西方石油 (OXY) 2005 Q1 法說會逐字稿

Welcome to Vintage Petroleum's conference call to review its first-quarter 2005 (technical difficulty) 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 (technical difficulty) Vintage.

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

Again, welcome to the Vintage first-quarter 2005 conference call.

A couple of quick housekeeping items.

We put out two press releases yesterday; both an operational update as well as an earnings release and you should have received both of those.

Two, just to go over who we have in attendance today.

We have with us Charlie Stephenson, our Chairman and CEO;

Bill Abernathy our COO;

Bill Barnes, our CFO;

Larry Sheppard, our Senior Vice President of New Ventures;

Vicki Bimerschtor (ph), VP and Controller; and Gary Jaminow (ph), Manager of IR.

One more housekeeping item that I need to share with you before we begin.

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

Although the dialogue and webcast slides contain current estimates and information with respect to targets, a number of factors could cause actual results to differ materially from the expectations we're going to discuss.

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

And occasionally on the call today we'll 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.

With respect to our agenda today, I'm going to lead off talking about a few highlights for the quarter.

I'll then turn it over to Bill Abernathy, our COO, to talk about our 2005 (technical difficulty) upward revised factors causing those revisions.

Bill will also review and update activity in our principal areas of operations.

Larry Sheppard will then discuss our exploration update and Charlie Stephenson again will come back with concluding remarks.

For those of you who are looking and listening in on -- vis-a-vis the webcast, we'll start on page two of the slides.

The first-quarter highlights, we had a very good quarter.

Income from continuing operations, basically the foreign non-cash unrealized derivative losses, was $43.4 million or $0.65 a share and this contrasts against $18.4 million last year or $0.28 a share in the first quarter.

Additionally cash flow was a strong $103 million, 6% above the First Call mean estimate, and a strong 58% above the cash flow of $65 million last year.

Additionally, we continue to show some balance sheet and liquidity improvement principally as a result of excess cash flow over CapEx.

Our net debt declined and our net debt to book ratio, also our capitalization ratio, also declined.

Finally, as Bill will go into in more detail in subsequent slides, we had a revision upward to our targets both financial and some of our operating targets based on year-to-date results.

The net net of that is that cash flow and EBITDAX targets were both raised 10% due to production (ph) and stronger oil prices in particular.

With that let me walk you through a couple of the (indiscernible) points (technical difficulty).

On slide number three, first-quarter average realized prices from continuing operations including the impact of hedges.

On the oil side, oil prices were up a strong 18% to $33.62 versus $28.54 in the last quarter year ago.

Gas prices were also strong, up 27% to $4.47 versus $3.51 last year.

And if you turn to the next slide, page four, where we (technical difficulty) volumes were also up for the quarter from continuing operations.

On the oil side it was up 24% to 4.9 million barrels versus 4 million barrels in the first quarter last year.

Similarly gas volumes were up 12% to 11.2 BCF versus 10 BCF in the last quarter a year ago.

And for total BOEs, it was up 20% (technical difficulty) million BOEs versus 5.6 in the year ago quarter.

So the stronger prices, stronger production resulted, as you see on page five, very strong oil and gas revenues up 45% in the first quarter this year versus the first quarter last year.

And we've discussed the income from continuing operations in cash flow comparisons.

I'd like to move on to slide six where we show you the improvement (technical difficulty) liquidity particularly from this time a year ago.

We saw some dramatic improvement when net debt a year ago was -- net debt to book was 59% and net debt was $620 million.

With the sale of our Canadian operations late in '04 it brought net debt to book down to 38% and net debt at year-end '04 at 446 million.

As a result of good, strong oil prices and excess cash flow over CapEx we've been able to grow cash and reduce net debt to $386 million at the end of the quarter and net debt to book down to 36%.

With that I'll stop here and turn (technical difficulty) over to Bill Abernathy (indiscernible).

Thank you, Bob.

I'd like to spend the next few minutes discussing the first-quarter production and lease operating expenses, some revisions to our annual targets and a few comments about our current operations.

For those of you that are on the webcast, slide seven presents our current and revised operating and financial targets for the year.

But before I address those I'd like to make a few comments about the quarter that will provide a little bit of background material.

Production for the quarter was 4.9 million barrels of oil and 11.2 BCF or 6.8 million BOEs.

This was about 300,000 BOEs above our expectation for production in the field and it has a number of components.

In the U.S. we produced about 150,000 barrels over expectations because we were able to return to production a little bit faster than we had expected.

A number of the wells in California that have been affected by the mud slides in January and additionally the exploitation drilling for oil in Luling and the Darst Creek fields in south central Texas turned out better than we had projected.

In Argentina oil production in the field was in line with our expectations and we sold about two-thirds of the inventory build that we had at year-end.

We would expect to complete that inventory drawdown this quarter.

And we were able to sell about 300 million cubic feet of gas over our expectation because of additional demand.

In Bolivia we sold about 450 million cubic feet over expectations as we were able to secure some additional sales into the Brazilian market, and we sold about 50,000 barrels more in Yemen than we had expected as we expanded our trucking operation.

Lease operating expenses were about $10 per BOE with lower-cost at the field level more than compensating for the higher severance in export taxes resulting from the stronger price environment.

So concerning our 2005 annual targets as a result of our production performance to date, we're increasing our annual production guidance by 400,000 BOEs from 26.4 million BOEs to 26.8 million BOEs.

And that increase is broken down as follows.

In the U.S. we'll increase the oil target by 200,000 barrels and for gas in Argentina we'll increase the target there by 500 million cubic feet and also in Bolivia we'll increase that target by 500 million cubic feet.

Lease operating expense for the year projected to increase from 972 to 1030 per BOE with cost in the field down just slightly and increased taxes resulting from higher prices being the driver.

We've increased our NYMEX reference oil price from $40 to $50 in light of the current and projected price environment and we've of adjusted our oil price realizations accordingly.

The gas reference price is unchanged at 650 per NMbtu.

Capital budget remaining at $250 million and resulting EBITDAX has increased to $486 million.

Cash flow increased to $350 million, up 10% to 11% in both cases.

Let me add one comment on the oil price realizations.

You may recall that at our year-end call in early March I pointed out the widening of the light/heavy crude price differential that we saw in December of '04 and those differentials were continuing into 2005 in the higher price environment.

For our current projections using the $50 NYMEX reference price we're reflecting those widened differentials to remain throughout the year and that's what causes the price realization to be dropped to 71% from the 75% that was used in the $40 (inaudible).

Now I'd like to turn your attention to operations for a brief update, slide eight on the webcast provides the map of our domestic operating area.

At present we have very active drilling and work over programs underway in the West Ranch, Luling and Darst Creek fields in South Central Texas, at South Gilmer and East Texas and in the Main Pass 116 area offshore Louisiana as well as various fields in California.

We have plans for continued work in all of those areas plus a number of other fields throughout the domestic operating area.

Our exploitation results to date, especially in Luling and Darst Creek, have exceeded our expectations and we will in all likelihood expand some of those programs.

With respect to exploration, Larry Sheppard will speak to that here in just a couple of minutes.

On the next slide addressing Argentina where we presently have five drilling rigs and ten workover rigs operating in the San Jorge Basin as well as one drilling rig in the Piedras Coloradas concession in the Cuyo Basin.

Argentina has our most active exploitation program with a budget of $113 million this year, the highest in our history in the country.

In the last several weeks we've drilled three wells that rank in the top 5% of all of the wells we've drilled in the country.

So our program there continues to be very successful.

In addition to the drilling and workover activities, there's a significant level of spending allocated to waterfloods and 3-D seismic, both of which are important to continued volume growth.

We just have a lot of upside in Argentina and we expect this activity level will allow us to continue to grow our volumes beyond the current level which is at the highest rate that we began operating there.

In Yemen, which is addressed on the following slide, we're continuing our An Nagyah field development and at this point we are drilling horizontal wells and we expect to drill at least two additional wells before the development is complete.

We're presently drilling an exploration well, the Wadi Markhah Number One which is about 50 kilometers to the southeast of the Nagyah.

And we expect to start up our pipeline later this quarter which will allow us to eliminate the cost of trucking.

And then the permanent production facilities will start up during the third quarter at which point we expect to be able to produce as much as 12,000 barrels a day drills volumes.

At this point I'll turn the mic over to Larry Sheppard for an exploration update.

Thank you, Bill.

On slide 11 we have captured what we believe to be the potential of our exploration portfolio as we're currently working on it.

These are prospects that are all actively being worked at the moment.

To provide you a reference point, our budget for this year for exploration is $72 million, 90% of that or 64 million is allocated to the United States.

Of that 38 million has been dedicated to our conventional exploration program as far as progress being made in that area.

We have just completed a 55 square mile 3-D survey in Wasus (ph) Bay.

That seismic is currently being processed and we would anticipate being able to commence drilling later this year and drill two, maybe three wells on that prospect this year.

Also the discovery that was made late last year in Matagorda Island 639 and 640 is progressing as it's moving forward to production phase and by midyear we would hope to see first production there.

In our own conventional resource play we have $26 million allocated for this year.

When we began the year we had four sanctioned plays and our plans for the year were to drill 10 wells in the four sanctioned plays to initially test those plays, also to continue to lease acreage and spend some G&G money on looking for new opportunities.

We had set for ourselves a goal to place ourselves into at least three new opportunities this year.

To date we have already sanctioned one additional play and currently have began leasing acreage there.

On the international side, as Bill mentioned a while ago, the one prospect that's shown here is the Wadi Markhah well that we're currently drilling.

It is a subsalt Lam prospect that's similar to An Nagyah and we're quite hopeful that here in the next few weeks we can have some positive indications from that.

On slide 12 we provide a comparison of our Palo Duro Basin unconventional play with the Barnett shale.

We have shown this before but it's to provide just a sense of comparing the two plays.

Although the Barnett is a little bit older being Mississippian in age, the Paulo Duro is middle Pennsylvanian, it's an Atoka shale.

Still they're somewhat similar to each other.

We're a little deeper in the Palo Duro than the Barnett, but we have thicker section -- both thicker growth shales and thicker net shales.

Where we stand currently at the moment, we have now drilled two wells, we've taken cores in those wells.

We also have quite an extensive amount of open hole log data.

We have almost finished all of the core analysis on our first well and that information is being utilized at the moment to design the completion and stimulation of that well.

We would hope to be in position that all of that would be completed so that we could commence completion and fracture stimulation certainly within the next six weeks, maybe eight weeks at the outside on the first well.

The cores are currently being analyzed for the second well and we don't really want to comment on blow by blow where we are other than to say that things are progressing nicely and so far what we've seen is certainly confirming our original analysis that this is a play that very much merited our participation in.

As far as the other four plays, we have to this date leased over 70,000 acres in those plays.

We continue to lease -- and I don't want to speak of where they are at the moment because we are in competitive situations, but I would say that we are moving forward not only with leasing but with plans to drill and it would be our expectation that we would be able to drill the initial test wells in those plays probably in late third quarter, maybe early fourth quarter.

And with that I will turn it over to Charlie Stephenson for our concluding remarks.

Charlie?

Thank you, Larry.

As you've heard, we are having good success in our operations so far this year.

I think the success that we had last year, not only reducing our debt but growing our production, has certainly set the stage for the performance that we hope to achieve this year which should be very good.

We fully intend to keep our Company at the very top of our peer group in shareholder performance.

In addition to the drilling and exploitation activities, we also are aggressively pursuing acquisitions.

I would like to see us acquire at least $250 million worth of new oil and gas assets this year.

We, as you know, kicked off our acquisition program last year.

We bought $110 million during the last half of the year.

So far we have evaluated acquisition ranging from 800 million probably down to $5 million in size.

We're very hopeful that we'll be able to make some very good acquisitions this year.

They'll be oriented do not just grow this Company in size but to add value for our shareholders.

If we make any large acquisition it will certainly be funded by the appropriate amount of cash flow, debt and equity that will allow us to be in a position to continue to pursue any activities that we choose to.

With any large acquisition we would certainly probably hedge our oil and gas prices to protect the economics of the acquisition.

I think that concludes my remarks.

I'll turn it back over to Bob.

Thanks, Charlie.

Matt, we're now ready to open if up for Q&A.

(OPERATOR INSTRUCTIONS).

Frank Bracken, Jefferies.

I was hoping you could give us a little color on this Yemeni exploration well.

From your cartoon map it looks like it covers a fairly large aerial extent.

I was opening you could give us a handle on how it's similar/different in terms of play type to the success you've had to the North?

Frank, it is similar to An Nagyah.

It's targeted to be subsalt in the Lam.

We're quite a distance away, as Bill said, 50 kilometers away, so very little well control where we are.

It is pretty frontier, as all of block S-1 has been.

What we have that controls the prospect is 2-D.

We've not shot 3-D down on this end of our area.

So the blob looks kind of big.

As far as how big the area is it depends on whether or not we find a nice good closed structure.

This whole area is quite complex in trying to look subsalt and really with high precision image the reservoir.

I'm one to say we need to get this well drilled.

It could be a nice size structure.

I think as far as in our thoughts we're believing it has every bit as good a chance to be the size of An Nagyah and keep our fingers crossed hopefully if it works it's even a little bigger.

Great, thank you.

Pavo Molkinov (ph), Raymond James.

Just looking at the balance sheet, you have one of the largest cash position you've ever had.

Just wondering if there's any possibility of either a onetime dividend or increasing the dividend or a buyback?

I think we look at those kinds of things all the time in conjunction with looking at acquisition and trying to figure out where we do want to spend our money.

So I think it's a fair statement to say that all of those kinds of things, including the acquisitions that Charlie talked about, our under active scrutiny.

Okay.

(OPERATOR INSTRUCTIONS).

Ray Deacon, Harris Nesbitt.

My question was on the drilling in the Palo Duro.

What data that you hope to collect would give you enough confidence to be drilling and could it be by early next year or do you think you could have some -- several more wells drilled by the end of the year?

The track we're currently on is really trying to make sure we do our homework well.

We're probably spending a little more to do science on this project than maybe what has been done on others where people intended just to drill and frac and see if that works and if it didn't try something different.

That is why we're being pretty methodical with the core analysis work we're doing in integrating all of the information.

Again as I said, I think we're going to be in the position here within the next six weeks or so that we're going to begin completion and fracture stimulation operations.

After that we will have a period of time with both of the wells that we've drilled where we will need to have some extended flow tests, try to make sure that we are defining the reservoir well and at that point in time I think we would begin to plan to see if we wanted to go ahead and move the drilling rig back in and drill a few more wells.

I think this process, particularly with shale gas plays, is not well understood and I found it interesting to listen to the Southwestern Energy conference call where they've now drilled 39 wells in the Fayetteville and are still refining their completion stimulation.

So we're trying to move ahead as quickly as possible, but we're wanting to make sure that we do so in a prudent way.

I would think that you would see us in a position that we would anticipate by early next year to be drilling -- hopefully drilling some more wells.

Okay.

You did recomplete one well.

I just was curious how that was going.

What we did, it actually wasn't recomplete.

The well that existed that was drilled a couple years ago when we bought the acreage had some -- we were a little confused about what the test results actually were on that well so we went back in to test it.

It had been completed all the way from the Morrow on up.

The Morrow are wet sands and so in essence we have been testing that well, trying to isolate the water and the source of the water that exists at the bottom of these zones.

But so far really doesn't have anything to do with the heart of the play that we're working on.

We're just trying to make sure we understand the entire section that we're working so we don't get a surprise later on that we could have known right now.

Okay, great.

And just anything -- results from the waterfloods in Argentina, do they seem to be living up to expectations in the quarter?

Yes.

There were about three or four floods that we spent money on installing last year and we're beginning to see a little bit of response at the moment.

But I think what is fair to say, which I probably have the best information on if I just look at incremental secondary volumes say at the end of '04 relative to the end of '03 it's a probably 850 barrels a day.

That's probably the best quantification that I have at the moment.

Typically these floods take a year or better to respond.

At this point we wouldn't have been expecting large volumes yet from the floods that we installed last year.

But I'd say the prognosis is good and obviously we're expecting some big things out of those.

Okay, great.

Thanks, Bill.

Brad Beago, Calyon Securities.

Larry, you went over real briefly the barn burner wells that you guys have put down in Argentina.

I was wondering if you could provide a little bit more color.

I see that you're talking about at least one of them was based on your new 3-D.

Are you doing something different?

Have you found something different or is it just a nice sweet spot?

Brad, those wells were in probably three different areas, so there's not a class answer that covers all of them.

I would say we're not doing anything different with the 3-D.

We're continuing to apply it the same ways that we have in the past.

We're continuing to use it to look at some infill locations as well as stepout locations.

Some of the areas in the West that we've not been as active drilling in the past and where we have some new 3-D surveys, over the last six months we've had a number of good wells there.

Some of these wells are also in areas where we have drilled a number of wells in the past, for example Canadon Seco and Canadon Leon as opposed to Sera Wenceslau (ph) and Las Heras/Piedra Clavada which are some of the areas to the West.

We're having good results in all over the Southern San Jorge basin, it's not just confined to one spot.

We're excited about those.

Obviously the wells come on at pretty good rates and sometimes they fall off pretty fast.

And we don't know exactly where these wells will settle out, but at this point we're very encouraged and they look like there are offset possibilities to all of these better wells that we've just recently drilled.

We're pretty excited about that.

It's just a little bit premature to tell exactly how much more running room that's going to give us around those immediate wells but it looks like there certainly is some.

So you're not ready to commit to 400 more of these?

No, we are.

I guess my other question is for Bill or Bob.

Just looking at LOE and how it's bounced around the last couple of quarters and you've raised your target really not for base LOE but just severance tax.

What can you tell me about LOE and what's going on there?

I guess probably the thing to point out is in some of our areas, particularly the areas where we have a lot of wells, large number of facilities and things like that, a lot of the costs are relatively fixed and so as you add incremental wells sometimes the LOE per BOE doesn't go up dramatically.

Certainly that would apply for Bolivia.

In the U.S. some of the newer volumes that we're adding in Luling in Darst Creek the oil rates are pretty good but the water cuts are also very high and we moved most of that water with electrical submersible pumps obviously driven by electricity.

And those are fairly high lifting cost wells that there are a lot of facilities and disposal wells in particular in that area.

Those wells, as we add those, are a little bit more expensive than the average.

Okay.

I'm just looking fourth quarter to first quarter where about $8 million of increased just lifting cost were added.

So a big chunk of that is California?

Yes, about 3.5 to 4 million of it was with respect to the mud slides and then for the volumes in Argentina, that was an inventory build that we sold during this quarter.

The LOE follows those barrels.

So it was maybe artificially lower in the fourth quarter and artificially a little higher in the first quarter.

So that can drive a number of things.

Thanks a lot, guys.

Good quarter.

Frank Bracken, Jefferies.

My question has been answered.

Thank you.

(OPERATOR INSTRUCTIONS).

It appears there are no further questions at this time.

I'd like to turn the call back over to management for any closing remarks.

Thank you all for joining us today.

We appreciate your time and your interest.

And if there are no more questions we'll conclude the call.

If anybody does have any questions, Gary and I will be around for a while, 918-878-5451 today or tomorrow.

Thanks very much.

Goodbye.