Filed by Plains Exploration & Production Company

Pursuant to Rule 425 of the Securities Act of 1933, as amended, and

deemed filed pursuant to Rule 14a-12 of the Securities Exchange Act of 1934, as amended

Subject Company: Stone Energy Corporation

Commission File No: 001-12074

The following is a transcript of a conference call made by Plains Exploration & Production Company:

Plains Exploration

Moderator: Scott Winters

May 4, 2006

3:00 p.m. ET

OPERATOR: Good afternoon. My name is Lynn (ph) and I will be your conference facilitator today. At this time, I would like to welcome everyone to the Plains Exploration, first quarter, and 2006 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speaker’s remarks, there will be a question-and-answer period. If you would like to ask a question during this time, please press star then the number one on your telephone keypad. If you would like to withdraw your question, please press the pound key. It is my pleasure to turn the floor over to your host, Mr. Scott Winters, sir you may begin your conference.

SCOTT WINTERS, PLAINS EXPLORATION: Thank you very much, Operator. Good afternoon to everybody. On the call today is Jim Flores, our Chairman, President and Chief Executive Officer; Tom Gladney, Executive Vice President of Exploration and Production; John Wombwell, Executive Vice President and General Counsel; Cindy Feebeck (ph), Vice President of Accounting, Controller, and Chief Accounting Officer, and Winston Talbert (ph), Vice President of Finance and Treasury.

I’ll begin by reminding everybody that during this call, there will be forward-looking statements as defined by the Securities and Exchange Commission. These statements are based on or current expectations, and projections about future events, and involve certain assumptions, known as well as unknown risks, uncertainties and other factors that could cause our actual results to differ materially. Please refer to our Forms 10-K, 10-Q, 8-K filed with the SEC for a complete discussion on forward-looking statements, with that, I’ll turn the call over to Jim.

JIM FLORES, CHAIRMAN, PRESIDENT, CHIEF EXECUTIVE OFFICER: Thank you, Scott and good afternoon everyone. With PXP reporting its first quarter 2006 results, it’s been a busy quarter in the first quarter, as well as in the second quarter with our announced Stone acquisition.

But focusing just on the first quarter, where the operating cash flow nearly doubled to 151.2 million in the first quarter is a wonderful feeling here at PXP, selling oil without the effects of underwater hedges. And it reflected also in our operating earnings in the first quarter, they’ve increased over 200 percent. The margin increase on a per barrel basis is upwards of a third, to 34 percent. We continue to enjoy those prices today. Production being 60,700 barrels a day, as compared to the first quarter 2005, of 637, when you adjust it for asset sales in 2005, it’s slightly ahead of where were in the first quarter of 2005 and flat with the fourth quarter of last year.

Now (INAUDIBLE) costs were up about 17 percent, this quarter basically due to service provider general oil fuel inflation, and also some accelerated work-overs and repairs.

With that, I’m going to turn it over to Tom Gladney, to kind of go through some detailed operating results on our ongoing operational wells. And then, Cindy Feebeck (ph) who’s our interim CFO upon waiting the close of the Stone deal and Ken Beer joining our outfit, and then we’ll open it back up for question-and-answer from there. So Tom.

TOM GLADNEY, EXECUTIVE VICE PRESIDENT, EXPLORATION AND PRODUCTION: Thank you. Good afternoon. I’ll provide more detail and information on PXP operations to go along with the release we made this morning.

Before getting into specific oil and project results I’ll discuss oil and gas volumes, which were 60,700 barrels of oil equivalent per day of sales in the first quarter of 2006. Our present volume recording is required by the SEC is net sales as opposed to reporting of production, as was done during 2006 and prior years. Because of the required accounting change, our full year volume guidance was issued in December of 2005, showing both production and net sales, with net sales guidance about 3000 net barrel oil equivalent per day, lower than production guidance.

1

Our full year guidance for sales is 67 to 77,000 barrel of oil equivalent per day. We’ve seen flat production in the first quarter, which will ramp up from our front end loaded capital program, and as our secondary and tertiary recovery program see oil production response.

Moving on to some well and project results, as stated in our release this morning, we did bring on our first Point Pedernales in field well, the 820 from our 100 percent owned Platform Irene located offshore California. The well rate is about 200 barrels of oil per day. Moving down the cost, to our Point Arguello platforms we have drilled our CPT Rock Point near horizontal wells to total depth, and we found geological markers and pay exposure as we expected. We’re presently starting on completion operations with our first production, the sales like in late May or early June. Based on well results, the well should be comparable to our other two Rocky Point near horizontals. The C15 completion would conclude our presently planned Rocky Point development, and the rig will demobilize from Point Arguello.

Presently, we are producing about 6100 net barrel oil equivalent per day, from the Point Arguello platforms which includes about 2000 net barrels per day, from the three completed Rocky Point wells. We continue to consider other opportunities for new wells from the Point Arguello platforms, and any that are viable could be drilled in the future from our PXP owned drilling rig on the Irene platform whenever that rig profitably occupied there on Irene. On an overall basis, total offshore California, provides about 23 percent of our total present production.

In the Los Angeles basin which produces about 27 percent of our total present production, we’ve had a busy rig year all ready along with gas plan, another facility construction and de-bottleneck projects. So far all of our drilling has been in the large Inglewood field, primarily in our bread and butter, Victor’s Ridge water flood zone. In the next few weeks, we’ll be directing some of our drilling efforts there in Inglewood to expanding a successful Monet formation water flood pilot, and establishing new water flood areas in the ruble (ph) formation both of which lie below the Victor’s Ridge.

Also in Los Angeles, we plan to drill six wells in the Las Cienegas field, we acquired in 2005. That drilling will occur this summer. We spent the intervening time since the acquisition, planning the mechanics and understanding the geology since we first evaluated this property. We’ve also been working along side our neighbors and local officials so that our drilling operations will be accomplished both safely and efficiently as well as harmoniously with the local community just like we do everywhere PXP operates.

One of our Las Cienegas wells will also have a deeper exploratory tail component which although higher risk could provide incremental new reserves if successful.

Staying in California, in the San Joaquin Valley, which provides about 38 percent of our current product, we drilled 78 wells so far this year, with the majority of 43 in Midway Sunset. Last year, our Midway Sunset drilling was focused on new reservoir steam flood, initial development. This year, we’ve done much more in field development in other established parts of the field. The difference in field drilling, versus new territory expansion is important when we consider volume interruption effects. Although we anticipate some drilling related production interruptions, it’s difficult to pinpoint the exact amount of durations. And by production interruptions, we have to take precautions to protect our rig crews and the environment when working in tight well spacing around live high pressure steam. So as our drilling rigs move from well to well we have to stop steaming certain areas, and relocates lines of facilities. We will finish one of our large interruption impact in field programs later this month but will continue to have less amounts of drilling related volume interference through August.

Moving to Texas, we’ve been working on two different exploitation plays involving horizontal formation, one in the Petit formation of East Texas, the other in the Ellenberger of West Texas. We’ve captured several large pacific prospects in each play and have started their evaluation. In both plays, we first drill a conventional vertical pilot hole through the target formation, to determine if there’s sufficient quality pay before going forward with the horizontal production well boar (ph). Thus far in the Petit play, we’ve drilled one vertical well which we evaluated and elected not to drill the horizontal portion. And we’re presently drilling the horizontal leg of the second well.

In the Ellenberger play, we’re testing a horizontal well at this time. We’ve drilled one vertical well without proceeding on to drill the horizontal, and we’re just starting the vertical part of a well on our third prospect.

2

Our last PSP area of interest, is the deep water Gulf of Mexico, middle lower, Miacenecrine (ph). Although we must wait on the wells to be finished, and our operators to make specific comments, I can say that we expect a considerable amount of results over the remainder of the year given our activity level. News that should nearer in time would include the (INAUDIBLE) results from the previously announced Big Foot discovery and information on the initial drilling at the Cesar prospect, located between the industry announced Tahiti developments and the Tonga discovery. PXP has a 12-and-a-half percent interest in Big Foot, and a 17-and-a-half percent interest in Cesar.

Not as far along, but underway is the Parisian prospect, which is also located in an upscale neighborhood between the Tahiti development and the Knotty Head discovery. We have a 10 percent interest in Parisian. In just getting starting with the rig moving in this week, there’s the Grand Cayman prospect in Barden Bank (ph) which PXP has a 30 percent interest. When other similar deep Miacene’s (ph) hit, Norman with a 15 percent PXP interest should also spud this summer.

Also as I should mention, as stated in our release this morning, we have increased our expectation for capital spending this year to $496 million of operational capital for PXP on a standalone basis to fund delineation work at big foot, as well as certain of the previously discussed deep water wells, that were not included in our original budget or guidance.

Lastly, I want to publicly mention our California owned and offshore field employees who found out this week, that they were awarded a national level industry leader award by the National Safety Counsel, for their safety performance in 2005. Well done there. Thank you.

JIM FLORES: OK, Tom. Thanks. Cindy (ph).

CINDY FEEBECK (ph), INTERIM CFO: Thanks, Jim. And good afternoon. PXP reported a net loss of $51.7 million or 66 cents per share for the first quarter of 2006. This compares to a net loss of $205.6 million or $2.66 per share for the first quarter of 2005. Both periods were impacted by mark to market derivative losses, non cash hedging charges, and stock based compensation. Reported results for the first quarter of 2006 also included $2.2 million after tax charge, for the cumulative effect of adopting FAS 123R, stock based compensation.

As Jim mentioned, after adjusting reported results for these items, net income was 65.8 million, or 83 cents per share in 2006, versus 20.2 million or 26 cents per share in 2005. This is a non GAAP measure and the last page of the press release has a table summarizing these adjustments.

For 2006, our crude oil derivative position consists exclusively of purchase put options. The only tax settlements we’re required to make on these contracts are option premiums which are approximately $7.5 million per month. As a result, the company’s realized price per BOE increased 73 percent from 28.09 in 2005, to $48.51 in 2006, as we realized the benefit of increased commodity prices. Cash payments related to hedging and derivative transactions were 405 for BOE in 2006, compared to $11.12 in 2005.

Operating cash flow increased to 151.2 million in the first quarter of 2006, compared to 78.1 million in the first quarter of 2005, due to the increased priced realization. Operating cash flow is also a non GAAP measure, and it’s reconciled to the GAAP measure on page 11 of the press release.

On the cost side, production costs were $13.03 for BOE, which is within the guidance range of $12.80 to $14.45. One item to note, is that the steam gas component of production costs was below guidance, and this was due to a couple of factors. One, we had large supply issues in California. And gas prices were lower than the prices we had used in our guidance forecast. The year over year increase in production costs from $11.14 in 2005, to 13.03 in 2006 is primarily attributable to general cost increases within the increase, and increased work-over and repair (INAUDIBLE).

G&A expenses for the quarter excluding stock based compensation were $15.3 million in line with guidance. We reported stock based compensation expense of 7.7 million in the first quarter of 2006, compared to 25.8 million in 2005. The decrease is related to changes in our stock price, as SARs and certain of our restricted stock payments are

3

subject to variable accounting. As a result, we expect continued volatility and reported stock compensation expense as our stock price changes.

As previously announced, we recently executed contracts to eliminate all of our 2007 and 2008 crude oil callers. Our remaining derivative position consists of crude oil puts, and any mark to market impacts limited to the deferred premium throughput. As a result, the volatility and derivative gains or losses on our income statement will decrease after the second quarter. The $600 million cost to eliminate the callers, represents the fair value of the callers on the date we entered into the contract to eliminate the position. The majority of this amount had been recognized in earnings as of March 31, 2006. We will, however, recognize mark to market losses of approximately $90 million in the second quarter of 2006, and this reflects the decrease in the fair value of the callers from March 31, through the date we entered into the contract to eliminate the position. Our current derivative contract position is attached to the press release.

Turning to the balance sheet, our debt balance was $812 million at March 31. This compares to $797 million at year end, and the increase is due to timing of our capital program.

And on a final note, we plan to file our Form 10-Q tomorrow, so you can get further information at that time.

JIM FLORES: Thank you, Cindy (ph). Operator, at this point, in time, we’ll open it up for questions.

OPERATOR: Thank you. At this time, I would like to remind everyone, if you would like to ask a question, please press star then the number one on your telephone keypad. We’ll pause for just a moment, to compile the Q&A roster.

Our first question is coming Duane Grubert of Execution LLT.

DUANE GRUBERT, EXECUTION LLT: Yes, guys. I’d like to see a little more commentary on the great well at Point Pedernales. You mentioned that there are probably four projects identified now. So, really my question is this, is that first one unusually good relative to the other three and what your expectations are? And is there a possibility after that well coming on as well as it did that there might be more than four?

JIM FLORES: Duane, this one is a little bit better in terms of initial rate than we forecast for an average of the four. The wells we’re going to be drilling are targeted in sort of different lateral and zonational (ph) parts of the reservoir. The lower most zones are more fractured and more productive in terms of volumes but generally they’re also closer to water.

This well counted is the first well, you know, we tried to drill our best shots first, is the way we rank things both in terms of mechanical ease of drilling and potential. And this one, as I said, exceeded a little bit. We’re also very pleased, the oil cut is quite a bit higher than either of the direct offset wells, which was one of our concerns, we just don’t duplicate, or we’re going (ph) to access substantial additional reserves. So we’re pleased. This year, time wise with the work-over also do, we probably won’t have time to drill four wells. As we drill and refine our models and look at our results, we’ll see if there are additional opportunities.

TOM GLADNEY: Yes, Duane. We’re going to take it slow. This is the first well that – the first new drill in 10 years on Point Ped, so we hope they all turn our like this, but we’re forecasting, you know, still around 1200 to 1500 barrels per day of production average.

DUANE GRUBERT: OK. And then, similarly on an area that hadn’t been worked on for a long, long time, if you could just talk a little bit more about Las Cienegas. Similarly, if what you’ve seen to date gives you encouragement, maybe there’s a little bit more there to work on them.

JIM FLORES: Duane, we really haven’t started drilling yet. And actually, the former owners, a private company did drill a well or two a couple of years ago. Other than that, you’re correct. It had been a pretty long period of time, you’d probably have to go back 10 years or more to the Unocal days.

4

We had a pretty good idea of potential from the evaluation when we did the acquisition. There’s a little bit of seismic data, and we’ve done some more sub surface data, so we’ve tightened up our geology, planned our drilling program very carefully. And even though the permitting was very straight forward there, this is an urban area, so we had a lot of community meetings, neighborhood meetings, church house meetings, if you will, to make sure everybody understood what we were doing, why we were doing, listen to their concerns. And then – and we did identify kind of a deeper zone there, it’s not a lot deeper, but it could be pretty nice if it works out albeit it is higher risk. But while we’re drilling there, one of our wells is going to sort of test that concept.

DUANE GRUBERT: OK. And then, finally, on your Diatomite stuff in the San Joaquin Valley. I didn’t hear anything specific on that. I’m wondering if there’s any update in your internal sentiment on the prospects of the thermal Diatomite. And maybe some of the competitor work out there has given you more or less enthusiasm for that stuff.

JIM FLORES: No, we’re real – we continue to be, I guess, equally as high as we’ve ever been. I won’t say we’re more or less anywhere. We are doing some thermal Diatomite work on sort of an in field basis in a simmeric (ph) field right now. We drill some simmeric (ph) to lorry (ph) thermal sand wells earlier this year. We’re now drilling some Diatomite in field wells. We’re actually pilot testing some closer spacing. And also, the nature of that sort of recovery where you actually crack with steam over and over again, some of those wells, you know, after so many cycles of high pressure steam crack injection will mechanically fail, and so we’re going in and replacing some of those.

Now there’s some green field new thermal Diatomite up to the north end of Midway Sunset that we drilled and delineated with a lot of stress test, last year. So we’ve got a pretty good handle on the size and shape of the resource. And it is a resource because, you know, until actually establish commercial production and have it going down the sales line, they’re not crude barrels no matter how highly convinced we are, and how highly probable they are. And that program will kick off kind of later this summer. And we’ll have some initial production established, as well as some more delineation of potential.

DUANE GRUBERT: OK. Great. Thank you very much.

OPERATOR: Thank you. Our next question is coming from Van Levy of Dahlman Rose Capital.

VAN LEVY, DAHLMAN ROSE: Good afternoon, gentlemen. How are you?

JIM FLORES: Fine.

VAN LEVY: Good. Jim, I was hoping you could give us an update on the Cook Kell (ph) real estate venture?

JIM FLORES: Can, we don’t have anything really material to talk about. We had to delay our meeting out there because of all of the Stone activity. But we’re pressing forward through the atomic (ph) process. And we’re going to have probably more specifics on the second quarter call, but we don’t see any imminent changes there, other than just getting our game plan in place, and continue to get more optimistic as far as the communications back and forth between the city county and all of the regulatory agencies as far getting it by rounded up and going in the same direction. So we’ll updates going forward.

VAN LEVY: And just big picture, when do you think this thing could come together? Is it end of next year, or middle of next year?

JIM FLORES: We’ve talked about end of next year, end of ‘07 on an optimistic basis, end of ‘08, on a more P50 basis.

VAN LEVY: OK. Game plan for integration of Stone?

JIM FLORES: Gosh, it’s pre mature to talk about that, Van. I’d love to tell you I knew all of the answers right now, we don’t. We’re basically in the learning stage of, you know, of what, you know, direction, personnel wise, and operations wise we’re going to do that. They have a lot of talented people. And they give us a lot of flexibility,

5

Rockies, the Gulf, a lot of things they were doing, that we think we can create a lot of value for us. So we’re going to be coming up with plans on that, you know, as we get closer to the close. Our objective right now is there’s been an S-4 filed so we can have all of the information out there, and people can kind of start putting their thoughts together on a combined basis.

VAN LEVY: Good. OK.

JIM FLORES: Also, I don’t think you mentioned anything about your Texas exploration program. I think you have seven to 15 prospects there kind of slated.

VAN LEVY: Yes, Tom talked a little bit about Ellenberger and the Petit a little bit – that was the Ellenberger and Petit in West Texas. Tom, do you want to comment?

TOM GLADNEY: Sure, Van. Yes. We’ve got about four Petit prospects, and thus far, we’re testing our second one. And we probably got, you know, four, five, Ellenberger prospects in West Texas, separate, you know, multi thousand acre, lease hold accumulations and targeted prospects. As I said, we’re currently just now starting, just now spudding in, if you will, on the third Ellenberger. One of those Ellenberger wells we drilled a vertical pilot hold. Didn’t see, you know, what met our criteria that would cause us to spend the money to drill the horizontal. So, you know, it pretty much stopped right there with the vertical.

The second Ellenberger well we did get encouraged on our pilot hold. We did drill our horizontal. We have flowed hydrocarbons out of it, but not on a sustained basis. We’re going to do some stimulation work, and actually this one is kind of an oiler thing, when really we’re expecting gas. Now that’s just fine with us, but we’re going to put it on pause to get a sustained production test, you know, see what we’ve got there.

So it’s early on, but there’s nothing really too much write home about other than a progress report.

JIM FLORES: Yes, and what we’re basically looking at to find out what part of the ‘07 capital budget we’re going to establish for development of these things, a large acreage spreads. And we’re purely in the exploratory phase of this.

VAN LEVY: OK. And again, on the last conference call, there was – I guess there was some disconnect in the sense of, you know, the merger pre the kind of leverage, recapitalization, stock buy back. Big picture Jim, has anything changed in your mind in terms of kind of an aggressive stock buy back program?

JIM FLORES: I don’t understand the first part, discontent. But the aspect of the ability to buy back stock, that’s still well in place post the Stone transaction.

VAN LEVY: OK.

JIM FLORES: As certain shareholders said, you know, it’s kind of strange to issue shares, do you can buy it back, but the aspect ratio (ph) for barrels that are higher value barrels on a PV basis, and we’re also extinguishing the callers in ‘07 and ‘08, which will give us the free cash flow to actually continue to buy back shares on a continuous basis, not only here in ‘06, ‘07 and ‘08 and beyond. And at the same point in time, using the tax attributes of the hedge buyout to deal with after tax dollars. So I think we’ll be in a good position, you know, later this year, if not the first part of next year to do that.

VAN LEVY: Sure.

JIM FLORES: We’ve got some rating agency meetings next week that are going to evolve around our debt and so forth to get some clarity. We’ve got to go through those communication processes and kind of just be in a holding pattern until we get the Stone deal closed, and we can speak more authoritatively there.

VAN LEVY: Sure. OK. So you have a lot of unhedge Stone incremental production, you’ll have a ton of cash flow. You’ll focus on paying down the hedge debt, and then you’ll move to the buy back when it makes sense.

6

JIM FLORES: Van, also, I mean the flexibility in doing the equity with Stone gives us a combination to do a combination of aggressively paying down debt, and also aggressively buying stock.

VAN LEVY: Good. OK. Great, thanks Jim.

JIM FLORES: OK. Thanks.

OPERATOR: Our next question is coming from Irene Haas of Sanders Morris.

IRENE HAAS, SANDERS MORRIS: Hi, my question really has to do with deep water. I didn’t catch how much of a cap ex (INAUDIBLE) there will be related to Big Foot? And can you perhaps give me a little time line as to how much increment of money you need each year, and how many years it would take before the first production will hit? And can we reasonably expect, sort of similar scenario stagger on, you know, if Cesar (ph) or Parisian or Grand Cayman all of (INAUDIBLE) successful, you know, how would that look? Do you have – you know have kind of run through preliminary cases as to how much extra money you would need for developing these kind of potential deep water finds?

JIM FLORES: Yes, Irene. That’s a good question. We’re going to be able to answer it authoritatively about August, I mean October this year, when we have a lot of the results and so forth. But what we don’t plan for is successes like Big Foot, where we plan for completion and those types of things. But when a major like Chevron wants to, you know, find something that they like and they want to aggressively develop it like Big Foot and add additional side track and development wells and are anxious to get it commercial and under these prices and we’re basically going to be there right there with them.

For example, on the Big Foot development we have a one eighth interest there. And, you know, if we drill say $100 million worth of wells a year that’s $12.5 million there. So we can easily handle any of those aspects, if we put in an $800 million slip spar (ph) facility, I mean you’re looking at $100 million paid over three years, so that’s about $30 million a year. So the increments for the production volumes in dollars are not challenging to this company.

At the same point in time, if you start multiplying discoveries, we get beyond one zeta, two to three to four to five or whatever you number you feel comfortable in using, I mean you can get into some pretty serious amounts of dollars, and that again, will be a capital allocation to the free cash flow that we’ll have out of this company that’s going to be very robust, and it will be an alternative investment to paying down debt or buying stock, is basically developing those reserves. But we don’t see a situation where they’ll do anything to strain us. It’s going to be strictly an aspect of part of our ongoing cap ex budget. But success is a good reason, we think to increase the cap ex budget, and more barrels and more production in the future.

As to your timing on production, we think with our deep water program we will have replaced any contribution from T Ridge over the next, you know, ‘08, ‘09, ‘10 period. So I think you’d have production starting some time in ‘08 out of deep water would be a reasonable assumption for us going forward.

IRENE HAAS: Thank you.

JIM FLORES: OK.

OPERATOR: Thank you. Our next question is coming from David Heikkinen of Pickering Energy.

DAVID HEIKKINEN, PICKERING ENERGY: Good morning – afternoon, actually.

JIM FLORES: Good afternoon, David.

DAVID HEIKKINEN: I had a question looking at post Stone, assume everything closes, balance sheet looks pretty solid, unhedged cash flow looks good. Do you see PXP as a further consolidator going forward?

JIM FLORES: That’s really going to be determined on our performance in creating value out of the two entities, many drilling the prospects that Stone has, the Rocky Mountain development of all of their big acreage position in

7

the middle Bacan (ph), further Jonah Pinedale development there, Eagle Prospect, our, you know, T Ridge resolution, deep water successes. Right now, our plate is pretty full operationally. And, you know, if half of that stuff keeps our attention by being successful, I think David, we’ll have a lot of running room on our own.

And that’s going to be kind of interesting for us, you know, where we feel like we’ve got some concentration and some plays and some leverage, where we have good work interest, to actually continue to move the needle at churnley (ph) where that’s not going to be a priority, let’s put it that way.

DAVID HEIKKINEN: OK. On the details of ‘07 production of the combined company, Stone on their call talked about 40 million a day of potential prerights (ph) on the Apache deal is that included in your guidance thoughts, whenever you were talking about ‘07 production?

JIM FLORES: No. We wouldn’t – that would be a contingent. That would be a contingent. We would never, you know, include a contingent.

DAVID HEIKKINEN: That’d be an additional amount of production potentially.

JIM FLORES: It could be, if it comes about.

DAVID HEIKKINEN: OK. And they are still evaluating it, I guess, the production was shut in it.

JIM FLORES: And we’re in discussion with them on that, and, you know, the coordination and so forth, but a lot of parties involved, and a lot of moving parts to it.

DAVID HEIKKINEN: This critical mass question kind of following on Irene’s question in the deep water, one spar, one discovery question of is it something you keep or not, two or three, definitely becomes a critical mass area for you. Would you see that as a core area of operations? And continuing going forward?

JIM FLORES: Yes, the way we look at it from a standpoint, of if we take the 60,000 barrels a day we produce out of California today and as a long life assets are going to be returning, we hope to grow the same type of exposure in the Rocky Mountains, but it won’t be that big over a five year model. It would be probably, hopefully a third or half of that. So we look at the Gulf of Mexico as an ability of growing a production volume that’s competitive to California, if not larger than California over the next five years, out of the deep water. So the multiple discoveries would have to be the way to get there, and that would obviously be an important part of our business going forward. We drill a bunch of dry holes this summer, it may not be.

DAVID HEIKKINEN: OK. Fair enough. Thanks a lot guys.

JIM FLORES: Sure.

OPERATOR: Thank you. Once gain, the floor is open for questions. If you have a question, please press star then the number one on your telephone keypad at this time. Our next question is coming from Paul Cho of Steadfast Financial.

PAUL CHO, STEADFAST FINANCIAL: Hi. Can you guys hear me?

JIM FLORES: Yes, sure, Paul.

PAUL CHO: I just have a few questions. I was looking, I noticed you actually referenced all of your previous guidance before in terms of I guess, D&A, I’m sort of curious here, given that production in D&A, DD&A or a little bit higher, this will just be coming down making sure production will be growing throughout the year? Is that just the way I should think about that?

JIM FLORES: Paul, we lost you on that.

8

PAUL CHO: Sorry. Because I guess your production expenses, are basically, I guess the range was 650 to 725 for the year.

JIM FLORES: Yes, they’re a little higher in the first quarter just on the expense basis due to work-overs and seasonal timing. We try to put it back in the annual box. We feel (INAUDIBLE) but the first quarter and the fourth quarter basically offset each other every year, in our operational planning. So the numbers on an annual basis look like they’re fairly consistent.

PAUL CHO: OK. And also, your production will be ramping up throughout the year as well?

JIM FLORES: Yes, once we start putting our steam lines back together.

PAUL CHO: Right. And on the DD&A (INAUDIBLE), it seemed a little bit high.

CINDY FEEBECK (ph): Our DD&A rate, the guidance range was 840 to 850, and we recorded 845, so it’s right inline.

PAUL CHO: I really have – D&A – DD&A was 50 million in the quarter, right?

CINDY FEEBECK (ph): It was.

PAUL CHO: Are you calculating the DD&A rate on the total production as opposed to sold production, is that how I should think about it?

CINDY FEEBECK (ph): Yes. On the total production, now the sold volume.

PAUL CHO: OK. So which of your – of the guidance numbers, what’s on sold production versus stock total production?

JIM FLORES: Paul, say the question again, we’re a…

CINDY FEEBECK (ph): We based on our DD&A rate on the production volume.

PAUL CHO: DD&A is based on total production. And everything else is based on …

CINDY FEEBECK (ph): Sold volume, that’s correct.

PAUL CHO: Sold volume, OK. That’s fine, all right. Thanks. And what’s your current production rate right now?

JIM FLORES: We’re a little over 63,000 right now.

PAUL CHO: That’s great. Thanks a lot.

OPERATOR: Thank you. Once again, the floor is open for questions. If you have a question, please press star then the number one on your telephone keypad at this time. There appear to be no questions at this time.

JIM FLORES: All right. Thank you very much. And we look forward to seeing everybody in the second quarter, and pushing forth towards the Stone integration and closure. Thank you.

OPERATOR: Thank you. This does conclude today’s Plains Exploration conference call. You may now disconnect your lines and have a wonderful day.

END

Except for the historical information contained herein, the matters discussed in this transcript are forward-looking statements that involve certain assumptions and known and unknown risks, uncertainties and other factors that could cause our actual results to differ materially. These risks and uncertainties include, among other things, uncertainties inherent in the exploration for and development and production of oil & gas and in estimating reserves, unexpected difficulties in integrating Stone Energy Corporation’s (“Stone”) operations into ours, unexpected future capital expenditures, general economic conditions, oil and gas price volatility, the success of our risk management activities, competition, regulatory changes and other factors discussed in Plains Exploration & Production Company’s (“PXP”) filings with the Securities and Exchange Commission. PXP and Stone will file a joint proxy statement/prospectus and other documents with the SEC. Investors and security holders are urged to carefully read the joint proxy statement/prospectus when it becomes available, because it will contain important information regarding PXP, Stone and the acquisition. A definitive joint proxy statement/prospectus will be sent to security holders of PXP and Stone seeking their approval of the acquisition. Investors and security holders may obtain a free copy of the proxy statement/prospectus (when available) and other documents filed by PXP and Stone with the SEC at the SEC’s web site at www.sec.gov. The proxy statement/prospectus and such other documents (relating to PXP) may also be obtained for free from PXP by directing such request to: Plains Exploration & Production Company, 700 Milam, Suite 3100, Houston, TX 77002, Attention: Joanna Pankey; telephone: (713) 579-6000; e-mail: jpankey@plainsxp.com. The proxy statement/prospectus and such other documents (relating to Stone) may also be obtained for free from Stone by directing such request to: Stone Energy Corporation, 625 E. Kaliste Saloom Road, Lafayette, LA 70508, Attention: Kenneth Beer; telephone: (337) 237-0410; e-mail: CFO@stoneenergy.com.

PXP, its directors, executive officers and certain members of management and employees may be considered “participants in the solicitation” of proxies from PXP’s stockholders in connection with the acquisition. Information regarding such persons and a description of their interests in the acquisition will be contained in the joint proxy statement/prospectus when it is filed.

Stone, its directors, executive officers and certain members of management and employees may be considered “participants in the solicitation” of proxies from Stone’s stockholders in connection with the acquisition. Information regarding such persons and a description of their interests in the acquisition will be contained in the joint proxy statement/prospectus when it is filed.

9