going on there?

Terry Swift

The production in the first quarter '09 as to fourth quarter '08 is that the question?

Leo Mariani – RBC Capital Markets

Yeah, your fourth quarter '08 oil production versus your first quarter '09 oil production in terms of your guidance it’s down pretty significantly on the neighborhood of 24%, 25% just trying to get my arms around what’s causing that sequential guidance decline in there?

Robert Banks

Yeah. Obviously that's within one category, the crude oil, and I think you see that the gas were actually guiding up. If you go into the actual details of that which we will at the Analyst Meeting, I think you'll see that we really focused on gas during the second half of 2008. And to the extent that the regarding forward, we're not doing as much oil, we're doing a lot more gas and then shut-in production, some of weak completions that are going on, are more gassy than oily, as to this specific decline in oil fourth quarter to the first quarter, we will have to give you more detail at the Analyst Meeting as to which areas, but principally in an area like Lake Washington. We are seeing more gas, we're seeing higher gas cuts and higher [GORs] in some of the wells. So in some of the wells we are actually trading the oil for gas?

Terry Swift

I think also part of that is just reduced activity. We basically have no activity going on in Lake Washington. Although we are looking at some recompletions in the sliding sleeves that going to be prove there.

Robert Banks

And there were a number of wells that might yet been completed with this kind of slow down a bit. So it really pulled back in the first quarter.

Terry Swift

Yeah, but I think, we'll show you next week, but in Lake Washington, as we came back from the hurricane, we shut-in for quite sometime. Some of those wells came back well on much more oily, and then as they produced, they came back to their kind of historic GOR and the GOR is going up. So I think that's where you are going to find a good bit of that.

Leo Mariani – RBC Capital Markets

Okay. Jumping over to your year-end reserves looking at your PV-10 here where the development costs associated with your year-end ’08 reserve?

Robert Banks

The development costs for year-end reserves. Again, we will give you more detail at the Analyst Meeting. I think it's between $700 million and $750 million it’s something like that.

Leo Mariani – RBC Capital Markets

Okay, right.

Operator

Our next question is from the line of Curtis Trimble.

Curtis Trimble – Natixis Bleichroeder

Good morning. Just a couple of questions here first up, looking at the 2009 budget, can you tell me on what commodity price is that based?

Alton Heckaman

We are currently using a $40 oil price deck and a $450 gas price deck.

Curtis Trimble – Natixis Bleichroeder

Very good, looking over on the cost side what would you estimate cost need to come down in order to get to work in 2009. And can you kind of knock the dominoes down for me on the various components whether it be steel costs, day rates for rigs completion costs et cetera?

Alton Heckaman

We've seen on the drilling side. We've seen, over the last month probably about 30% down on the rig related cost. On the oil country tubular goods side, we haven't seen as much evidence of price declines there, I think that that's because a lot of this inventory was pre-bought, pre-ordered on mill runs. So we believe this start to seeing that come down a little bit further. We did just recently did out a construction project. We noted about a 40% decline from where we were previously on those costs. So, we fully expect the drilling costs to come down further, the completion costs to come down further. Also we're undertaking a formal bidding process with our vendors, and entering into direct negotiation with our key contractors and suppliers to try to make sure, we get the best value for the programming we do have this year.

Curtis Trimble – Natixis Bleichroeder

On the rig side, on the contractors at the point yet where they will exchange term for day rate?

Alton Heckaman

Yeah, we're not doing term contracts. We haven't been for quite sometime may be two years.

Curtis Trimble – Natixis Bleichroeder

Are they offering up that opportunity for a lower day rate? Are you going down 40% if you will take to the six month?

Robert Banks

Yeah, probably, as Mike said, probably 30% to 40% range, with no term type contracts?

Curtis Trimble – Natixis Bleichroeder

Okay. Again also would you tell me what you paid for the recent acreage additions in Eagleford?

Alton Heckaman

That's a good question. I think what we really need to say there is we're still actively acquiring acreage in the area. And the historic acreage cost has been higher the current acreage cost has been much higher than history. In the past, you could get acreage costs down there for $50 to $75 an acre. There are some areas you can still do that, but not very many, and because we've got an active program, I'd hesitate to put on price and everything.

Curtis Trimble – Natixis Bleichroeder

I understand. I appreciate it.

Alton Heckaman

Thanks, Curtis.

Operator

Our next question is from the line of Jeff Robertson.

Jeffrey Robertson – Barclays Capital

Thanks. I'm sorry if you all talks about this earlier, but the 120,000 acres you have that are perspective for the almost various much of that develops with vertical wells or is that all perspective for this potential horizontal play?

Terry Swift

Well, a good bit of that is over in the Briscoe TSH Sun area as well as AWP. In the AWP area itself, I would say probably of 120,000 acres, we probably have about 45,000 to 50,000 acres that has not been drilled out on the vertical side. So big, big chunk of the 120 is in AWP area proper and does not have vertical wells in it and a big chunk that was over in the Briscoe area and probably another 6000, 7000 acres in the TSH Sun area. But we have considerable HBP acreage position also in the AWP area. And some of that HBP position actually has which is held by almost production some of it is prospective for the Eagleford as well. So, it's quite a mix depending on whether you are Eagleford or you looking at Olmos, but when we're referring to the upside and the Olmos we're not contemplating going back and drilling horizontal wells where we've drilled the vertical.

Jeffrey Robertson – Barclays Capital

Okay. And the 45,000 acres for the Eagleford just to be clear is that included in the 120 or is that separate acreage?

Terry Swift

Well that’s a good question. Generally all of our Eagleford acreage, we refer to it also have Olmos opportunity with the exception of some HBP position, which might be about 15,000. I would determine in AWP block.

Jeffrey Robertson – Barclays Capital

Okay, thank you.

Operator

Mr. Vincent, there are no further questions at this time.

Terry Swift

If there are no questions let me just try to walk on that earlier question about future development cost that we've estimated around $750 million. The actual number is $729 million of future development costs in the reserve base. So, Leo I hope you’re still listening.

And if there are no other questions, then we really appreciate everybody's time, attention, and support. And looking forward to seeing those of you that will make it next week. Thank you.

Operator

This concludes today's conference call, you may now disconnect.

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