SilverBow Resources Inc (SBOW) 2008 Q4 法說會逐字稿

Good morning. My name is Angelia, and I will be your conference operator. At this time, I would like to welcome everyone to the Swift Energy 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.

Thank you. Good morning. I'm 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 to 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 operate. 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.

Thanks, Paul. Thank you again for joining this morning's conference call. Before we comment on the fourth quarter, it's important to note to our shareholders and the investment community participating in 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. In the time since our last quarterly conference call, crude oil and natural gas prices have continued to deteriorate as global economic results and forecasts have continued to weaken. Hydrocarbon pricing has fallen from peak in the summer of 2008 much more quickly than in previous downturns which we've witnessed over the past 25 years. This steep decline in prices has exerted increased stress levels on our business. The (inaudible) oil market and the results in 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 significant noncash write-down due to a 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 costs have begun to retreat recently, we don't believe they are 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 period of rising oil and gas prices with the hope that we won't ever collect on them. However, in the event of a precipitous decline in commodity pricing, these floors do provide with us revenue and time to conclude our current operations during a given period and adjust our operating budget to market conditions. Unfortunately, as a result of the recent price declines, the fourth quarter saw us collect over $28 million from oil and gas natural gas floors that we had in place.

As I mentioned earlier, low leverage and high 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 a 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've taken significant steps during late 2008 and early 2009 to reduce our spending levels in 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 on 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 our exploration activities in this area. This well is an excellent example of the projects we are developing from a large regional 3-D data set in Southeast Louisiana. We won't be able to speak about reserve implications or precise recovery expectations of this prospect until we've completed more sustained tests and observed longer term well performance, but initial indications are that this is in fact a very large discovery and has a potential size of 30 to 50 Bcf equivalent gross. This discovery also helps us assess the risks associated with other prospects in the immediate area, and leaves us very excited about other activities we have 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 facility 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 data sets 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 33 H well recently was completed with a nine-stage simultaneous hydraulic fracture enhancement. This is the first horizontal well of this type that we have drilled in the Olmos formation in 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 will drill at least three additional horizontal wells in 2009 in locations designed to extend the field. 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 prospective for 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 today we have approximately 45,000 acres which may be prospective in this play. We will drill at least one vertical well in 2009 to test this formation on our acreage.

It is during times of great uncertainty and fear that experience and discipline are rewarded. It is our job to be prudent custodians of assets and capital provided to us by our stakeholders. Although we have the ability to borrow additional funds under our bank line, we will only utilize that ability to fund critical projects which will create long-term value. There can be no mistaking that this downturn is severe and if current conditions persist, we are prepared to curtail activity even further and accept 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 to emerge a stronger, more efficient company.

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

Thank you, 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 this 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, a $754 million noncash 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 noncash 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.

In 4Q '08 production decreased 12% to 2.5 million barrels of oil equivalent, partly the result of the 2008 hurricane events. Both crude oil and natural gas prices declined from both sequential and prior year quarterly levels. Swift's average realized price in 4Q '08 decreased 33% to $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 in 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 in line 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 costs came in below guidance at $10.10 per barrel, and interest expense decrease slightly to $2.93 per barrel which was at the high end of our guidance. Production 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 pretax noncash 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. The result was a loss from a continuing operations for the quarter of $452.5 million, or $14.66 loss per share both basic and diluted. Excluding the noncash write-down, as I mentioned, our income from continuing operations was $20.6 million or $0.66 per diluted share.

As I'm 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 requirements in alignment with current industry practices and adapt to changes in technology. As we indicated in our press release, the company would have used considerably higher crude oil and natural gas prices for its accounting impairment test as well as calculating the PV-10 value had 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, while 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 markets, let me spend a moment to highlight Swift's 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 noncash write-down of oil and gas properties, which highlights our conservative leverage strategy and our conscious historical decision to basically maintain our CapEx within our cash flows. Our two senior notes outstanding had very good interest rates and are well aligned with our long-term assets. As mentioned earlier, we fully expect 2009 will be a difficult operating environment, and will require greater discipline and emphasis on reducing costs across the enterprise, which we have already begun.

The first step in this initiative was reduction in our workforce that we implemented during the first quarter 2009. Although a very difficult decision, it was one we felt like we had to make. The reductions in headcount that were made will reduce G&A costs going forward, although the effect on 1Q '09 will be minimal given the severance and other associated costs. We've also implemented other cost savings 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 have identified several cost saving opportunities in all of our core operating areas. We also are working very closely with our vendors for additional cost savings for the 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 at $350 million. Swift had an outstanding balance on the line of $181 million at year end 2008. With the rollover of year end costs into '09 and the lower hydrocarbon pricing environment, our drawdowns have increased. Our current cash forecasts do not anticipate our draw-downs 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 draw-downs on our line of credit. I should note that the recent affirmation of our line speaks to our solid bank group. We continually monitor and review the credit worthiness 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 credit worthiness of people that 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 the risk of these unsecured receivables is mitigated by the size, reputation, and the nature of the companies to which we extend credit. From certain customers we also obtain letters of credit, parent company guarantees, if applicable, and other collateral assets considered necessary to reduce our risk of loss.

As to Swift's 4Q '08 hedging activity as mentioned earlier, we had a significant gain of $28.8 million from our hedges in the fourth quarter. However, recent downward pricing volatility has not allowed Swift to currently enter into any 2009 hedges. Our website remains the best source for complete and current detailed ongoing hedging activities. 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.

Thanks, Alton, and good morning, everyone. Today I will discuss fourth quarter 2009 activity, including our production volumes, year-end reserves, recent drilling results, activity in our core operating areas, and our plans for the rest of 2009. And then we're going to have Bob provide a little more detail on the Shasta discovery and the horizontal well in AWP, two of our recent projects that we're pretty excited about.

Beginning with production though, 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 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 recover from hurricanes Gustav and Ike. Sequential production increased 6% when comparing fourth quarter 2008 production to production in the third quarter 2008.

Now, for our reserves. Swift Energy's year-end 2008 reserves consist of 116.4 million barrels 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% improved developed compared to 47% 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 for 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. I'm sure there will be more questions on our reserves, and we will discuss our 2008 crude, probably and possible reserves in great detail during the annual analyst investor day which we'll be hosting in Houston next Thursday, February 26th.

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 Company's 2007 year end 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 for oil and $6.65 per Mcfe at year end 2007.

Moving to our drilling results, Swift Energy completed 29 of 32 development wells in the fourth quarter 2008. A completion rate of 91%. I will briefly review our activity in each of our four areas.

Beginning with our Southeast Louisiana core area, which includes Lake Washington and Bay de Chene fields and would 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 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 the 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 2008 volumes. Bay de Chene sequential production decreased 82%, 420 net barrels of oil equivalent per day, as production remained completely shut in for most of the quarter. At the end of November, high pressure gas sales resumed in Bay de Chene but oil 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 mid year in the third quarter.

In total, we estimate 3,000 to 5,000 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 in Plaquemines Parish, Louisiana, five wells were drilled during the quarter. Facility 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 sit 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 2364 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 carry out the work necessary to design and plan an 18,000 to 20,000 foot sub salt test in the Lake Washington area, the timing of which is also dependent on a 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 of development drilling projects but currently has zero rigs operating. The Company intends to commence the 2009 drilling program once oil field drilling and service costs accurately reflect the current operating and pricing environment.

In our South Texas core area, which includes our AWP field, Sun TSH, and Briscoe Ranch and Las Tiendas, fourth quarter 2008 production averaged 8,226 barrels of oil equivalent per day, from 49 million cubic feet a day, a 12% increase in production when compared to third quarter 2008 production in the same area. During the fourth quarter we completed 12 of 12 development wells in the AWP area, five of seven development wells in the Briscoe Ranch field, and four of five 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 2009 of 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 (inaudible) contributed 2,719 barrels of oil equivalent per day of production in the fourth quarter 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 Island, and Bayou Bijou, production averaged approximately 2,090 barrels of oil equivalent per day, 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 being uninterrupted by weather.

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

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 in the rate of 11 million cubic feet of gas per day and 739 barrels of oil per day at 11,279 psi on a 1464 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 at the company's Westside facility in its Lake Washington field. The pipeline will be approximately eight 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 '09. Peak test rates of 10.4 million cubic feet equivalent per day were achieved on a 3664 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 3264 inch choke with flowing tubing pressure of 1,880 psi.

The R Bracken 33H is expected to recover between 3 million and 5 million 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 drill and complete. By eliminating certain procedures and realizing both cost 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 2009 capital program. The results of these wells will be used to determine the extent to which this type of drilling and completion technology will be applicable for the Olmos formation in the AWP and (inaudible) TFH fields as well as for the additional acreage that 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 enhancement, the decline rates associated with the reservoir, and the 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 may be prospective for further Olmos development. During 2009 Swift Energy will also drill a well to test the potential at the Eagleford shale formation, and the company currently has 45,000 acres leased in this area which may be prospective for this formation. 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 it back to Terry to recap.

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 real time. We maintain frequent dialogue with our bank group and believe we have ample liquidity to weather the current downturn. Although we did have a significant noncash write-down, we also had strong financial results in the fourth quarter 2008 with revenues of $145.4 million, income from continuing operations of $20.6 million, or $0.66 per diluted share before the ceiling test adjustment of our oil and gas properties, and cash flow before working capital changes was $85.3 million or $2.73 per diluted share.

We expect to get our Shasta discovery on production by mid year. Additional development will be conducted as market conditions improve. This is a great discovery which will help us analyze and develop other prospects in the area. Including the recent Shasta discovery, the company currently has between 3,000 to 5,000 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 well in the Olmos sands has performed at that time high end of our expectations. As a result, we'll be moving forward with additional horizontal wells in this area and also evaluating the Eagleford shale in our operating area. If these wells prove to be successful we expect very positive results to both our production and reserve numbers for 2009.

Next Thursday, February 26th, we'll host an analyst investor day here in Houston. At this meeting we will review our 2008 operational and financial performance and detail our 2009 plans and guidance. Lastly, we have been through pricing downturns in the past. We believe that we have the experience, 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.

(Operator Instructions) We will pause for a moment to compile the Q-and-A roster. Our first question is from the line of Adam Leight.

Hi, good morning. Could you give us an idea -- you referenced it, and maybe I missed it, but price related revisions versus technical revisions, first of all.

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

Okay. How about on the capex side, either for '08? How much of that was drilling versus acreage and facilities and the '09 number, particularly given the reduction in the indication that you are deferring drilling spending, how much of that' s infrastructure and how would you expect the quarterly progression of capital spending to proceed?

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

Yes, that will do. And then timing.

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

I think we can add to that, though, that 2009 will focus very much on recompletions, fracture treatments, enhancements. We also have a lot of shut-in production where 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 a lot of completions. Some of that money flows over into 2009 finishing up the completions. We do have development well drilling which was in the South Texas. We also have a couple of delineation type wells that we'll be drilling. We've really backed off of the exploratory component. So we'll get you those details, but I think it's very fair to say that it's a very low risk leveraging of our capital in 2009.

I think, just to give you some rough estimates for '09, drilling is probably going to be in the 45% plus or minus range. And facilities infrastructure is 15%, 16%.

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

Yes, the '08 numbers, the drilling component of the capital budget was 69%, and the facilities infrastructure was just short of 8%. Acquisitions was 7%.

Given the number of successful wells you drilled compared to the amount of extensions and discoveries, is there something that can provide a little bit more color on -- were there fewer offsets and PUD adds, or were they lower well?

I'll take a shot at that. Again, we're going to have a lot more detail, a 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 were definitely looking at $100 possibility, really $75 to $100, and we were looking at gas prices in the $7 to $10 range, and acquiring additional acreage in South Texas, in particular. We did have a pretty aggressive attempt going on. We had already instituted this horizontal activity.

We did believe that 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 year end '08 to year end '07, there are a bunch of price related revisions downward that really are intra year, and you don't see on the year on year. We'll get into that at the investor analyst meeting.

We also, it's very clear that when we look at the drilling cost, the day rates, the cost of pipe, the cost of completions, it was very, very high at 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.

In the reserve determination, we have to use the cost as they are, where as 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 changes to the economics on the number of reserve potential areas.

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?

Probably is but we don't see that. We've been in a number of conversations with our bank, particularly our agent bank, and they are out talking to people who they see would have problems with the 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 last fall we actually discussed with them what additional capacity we had, and we did discuss that if we were to provide additional collateral. So we believe not only do we have the capacity and the borrowing base of $400 million, be we also believe there are additional assets that could support a borrowing base if necessary. We're really not it at all concerned about our spring borrowing base redetermination.

Okay.

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 felt very confident we had material room to increase it. And I think because you never saw us increases it to that level, you may not have the same comfort that we have. But we've got some comfort here.

Okay. Thanks. I will give up the floor.

Our next question is from the line of Andrew Coleman.

Hi, how are you doing? Had a couple questions. Looking at the almost well you guys drilled, Bracken, I think, can you describe how you cased that, and was that packer plus or was it a metaliner?

This was a Halliburton system. These were the Delta (inaudible) systems with expandable packers that swell up and isolate each individual zone.

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

Yes, four and a half inch, that's correct.

Okay. All right. Can you give any comment as well on, moving over to lake Washington, how the water injection facilities are moving along? I guess you guys were looking to convert another six wells, I think.

Yes, Andrew, we're going to address that really quite heavily at the analysts meeting. We've actually engaged with a group that's done some very high end petrophysical analysis with us, as well as some internal reservoir modeling. And basically what we're finding is that the [Blueford] is much more complicated than we had originally modeled, and we have a whole course of action that we're going to lay out at the analyst meeting next Thursday.

I'll add on that we continue to wait on approval of permits, many, many months ago, five to six months ago.

Okay.

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

Yes, I will add one more comment to that. We are injecting, I believe, about 1,500 barrels a day, so there is some pressure maintenance going on. However, as they've gotten out and done this additional work for additional maintenance, it's very focused on optimizing where you put the water and where you're going to get your best results. In optimizing that they have moved some sliding sleeves around, and I don't want to take the wind out of the sails, but at the analyst meeting I think they're going to show you that in some respects, things have stabilized there, we've gotten some more oil than we had anticipated. We'll give you details on that. So we want to be very careful and not immediately start injecting into some of these finger or -- there's multiple sands where we still have good oil production. We just want to optimize. We will show that you next week.

I didn't know if you said it earlier, but could you give a break down on the PUDs in terms of oil and gas? It wasn't in the release there.

I don't have a percentage on the PUDs. We can get that and have that next week in the call.

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

It's a mixed bag, as you would imagine. In Lake Washington they're clearly up close to the zone types of wells that get that nice flush production. They're declining in excess of 35% when you get those (inaudible). 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 in we expect some uptick in that. So actually it's a mixture across Lake Washington, I just have seat of the pants 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.

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 refrac potential on some of those wells, or is the shortest answer is it's a way to save on the drilling costs in having to put so many verticals down?

Obviously the first well we considered it to be quite a success. But we did run some micro seismic technology in 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.

It's combination of clearly reduced drilling costs, but also improvement of performance. I mean, if you look at it, the nine (inaudible) frac, you are drilling nine wells, it obviously costs less to drill one horizontal than it does nine verticals wells. But in a vertical well you are going to encounter maybe 30 to 40 feet of sand, and that's what you are going to frac, and these horizontal multistage fraction, we're actually fraccing the surface area that's 300 feet long. We think we maybe will be able to extend that to 350 feet. So you are actually fraccing a much larger area at that particular point when you're drilling a vertical well which we believe will end up giving us better recoveries out of those particular fracced areas.

To add to that, historically the field's had a lot of different types of results in the early days. We were up north in the much higher quality sand. As we progressed to the South we got into thinner sands, shalier sands but never found water. We did actually in some cases find thicker sands to the south. Shalier but thicker. It's a very vast accumulation of gas that may in fact have something that's familiar to a pasty storms where you go from fairly high quality sand to very shaley, but all with gassy sand. As we came to the fringe limits of this field, it was not uncommon to get a quarter of a million a day or half a million a day from a vertical frac, from a one-stage vertical frac, a quarter million a day to a half a million. 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. So we've still got a lot to learn, but initially, it's come back very strong. We're very excited about it.

Okay. Thank you.

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

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

First quarter '09, as to fourth quarter '08? Is that the question?

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

Yes. Obviously that's within one category, the crude oil, and I think you see that the gas we're actually guiding up. If you go into the actual details of that, which we will at the analysts meeting, I think you'll see that we really focused on gas during the second half of 2008, and to the extent that we're guiding forward, we're not doing as much oil. We're doing a lot more gas. The shut-in production, some of the recompletions that are going on are more gassy than oily.

As to the specific decline in oil, fourth quarter to first quarter, we'll 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 you are actually trading oil for gas.

I think also part of that is just reduced activity. We have no activity going on in Lake Washington, although we are looking at some recompletions in the sliding fees that can improve that.

And there were a number of wells that have not yet been completed. We just slowed down a bit. So pull back.

But I think, we'll show you next week, but in Lake Washington, as we came back from the hurricane, we'd been shut in for quite some time, some of those wells came back on much more oily, much more oily. And then as they produced, they came back to their historic GOR and the GORs going up. So I think that's where you are going to find it.

Okay. Jumping over to your year-end reserves, looking at your PV-10 here what are the development costs associated with your year end '08 reserves?

Development costs for year-end reserves? Again, we'll give you more detail at the analyst meeting. I think it's between $700 million and $750 million.

Okay. Thanks.

Our next question is from the line of Curtis Trimble.

Good morning, couple questions here. First up, looking at the 2009 budget can you tell me on what commodity prices that's based?

Yes, we're currently using a $40 oil price deck and a $4.50 gas price deck.

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 dominos down for me on the various components, whether it be steel costs, day rates for rigs, completion costs, et cetera?

Well, we've seen, on the drilling side, we've seen, over the last month, probably about 30% down on rig related costs. On the oil country tubular goods side, we haven't seen as much evidence of price declines there. I think that's because a lot of this inventory was pre bought, preordered on mill runs, so we need to start seeing that come down a little bit further. We did just recently bid 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 are 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 program we do have this year.

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

We're not doing term contracts. We haven't been for quite some time, maybe two years.

But are they offering up that opportunity for a lower day rate, i.e., going down 40% if you will take it for six months?

Yes, probably, as Mike said, probably 30% to 40% range, with no term type contract.

Okay. Very good. Also, will you tell me what you paid for the recent acreage additions in Eagleford?

That's a good question. I think what we really need to say there is we're still actively acquiring acreage for 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 a price on everything.

I understand. I appreciate it.

Our next question is from the line of Jeff Robertson.

Thanks. I'm sorry if you all talked about this earlier, but the 120,000 acres you have that are prospective for the Olmos, Terry, is much of that developed with vertical wells, or is that all prospective for this potential horizontal play?

A good bit of that is over in the Briscoe area as well as AWP. In the AWP area itself, I would say probably of the 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 120,000 is in the AWP area proper, and does not have vertical wells in it. And a big chunk of it is over in the Briscoe area and probably another 6,000 or 7,000 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 Olmos production, some of it is prospective for the Eagleford as well. So it's quite a mix depending on whether you are looking at Eagleford or you're looking ta Olmos, but when we're referring to the upside in the Olmos we're not contemplating going back and drilling horizontal wells where we've drilled the vertical.

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

Well, that's good question. Generally all of our Eagleford acreages, as we refer to it, also has Olmos (inaudible) with the exception of some HBP position which might be about 15,000 of it that's in AWP.

Okay, thank you.

Presenters, there are no further questions at this time.

If there are no questions, let me just follow up on that earlier question about future development costs that we had estimated around $750 million. The actual number is $729 million of future development costs in the reserve base. 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 I'm looking forward to seeing those of you that will make it next week.

Thank you.

This concludes today's conference call. You may now disconnect.