W&T Offshore Inc (WTI) 2008 Q4 法說會逐字稿

Good morning, Ladies and Gentlemen. Thank you for standing by. Welcome to the W & T Offshore Fourth Quarter earnings Conference Call. During today's presentation all parties will be in a listen only mode.

Following the presentation the conference can be open for questions. (Operator Instructions).

This Conference Call is being recorded today, Thursday, February 26, 2009. I would now like to turn the conference over to Manual Mondragon, Vice President of Finance, for W & T Offshore.

Please go ahead, sir.

Thank you, Operator and good morning to everyone. We appreciate you joining us for W & T Offshore's conference call to review the Fourth Quarter and full year 2008 results.

Before I turn the call over, I have a few items to go over. If you wish to listen to the replay of today's call, it will be available in a few hours by Webcast or via recorded replay until March 5, 2009. You'll find access instructions in today's Press Release.

Information recorded on this call speaks only as of today, February 26, 2009, and there for time sensitive information may no longer be accurate as of the date of any replay. Today Management is going to discuss certain topics that contain forward-looking information which is based on Managements beliefs as well as assumptions made by and information currently available to Management.

Although Management believe these expectations reflected in such forward-looking statements are reasonable, they can give no assurance such expectations will prove to be correct.

Such statements are subject to certain risks, uncertainties and assumptions which are described in this mornings Earnings Release and the Companies most recent Annual Report an Form 10-K and subsequent filings with the Securities and Exchange Commission. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may vary materially from those expected.

Today's call also includes a discussion of probable and possible reserves or may use terms like risk, reserve potential, upside or other descriptions of non-proved reserves. The SEC generally only allows disclosure of proved reserves in security filings and these estimates are non-proved reserves or resources are, by their nature, more speculative and are subject to substantially greater risks.

Please also note this conference call contains references to non-GAAP financial measures. You can find reconciliations of these non-GAAP financial measures to GAAP financial measures in the Form 8-K filed by the Company earlier today, as well as in this mornings Press Release.

Now I'd like to take the time to turnover the call to Mr. Tracy Krohn.

Thanks, Manny. Good morning everyone. Thanks for joining us for our fourth quarter and full year 2008 conference call.

Again, I'm Tracy Krohn, and this morning I'll review the key events that took place in the Fourth Quarter and full year 2008. Here with me today are Danny Gibbons, our Chief Financial Officer. Dan will review the Companies year and financial position and Steve Schroeder, our Chief Operating Officer. Steve will talk about our operations, production and LOE guidance and our President, Jamie Vazquez is also here and available to take your questions during the Q & A session.

Let's talk a little bit about reserves. Netherland, Sewell Associates are our third party consultant, evaluates and calculates our reserves from the ground up. This means they perform an independent engineering and geologic assessment of all our reserves.

At December 31, 2008, the Companies proved reserves were 491.1 billion cubic feet equivalent compared to 638.8 billion cubic feet equivalent at December 31, 2007. That's a net reduction of 23%. This decline in reserves was primarily due to the decline in oil and natural gas prices.

The good news is that we replaced 108% of our 2008 production through acquisitions in the drill bit including, excluding revisions and extensions. The PV10 of our total proved reserves is 930.9 million of year-end pricing and includes estimated asset retirement obligations.

In 2008, Netherlands, Sewell & Associates evaluated not only our proved reserves, but also our probable and possible reserves as well on a 3 P basis at year-end 2008, we had 347 Bcfe of probable and 505 Bcfe of possible reserves bringing the Companies 3 P total to 1.3 trillion cubic feet equivalent and that's an increase to 3 P reserves of 160 Bcf equivalent or 14% over 2007 3 P reserves.

The probable and possible reserves associated directly with the 2008 drilling program were 26.4 Bcf and 57 Bcf respectively. The 3 P reserve additions from our 2008 drilling program were there for 128.2 Bcf equivalent.

We think this number gives you a more accurate idea about what we were drilling for when we initiated the plan in January 2008. In reconciling the reduction of our year-end reserves, the major component is a revision line.

Last years revisions consist of three distinct components, revisions related to pricing, well performance and hurricanes.

As we all know, commodity prices fell hard for the July peaks and by December 31, oil was $41 and gas was $5.71. As a result certain projects became uneconomic and the associated proved reserves were written off.

The reduction in pricing from year to year accounts for 67% or 105 Bcf equivalent of total negative revisions of 157.5 Bcf equivalent. Regarding the negative 42.4 Bcf of well performance related revisions, approximately 48% were 20.2 Bcf equivalent related to a mechanical issue impacting the single completion that allowed the proved reserves to be produced already and that was in our (inaudible) 177 field.

Approximately 38% or 16.1 Bcf equivalent are the results of the performance changes throughout the year or three completions. Two completions began producing water earlier than anticipated and one completion experienced a steeper decline than predicted.

We did have positive performance revisions of nearly 10 Bcf equivalent due to better than forecasted performance and several other completions. The negative revisions due to hurricanes which were approximately 10 Bcf equivalent were primarily associated with a loss of host platforms. Approximately 93% or 9.5 Bcf equivalent of the reserves were associated with (inaudible) bank 949 due to the loss of the non-operated (inaudible) bank 947 A platform. As we have already mentioned, we only had about 2.7 million cubic feet a day being produced in these fields.

Overall the impact from the hurricanes Ike and Gustav on our proved reserves were fairly minimal. In 2008 we had several drilling programs that consisted of multiple wells in a particular field or area. Two of our most successful programs were at Main Pass 108 and Ship Shole, 299, combined these two programs added approximately 28 Bcfe approved, 10 Bcfe of probable and 34 Bcfe of possible reserves for a total of 72 Bcfe of 3 P reserves. We're pleased with those results and we'll discuss shortly we have more wells to drill in both those locations.

Well drilling update. In 2008, W & T made discoveries and successfully completed 18 of 24 exploration wells for the exploratory success rate of 75%. That included 16 out of 19 conventional shelf wells and two applied wells on the deep shelf.

Additionally, the Company successfully drilled and completed two of two development wells, both of which were on the conventional shelf. For the 26 wells drilled in 2008, the Company achieved a success rate of 77%.

So far in 2009, we drilled three successful exploration wells, we also have one development well that's still under evaluation that we would be able to complete under a higher crude oil price environment but is currently listed as non-commercial.

As a result of continued economic uncertainty, our drilling and CapEx expenditures in 2009 will be less than our drilling and CapEx expenditures in 2008. Our capital expenditure budget for 2009 will raise between approximately $220 and $270 million and includes estimates for the completions of wells that were in progress at the end of 2008. Wells are projects that we are presently committed to, lease dating operations development wells with rigs on locations with scheduled completions and the development of our Green Canyon Block 646 project, that's Daniel Boone. We anticipate fully funding our 2009 capital budgets, excuse me Capital Expenditures with internally generated cash flow and cash on hand. Keep in mind that we don't budget for acquisitions.

We're able to confirm any prospects, since most are held by production leases. However, the Company remains dedicated to remaining flexible and retains the ability to pursue other strategic options.

As was the case in 2008 a majority of this years program is off existing infrastructure and there for we expect to see production come on line shortly after a successful well is completed.

We also are continuing forward with our Daniel Boone project which Steve going to update you on shortly.

This years capital dollars are front end loaded and we're expecting to spend a majority of our currently designated capital in the first six months of 2009 and I'll turn it over to Danny Gibbons to discuss our financial position.

Thanks, Tracy and good morning everyone.

Today I'd like to start with an update of some of our balance sheet items. Let me begin with cash and long term debt. We ended the year with 357.6 million in cash and cash equivalents which represent a $43.5 million build-over-year in 2007; however, the year-end 2008 balance is below the level we had at the end of September 30, 2008.

During the fourth quarter we set $148.4 million on capital expenditures net. At accounts payable, another decrease to $158.6 million. Please also note that adjusted EBITDA was $22.2 million, due to lower production volumes associated with the hurricane damage to third party pipeline and the drop in oil and gas prices without a corresponding decrease in operating cost.

We also paid $22.1 million of interest, and $20.8 million in dividends. The sum of these items the for the $328 million decline in cash balances between the end of September and the end of December.

At the end of January 2009, we had $300 million of cash on the balance sheet. We ended the year with total debt of $653.2 million, that represents a slight decrease of $1.6 million from year-end 2007 and a $400,000 decrease over the third quarter.

As you know, we have a $500 million revolving bank credit facility that continues to be undrawn and available to fund opportunities. Our borrowing base was reassure firmed on October 24, 2008 and is subject to redetermination every six months. Although we do not know yet what the future borrowing base will be, we would expect that at current prices and the reduction in reserves into the last redetermination our borrowing base will be reduced.

Nevertheless, with our cash balance and undrawn revolving credit facility our liquidity position continues to be sufficient to take advantage of opportunities that we believe will rise in the continuing economic environment.

Let's move on to the ceiling test impairment. As we reported in our announcement of year-end reserves and in the Earnings Release this morning we recorded a ceiling test impairment at year-end of $1.2 billion pre-tax or $769 million after-tax.

For those of you who are not familiar with mechanics of the limitation on costs on the ceiling, the test is conducted at the end of every quarter, and it compares the net book value of the Companies oil and gas properties less deferred taxes plus the estimated asset retirement obligations, to the costs under ceiling. The costs under ceiling is the present value of expected future cash flows of proved reserves after-tax plus the cost of unevaluated oil and gas properties.

In calculating present value of expected cash flows of proved reserves, oil and gas prices and costs on the last day of the quarter are held flat for the life of the reserves and discounted at an annual rate of 10%. If the net book value of a Company's oil and gas properties exceed the calculated costs under ceiling, the excess must be recorded as a ceiling test impairment.

The primary reason for the decline in the value of our cost center was a significant decline in oil and gas prices. Also contributing to the decline was $138.9 million in unevaluated properties moving to the full cost pool as a result of changing economic conditions and much lower commodity prices.

Although the costs under ceiling test impairment negatively affects our balance sheet, the charges is non-cash item and does not affect any of the covenants in any of our debt agreements.

Let's move on to taxes. Because of the pre-tax loss we recorded a federal income tax benefit and our effective tax rate was approximately 32.5%. The effective rate for 2008 includes the federal statutory rate 35%, reduced primarily by the effect of 100% valuation allowance against deferred tax assets as the realization of future benefit is uncertain in the current economic environment.

Several other less significant adjustments were necessary in the Fourth Quarter including adjustments for employee stock compensation plans, all of which have the effect of reducing the potential benefit from loss computed at the statutory rate. Our deferred tax liability position at year-end 2007 and September 30, 2008 for that matter, changed to a deferred tax asset position at December 31, 2008.

At December 31, 2008, we had a federal income tax receivable of $34.1 million. This amount is comprised of estimated federal tax payments and other credits deposited in 2008 of $17.7 million and a net operating loss carryback to 2007 of $16.4 million.

With that I'll turn the call over to Steve Schroeder.

Thanks, Danny.

We currently have five rigs contracted, four operated and one non-operated. For 2009 we've already had success with three exploration wells along with one non-commercial development well on the conventional shelf. We expect to continue a modest drilling program in the first quarter of 2009. Similar to 2008, we are focusing on platform based exploration, such as two wells planned in the Main Pass area.

One of these wells, the Main Pass 283 A3 side track, has already been successfully drilled and is currently in the completion phase. Additional platform base drilling is planned for the South Timbalier area, where we plan to operate a multi-well exploration and developing program targeting primarily oil reservoirs. As discussed in our last call, we began drilling the Mahogany A12 side track development well at year-end 2008. This subsalt well has since drilled into the development section and we are still planning to drill the deeper exploration section to potential pay sands below 15,000 feet.

Additionally, while not budgeted for 2009, planning work continues on another Mahogany deep shelf well designed to explore the Mahogany deep geologic structure. This proposed well targets are in the upper and middle Miocene age sediments at a much deeper depth of about 25,000 feet.

Last week, we found our objectives, as planned, in the South Marsh Island 39 C4 well encountering 153 feet of gas sand, full to base in the 50% working interest field. The well is currently being completed and is expected to be online early in the second quarter. This well will be followed up by one additional opportunity in this non-operated field.

Relative to operations, we continue our work on the Daniel Boone development project and have budgeted approximately $32 million to complete this project in 2009. The pipeline route and installation analysis have been finalized and we will submit these to the MMS shortly. All long lead materials are arriving on schedule. Pipe welding onshore is planned to start this week in Mobile, Alabama. The Techniques' 'Deep Blue', which is an ultra-deepwater pipe lay vessel, is scheduled to start mobilization in early April starting offshore construction in mid-April.

Now let me give you an update on the status of the hurricane repairs to platforms and pipelines. As recently as last week the MMS granted approval to flow on a third party oil pipeline system at our 100% owned East Cameron 321 field. We are bringing the final few completions back online and anticipate production from this field to be fully restored by early March. This field had accounted for a large portion of our remaining shut-in production due to hurricane damages and will increase our net sales by approximately 2600-barrels of oil per day and 5.3 million cubic feet per day when fully restored.

The Ship Shoal 299 field had been off-line as a result of hurricane damage to a third party gas sales pipeline. In order to reestablish production we requested and received Mineral Management Services approval to produce several oil wells and reinject the gas in the field.

As a result, in early February, we reestablished 2500-barrels of net daily oil production. We anticipate the resumption of gas sales in the second quarter.

We currently have about 35 million cubic feet equivalent per day shut-in from hurricane damage. Approximately half of the remaining shut-in production is related to hurricane damage on several third party pipelines. About a quarter is related to field infrastructure damage, primarily in two non-operated fields both of which we expect to be back online this summer.

Relative to production guidance, we are currently producing between 250 and 260 million cubic feet equivalent per day. We have three wells currently in the completion phase and expect to add 13 million cubic feet equivalent per day next month and an additional 10 million in the early second quarter.

For the first quarter 2009 the Company anticipates production to be between 1.4 and 1.7 million-barrels of oil and 11.6 and 14.2 billion cubic feet of natural gas or a total of between 19.8 and 24.2 billion cubic feet of gas equivalent. For 2009, we anticipate production to be between 6.5 and 8.4 million-barrels of oil and between 43.6 and 56.1 billion cubic feet of natural gas or a total of between 82.8 and 106.4 billion cubic feet of gas equivalent.

In our production guidance we have estimated when hurricane related shut-in production will resume. In most cases, we do not have direct control construction effort required to reestablish this production and so up to 8 Bcfe of 2009 production could fluctuate, dependent on the in service date.

The 2009 production contribution from significant PUD's is approximately 6 billion cubic feet of gas equivalent. We are the Operator of the majority of these projects and have included our best estimate of when we anticipate build up.

Additionally, we have estimated risk build up from our planned exploration program. We could realize an additional upside of 10 billion cubic feet of gas equivalent should this program realize the unrisked potential. Looking to the first quarter of 2009, lease operating expenses are expected to be between $47 million and $56 million. This does not include allowance for hurricane related expenses.

This is a slight decrease from the fourth quarter due to the normal slowdown in activity during the winter months. For the year, LOE is expected to be between $214 million and $256 million.

Gathering transportation and production taxes for the first quarter are expected to be between $5 million and $6 million and between $20 million and $24 million for the year, respectively. This slight decrease, year-over-last year, due to lower production taxes results from the decrease in sales in fields producing from within State waters and the lower commodity prices.

Now I'll turn the call back to Tracy for closing remarks.

Thanks, Steve. One last word about 2008.

In 2008, we visited or evaluated over $2 billion worth of assets in data room for private transactions. As you know, we acquired only one property and that was Ship Shoal 349 for $117 million. That's a project we've been working on for over two years. We were simply unwilling to pay the types of prices that others were willing to pay and in hindsight we made some really good decisions. We believe we're in a much better position than many of our competitors and we'll get more than our fair share of opportunities.

We don't budget for acquisitions but will maintain liquidity to act upon an acquisition when one becomes available, at what we think is the right price. We're still in this for the long term and looking for the right reserves at the right price. We're very excited about our opportunities set this year and the fact that we do have the liquidity and look forward to the challenges ahead of us.

That concludes our prepared remarks and we are ready to take your questions. Operator would you please open the phone lines for Q & A?

Thank you, sir. (Operator Instructions). The first question comes from the line of Scott Hanold with RBC Capital Markets. Please go ahead.

Thank you, good morning.

Thanks, Scott.

When you look at your CapEx budget and some of the wells you're drilling I know you talked about this platform based activity. Can you talk about how big are these prospects you're drilling right now, how many wells do you plan on drilling in total in 2009 and is that $220 million to $270 million spending plan going to basically keep production flat absent, obviously, anything like Daniel Boone coming online?

That's a pretty all encompassing question but I'll do the best I can with it here. Scott, I think that as we look at targets, we don't normally publish our individual targets on a well basis, but certainly, the intent is that we'll spend enough money based on what the current price is to justify our CapEx program. With regard to that, I think it is important that you note that we're front end loaded, for instance, a lot of that expenditure will be in the first and second quarters as a result of Daniel Boone. We do have rigs on location now.

Most of the activities associated with existing infrastructure, so those targets can vary widely from a couple Bcf to double digit Bcf, so I don't really watch individual wells, but it's being done with an eye on what current pricing is.

Well, maybe if I can present it a different way. When you look at your prospects on the shelf, can you talk about economic thresholds for what you're doing and with gas prices around $4, does that stress a lot of your inventory that you look to drill?

It certainly does. I think it does for everyone, as prices go down and come up, we will adjust that budget to what we think is the correct procedure to finish the rest of the year. I do expect that throughout the course of the year, we'll be evaluating this monthly, really. We've got five rigs out there right now, most of which we operate and of those rigs most are associated with platforms. I think that the ones that we have on platforms are committed to certain programs. Most of it is not variable and in terms of wells that we'll drill, we don't know exactly what that well count will be, some of it is contingent upon success, so I'm hesitant to give out an exact well count at this point.

Okay. And a follow-up then, bigger picture, you've always been an acquisition-driven Company and at the low in the market where we're at right now as far as pricing. Would you expect more assets to come to market or would it be something you'll need more support for commodity prices before people start to sell assets and things to come to market?

The short answer is yes, I do expect to see more assets in the market. There are assets out there available now at a price; that's very difficult to determine what that proper price should be. There's only one one real market in the last six months for the Gulf of Mexico. We're very content to be patient and take our time and take advantage of the opportunities that we think will fit us best.

Okay, so if you don't find anything that's out there in the market that meets your price, what else would you look to do with your cash? Is it basically just sit on the balance sheet for now and/or would you look to do a special dividend as you've done in the past?

You know, I've been through this more than once in up cycles and down cycles and our best benefit has always been just exercising patience and seeing what develops as we continue to go through. Opportunities come up and they usually come up pretty quick, so you want to maintain some liquidity.

Appreciate it. Thanks.

Thank you, sir.

Thank you. Our next question comes from the line of [Crystal Choi] with Raymond James. Please go ahead.

Good morning.

Good morning Crystal.

A follow-up question on CapEx. I know that spending is flexible given prices and your plans for well activity is too. I just want to know the general split, percentage wise, between how much will be development and exploration?

Hold on just one moment. I'll see if I can give you that split in numbers. I don't have it right here in front of me. It's fairly weighted toward development since we've got Daniel Boone coming up, but if you'll stand down here just a minute I'll see if we can get you those numbers, Steve's looking them up for me right now.

Actually about 40% is on the exploration side and that excludes the completion of the wells once they've been drilled, so that's strictly the drilling cost for the exploration wells.

Okay, that's helpful, and I was wondering what you're seeing on jackup rates and what kind of cost decline assumptions are you using, if at all, in your CapEx budget?

It's difficult to forecast what you think rig rates are going to do. Certainly, right now, they're going down and the reason for that is that normally with jackup rigs, you'll have a one or two well committment with an option for a second or a third. It takes about one to six months for these wells for these rigs to come off contract. As they come off contract, they are at spot, so at spot, they are treated with market deference, so as you continue to see commodity prices go down, you'll continue to see rig prices go down. Similarly, you'll continue to see transportation prices go down, etc., so no, the short answer is, I don't expect that we see the bottom of the rig market yet.

Okay, thank you.

Yes, ma'am. Thank you.

Thank you. Our next question comes from the line of Neal Dingmann with Wunderlich Securities. Please go ahead.

Good morning guys.

Good morning, Neal.

Tracy, Steve mentioned the same that the CapEx is front end weighted. I guess my question centers around how much could you react to prices due to second half of this year, would you be able to, obviously you've got the dry powder to spend, do you have developmental activities or exploration where you could see some very quick near term growth if prices do cooperate second half?

Yes, the short answer to that is yes. One of the reasons is you'll see as far as growth is concerned, you'll see reserves come back on the books as prices increase. Similarly, as we get to a different price threshold for different well we might want to drill in inventory then you would logically expect to see that activity level go up some.

So Tracy, would that be around the Daniel Boone, or some of these areas where you just immediately do some more developmental around those, or are we talking entirely new plays?

Well, I think it's probably a little bit of both. There's not really a whole lot that we need to do additionally in development at Daniel Boone at this point in time, other than get the darn thing hooked up, and that's taking up some of our stamp time and what not, so as far as other areas to develop, yes, I mean we have other wells to drill such as our deep well at Mahogany, 25,000 footer which is not something we are planning on doing this year. We still got more planning to do, and reserves, they are at some point in time we think would be quite substantial on a risked or unrisked basis but we haven't fully finished our evaluation on that but yes, the short answer to your question is that yes, we would expect to be drilling in different areas that would be exploratory in nature as well.

And a follow-up is for either yourself or Danny. As far as two areas, one; on the receivables, are you pretty confident that you'll see all of those come in in the number of, that it's not any high higher than it has been but a relatively high number and then second; on what you're assuming for LOE cost, does that, have prices come down or what does that have baked in as far as you go forward just on rig rates and those type of things?

Well, I'll let Steve talk about LOE. Most all of our customers from a sales side of the majors, Chevron, Shell and the like, so usually we're not going to have a problem with who we sell to. The other portion of the receivables are from joint interest parties who we do work with. We haven't had any issues with that, as long as we Bill correctly we're not seeing issues with that, so most of that stuff is property related anyway, so we're not expecting any issues with that and obviously, we pay very close attention to it now.

Got it.

And Neal, relative to LOE, right now, the main reduction service costs that we seen has been in the cost of fuel and we have baked that into our number. The rest of them we pretty much kept flat, although we do think that during the year the service costs will go down.

Okay, thank you all.

Thank you, sir.

Thank you. Our next question comes from the line of Noel Parks with Ladenburg Thalmann. Please go ahead.

Good morning.

Just had a few questions.

Sure.

One of them had to do with the fourth quarter numbers. I was trying to arrive at a clean discretionary cash flow number for the quarter and so I just wanted a little help on the taxation. Can you just shed a little light on the tax treatment of the impairment and also what discretionary cash flow would have looked like without it and my main question is around what the deferred tax percentage would have been without the impairment?

Noel, as I think about pre-tax excluding the impairment, would have been about $354 million. As a result of that, you would still have the Section 199 deduction, which is that qualified domestic reduction activity, which is a tax credit that's about a 1% impact on the statutory rates, so you would have been at about 34% on a clean basis.

Other than that, I can't remember the reconciling items, what happens with the impairment is you get away from a deferred tax liability to a deferred tax asset. You've got the evaluation allowance against the deferred tax asset, you've got the recapture of the Section 199 deductions, you've got some of the recapture related to the employee benefit plans, so you end up with a really messy number in the fourth quarter when you go from say tax position of a liability to an asset. Sorry about that but that's what happens but again excluding the impairment, again, $354 million pre-tax, you've been effectively the 35% statutory rate minus the Section 199 deduction so 34%.

This is Tracy. For those of you that don't do tax speak, that means we'll get a tax credit.

Thanks. But and again, sorry, if this is implied in what you said, so if we didn't have the impairment, then the cash tax percentage, can you give me a sense of what that would have been?

You were still, from a cash standpoint, the deferred would have been still pretty large, the cash tax would have been small and the reason is we're deducting IDC for tax and advertising is for book, so we would have been in a very small cash tax position.

Okay, so but say 75% deferred be fair?

It's probably higher than that.

Okay, great. And just a question about the Healy project. Where does that stand? I know you were evaluating just how to design the production lay off for that.

Yes, we are. With regard to Healy, we are still doing some work there. We've got about six years left on that lease, so we are deferred there at this time. We're still doing the engineering evaluation that we need to do to bring this project to fruition, but at todays prices, I wouldn't put the thing online right now.

Okay, great. Thanks.

Okay.

Thank you. Our next question comes from the line of Phil Mcpherson with Global Hunter Securities. Please go ahead.

Good morning guys.

Good morning.

Nice work surviving this tough environment. Steve, can you give us a little more detail on the Daniel Boone and maybe like over the entire project kind of like total costs incurred to date? I know you talked about future costs and maybe the amount of reserves that are booked for the project and the upside in maybe the probables and possibles in that area?

Actually, we drilled the well for about $10 million about four or five years ago. That was a good thing and then in terms of to bring it online and complete it, I think the number is somewhere around $75 million to 100 million gross.

In terms of the well itself, we found three pay sands and we have gotten MMS down hole co-mingling permission on the bottom two sands, so when we bring it online, we'll actually be bringing on a couple of pay sands and then it's got a smart completion in it so in the future, when those sands have played out, then we'll be able to remotely, from the platform that it's being run back to switch from the zone that we initially go to the second completion in the well bore.

Rigless.

Rigless.

And are those, that third zone, is it considered behind pipe and booked as a reserve right now?

Yes, it is.

And what are like the reserves booked currently on that project?

I don't think that we've given that, Oh, okay, Dan said that we have. 20 Bcfe, net

Okay, thanks. And the capacity of the pipeline, what kind of production do you anticipate it coming on? Does it come on once or does it take time to ramp up?

Yes, in any subsea well you do want to ramp it up slowly, give the gravel packs and in this case frac packs a time to settle out. I believe the capacity of the line that we laid was for 10,000-barrels per day gross.

Great. And I just have one more question for Danny. With the ceiling test writedown, you didn't really give us any guidance but can you give us an idea of what we should use for the DD & A right now? It should come down, right?

It definitely does come down. It's going to be a little over $4, it just depends. One of the things we have to also consider, potentially, is another impairment in the first quarter. We talked about that in the Earnings Release. If prices continue to be lower we'll start to see some rally in crude. We're starting to see a little improvement in gas, but exclusive of the impairment, if there were to incur it would probably below the $4 range.

Great guys. Keep up the good work.

Thank you, sir.

Thank you. Our next question comes from the line of [Eli Canter, with Prichard Capital Partners]. Please go ahead.

Hi, good morning. Thanks for taking my question.

Sure, Eli. Thanks.

With an undrawn revolver and no real need to borrow in the foreseeable future, are debt covenant restraints a non-issue for W & T and, on a related issue, what's the year-end SPE calculated PV10 value?

I'll answer your first question here. First question is no, we don't have any debt covenants that are of concern to us at this point in time, and as far as PV10, I think I gave out that as $930 million.

So, is the SEC PV10 is equivalent to the SPE calculated PV10?

The SEC, what we start with is a $1.371 billion that we take out the ARO related to that, that's how we end up with the $930 million so that is the after ARO.

The short answer to the question is no, that is not the SPEdefinition, since SPE is not on flat pricing.

Got it, yes. I was just asking because I guess the asset coverage ratio covenant, that 2 to 1, I believe that's based on SPE pricing; is that correct?

That's based on bank pricing.

It's a forward curve. It's the bank strip but it is the forward curve so there obviously is a lot more room in the forward curve as opposed to a flat price in the 2008.

Got it. Thank you very much.

Thank you, sir.

Thank you. Thank you. (Operator Instructions). Our next question is a follow-up from the line of Scott Hanold. Please go ahead.

Yes, a couple of quick maintenance-type questions. You did indicate that you thought the revolver might get tight a little bit. Can you talk about the size of that reduction, what you kind of expect right now?

Yes, I can't really address what exactly the banks will do as far as cutting the revolver. We've had a reduction in our reserves, so you naturally expect to see that revolver cut, I think it will be a function of where they are on pricing when we get to our next renewal date, which is in March, April?

Yes.

Okay, and related to guidance, I think a comment Steve had made was that LOE does not include any hurricane related cost. Is there going to be some that's going to be spent in the quarter that we should be thinking about there related to last years activity and then, what do you anticipate to be the cash tax rate here in '09?

As far as LOE, we will have some hurricane in there. We are going to get reimbursed as we go. We're going to see some timing impact. We'll spend the money, make a claim, get reimbursed, so we will see some impact and we're going to see some lumpiness as a result of hurricanes but to try to model, that's going to be difficult.

Okay, and what's your cash tax rate going to be this year?

Again, because of the drilling program in the NOL that we're going to have, you aren't going to be paying any cash taxes. You might have some small AMT, but I'm not sure if even that's going to be the case.

Okay, pretty marginal. Thanks, guys.

Thank you, sir.

Thank you. Your next question is a follow-up from the line of Noel Parks. Please go ahead.

Just a couple quick ones. Realized pricing for the fourth quarter came in a little lower than I was expecting, I was expecting you to be closer to Henry Hub. Was there anything going on in the quarter that was unusual?

Yes, there's a little bit going on and some of the production was routed to different pipelines, at a little higher price because of the hurricane. That's one of the things that went on. Other than that, it was just differences in bases that we're probably changing at the time.

Oh, okay. Well, can you give us a sense of whether that will have any impact on differentials for first quarter?

I don't think you'll see a whole lot of impact.

Okay, and actually what's the current rig count and excuse me if you guys talked about that before.

Sure. The current what?

Rig count, number of rigs you're operating now?

We have five. Four that are operated and one not operating.

Okay. Great. Thanks a lot.

Sure.

Thank you. Management there are no further questions I'll turn the call back over to you for closing comments.

I think we're done. We appreciate everybody listening and we'll talk to you again soon.

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