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Plains Exploration & Production Company (NYSE:PXP)

Q1 2009 Earnings Call

May 7, 2009 3:00 pm ET

Executives

Jim Flores - Chairman, President and CEO

Doss Bourgeois - EVP of Exploration and Production

Winston Talbert - EVP and CFO

Scott Winters - VP, Corporate Communications

Analysts

Dave Kistler - Simmons & Company

David Heikkinen - Tudor Pickering & Co.

Duane Grubert - CRT Capital

Michael Bodino - SMH Capital

Nicholas Pope - Dahlman Rose

Adrayll Askew - Hartford Investment

Joe Magner - Tristone Capital

Bill Frazier - Greenhill Capital

Marshall Carver - Capital One Southcoast

Andrew Coleman - UBS

Phil McPherson - Global Hunter

Operator

Good afternoon. At this time, I would like to welcome everyone to the PXP's first quarter earnings results conference call. (Operator Instructions).

I would now like to turn the call over to Scott Winters, Vice President of Corporate Communications. Sir you may begin.

Scott Winters

Good afternoon, everyone. Welcome to PXP's 2009 first quarter Earnings Call which is also being broadcast live on the internet. Anyone may listen to the call or the replay by accessing the company's website at pxp.com. Also located on the website are the earnings release and the 10-Q.

Before we begin today’s comments, I would like to remind everyone that during this call, there will be forward-looking statements as defined by the SEC. These statements are based on our 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 and 8-K filed with the SEC for a complete discussion on forward-looking statements.

In our press release and in our prepared comments this afternoon, we represent some non-GAAP measures and explanation and reconciliation of non-GAAP financial measures is included at the end of the release.

On the call today is Jim Flores, our Chairman, President and Chief Executive Officer; Doss Bourgeois, Executive Vice President of Exploration and Production; Winston Talbert, Executive Vice President and Chief Financial Officer; John Wombwell, our Executive Vice President and General Counsel; and Hance Myers, our Vice President of Investor Relations.

PXP reported solid quarterly financial and operating results, remains committed to a strong balance sheet and maintains focused on its development and exploration programs. For the first quarter of 2009, PXP reported adjusted net income of $133.6 million or $1.23 per diluted share, which includes realized gains and losses and excludes unrealized gains and losses on mark-to-market derivative instruments and debt extinguishment costs.

Net income as reported was $5.2 million or $0.05 per diluted share on revenues of $228.5 million. Realized cash sales prices, which include the derivative settlements for the first three months of 2009 were $81.14 per barrel for oil compared to $83.82 per barrel in the prior year period, and $7.98 per Mcf of natural gas compared to $7.92 per Mcf in the prior year period.

During the first quarter of 2009, sales price realizations before derivative transactions were 81% for oil and approximately 86% for natural gas. Sales volumes were 80.9 thousand barrels of oil equivalent per day for the first quarter, and slightly above the midpoint of our full-year 2009 guidance range of 78,000 to 82,000 barrels of oil equivalent per day.

Compared to the prior year period lower daily sales volumes during the first quarter of 2009 primarily reflect the impact of the 2008 divestments. Excluding the divestments increasing production from Flatrock and the Haynesville shale properties are primarily responsible for an 11% increase in sales volumes in the first quarter of 2009 compared to the same period a year ago.

Operating cash flow was approximately $343 million for the first quarter and oil and gas capital expenditures including capitalized interest in G&A were approximately $350 million.

Total production costs were $15.89 per BOE during the first quarter of 2009 or approximately 10% lower than the prior year period. Lower per unit steam gas costs and production and ad valorem tax costs accounted for the majority of the year-over-year improvement.

Lease operating expenses a component of total production costs were $9.74 per BOE in 2009 versus $8.56 per BOE in 2008 due primarily to the divestment of the Permian and Piceance Basin properties. First quarter 2009 costs do not fully reflect decreased industry costs resulting from the significant decline in oil and gas prices or the program that PXP implemented early in 2009 to reduce costs.

Lower steam gas costs per unit reflect lower cost of gas used in the steam generation. In 2009, we burned approximately 3.9 Bcf of natural gas at a cost of approximately $4 per MMBtu compared to 4.2 Bcf at a cost of approximately $7.70 per MMBtu in 2008.

Lower production and ad valorem taxes per unit primarily reflect the divestments in 2008 and lower commodity prices. The effective tax rate of 85% for the first quarter is a result of the relationship between 2009 estimated permanent differences and pretax income used in the annual effective tax rate computation.

The current tax expense was approximately 160% of pre-tax income. This unusual rate is a result of the temporary differences between the book and tax recognition of income attributable to the oil and gas derivative positions.

PXP continues to aggressively manage its project inventory, cost structure, capital structure and commodity price risks for its hedge strategy. So far this year, PXP strengthened its liquidity by monetizing derivatives, issuing new senior notes and issuing shares of PXP common stock.

PXP currently has no amounts outstanding under its $1.34 billion senior revolving credit facility and holds in excess of $500 million in cash reflecting the effects of the senior note and common stock transactions occurring subsequent to the end of the first quarter. Debt to capitalization was 43% at quarter end compared to 54% at year-end 2008.

With respect to hedging, PXP continued to manage downside commodity price risk during the quarter by resetting its 2010 crude oil derivative positions with $55 floors and 40,000 barrels of oil per day and by acquiring $6.25 by $8 natural gas three way collars with a $4.80 sliding floor for 2010.

The company retained its 2009 $55 crude oil puts on 32,500 barrels of oil per day and the 10 by 20 natural gas collars on 150,000 MMBtu per day. Approximately 80% of PXP's 2009 estimated production sales volumes using the midpoint of the annual guidance are protected by existing oil and natural gas derivative positions and natural gas physical purchases.

As previously discussed, the company's 2009 capital spending is being primarily directed to the Haynesville shale, the California long-life oil resource base, Flatrock and the Friesian, Salida and other high impact exploration projects in the Gulf of Mexico. Since the first of the year, PXP has been moving quickly on both its development and exploration programs.

The Haynesville shale continues to deliver outstanding drilling results. Production is currently 21 million cubic feet equivalent per day net to PXP or 160 million gross. With approximately 9 million cubic feet equivalent per day net to PXP currently curtailed from the play.

PXP anticipates reaching a production level of approximately 70 million cubic feet equivalent per day net to PXP or 600 million cubic feet equivalent per day gross by year-end 2009.

There are 24 rigs currently drilling with an average of approximately 28 rigs expected in 2009, and 36 rigs in 2010. Four wells in the Flatrock field are currently producing a gross rate of approximately 235 million cubic feet equivalent per day, which is 52 million cubic feet equivalent per day net to PXP. Completion efforts are in progress to the Flatrock number 5 and number 6 wells with first production from both wells expected by mid-year 2009.

Drilling, operations to deepen the Friesian number two discovery well are underway. PXP as operator and its partner, decided to deepen the discovery well an additional 3,500 feet to approximately 32,500 feet of true vertical depth to test the prolific main field equivalent sands such as the M15, M18, M21A and M21B at Tahiti.

Existing data shows strong correlation both geologic and pressure from the initial Miocene field pay sands at Tahiti to the drilled portion of our Friesian number two well. This well is currently drilling below 29,000 feet and results are expected by the end of the quarter.

The Ammazzo exploration prospect, operated by McMoRan and located on South Marsh Island Block 251, is currently drilling. The Salida exploration prospect, operated by Shell and located on Garden Banks Block 988, is scheduled to begin drilling in the third quarter 2009.

Engineering planning is underway for the completion and testing of the Blackbeard West ultra-deep exploratory well in South Timbalier Block 168. And the geologic data derived from the first well on Block 124 offshore Vietnam is being incorporated into evaluation and selection of the second well location there.

PXP is scheduled to commence drilling on the second well during the third quarter of this year.

With that I will turn the call over to Jim.

Jim Flores

Thank, Scott. Good afternoon, everyone. We had a solid quarter, good operating results, and earnings on adjusted basis, as well as on a net income basis according to GAAP. Company is running quite well. We have one update to our press release, on our Friesian number two well.

When this press release went to press, right afterwards we had a rig breakdown situation where our top drive seized up and we were unable to drill below 29,000 feet as of yesterday. [Of course] its going to be repaired in the next two to three weeks and will be back to drilling, but today we have not drilled any new hole other than re-drilled a side track of the existing hole that's found the same four pay sands, a little bit thicker because we are all structured, but we have not drilled any new dirt yet at freezing, and hope to do that and have results at freezing probably in the next 45 days.

We got a new piece of equipment at the Ocean Monarch, it is a fabulous rig by [Diamond], it's got a few bugs to work out now with the top drive issue that we will get through all that and I am sure we are going to have an exciting deeper part of the hole, but I want to update everybody because the press release is a little stale when it came to that, just in the last 24 hours. As you know it's a workforce dynamic and we're well position to be flexible enough to handle and look forward to the opportunities there.

I am going to open it up for questions. We have Doss Bourgeois here, Head of E&P and Wright Williamson, Vice President of Reservoir Engineering to answer any operation questions along with me and Winston on the financial side. So operator?

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Dave Kistler with Simmons & Company.

Dave Kistler - Simmons & Company

Quick question with $1.8 billion of liquidity, can you walk us through the capital requirements for the next two years and what effectively your surplus will look like with that much cash and credit available under your current facility?

Winston Talbert

Yeah, the way we are looking at the business and after we did the equity offering, we think we could a current outlook and the strip, probably a little lower strip than you got right now, probably get through 2010 without really drawing down anything meaningful on the revolver. Does that help?

Dave Kistler - Simmons & Company

Yeah. So essentially absorb 500 million in cash and still have the flexibility of the revolver at the end of 2010?

Scott Winters

That's right.

Jim Flores

Yes. And Dave just a little more color on that. The equity offering gave us a great backstop to the revolver. The banks are all, have issues and various degrees of health and so forth, but we wanted to make sure that our revolver was something we would be willing to use and feel confident and our balance sheet was strong enough to borrow on the revolver.

Lot of people have liquidity on the revolvers and especially with all the write-downs that people take in this quarter and so forth are not going to be in a position to even have the courage to borrow unless they're desperate. We are not going to be in that situation. We're going to make sure that we maintain a conservative financial stance and if we need to borrow on the revolver or see something opportunistic from a standpoint and we can do that. Feel comfortable about our leverage even post drawing down on the revolver which is kind of a key part of our strategy.

Dave Kistler - Simmons & Company

Great. Following up on the opportunistic comment, compressed gas prices right now as you mentioned companies that are having liquidity problems. Are you seeing an increase traffic in terms of people who are looking for partners and either well interest formats or in just straight sales of assets these days?

Jim Flores

We are seeing more opportunities in areas that are interesting to us, some of the lower cost shale plays and also some in deepwater that that not necessarily distressed assets. I would say premium asset where people are trying to fund operations and those types of things.

We are staying away from the distressed market at this point in time, because there's a risk that gas prices don't recover for a few years. We won't, we are not going to play in the distressed market right now. But we are going to continue to just add to the business we have. We are not looking to do anything strategic along those lines.

We got to be responsive for our operator Chesapeake make some acquisition in the Haynesville that’s going to be meaningful to near term production, and near-term reserve growth not just adding to our existing our [Gentian] lease block. That type of thing, we want to be in a position to leverage the operations that we have currently.

Dave Kistler - Simmons & Company

Thinking of large lease block switching over to Vietnam for a second.70 feet, in net payers of your report about a week or so ago yet plugged and abandoned. Can you talk to us a little bit about what you saw that has you excited to drill a second well. Whether that well is in close proximity and whether that well itself changes or informs your thoughts on the resource potential for Vietnam?

Jim Flores

Sure, Dave. There's not a whole lot of correlation as to whether we [T&A] the well or [P&A] the well. This is a million acre block, 200-miles from production. The key aspect is, it's going to take a few expandable wells, if you will to figure out whether we have the commercial reservoir to develop. What we learned on the first well we found both sands and carbonates productive. Sands had a lot better permeability than the carbonates.

So what we are looking for is move to our next test about 10 miles away, to drill a pier stack sand test more of a traditional Gulf of Mexico looking play that hopefully will be fed by these source rocks, these bedrocks and the sands that we found on the small structure will be plumbed into this large sand pile that we are going to go drill.

The next test we'd probably drill would be back to test the carbonate structure, larger structure or more solid structure to the north would help us give more defined the carbonate aspect. The reason we plugged the well is that this is not a place we'd put a platform or wouldn't be part of our development program.

So instead of having to just come back and plug it later and we'd fully evaluate the well that we and PetroVietnam agreed to plug this one, and then we can develop this reservoir from a side full of further off structure. We hope we get a little thicker and thicker carbonates and a little bit of permeability.

The next test will be a very significant test in defining what the sand, productive sand, stacked sand potential is for block 124. Then we're going to decide whether to go back and do another evaluation of the carbonates to give us kind of a good feel whether we can deem it commercial or not.

Operator

Your next question comes from David Heikkinen with Tudor Pickering & Co.

David Heikkinen - Tudor Pickering & Co.

Good afternoon. Just a couple of questions on the production side and thinking about Flatrock, first production mid-year. What are you expecting now to be your peak rates or what are you expecting for rates from that as you get into mid-year?

Jim Flores

Yes, David as you know we are not operator, Chevron is operator and Chevron still maintains a three handle, 300 million a day as gross production. From a standpoint, we are questioning the logic, with gas prices where they are and why that's going to critical but that's what they have been telegraphing to us and told us as partners.

We are comfortable, with that rate but we are using more of an average this year and an average for next year somewhere around 265, 275, average through the year, and then, this year and then somewhere around a 240 to 250 next year.

David Heikkinen - Tudor Pickering & Co.

Then on the exploratory side, I know you are not operating, but wanted to get a thought as far as when you reach TD on Ammazzo and kind of the status of when in the third quarter you think you begin drilling at Salida.

Jim Flores

Salida is expected to spud here in June, the rig is on operation in the eastern gulf and will be moved right after that. So we are still here in late June. So that will be a late second quarter spud on that and on Ammazzo we should know in the next 30 days and MacMoRan the operator will make any release on that.

Operator

Your next question comes from Duane Grubert with CRT Capital.

Duane Grubert - CRT Capital

Jim, in the Haynesville you and Chesapeake are going to have a very large project, 600 million a day by the end of the year, which really out performs just about anything out there. Can you talk a little bit about what challenges might come up in attaining that piece of the development? What are you most concerned about.

Jim Flores

Duane, the challenges we face so far is that the [cartage] gas plant blew up. We have had to repair that, and that is one of those bad and good things. The bad thing it blew up, the good thing is they are going to rebuild it with 50% to 70% more capacity and help expand it and that’s kind of what usually happens after disaster you built it back better and faster.

So that will get back online. It is a new field as you say. You have got lot of experience, in bringing on new fields, we got a new rig at Friesian. So equipment delays or equipment problems production handling facilities for that volume of gas. Chesapeake has got a great plan. We have endorsed it, our guys were up there last week for all day and they're well prepared for, but it's those type of issues.

I feel very confident that we can get to those rates by year end and so forth. It is more along the lines of that and then also on the marketing side, gas prices continue to be at three handle and so forth is whether that makes sense. We are going to take direction from (inaudible) and everybody up there as to whether they are the operator, whether want to floor everything that hard or just continue to ramp things up in a more moderate pace and try to preserve the reserves for higher prices if we curtail enough production. Those are the two areas.

Duane Grubert - CRT Capital

Then in terms of just portfolio building, you got a nice roster of exploration wells. What is your appetite for if there is a bias, for adding incremental exploration projects of this quality versus maybe taking a look at the type of distressed assets that are being shopped around?

Jim Flores

Well, our portfolio is really getting streamlined from the standpoint of big California base and development projects we have out there, Haynesville and everything going on there, and both of those things have like a 15-year development inventory. We have a nice portfolio of great opportunities in the deepwater.

We are seeing some unique opportunities there in the inboard Paleogene that you are going to hear a lot more about here this fall from the majors. That we are going to take a look at participating in with some of our liquidity. The other thing, we have got South Texas and we got the Panhandle. Both those areas are higher cost than the area, the other areas I talked about and those kind of our optional area.

So our inventory is really full. It would have to be something that would be a dynamic near-term or immediate-term and I am going to say shale play just from a standpoint of adding to production and adding to near-term growth on top of the Haynesville as something as being competitive as we model it.

Now those go at premiums and so forth. So I wouldn't put those in distressed categories are looking at situations that are going to be from companies that are dying at all. So we are going keep our eyes open. Our plate is basically full. So it has to be very, very special for us to even think about doing it. So we are kind of taking that as the highest bar to climb for us to do any additional projects.

Operator

Your next question comes from Michael Bodino with SMH Capital.

Michael Bodino - SMH Capital

So, real quick question on just some housekeeping stuff. Related to California I know year-end had the basin blowout and costs were quite high. With things returning to normal put that in quotes relative to prices and costs, is it fair to assume that at these level of costs and prices, that those PUDs that we're taking of the books could be economically viable again?

Jim Flores

Yes. Let me answer the question. Everything in California works at these prices and these differentials, I will turn over the DOS and the DOS taking through some of the differentials and kind of these comments there, but also want to talk to you about how we are going to be looking back, the PDPs and so forth. But the PUDs, we are going to judiciously look at those from a standpoint of trying to bring those back as PDPs with investments. So California is actually going be growing from an F&D perspective and be able to add back all our [diatomite] and our Arroyo Grande steam flood project. Once we get that money spent instead of just booking a bunch of PUDs behind it. So Doss?

Doss Bourgeois

Sure. Currently right now, we did have the old blowout on the differentials. From first quarter to now, our differentials on oil have risen from 83% up to 86%. On gas, they have gone from 86% to 91%. So, things have really turned around and getting a lot better.

From current price standpoint, on adding the reserves back on to the books, the current price is about $64. We could be looking to be able to add another 100 million barrels back to our reserve base. So, from that standpoint, that is if the $55 holds in, but if it gets better, then we will be able to add more back in. We will be able to manage that as we go forward. It looks real good.

Michael Bodino - SMH Capital

Okay. Doss, were you finished?

Doss Bourgeois

Yes.

Michael Bodino - SMH Capital

Okay. I know oil prices have moved up. Looking at the strip on oil, I know you had a small part of your budget, about 7%, allocated to California. At what price or what time do you start thinking about maybe adding a few more dollars to the Californian budget?

Doss Bourgeois

That would be 2010, Michael. We are making those plans right now to get a budget approved this fall for 2010. And look at what we think prices and cash flow are, Haynesville commitment, any commitment we have behind expiration successes, that type of thing.

The California subs (inaudible) are fee acreage, and you are talking about a large number of barrels over a period of time. Like the [diatomite] project, we are talking about a breakeven at $32 NYMEX. When you took $44 NYMEX in the last year and 68% spot differentials that we had on the spot market versus what Doss gave you our contract plus our spot differentials on a marginalized basis, then that's what tripped a lot of the Dynamite stuff for us.

Then Arroyo Grande, I think about $42 a barrel. Is that right? Somewhere in that $42, $43. So, both of those projects look real good at $60, $70 a barrel on rate of return basis. We will start adding those projects back starting in 2010, probably sequentially with Dynamite being somewhere around 125 million to 150 million barrels and Arroyo Grande being 80 million to 90 million barrels. Arroyo Grande would be after the Dynamite post-start that in 2012.

Michael Bodino - SMH Capital

I know the guys from Delta Petroleum booked a receivable from the Offshore California litigation. Are you party to that litigation still?

Doss Bourgeois

Yes, we are. We have not factored our receivable, but they're highly confident of the factor. We feel we are happy about that. Roger's dad used to be a federal judge. I think he still is. He has a different perspective on the legal system than I do, but we haven't booked it as receivable, I don't think. Winston, have we?

Winston Talbert

No. If we didn't get some sort of settlement, it would run through income.

Doss Bourgeois

We are supposed to get $80 million or something like that.

Winston Talbert

$80 million.

Doss Bourgeois

$80 million.

Winston Talbert

A little over.

Operator

Your next question comes from Nicholas Pope with Dahlman Rose.

Nicholas Pope - Dahlman Rose

A quick question on operating costs. Across the board, things look they're improving down a bit on all metrics. The gathering and transport went up a little. Is that new systems coming on line? What's attributed to that little bit of a sequential increase?

Doss Bourgeois

The bulk of it was Haynesville where some of the installation costs going on there, the CapEx. It was driven up a little bit. At the beginning of the year where we had divestments of some of our properties, the Permian and Piceance where we lost some barrels there. Overall, the general maintenance capital costs there are trending down. It's looking pretty good.

Nicholas Pope - Dahlman Rose

The crude capital costs that showed up in the first quarter, I think it was like $70 million. Is that an unusual number for the first quarter? Where is that relative to normal accrued capital from quarter-to-quarter?

Doss Bourgeois

I think last year we had like $40 million or $50 million. I would have to check, but I think it's a little higher than normal, because we were drilling the Friesian PUDs project in the fourth quarter. We had about three or four things going on at once. That's why it jumped up a little bit.

As we back off CapEx a little bit, you are going to see not only the accrueds come in, you also see the payables start to go up a little bit as we ramp things down.

Nicholas Pope - Dahlman Rose

Okay. I see there is like $5.8 million that was going to real estate and others. Is California still on the plate? Is that what that's attributed to?

Doss Bourgeois

Real estate doesn't go away, as you know. It's there. The value changes, but we are still in the process of getting our Montebello project through the City of Montebello permitting aspect. So, we saw the expenses there. I think we reduced those expenses to less than $2 million this year. So, that's one of the cost areas we were able to reduce. Wait for the next real estate.

Operator

Your next question comes from Adrayll Askew from Hartford Investment.

Adrayll Askew - Hartford Investment

Yes, This is Adrayll Askew. What's the expected EUR on the Friesian number two well?

Doss Bourgeois

Right now, we feel like we have identified about 40 million barrels of probable reserves, net to PXP, with the deepwater hole probably at 110 plus million barrels. So, 150 total. So the range is 40 to 150 depending on what the next 3,500 feet shows.

Adrayll Askew - Hartford Investment

What's the total cost in the budget for that well?

Doss Bourgeois

Total cost in budget for that well is about $100 million.

Adrayll Askew - Hartford Investment

What is the expected number of wells drilled at Flatrock for 2009 and 2010?

Doss Bourgeois

Flat rock area, which has some adjacent fault blocks, 2009, I think we are probably at our fourth one right now. That's pretty much it. That sun sets Flatrock from our perspective unless this block here on this latest well is going to be expanded.

Adrayll Askew - Hartford Investment

Okay. You were saying that you guys have expectations of somewhere around 240 million to 270 million a day or so there?

Doss Bourgeois

That was more 270, 275 this year as an average and then around 240 to 250 next year. That's a gross number, and we are 30% working at just at about 23% net revenue interest.

Operator

Your next question comes from Joe Magner with Tristone Capital.

Joe Magner - Tristone Capital

Just wanted to touch base on the accounting side. The operating cash flow number as reported, including some amounts that flow through the investing that's associated with some of the hedge settlements, just two questions. One, why weren't those amounts rolled through the income statement and the operating cash flow side of the equation?

And then also, going forward with the resettlement or the restructuring of those hedges, is that something that we will continue to see or will the new hedges roll through realized prices in the income statement?

Winston Talbert

Well, as you know, we use mark-to-market accounting. So, the gains on all of those, the unwinds and the cash that we settled in this quarter, were actually realized on a mark-to-market basis in the fourth quarter. When we released the fourth quarter earnings, we took out those gains because they were non-cash. We took out the write-down and we took out the gain in the mark-to-market.

So, in the first quarter, what we did was we actually realized $1.3 billion worth of cash because we settled some of the hedges and we unwound the $100 puts. So, what we did when we added back the operating cash flow, we added back all of the amounts associated with first quarter production.

What it does is that gets you back to sort of mark-to-market type accounting. In the cash flow statement, we always put hedge settlements in the investing portion. We think that's the rule, that's what you are supposed to do and that’s the way we have always done it.

Joe Magner - Tristone Capital

So, that's even for hedges that are tied to current period productions in the Q1?

Winston Talbert

Yes. We think that using mark-to-market accounting that you need to recognize is in the investing portion of the cash flow statement. So that’s what we do, and we have been doing that since we started mark-to-market accounting.

Operator

Your next question comes from Bill Frazier with Greenhill Capital.

Bill Frazier - Greenhill Capital

Yes. Good afternoon, gentlemen. In California, do you see any opportunities to grow the production volume? It looks like you are doing about 50,000 a day. Does that stay more or less flat for the whole year?

Winston Talbert

Actually, that's just a direct correlation to how our capital budgets are allocated. And currently right now we are making sure we are maintaining enough capital for the most part to keep them flat and then next year, as we are planning our big budget, we will decide, how much capital we will push out there.

Through the years, we have been able to learn and figure out how much capital to be able to push out there and not have too much interruption with our production. We have steam floods and all out there. So it's a balance between how much capital, we want to push and when you want to grow that or without interruption.

Bill Frazier - Greenhill Capital

The DD&A rate was about 11.50 for the first quarter. Does that more or less stay constant for the whole year or does that change each quarter based on your capital expenditures?

Winston Talbert

Yes. I think that's going to stay constant. Now, when we go and we hit the fourth quarter and we redo our reserves and go through all of that, kind of depending on prices that may change a little bit.

Bill Frazier - Greenhill Capital

Okay. You mentioned earlier maybe 100 million of reserves come back on because of the higher prices. Does that change that rate as well?

Winston Talbert

It would have an effect on it. Yes.

Bill Frazier - Greenhill Capital

Would you go through that exercise later in the year; is that it?

Winston Talbert

Yes. You do that when you did the year-end reserves. Then you would go back and look at your DD&A rate and change it to the fourth quarter and then that would kind of reset it for 2010.

Bill Frazier - Greenhill Capital

Do you have a contract up for renegotiation as far as what you receive on your oil from either conical or plains marketing? Is that coming up in a few years?

Winston Talbert

We don't have a contract up for renegotiations. The contract goes through 2015. But every two years we reopen the price discussion based around differentials. The differentials have been each year, every two years continuing to close.

Obviously with the spot differentials being above what we are receiving right now, then obviously that trend has an opportunity to continue, but we always try to reach a fair price between our customers ConocoPhillips and us. So, we expect that at least to be a neutral to net positive, when it comes about here in October, again.

Again it is not going move a lot because you average a lot of historical's with future so we have got lot of history there. So, it's pretty benign discussions at this point in time.

Bill Frazier – Greenhill Capital

Okay. You've had with the hedge monetization and the debt offering. I was wondering, what your thinking was in the, why you needed to do the equity offering on the heals of all of those other actions?

Jim Flores

Our situation here is we are going to have spend cash flow by at least $700 million here for the next two years developing the Haynesville. We got one of the biggest gas fields in country of the world, and so forth in accelerated basis, we have got great opportunities to put money to work in the ground for some of the best economic projects. Our deepwater project with Friesians ramping up and we expect to have a lot of successful development behind that.

If you look at our balance sheet and so forth, yes on a liquidity basis we have tons of liquidity, but we are not where we want them to be from a strength basis to where we feel like we could issue bonds again or pull down significant on a revolver or wait to issue equity at that point of time.

We felt like the industry is continuing to be under strained, the banks are continuing to be under strain with gas prices. I know gas prices hit 4 bucks and it feels like $40, but it is still way below the cost and there's a lot of restructuring going on in the industry.

While we are spending aggressively on the operational front to position our business to grow the next five years, we stated over and over, we are going to maintain a conservative financial stance, and so putting the equity out there is the first time, we have done equity in this company from the basis of directly to the market allows us to have the financial footing to be aggressive operationally and position this company, continue to position this company through this downturn to be one of the top tier growers on the other side.

So that fits our plan. If we have a lot of exploration success and we got to complete a lot of wells and ramp CapEx up and things like that, I mean, you are going to see more financings on the debt and equity side that now try to keep out in front of our CapEx as long as it is on the success basis. It's not going to be just for the aspect to fill potholes, it's going to be strictly to build value as we grow reserves 20 plus percent over the next five years. Each year that we are going to be one of the fast growers and we need to keep up with that growth of the capital.

Operator

(Operator Instructions). Your next question comes from Marshall Carver with Capital One Southcoast.

Marshall Carver - Capital One Southcoast

In your presentation on the resource potential at Vietnam, you had that as 100 million barrels. Is that over several structures and how did that change with the [PN8] well?

Jim Flores

These is just two different sand types, I mean two different play types, the carbonates were about 100 million barrels of potential that we drill for and the sands a separate 100 million barrels that we think has got potential. Since, we are testing the sand theory, then we feel like, we had a, that's really what our target is on the sand theory.

Right now we have more confidence in that than the carbonates, and if we take it a step further. There's going be a decision point after the second well as whether we continue to pursue Vietnam further or I try to monetize that type of thing. And that's going to point more to how we feel about the sand test after we get down at work, we are successful there and whether we want to go back and try to look at the carbonates and try to continue to expand that.

So we like it from a diagnostic standpoint, the amount of oil, we found, but we would like some more encouragement toward really find a place to put a platform that we are all comfortable with.

Marshall Carver - Capital One Southcoast

How much does each well cost?

Winston Talbert

They're 10 to 15 million bucks.

Marshall Carver - Capital One Southcoast

That's helpful. Thank you. And, one other question, the two other inboard [beligien] prospects you talk about, could you elaborate on that a little bit?

Jim Flores

I really can't right now because we are finishing up sensitive negotiations with our partners. They're world class projects they are in the Salida class type projects. On the inboard side, they're in the thicker salt sections, will have the better porosities and better permeabilities, kind of when you look at Kaskida, Shenandoah, Big Foot and Buckskin those four kind of discoveries, those are all inside the area, where you see a lot of the other Paleogene projects that have been out on a just all kind of where the salt has eroded. We feel like we are seeing a good trend and have confirmation from many industry partners that this inboard or Back Bay Paleogene trend is where the bigger barrel fields are going to be like Kaskida and we're hoping to find one of those with these three projects. But, we will be talking more about that through the summer as we get those things nailed down but if you look at Salida and use that as comparison then you are in the ballpark.

Marshall Carver - Capital One Southcoast

Is that something that could spud this year or would that be 2010?

Jim Flores

Yes. They all three would spud this summer.

Operator

Your next question comes from Andrew Coleman with UBS.

Andrew Coleman - UBS

Just one of the few companies that didn't have a ceiling test impairment that's pretty good, I think a reflection of the oil hedges and just the portfolio you guys have, but can you give any colors as to how much cushion you had on that ceiling test at the quarter end?

Winston Talbert

Yes. We had probably about 5% cushion.

Andrew Coleman - UBS

Okay.

Winston Talbert

The hedges really don't factor into ceiling tests. But really what happened was the oil and differentials changed enough to offset any degradation in MPV on the gas side of the equation. So, we figure that's what happened, if oil prices came back and gas prices went down, we figure we would be the -- really than sort of the opposite of the fourth quarter where we had big right-down and there is a lot gas guides that didn’t because -- the gad prices are near 6 bucks.

Jim Flores

We love our oil production because it is something, we can finance off of and kind of afford our gas business right now whether its so. It's got the cash flow. So it's the key part of our portfolio that's working and of course price of oil has gone up 4, I mean 10 bucks since the quarter. So, we have got a lot more cushion today than we had at the end of the quarter.

Andrew Coleman - UBS

Okay. Good deal. How much CapEx are you guys, have you allocated to California for this year? And I guess…

Jim Flores

Just over 60 million bucks.

Andrew Coleman - UBS

60 million.

Jim Flores

And that's a, that's a mill rode maintenance CapEx just to keep production flat and do the minimum out there use the cash flow out of California. We expect to get about $400 to $450 million of cash out there spent 60 in fact that might input it in the Haynesville.

Andrew Coleman - UBS

Okay. And then that just to make sure I understood what was discussed earlier about the re-booking potential for the [diatomite] and Arroyo Grande. That's basically going to be tied to I guess having a CapEx plan starting in 2010 for drilling more wells out there. That would allow you to recapture some of that.

Jim Flores

I’m glad you asked the question. Strictly if we wanted to book according to price. Basically when the price of oil fell from our average last year from 95 down to 44 bucks, we would normally have still kept to [diatomite] on the books and Arroyo Grande would have been right on the bubble, except that the spot differential which we’re not suddenly to here in the near term because of all of our contracts to settle. Well our differential is about 88% of Nymex. But the spot differential was 68% because none of the refineries wanted any of the oil they couldn't sell any gasoline.

At the end of our contracts, we have three, five and seven-year rolling contracts with Conoco and Shell and others, that according to SEC for our booking purposes, we have to go back to the spot differential at the end of that contract.

So at the end of the Conoco contract seven years from now, we had to go to 68% of Nymex at $44 price, which gave us about $32 Nymex, and then we had LOEs that we were spending whatever it took last year at a $100 oil to get oil out of the ground, and we had to take those LOE costs, $100 a barrel LOE cost and escalate those at to 2%, which cut our reserve life down from 22 years down to 10.

So it is a mathematical equation that has only one answer. So what happens is, this year, let's say oil is 55, like that Doss just gave you right there. Well, 55 in differentials are back within range on the spot market, because we have a decent market. Well then we have 35 to 37 million barrels of PDP we’re going to book back; that’s just our tail reserves, and then we got about 65 million barrels of PUD reserves that easily qualify for us to book back at 55 bucks a barrel.

I just cautioned everybody that we may not book all of those PUD barrels back, because we want to book more PDP barrels out there. We just go ahead and spend the capital instead of just booking a bunch of PUDs, spend the capital and make sure that we continue to grow reserves over a long period in a aggregate of 20 plus percent. So the figure is correct of 100 million barrels for this year just in California, but we got great contribution out of the Haynesville, we plan on having great contribution out of Gulf of Mexico and Deepwater. So we plan on booking California in a very judicious fashion to where we can grow it.

So from the F&D standpoint finding development, California is our lowest finding development cost for us to book those reserves. Haynesville’s next at about 11 bucks a barrel, California sub $8 a barrel, and then we will find out what happens in the Deepwater and Gulf of Mexico as we finish drilling this year, and it should be somewhere in the 10 to $12 a barrel. And if we have some failures and dry holes or so what we have. We are trying to make sure our business stays sub $15 a barrel F&D going forward, and we have with our spending in the fields and the assets to accomplish it now on the development basis as well as an exploratory basis.

I know, that’s a big answer, but I hope I covered what you are looking for.

Operator

Your next question comes from Phil McPherson with Global Hunter.

Phil McPherson - Global Hunter

You mentioned that the Friesian well was $100 million budget. Was that a gross number?

Jim Flores

That's a gross number. This is the last well we have to carry shale for the deep part of the hole. It was not going to be a $100 million, it was only a $70 million operation. We got to earn the deep part of the hole, because below 28,000 to 32,500 and we sidetracked the number two well out of 26,000 feet, we re-drilled a lot of the original part of the hole to get to this point. And then plus we have had some rig delays with some of the mechanical issues, so I just gave you a high figure, it’s somewhere between 70 and 100 million bucks.

Phil McPherson - Global Hunter

Then after that what does it revert to?

Jim Flores

We are 50-50 on all costs going forward.

Phil McPherson - Global Hunter

On the Salida, what’s the cost on that well and the reserve potential?

Jim Flores

The whole project is about 200 million bucks, 225. Our cost is about 120 when you put in some cost, land, and the small carrier via shale. We are 25% interest and we think the [pay mean] on the project is around a billion barrels.

Phil McPherson - Global Hunter

And then any color on the [Blackbeard] statement? You talked about the engineering work just briefly in the press release. Can you give us a timeline and what's kind of going on?

Jim Flores

Well it’s really driven by our partner MacMoRan and the other partners in the well, because we have maintained it. We would like to test this discovery, make sure we can define commercial production and find out what we have in this existing well bore before we drill other wells. MMS has cooperated with us as far as suspending lot of the lease explorations of the other projects, and when we get finished drilling Ammazzo, we need to go complete this well or maybe do another small operation with the Mississippi rig that Rowan has.

They're doing all the engineering, trying to figure out the right equipment. We got the surface tree I think squared away. I think they're working on some of the subsea safety valves and so forth, some of the alloys, just being very, very careful. It’s going to take a little while to get this thing completed, and we are going to be the ones we complete the well and then take more judicious steps, and some of our partners that are going to need to find some money to partner with them, they're going through that process right now. So I fully expect this well to be tested sometime next year and we will be able to take some positive steps forward. And in the meantime that gas is sitting there at $3 and (inaudible) produces at 6 or 7 sometime later next year or the following.

Phil McPherson - Global Hunter

So, it’s definitely 2010 event then?

Jim Flores

From our perspective, yes but MacMoRan's direction is going to be more specific. We’re trying to react to what their needs and wishes are, but I think they're going to be limited by equipment issues and timing on that to where it’s going to be more in 2010.

Operator

At this time, there are no questions. I would now like to turn the call over to management for closing remarks.

Jim Flores

All right. Thank you, operator. Thank you, everyone. It has been a great first quarter. We got lot of exciting things happen and we look forward to getting [Friesian] and all the other stuff down in the second quarter and having a good call then. Have a good day. Bye.

Operator

Thank you. That concludes today's teleconference. You may now disconnect.

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Source: Plains Exploration & Production Company Q1 2009 Earnings Call Transcript
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