西方石油 (OXY) 0 Q0 法說會逐字稿

Welcome to Vintage Petroleum's conference call to review its third-quarter financial aid operating results -- I'm sorry, financial and operating results.

This call is for the benefit of Vintage shareholders and other interested parties and any rebroadcast of this call for commercial purposes is prohibited without the permission of Vintage.

At the end of the Company's prepared remarks and the Company has indicated it's time to have a question-and-answer period. (OPERATOR INSTRUCTIONS).

I would now like to turn the program over to Mr. Phaneuf.

Welcome to the Vintage Petroleum conference call.

Before we begin I need to remind the listeners that some of the information we plan to discuss during the course of this call may be considered forward-looking and that all statements made during this call other than statements of historical facts are forward-looking statements.

Although the dialogue and the webcast slideshow that we're going to have up does contain our best and most reasonable estimates and information with respect to targets, a number of factors could cause actual results to differ materially from what we are going to discuss.

You should read your forward-looking statements in the Company's filings with the SEC for risk factors associated with our business.

Occasionally today on the call we will be referencing non-GAAP measures in particular cash flow and EBITDAX, so I need you to be sure to reconcile those with the corresponding GAAP disclosures in our earnings release and accompanying tables.

For those of you tuned in to the webcast, if you will turn to page two or slide two, there we show our call agenda for today and I'll briefly outline that agenda of prepared remarks that we have and introduce the Vintage participants while I do so.

I'll begin it briefly reviewing fourth-quarter results and our '04 summary and also discuss briefly our improved debt position and liquidity.

I'll turn the microphone over then to Bill Abernathy, our COO, who will discuss fourth-quarter and full year production, year-end reserves, replacement, finding cost, 2005 CapEx and our 2005 revised targets.

He'll then turn the microphone over to Larry Sheppard, our Senior VP of new ventures, who will discuss exploration and our 2005 outlook for exploration.

Following Larry our Chairman and CEO, Charlie Stephenson, will have a few remarks, an overview and '05 strategy.

And in addition to those that I just mentioned, we have other members of the Vintage management team in attendance today to help answer any of your questions.

We have Bill Barnes, our CFO;

Mickey Meimerstorf, our VP and Controller;

Gary Watson, our BP of International;

Chris Jacobson, our VP of Domestic Operations, and there are others.

Just to bring everyone to the same page in case there are listeners who are not very familiar with Vintage out there, we sold our Canadian operations in November of '04.

As a result, the financial accounting standards require us to reclassify those assets and liabilities and operations as discontinued operations.

And so on our earnings release you will see that.

In addition, we have GAAP and non-GAAP key results that we will present.

We will focus on non-GAAP results in our conference call today; we'll be discussing those results on a continuing operations basis or excluding the discontinued operations in Canada both on the fourth quarter and annual basis.

So with that being said let me jump right into talking about our fourth-quarter results.

On pages three through six we're going to be covering our fourth-quarter results.

And so if you will move to slide three, briefly we'll discuss the highlights.

We had income from continuing operations that was very strong in the fourth quarter of $35 million or $0.68 a share.

In addition cash flow, excluding the discontinued operations in Canada, rose to $93.4 million versus about $57 million in the same quarter last year.

Similarly EBITDAX was strong in the quarter rising to $119 million, almost $120 million versus $77 million in the fourth quarter of '03.

Additionally production from continuing operations rose 13% to 71.5 thousand BOE a day and we closed a good sized acquisition in December late in the year adding 7.5 million BOEs and about 1900 BOEs of daily production.

So all that made for a good strong fourth quarter.

On page four we break that down for you a little bit by components.

In terms of fourth-quarter sales volumes, they were strong for both oil and gas.

Oil volumes grew 5 percent for the quarter to 4.4 million barrels.

This was underpinned by strong growth in oil production in Argentina excluding an inventory adjustment where Argentina was up 9% and also good strong increases in production in Yemen versus nothing in the year ago quarter.

Gas was awfully strong in the quarter; volumes were up 31% to 13.2 Bcf largely as a result of good exploitation success in the U.S. and continued strong Argentina demand for gas from our Bolivian operations.

These made for total production for the year up 13% to 6.6 -- I mean for the quarter, 13% up to 6.6 million BOEs.

Prices were also strong in the quarter.

And if you turn to page five or slide five we have a recap of prices in the quarter.

Oil averaged $34.18, up 36% for the quarter; gas as well was strong averaging $4.64 an Mcf, up 70% for the quarter versus the year ago level.

All together the strong volume gains and price gains made for good overall strong results in the fourth quarter.

Revenues were up 60% to $210 million, income from continuing operations, again, up 411% to $45 million.

Cash flow, excluding discontinued operations, up 65% to $93 million and EBITDAX also up a strong 56% for the quarter.

Moving briefly to 2004 highlights on slide number seven.

Just want to note that early in 2004 we set out three key goals from a corporate standpoint to achieve in 2004, and I'm pleased to report to you today that we have achieved or made substantial progress on all three of these goals.

We set out to improve our balance sheet and we did that substantially, improving financial flexibility with proceeds from our sale of Canadian interest.

We eliminated our bank debt.

We funded acquisitions and built cash leaving us in a very strong financial position at year-end.

Number two, we said we would rekindle the contribution to growth through acquisitions.

We did so making two principal acquisitions spending $110.5 million, adding 16 million BOE of reserves, as Bill will talk about in more detail, and 3800 BOE in daily production which will be a good, strong positive impact to our full year '05 production.

And third, we pledged to return the Company to being the top tier operational and financial performer and with that we grew production growth by 6 percent for the year, we achieved our stated volume targets for '04.

We also had strong total return to shareholders among the top in our peer group with our stock price rise.

And we ended up with a net debt to book capitalization ratio that dropped by a third versus the year-end prior down to 38% at year-end versus 60% at year-end '03.

Now if you'll turn to the next page, page eight or slide eight, I'll run through briefly with you a reconciliation of income from operations to reported net income.

In the fourth quarter we reported net income of $249 million or $3.49 a share; income from discontinued operations was 204 million or $3.06 a share; and income from continuing operations as a result was the aforementioned $45 million or $0.68 per diluted share.

For the year as a whole ended in 2004, reported net income was $332 million or $5.06 a share; income from our discontinued operations was 207 million or $3.15 a share; and income from continuing operations a strong $125 million or $1.91 per diluted share for the year.

The reconciliation of the non-GAAP results to the GAAP results for cash flow and EBITDAX can be found in the appendix to this slide show on pages 28 and 29.

And for those of you who are just tuning in on the teleconference and can't see the webcast, it's also contained on the last page of the earnings release.

To conclude I'd like to just review briefly a few more details of our financial position at year-end, show you a snapshot of our debt position.

Essentially with proceeds of $275 million from the sale of our Canadian assets we used that to -- and excess cash flow -- we used that to pay off our bank debt, fund acquisitions and build cash.

So at year-end we had no bank debt, nearly $300 million of unused availability on our bank line, our net debt of $426 million comes exclusively from two note issues with the earliest maturity being in 2011.

Net debt of 426 million is right now 1.3 times our '05 targeted cash flow and right at one times our '05 EBITDAX target.

With that I'll stop and turn it over to Bill Abernathy for production reserve comments.

Thank you, Bob.

I'd like to spend the next several minutes discussing fourth-quarter and year-end results focusing specifically on production, operating cost, reserves and then a few comments on oil price differentials.

For those of you that are on the webcast I'll be starting with slide number ten.

In the fourth quarter we reported production of 4.4 billion barrels of oil, 13.6 Bcf or 6.6 million BOEs from our continuing operations.

This is consistent with our total expectations for the quarter, it does not, however, tell the whole story on production.

We actually produced in the field an additional 400,000 BOEs, the biggest piece of that was gas in the U.S.

But because of some bad weather in our marine terminal in Argentina we missed a scheduled tanker loading of a little over 400,000 barrels of oil in the last week of December.

So although we actually exceeded our targeted forecast by about 400,000 BOEs in the field, we're only reporting volumes that we sold for the quarter and we have reported a corresponding inventory build in Argentina.

Total LOE per BOE for the quarter was $9.59, again from the continuing operations.

That was below our expectations because of lower cost and higher production in the U.S. and also because of lower export taxes in Argentina because of the lower reported volumes there.

These results bring our total reported production for the year to 16.7 million barrels of oil, 47.2 Bcf or 24.5 million BOEs from continuing operations.

And as for the fourth quarter, this is consistent with our public guidance and does not include the 400,000 barrel inventory build in Argentina.

Total LOE per BOE for the year was $8.90 and as of the fourth quarter figured below our expectations both in the field and in total for the reasons that I discussed for the fourth quarter.

Results in EBITDAX was $423 million and cash flow 313 million.

So we are quite happy that for the fourth quarter in a row we have been able to report results in which production volumes for the year were increased and we're also very happy to show decreased unit operating cost at the field level.

Let's move on and talk for a couple minutes about year-end reserves, that will be slide 11 of the webcast.

We entered 2004 with 447 million BOEs of proved reserves and during the year either produced or divested of the Canadian reserves of 14.6 million BOEs, leaving us with an adjusted starting point for the year of 432 million BOEs in the continuing operating areas.

During the year we produced 24.5 million BOEs and we had net additions from organic sources of 13.2 million BOEs, acquisitions of 16 million BOEs yielding year-end '04 reserves of 437 million BOEs.

On the next slide you can see that the year-end reserve figure is based upon a NYMEX oil price of $43.45 per barrel, an IMEX gas price of $6.15 per MMbtu.

That gives you a pre tax present worth at 10% of $3.7 billion.

Proved reserves of 68 percent oil and they are 67% developed.

On the next slide you'll see that we had reserve additions from all sources of 29.2 million BOEs and an all-in finding cost of $11.90 per BOE.

This is based on total capital spending of $347 million of which 110 was from acquisitions and 237 million was exploitations and exploration.

And this 29.2 million BOE of reserve adds replaced 119% of our production.

Three-year finding cost $5.27 per BOE and three year production replacement rate 146%.

So all in all we had a very good year in terms of production increases and reserve growth and beating our unit operating cost targets and beyond that just generating cash from those activities.

We have a very long-life reserve base and we still have quite a number of years of work to do on these properties.

Let's move on and look at our latest look at 2005.

First of all our non acquisition capital budget which is slide 14 on the webcast.

It will remain at $250 million with 178 million or 71% allocated to exploitation and 72 million or 29 percent allocated to exploration.

In the U.S. $40 million will be spent on exploitation of our existing asset-base with the significant programs being drilling and workovers in the Luling, Darst Creek and West Ranch fields in South Central Texas; the Gilmer South field in East Texas; the South Pass 24 and Main Pass 116 areas of South Louisiana and off-shore Louisiana and then several areas in California.

Domestic exploration has allocated $64 million of which 38 million is for conventional exploration along the Gulf Coast and 26 million is for unconventional gas exploration in four different plays.

In Argentina we expect to spend $113 million as we have our highest level of activity ever there with five rigs drilling in the San Jorge basin and a second year of more significant focus on water plug (ph) installations and 3-D seismic shoots (ph).

In Yemen we'll spend $25 million to finish the development of the Nagyah field and install a central production facility and pipeline and then we'll spend an additional $6 million for explorations in Yemen.

On slide 15 you can see our production target for 2005 is now 19.6 million barrels of oil, 40.8 Bcf or 26.4 million BOEs.

This is an increase of 600,000 BOEs over our previous target.

It's driven by the acquisition we reported in December of the big Escambia Creek field in South Alabama from Exxon Mobil, and that's just a stones throw from our existing operations there in the Flomaton and Fanny Church fields.

Beyond that there are a couple of instances where we are adjusting our guidance to the country level.

Because of the 2004 inventory build that I mentioned in Argentina we're increasing our targets there by that same 400,000 barrels.

And at the same time we are reducing our target for domestic California production by 400,000 BOEs as a result of the production that was shut in mid January in the midst of the mudslide in Ventura County.

Bolivia in Yemen will remain unchanged.

Altogether this is a little over a 2 percent increase from our previous guidance and it represents about an 8 percent increase over 2004 from continuing operations.

On slide 16 you can see the broader targets for 2005.

We're reducing our total LOE per BOE target to $9.70.

Although we will increase some increased cost in the field because of repairs and the California mudslide area, they will be more than offset by a reduced export taxes in Argentina resulting from moving certain volumes from the export to the domestic market.

We will continue to project 2005 financial performance on a NYMEX reference price for oil at $40 a barrel and at 650 per MMbtu for gas.

We'll see a reduction in our realized price for oil driven largely by a widening of the differential and Argentina oil prices, but we'll see an increase in our realization for gas.

And although there are a number of adjustments to our volumes, LOEs and realizations, our estimate of EBITDAX remains at $440 million and cash flow at $320 million.

One final item I'd like to address, one that I alluded to earlier is oil price differentials.

As you all know, the market saw a general widening in light heavy crude differentials in December of '04.

Specifically in Argentina our crude differential rose from a historical relationship with NYMEX of about 15% to average 20% in the quarter.

In setting our 2005 targets for Argentina we've assumed a continuation of our wider than historic differential for the year.

But our assumed NYMEX price for oil of $40 a barrel we've assumed a differential near that of the 20 percent that we experienced in the fourth quarter of '04.

If however the price of oil remains closer to that of the current strip, which is around $51 a barrel for the year, then you can expect differentials in Argentina to be wider than the average that we used in our model for '05, but altogether the cash flow for the Company will be quite a bit higher.

At this point I'll turn the mic to Larry Sheppard for a few comments on exploration.

Thank you, Bill.

To begin with let me take just a brief moment to summarize the significant events in our exploration program during 2004.

In our U.S. conventional exploration program we saw our first meaningful production come online mid year with the initiation of production from our Highland 55L (ph) and 56 (indiscernible).

Also during the year we had a nice -- actually two nice discoveries in Matagorda Island 639 and 640.

In our international exploration program we were successful in extending the western limits of our An Nagyah field and we also proved very successful in drilling horizontal development wells in the field that to date have resulted in our current production capacity exceeding the originally targeted 10,000 barrels a day by approximately 20 percent.

Finally, in late 2003 we began an effort to pursue unconventional resource plays in the United States with the goal of identifying and technically validating three play concepts during 2005.

Fortunately due to the hard work and the concerted efforts of our professional staffs, this endeavor has progressed much quicker than we had anticipated.

As we concluded the year we have identified and established meaningful leasehold positions in four plays and had even drilled and tested one of those play concepts.

Moving on to our outlook for 2005, as shown on slide 14 that Bill referenced just a moment ago, the inquiries from budget for 2005 is $72 million or approximately 29% of the Company's non acquisition capital budget. 89% of this total is allocated to our domestic exploration program while the other 11% is dedicated to the international.

In the U.S. conventional exploration program we have budgeted $38 million or 53% of the total exploration capital.

This budget provides for seismic, leasehold and the drilling of at least 10 wells principally along the Texas Gulf Coast.

Specific 2005 activity of note that are contained within the budget are the completion and facility dollars that are associated with bringing our Matagorda Island 639 and 640 discoveries onto production which should occur midyear this year.

Also we have budgeted the completion of the 3-D seismic program and the drilling of at least the initial two wells in Frio redevelopment gas project that contains deeper exploration potential.

Moving on to our international exploration program, we have allocated $8 million during 2005 or 11 percent of the total exploration budget, approximately three-quarters of this amount, as Bill mentioned a while ago, or $6 million has been earmarked principally for the drilling of two subsalt Lam wells in our Yemen Block S-1.

The first project, our Malaki well, has reached TD, and we have just completed logging operations.

Although we were encouraged because we found an extremely thick section of Lam sands, unfortunately it contained noncommercial shows of hydrocarbon.

Therefore, we are proceeding to plug and abandon this well at this time, and are going to move the drilling rig to our An Nagyah #15 horizontal development well.

However, based on the amount of Lam sands that were seen in our Malaki well, we remain very encouraged about our Lam exploration model, and its sand risk was always one of the greatest risks that we had.

We have one additional Lam prospect that is in the budget for this year, and we are continuing to work on several additional prospects that I am confident will generate additional exploration drilling in the future on Block S-1.

Let me conclude my remarks on exploration by bringing you up-to-date on what I think is one of the most exciting organic growth opportunities that we are currently pursuing at Vintage, and that is our U.S. unconventional gas resource program.

In response to the rapid progress that we made on this endeavor during 2004, we have significantly increased the portion of our exploration budget that is allocated to this activity.

Current plans call for us to spend $26 million during '05, which is 36% of our exploration budget.

That is almost double the amount that we spent during calendar year '04 on this activity.

Also, this budget will provide for us to be able to drill 10 wells to test four play concepts during this year.

To bring up to date on specific progress that we have made, just last week we sanctioned another shale gas project that we have commenced leasing acreage on in order to test this play.

Hopefully, we will be able to test the play before year-end.

So as of today, we currently have five sanctioned projects that we are pursuing.

Four of those projects are shale gas plays and one is a tight sand basin center gas play.

You can find reference material on these plays on slides number 17, 18 and 19.

If you look at slide 17 and 18 I'd like to specifically address the project in which we currently have our most activity going on.

We currently control over 175,000 acres in the four plays that I mentioned a while ago, 70% of this acreage, though, is contained within our Palo Duro basin project.

In respect to our Palo Duro basin project, you can reference what's described as play number one on both slide 17 and 18 as those demonstrate the project that we are proceeding there.

We have recently completed drilling the first well in this project and are currently evaluating the core data to aide us in designing the completion, stimulation and testing program.

A second well is currently drilling at 4,000 feet in this project.

In respect to the other sanctioned projects, we anticipate that we will have sufficient lease hold position accumulated to allow us to begin drilling on at least two other of these plays by midyear this year.

At this point let me take just a moment to remind you that unconventional plays are fundamentally different in nature from conventional exploration plays.

In conventional exploration the greatest risk is the location of a trap that contains hydrocarbon.

Simply put, the main risk is hydrocarbon presence.

In an unconventional play the risk of occurrence is almost negligible; you will almost always find hydrocarbons that can be produced.

The major issue that must be resolved in these plays is whether the reservoir is of sufficient quality that application of modern stimulation technology can enable the gas to be produced to commercial rates.

To mitigate this not well understood risk of commerciality in addition to applying best practices methodology to our technical and operational approach to these plays, we also plan to assemble a meaningful acreage position in a portfolio of plays so that we are not wholly dependent upon the success of only one or two plays.

In conclusion slide 20 provides you a summary of our current exploration portfolio of opportunities and the potential exposure that this provides to Vintage.

Consistent with our states philosophy of success-based budgeting, we will continue to allocate funds among these projects in a manner that will provide the maximum value creation.

And with that I'd like to turn it over to our Chairman and CEO, Mr. Charlie Stephenson, to conclude our prepared remarks.

Thank you very much, Larry.

Good afternoon, ladies and gentlemen.

You've heard the report of our financial and operational results for 2004.

We've met most of the globals that I set when I came back earlier last year and I'm very pleased with the results that we were able to achieve that has been described primarily by Bob Phaneuf.

This gives us very good momentum I feel like going forward to build from for this year's activities.

Going forward this year it's very important that we continue to be successful in property acquisitions.

Our focus will be on properties located primarily in the United States and South America.

Those properties that can provide us good economics that will allow us to build shareholder value and not just grow for the sake of growth alone.

We want new acquisitions to be available not only in the areas that we operate in but perhaps even in new core areas that will allow us to enrich our property base and provide for future exploitation and development activities.

We also want to continue to maintain and improve our financial flexibility so that we can take advantage of these opportunities as they become available whether they're in acquisitions, exploration or additional exploitation activities.

Exploration this year, as you heard from Larry, will be primarily focused in the United States around our unconventional gas projects and also in areas that we are having success in.

Simply stated I think, our goal going forward is to continue to build shareholder value by doing the things that our Company can and will do best.

And we'll continue to remain a top performer in our industry.

Thank you.

Leo, that concludes our prepared remarks and we can now open it up for the Q&A.

(OPERATOR INSTRUCTIONS) Joe Allman, RBC Capital Markets.

Your Yemen reserves, I thought they'd come in a little higher than they did.

Can you comment on what you had booked at year-end '03 and then also at year-end '04 and what went into those bookings?

Give me just one moment to pull a reference sheet so that I get the (inaudible) numbers.

For Yemen at year-end '03 we had 3.1 million barrels and at year-end '04 5.8 million barrels.

We produced during the year a little over half a million and we had positive revisions of about 630 and then through additional development in the field about 2.5 million of adds there.

At this point I think we have the reservoir almost completely developed.

There are a few additional wells that we'll drill this year but I think between what is producing and what is proved undeveloped, the entire reservoir is considered proved at the moment, but there are still some issues about what the recovery factor will be and at this point we're still using a relatively conservative recovery factor.

As you know, this is an oil leg with a gas cap.

We would expect that as the gas cap expands we could get recovery factors approaching 30% and I think something around 20% is what's being used in the reserves at the moment.

So there's another few million barrels net to Vintage that could be added as we go in the next years that we're producing.

But the pace at which those reserves will be added will be depending upon the pace at which the gas cap expands and exactly the efficiency that it provides us.

And then my final question is also international but not Yemen.

Your Bolivia gas production guidance seems to be for production to be lower than you had in 2004.

Can you talk us through that?

Yes.

You may recall that at the end of a couple of quarters during '04 we talked about the fact that we had been able to sell additional gas in Bolivia.

As we backfilled into the domestic market as some of the other producers were sending gas into Argentina that left a void in the domestic market that we were able to backfill into.

That backfilling was something that was very difficult to predict and we felt that as we came into '05 what made sense in terms of public guidance would be putting the forecast out that for sure had the B2B volumes in it and any domestic sales that we were confident that we were going to make.

But that these volumes that would be to any backfilling was something that we didn't have an ability to predict very well and we just didn't include very many of those volumes at all, really probably only 5 or 6 million a day for about half of a year.

The other thing I would point out that B2B volumes were -- are lower in '0 5 than they were in '04.

That was the way those volumes were contracted and that was expected for '05.

So what you see is B2B volumes and some domestic volumes but not an exceptionally large amount.

The truth is we will likely be able to sell some volume into the backfill market, but predicting what that's going to be is something that we just can't do right now so it's not in the guidance.

Thank you.

(OPERATOR INSTRUCTIONS) Brad Beago, Credit Lyonnais.

Congratulations on a good year where you met some really high goals and you guys were able to meet them.

So good job.

My question I guess on fourth quarter, the Argentina export tax went up by a lot.

I know they've reenacted or increased the tax rate.

Can you talk us through that and how you would suggest that we model it rather than just on a BOE basis, kind of on an absolute dollar basis, percent exported and the tax rate applied, that kind of thing?

Brad, this is Mike (indiscernible), I'll see if I can help you a little bit what that.

For the fourth quarter of '04 -- we experienced the full impact of the August '04 export tax increase.

And in the third quarter of '04, because our books were already scheduled, we did not see much of the increase flow through to those earnings.

What we really saw on the exports as a percent of NYMEX is it grew from about 17% in the third quarter as the previous export tax rate to about 24 percent in the fourth quarter as the new export tax rate.

Now you'll see the export tax manifest itself in two places, you'll see it as export tax expense for the portion of our barrels that we do export and you'll see it as a realization loss or a decrease in revenues for the portion we sell in the domestic market.

So you can safely say the impact of the export tax for the fourth quarter was about 24% of NYMEX and we expect that level to kind of hold true during 2005.

And I think that assumption is pretty much built in to our model at that level.

The expense itself should decrease because during '05 we plan to export fewer barrels than we did in '04.

So in '04 we were at a 50-50 domestic sales versus export sales mix.

In '05 we plan to be at about a 35% export versus domestic sales mix.

So you can see the expense actually decrease but the impact of the tax on our margins is the same as it was in the fourth quarter, about 24 percent (inaudible).

So going forward you would assume 35% exported and then a 25 percent tax on those barrels -- on the revenue of those barrels?

That's the correct assumption and then we would see that same 25% impact on the domestic barrels but it would not manifest itself as an export tax expense, it would show up as a reduction of revenues due to export parity coefficients that work in Argentina.

Brad, in terms of just absolute dollar guidance, our $40 assumed NYMEX for '05 is about what we averaged for '04.

And included in that per BOE number for taxes that's in our guidance table, that includes both the export tax and production and ad valorem taxes.

Our production and ad valorem taxes for '04 were about $23 million on an absolute basis and that's about what they should be given the price assumptions for '05 and '04 are pretty close.

Which would leave the export tax expense item at probably just under 40 million.

Okay.

Alright, great.

And then one another question if I can.

Looking at your domestic gas volumes, you actually hit it looks like a record level in fourth quarter, yet you've got a pretty modest guidance.

And I assume that that's assuming pretty rapid declines in High Island 55 and some of the Gulf Coast wells.

Is that the case and are you assuming really no additional drilling success to boost those gas volumes?

Brad, you hit the nail on the head there with Gulf Coast and offshore gas volumes being predicted to be on the decline.

That is absolutely built into the forecast.

But we are doing in the exploitation program this year drilling in a few areas where there will be additional gas volumes added.

Gilmer South is one, that's in East Texas, and also there will be some -- we will be continuing the gas work over program that has worked well for us in the South Central Texas area.

At this point those are not proved reserves and we are risking them in the forecast, but we have pretty high hopes for those and obviously our hope would be being able to beat the forecast that's out there.

Just to answer the last part of your question, I don't know if you heard that, but --.

Right, no exploration volumes.

No exploration volumes in the forecast, right.

Okay.

And then a follow-up on Ray's question.

But it looks like the Yemen reserves, that's like a 3.2 year RP and you discussed I guess the gas cap, etc.

But with the recent horizontal wells that you guys did it sounds like your volumes will well exceed that 10,000 barrel a day capacity that you're building the plant and the pipeline for.

Are you thinking about increasing the size of that project?

I think what we'll do is we'll watch and see exactly what happens when we bring the wells on.

I think the boilerplate capacity for the facility is 10,000 barrels a day and the capacity of the wells that we have at the moment is something like 12,000 barrels a day.

But depending upon how rapidly the gas cap expands and the pace at which gas volumes start to increase, there's a chance that we could move more than 10,000 barrels a day through the facility in the beginning and we will move absolutely as much as we can.

And then depending upon how well the wells hold up we'll decide at that point if there's a need to expand the capacity or not.

Okay.

And for modeling purposes, once that facility is up and running will that improve your oil price realizations in Yemen or would it impact operating costs there?

Just one moment.

Yes, it would improve realization from -- from about 80% to 88% of NYMEX.

And that's because of the elimination of the cost associated with trucking.

Okay, great.

Well, I had better let you guys go.

I appreciate it.

I've asked my one question.

Ken Beer, Johnson Rice.

A number have been asked luckily before me, but a question just on the Argentine export tax as it relates to your reserves.

Was there any sort of negative adjustment because of the export tax and how it relates to some of the proved reserves that you had?

What was the reserve impact of the export tax going up?

Ken, that export tax is scheduled to expire by its decree in about another two years.

And so only to the extent that a producing well would go uneconomic in the next couple of years would that export tax have any impact on the reserves.

So I'd say that it would be very small in its impact on reserves.

Perfect.

That's what I was aiming at.

Thanks so much.

Leo Mariani, Jefferies & Co.

It's actually Frank Bracken.

Two questions.

You all have amassed a pretty significant position in Big Escambia Creek and I was hoping maybe you could outline for us any additional plans to consolidate that area or maybe move forward with some sort of alternate processing scheme?

It looks like there's a lot of gas that doesn't make it to market.

Just hoping you could touch on that first and I have a second question after I get an answer to that one.

We'll let Chris Jacobsen visit that.

Frank, actually we are looking at some ways to consolidate some of those operations and even aggregate existing ownership in that (indiscernible) field area facility.

We're early in the process, we took over operations and became operator here recently.

We had a transition agreement with Exxon Mobil and we've got our hands on it.

We've already made significant progress in terms of improving the production, the Ngls and other matters out of the field as a result of taking over operations.

So we expect over the next several months that there will be ways to aggregate and improve the realizations both from a financial and a production reserve standpoint.

But we're not prepared to discuss which of those we think are best suited at this point, but we are actively looking at that.

And then secondly, correct me if I'm wrong, but as I understand it in your aggregation of acreage in the Palo Duro, one piece of that acreage came with a well bore.

Could you discuss -- and there are all sorts of accounts out in the public in the press as to what kind of performance that well bore had.

Could you clarify for us if that was in fact the case and whether it saw any production history?

Yes, we did indeed acquire a well bore in the acquisition of the acreage that we have in the Palo Duro basin.

And the well name is reported correctly in the press and probably nothing else is.

That well bore -- we have done some limited testing on it.

I'm not prepared to discuss the results although I can say that what I have read is not valid.

What we are doing at the moment, and this is critical, we have drilled our first well, we've taken substantial cores and we are in the process of analyzing those cores which will be quite a detailed process that will last over probably the next six weeks or so.

And then after that we will be in a position to know how to design what we hope to be the most effective stimulation for the Pennsylvanian shales that are the primary target of our effort.

At that point in time also our second well will be down, we will have those cores and we will be prepared at that point in time to go and to try to effectively test this play.

So it is not the Cogdell well that is going to provide us the answers to this play.

It is the Eckels (ph) well that we have just completed drilling and the Burleson Ranch well that we're currently drilling that are going to put us on the step forward.

But again I must remind everybody -- unconventional resources are different than conventional.

You drill a well in a conventional play, you log it and you know whether or not it's going to be productive most of the time.

Unconventional you just don't know and oftentimes it is a process of continuing to test and to refine your process, your approach and even your stimulation procedures.

As it's well-documented in the Barnett Shale, they have been improving that process now really for the last five years that that has had high activity and the process is better today than it was last year, that was better than the year before and better than the year before.

So that's the path that we're on.

Great.

I appreciate it.

John Herrlin, Merrill Lynch.

Just a couple quick ones.

You gave your global CDP/PUD (ph) kind of split.

Could you break it up between oil and gas or your own developed reserves?

John, we're searching.

Also how about estimated production development costs used to calculate the PV10 (ph)?

Okay.

John, for clarity would you repeat the first part of the question (multiple speakers)?

On your reserve statement you have your PDP accounts globally, but I don't see them broken down by gas and oil, just oil equivalents.

So I wanted the constituent breakdowns on gas and oil.

Just U.S. and Canada -- or I'm sorry, U.S. and Argentina.

Or if you don't have it you can just call me.

Okay, for proved undeveloped reserves oil is 98 million barrels, gas is 277 Bcf for 144 million BOEs.

Okay.

Don't have the development cost handy but I can get that and get it to you.

That's what I needed.

Thank you.

And there are no further questions.

I'd like to turn the program back over to -- actually we've got a follow-up from Mr. Joe Allman.

Sorry about that, everybody.

A question for Larry.

Larry, Kansas, that CDM play, am I correct that you guys have abandoned that opportunity?

Yes, Joe.

We drilled two wells in our project that was in the Cherokee-Forest City basin.

Unfortunately as it turned out the coals were thinner than we anticipated, but probably the most disappointing aspect of it is after we did our core evaluations the gas content of the coal was much lower than had been anticipated.

So we had probably a little over $1 million in that project and we were able to get to a point of deciding that it was not worth continuing to pursue.

So again, I think consistent with our philosophy, we amassed a significant enough acreage position.

We had over about 60,000 acres.

We got in there and tested it, we did it at a pretty effective cost on a risk potential basis and were able to determine that that one didn't work.

So we have impaired that and are moving on.

And moving over to Argentina, I know you folks did a couple water floods in 2004 and maybe you actually initiated some in late 2003.

Can you talk about responses you've seen from those so far?

We've seen -- from the project that we started in '04 we've seen just right at about 800 barrels gross or response in them.

And that would be new projects that we installed and then we have a continual program of going back and reworking existing water floods, both barrel expansion and vertical expansion into new seams.

Okay.

And then I noticed -- another PV10 question.

Your PV10 in '04 -- year-end '04 was based on an $11 higher oil price in that for year-end '03 and yet your PV10 on an Mcfe basis is just a little bit higher at year-end '04 versus year-end '03.

It's $1.41 versus $1.35.

What's the biggest component that causes it just to move up a little bit on a unit basis even though the oil price is quite a bit higher at year-end '04?

Is it really the tax situation in Argentina?

I'd say December differentials is probably the biggest thing that makes a difference there, Joe.

Like we mentioned earlier, the light/heavy spread ended up being pretty large in December and the reserve reports are done with what the differentials end up being on December the 31st.

So that is the driver there.

I was given the unit values on an Mcfe basis.

So I know you folks are mostly oil.

But I appreciate it.

That's all I got.

Thank you.

I'd like to turn the program back over to our hosts.

Thanks, everyone, for attending the conference call.

And as always if you have any additional follow-up questions that Gary Gamino (ph) or I can help you with please give us a call, 918-878-5451.

Thanks, bye-bye.

Thank you.

This does conclude our conference for today.

You may now disconnect your lines and thank you for participating.