Plains Exploration & Production Company Q3 2009 Earnings Call Transcript

| About: Plains Exploration (PXP)

Plains Exploration & Production Company (NYSE:PXP)

Q3 2009 Earnings Call Transcript

November 5, 2009 9:00 am ET

Executives

Scott Winters – VP, Corporate Communications

Jim Flores – Chairman, President & CEO

Doss Bourgeois – EVP, Exploration & Production

Analysts

David Heikkinen – Tudor, Pickering, Holt & Co.

Joe Allman – JP Morgan

Leo Mariani – RBC Capital Markets

Nicholas Pope – Dahlman Rose & Co.

Marshall Carver – Capital One Southcoast, Inc.

Adriel Asque [ph] – Hartford Investment

Phil McPherson – Global Hunter Securities

Operator

Good morning. My name is Kellia, and I will be your conference operator today. At this time, I would like to welcome everyone to the PXP third quarter earnings results conference call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator instructions) Thank you.

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

Scott Winters

Good morning everyone and thank you, Kellia. Welcome to PXP’s 2009 quarterly earnings conference call which is also being broadcast live on the Internet. Anyone may listen to the call or the replay by accessing the company’s Web site at www.pxp.com. Also located on the Web site are the earnings release, slide presentation, the 10-Q, and the 8-K, which includes the full-year 2010 guidance.

Before we begin today’s quarterly comments, I’d 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 is morning, we present non-GAAP measures. A reconciliation of non-GAAP financial measures to comparable GAAP financial measures is included with the press release.

On the call today is Jim Flores, our Chairman, President and Chief Executive Officer; Doss Bourgeois, our Executive Vice President of Exploration & Production; Winston Talbert, our 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.

Revenues of $312.2 million generated $39.3 million of net income or $.30 per diluted share in the third quarter of 2009. Net income for the quarter, including realized gains and losses and excluding unrealized gains and losses on our mark to market derivative contracts, was $183.3 million or $1.40 a diluted share, this is a non-GAAP measure.

Net cash provided by operating activities was $168.2 million and operating cash flow was $427.9 million. This is a non-GAAP measure. Sales price realization before derivative transactions was 84% for crude oil and 94% for natural gas during the quarter. For the nine-month period, sales price realizations before derivative actions were 82% for crude oil and 91% for natural gas.

Oil and gas revenues when compared to the third quarter of 2008 were significantly lower due primarily to a substantial decrease in realized prices before derivatives and decrease in sales volumes primarily associated with the 2008 property divestments. Excluding the impact of divestments, increased production from the Haynesville Shale and Flatrock properties is responsible for a 4% increase in sales volumes for the three months ended September 30, 2009 compared to same period a year ago, and an 8% increase in sales volumes in the first nine months of 2009 compared to the same period a year ago.

Average daily sales volumes were 83,000 barrels of oil equivalent for the third quarter and 81, 500 barrels of oil equivalent for the first nine months of this year. Our full year 2009 sales volume guidance range is 78,002 to 82,000 barrels of oil equivalent per day. During the quarter, crude oil represented approximately 57% of our sales volume.

Total production costs were $13.11 per barrel of oil equivalent for third quarter, a 31% reduction to the third quarter of 2008. For the nine-month period, total production costs averaged $14.45 per BOE. A quick review of the components of the total production costs for the quarter is as follows. Lease operating expenses decreased 13% to $7.89 per BOE in the third quarter of 2009 versus $9.06 per BOE in the third quarter of 2008 due primarily to the implementation of the cost reduction program. Lower steam gas cost per unit primarily reflects lower cost of gas used in steam generation.

In 2009, we burned approximately 3.7 BCF of natural gas at a cost of approximately $2.95 per MMBtu compared to 4.2 BCF at a cost of approximately $8.99 per MMBtu in 2008. Lower electricity cost per unit primarily reflects lower electricity rates primarily in California. Lower production and ad valorem taxes per unit primarily reflect lower commodity prices and the divestments in 2008. Higher gathering and transportation expenses per unit reflect an increase in production from our Haynesville Shale and Flatrock properties.

There have been no changes in our open derivative positions since our second quarter report. Approximately 80% of our 2009 estimated sales volumes using the midpoint of our annual guidance are protected by natural gas volumes with a $10 by $20 collars on our 150,000 MMBtus per day. Crude oil was units with put options with $55 strike price on 32,500 barrels per day and natural gas physical purchases for our California operations. Approximately 68% of our 2010 estimated sales volumes using the midpoint of our annual guidance are protected by natural gas volumes with three-way collars on 85,000 MMBtus per day. Crude oil volumes with put options with a $55 strike price on 40,000 barrels per day, and natural gas physical purchases for our California operations. The 2010 natural gas three way collars have a $6.12 floor with a $4.64 limit in an $8 ceiling. Please review the open derivative positions summary included in the press release for more information.

As of September 30, 2009, PXP has approximately $1.14 billion available under its senior revolving credit facility. Operationally, we remain focused as well. Our 2009 capital budget is expected to be $1.55 billion, including capitalized interest and general and administrative expenses. The capital budget reflects our participation in additional Gulf of Mexico exploration drilling, additional Haynesville Shale wells, a lower than anticipated reduction in rig rates and service costs, and increased capitalized interest general and administrative expenses, partially offset by the elimination of the Haynesville carry.

With respect to the Haynesville, we continue to see outstanding results and production from this resource base is growing quickly. Third quarter average daily production of approximately 48 million cubic feet equivalent net to PXP has ramped up from 14 million cubic feet equivalent per day net during the first quarter of this year and 28 million cubic feet equivalent per day net in the second quarter. Production is expected to continue to increase and exceed approximately 70 million cubic feet equivalent per day net by year-end 2009, and approximately 125 million cubic feet equivalent net per day by year-end 2010. PXP and its partner and operator Chesapeake Energy Corporation are currently operating 35 rigs and expect to operate an average of 40 rigs in 2010, plus 15 or more rigs operated by others on our acreage consistent with this year’s activity.

In the Gulf of Mexico, the Flatrock area wells averaged 59 million cubic feet equivalent per day net to PXP in the third quarter of this year. As previously reported by the operator, Flatrock #3 well is currently off-line and will be recompleted in the fourth quarter of this year. The Flatrock #4 well was shut in during August 2009 because of a mechanical, not reservoir, issue associated with the well bore and is expected to recommence production by year-end of this year.

We have an active Gulf of Mexico drilling program with delineation drilling success at the Friesian development project in the Green Canyon area and the announced discovery at Blueberry Hill exploratory prospect on Louisiana State Lease 340. The Hurricane Deep sidetrack well, operated by Chevron and located on South Marsh Island 217, on the southern flank of the Flatrock structure has a proposed total depth of 21,750 feet and is targeting the significant Gyro sand encountered in the Hurricane Deep well. The operator plans to commence sidetrack operations in the fourth quarter of 2009, and PXP holds a 30% working interest.

Three significant Gulf of Mexico exploration prospects with a total reserve potential of more than 200 million BOE net to PXP are currently drilling. The Davy Jones exploration prospect, operated by McMoRan and located on South Marsh Island Block 230 is drilling towards a proposed total depth of 28,000 feet. PXP holds a 27.7% working interest. The Rickenbacker exploration prospect, operated by Anadarko and located on Keathley Canyon Block 470, is drilling towards a proposed total depth of approximately 33,700 feet. PXP holds a 15% working interest in this prospect.

The Lucius exploration prospect, also operated by Anadarko and located on Keathley Canyon Block 875, began drilling operations in October and is drilling towards a proposed total depth of 21,000 feet. PXP holds a 33.3% working interest in this prospect.

PXP reported a strong quarter and continues to efficiently manage its business by focusing on operating costs and profitability, maintaining liquidity and an active hedge program, while moving to accelerate the Haynesville development to develop its existing high free-cash flow California oil business to develop the Flatrock area, and to fully evaluate its exploration projects in the Gulf of Mexico shelf and Deepwater.

With that, I will turn the call over to Jim.

Jim Flores

Thank you, Scott, and good morning everyone. We are very proud of this third-quarter. It's a good strong quarter for us on the production side, lowering our costs, doing all things right that we told everybody we are going to do this year during low gas prices and the volatility around oil prices and so forth. We continue to remain bullish about our 2010 strategy of deploying capital on our assets, accelerating the production of our existing assets. These are assets we collected over the last two years, and Chesapeake has been very diligent and exploiting our Haynesville position, we have been mapping working on our Panhandle stuff or South Texas, Southeast Texas stuff, Gulf of Mexico staff at McMoRan, and we think we have some really dynamite initial production reserve add type projects that we will be doing outside of California.

Inside of California, we are going to return to capital to California, not only build our production curves back up to positive territory, but at the same point in time really work on our new projects, like Arroyo Grande and our Diatomite development. These are projects that were formally booked as pods and now they are probable. So we can actually spend capital and grow our reserve base as depicted on page 11, I think of our presentation.

We think we have one of the more durable reserve gross stories out there because of the amount of barrels that we have already identified both in California and in Haynesville in incremental barrels that will get by our spending.

We continue to be bullish on the marketplace because in California, we got a unique look at what differentials are doing, both on the oil side and on the gas side. We continue to see oil differentials tight, at the same point in time while we have slack US demand. And there is a new one way you can do that is have competition for waterborne barrels that formally used to slop into Long Beach are now being dragged over to China and India and so forth and it’s making the domestic California barrels onshore, our barrels and others, more valuable to the refiners out there. So we are seeing tightness in the crude market and at the same point in time we are seeing differentials on the gas market that are tighter than we are seeing here in the Gulf Coast and the Midcontinent. We are seeing SoCal Border and San Francisco city gate, being tighter differentials in Henry Hub and Perryville/Carthage. That happens when California start for gas and that where we think the gas market will begin to clean up. So we are seeing signs of that. That plays into our strong capital budget for 2010 driving our per share growth on production and reserves going forward.

So we continue to be confident in our program, and it’s good to talk about it today. I know everybody has got a lot of questions and specifics and so forth. Operator, we will get right through those and we will give you some more commentary with everybody here. Operator?

Question-and-Answer Session

Operator

(Operator instructions) Your first question comes from the line of David Heikkinen of Tudor, Pickering, Holt.

David Heikkinen – Tudor, Pickering, Holt & Co.

Scott and Winston I'll say hi to everybody. As you look at CapEx exposed for your three exploratory wells in the Gulf of Mexico, can you give us dry hole costs net to PXP?

Jim Flores

Yes, David, we'll total all that up for you in just a second. Give us another question on that.

David Heikkinen – Tudor, Pickering, Holt & Co.

I really wanted to look at the resource potential on each of those and then some details or thoughts on what you are thinking on Blueberry Hill from a discovery and what the implications of the sidetrack could be?

Scott Winters

Okay. On our presentation, on page 24, we’ve got detail of net reserve potential, Davy Jones of 50 million barrels drilling at this point; Lucius 70 million barrels net to PXP; and Rickenbacker, plus 100 million barrels, about 200 million, 220 million barrels net to us. Doss is filling out the exact cost for you. And Blueberry Hill, talking about that a second, the first well – getting the first well down, we reentered the old Blueberry Hill well saving costs of sidetrack and made a discovery, had some well problems as some different pressure regimes and the sand showed up that we didn’t foresee it, whatever.

So the drilling was a little more complicated than we thought, not in a bad way, actually in a good way because we are running into lower pressure and actually that’s better sand conditions, better productivity conditions than what we have planned. So what we did is was the third sidetrack was basically to sidetrack to a good production position just for the Gyro #1. As you recall when we drill the initial well on the first sidetrack we found some deeper Gyro sands with so [ph], so we are really excited about the second well, the well to the south, which is going to be drilling out a straight hole and try to get as deep as we can through the whole Gyro section.

What excites on the potential here is that we are seeing a geologic setting where we’ve got a high-pressure shale plug to the east and we are seeing lower pressure sand rich environment to the west and that’s where we are drilling the wells. And it correlates with one of our earlier wells we drilled, Tom Sauk, that was a dry hole to the north but it had a tremendous amount of sand all the way through the Gyro section, and it was in the same pressure regime. So we are very pleased with Blueberry Hill at this point, David, to be a nice production add to our Flatrock complex. We will be very curious to see what happens on the # 2 well, whether it becomes something of Flatrock status. So it’s still stay tuned there. But in the mean time, we are making some money with the production out there that we'll get out of the number 1 well.

Back to your question on the cost standpoint. Davy Jones, I need the cost on that but I have got Lucius at $29 million, I got Rickenbacker at $38 million net to us, and Davy Jones is about $25 million.

David Heikkinen – Tudor, Pickering, Holt & Co.

Okay, perfect. And as you think about Panhandle, the Wash play and then you mentioned south Texas and southeast Texas, that’s the seismic sheet. Can you just give us an update on those and then I will turn it over to other questions.

Scott Winters

Think about this way. We are starting our capital budget well. All our money is going into California well here in the fourth quarter and first quarter next year. We will start doing some of our heavier condensate plays like the Granite Wash, like Edward Yayworth [ph] gave a trend in Southeast Texas, Big Mac play and so forth. And then in late next year, third quarter, fourth quarter, start drilling south Texas and additionally the Gulf of Mexico. So we are trying to go from oil to condensate to gas through our capital budget because of strictly trying to time when we see a rebound in gas prices. Right now the oil business is doing quite well at $80 where the price is today, but the curve looks so strong that there is little we won't do to get much oil out of the ground out of our assets that we have.

David Heikkinen – Tudor, Pickering, Holt & Co.

Since you mentioned oil in California, how is the – you drilled the Arguello point [ph]. How is that producing? Is that additional opportunity for any other follow ups there?

Scott Winters

We have half a dozen opportunities out there, Dave. As we learn more about the production and how individual wells do across falls and so forth. Those wells typically come on to about 600 barrels to 800 barrels a day. This one is a little stronger than that. But somewhere a little north of 800 is probably the right number.

David Heikkinen – Tudor, Pickering, Holt & Co.

Okay, thanks.

Operator

Your next question comes from the line of Joe Allman of JP Morgan.

Joe Allman – JP Morgan

Thank you. Good morning everybody.

Jim Flores

Good morning.

Joe Allman – JP Morgan

In terms of Blueberry Hill, Jim I am not sure if you want to get into the details of it too much, but in sidetrack #2, I know McMoRan indicated that it saw these two sands that it didn’t see in any of the prior – the original well in 2005 or the sidetrack #1 or the bypass well. And then when you went deeper, did you actually get some good hydrocarbon and some good oil in the pay [ph] zone that you saw in sidetrack #1 in the bypass?

Jim Flores

Yes, the original well, we had 150 feet of pay in the Gyro #1, the first sidetrack was sidetrack down dip. We found the water level and that Gyro #1 sand plus pay we think is what’s in the Gyro #3 sand and we didn’t get any deeper. What we also saw were two large sands above the Gyro #1 that look perspective because we have our original well to the east that didn’t have any of these sands in it. So we’ve got some kind of – we got a barrier there. And that what we are trying to line up with the #2 well is the two shallower sands to the Gyro #1, Oak Perk [ph] series probably in the Gyro #3 and drill it as deep as we can get it and Tom Sauk wells saw sand for about 5,000 feet to the Gyro section, maybe to the Gyro #6. So if we can correlate the sand pile with the hydrocarbon column up against the shale barrier to the east, then we could have quite a large column of gas here, a large discovery. Not a huge area either. So we are waiting for the #2 well, and hopefully we will line up the right amount of taste. We say it is a significant discovery at this point. Right now it's a very good producing well with a lot of significant, we call it exploratory upside. So I think that’s the right way to characterize it. But stay tuned on the number #2 well. (inaudible) you asked about the cost of Davy Jones, I had misquoted, our net is $11 million dry hole, but we sold some interest down to Moncrief and so forth, just to clear that up.

Joe Allman – JP Morgan

And then, thanks, and thanks to David on that one too. In terms of the Gyro #1, so that’s where you sold 150 feet of pay, I think McMoRan indicated that their column was 190 foot column. So how thick was the pay in sidetrack #2 for that Gyro #1?

Jim Flores

The sidetrack #2, we had about 50 feet of pay. We were up deep and getting closer to the shale. So it was natural [ph] center so it was getting thicker as this going off structure, kind of the wedge model that Jim Bob's talked about so much is kind of a classic. So the #2 well is going to be a little off structure in the thicker parts of the sand, and trying to line up all the sands as we drill down and we put a lot of effort. Our geologic team, their team and of course Jim Bob's wizardry is all focused is all focused on this #2 well and we are getting ready to spread that in fourth quarter, right?

Scott Winters

Yes, correct.

Joe Allman – JP Morgan

Yes, it’s okay. And then will this well to the south – will this hit any of those four pay zones that you saw with the original well during 2005 and that you saw with the bypass well, the one that’s farthest to the west.

Jim Flores

The plan is to hit as many of those we possibly can. As this Gulf Coast geology is moving through here you’ve got sands and shales and iffaberious [ph]. I'd love to say we are going to try to hit. We are going to hit them all. But we will miss some and get some. But we’ve got seven exploratory targets on the same plus 2 development target. So if we get half of those on this #2 well we will have a lot more drilling to do. And we are looking for this production here at Blueberry Hill to be a contribution late next year. So the #2 well will be a big bonus that we do not have in our plan and #1 well for that matter , do not have in our plan for national production. So all of these type things will be incremental to what our current plan is.

Joe Allman – JP Morgan

Do you have any estimate of what the gross production could be based on what you know right now?

Jim Flores

These are anywhere from 25 million to 75 million a day wells. It just depends on what you want to flow them at.

Joe Allman – JP Morgan

Got you. Okay, then lastly any comments on what you are seeing so far at Davy Jones?

Jim Flores

Davy Jones, yes, I’ve told people that Jim Bob once again has proved himself to be the world’s greatest geologist. We found the Eocene much shallower in the northern part of the Gulf of Mexico than it’s ever been found and proved a lot of the miss about the Eocene and Wilcox being at 60,000 feet in the northern part of the Gulf of Mexico. We are at 255 in the Eocene. We have not seen the Wilcox sand. It’s below Paleo [ph] was, and we are going back into drilling it. So the geologic concept is no longer wild. It’s no longer unproven. The geologic concept is right now we are down to whether we get the trophy or not and have some good sands on the structure and have the hydrocarbons that we think on the 20,000 acre structure in the middle of South Marsh Island should have. So we are into pure commerciality at this point, but it is quite amazing to rethink the geology in the northern half of the Gulf of Mexico based on this well and what’s possible if we find some good sands.

Joe Allman – JP Morgan

And just, I was thinking a quick one on Granite Wash, now you are going to drill test well in the first quarter. What’s your plan for Granite Wash next year. How many wells do you plan on drilling over there? Or is it dependent up on the test well?

Scott Winters

We have four, right now; but, that’s a risk model. It’s really going to be determined on success and gas prices. The way we looked at our budget, the reason why I give a range is that gas prices stay $5 all next year we will be on the low end of that range. If gas prices are $7, we'd be on the high end of that range on our CapEx. So there is some flex in that. But, it’s all HBP does not go anywhere, that’s into our model. And if we don’t get it next year we will get it in 2011.

Joe Allman – JP Morgan

All right. Very helpful. Thank you.

Operator

Your next question comes from the line of Leo Mariani of RBC Capital Markets.

Leo Mariani – RBC Capital Markets

Yes, good morning. I was just wondering you could update on what your current acreage position is in the Haynesville and whether or not you guys are still actively adding acreage here?

Scott Winters

We have about 116,000 acres. I got Hance over there giving me hand signals, maybe 113,000, 116,000. We haven’t changed that much. We continued to get medals [ph] from operator. We take some, some we pass on. We are trying to manage our cash and manage our business from the standpoint. We are very high on the Haynesville. Haynesville has been spectacular. It continues to get better in the activity. We have planned out 35 rigs running out there. We have 51 operated by Chesapeake and non-operated, so we are getting the benefit of that production, we are getting the benefit of that activity. So we much rather at this point have more drilling activity than acreage because we have 15-year, 16-year inventory at this point in time. So if we miss a couple acres here and there, it's not going to change our lives and it shouldn't change your outlook on the Haynesville. It’s more about – we want to try, get as much of our CapEx dollars towards driving production volumes. We have a lot of assets.

Leo Mariani – RBC Capital Markets

Okay. Jumping over to California here, you guys talked about increasing your CapEx there next year when you starting to drill. Have you guys already started to get some rigs back out in California? I am just trying to get a sense of what the magnitude is in terms of CapEx increase. I know you targeted somewhere around $90 million in ’09. So we expect that to double next year or –?

Jim Flores

It will be a little bit more than double. Doss, wanted to give some color on that total?

Doss Bourgeois

We are going to be close to around 200 million, part of that will depend on where we drill the wells. But we are targeting the (inaudible). We’d be drilling those 30 plus wells there. Cymric, Tulare, we are targeting around 15 wells in Belridge and Midway Sunset, somewhere in the neighborhood of about 40 wells, 45 wells. Also looking to drill some at Montebello in Inglewood and depending on permits and that type of thing it will fluctuate somewhere around that 200 million total.

Leo Mariani – RBC Capital Markets

Okay. Any update on T-Ridge?

Doss Bourgeois

Not at this point in time. The aspect of it, it’s still in the political process. But we have not been asked to resubmit our – get our deal back on the dock of the state lands. We are waiting for Lieutenant Governor situations to clear up. And then once that does then maybe we get another shot at it before Governor Schwarzenegger gets out of office.

Leo Mariani – RBC Capital Markets

Okay. I just want to get more clarity on your Gulf of Mexico program. In 2010 obviously you guys have got three wells drilling now. Just curious as to what’s on the schedule for next year and is that going to be more back half of ’10 weighted, if I heard your comments correct?

Doss Bourgeois

Well, that was more – the back of ’10 is more of some of the McMoRan type projects we are thinking about from that standpoint. But the Deep Water, we have always designed it to have an active exploration program this year and a very muted program next year, if any. Basically, we are hoping to drill development wells to our discoveries. Now we still have that hope on these three wells drilling at this point in time. So I think you will see us be in a much, much more mode of developing what we have after this identification year. The Northwood’s dry hole was not comfortable whatsoever from a standpoint of – we felt very comfortable getting into our Paleogene program.

We have one of the three discoveries, we didn’t expect to go over 0 for two, to be quite honest with you. So we have high hopes on Rickenbacker and then Lucius is a neat little play, and of course, Davy Jones we thought was wildest wiles away but we have high hopes for that the way it’s starting to drill out. So, you just never know about this business, but it's going to chart all well to be development. Again, it goes back to the Haynesville. Here we want to put the drill bit to production instead of drill bit to developing assets is the key thing next year. I think that we'll keep that. As you see in our CapEx budget, we’ve reduced our exploratory spuds to 26% to 9% on our CapEx budget, and that is down significantly from years past. So this is what we always wanted to do is to have a active exploration program to develop a lot of assets that we can just go and develop and pick low hanging fruit and next year and the year after is going to be – that's the mode we are going to be in for a while.

Leo Mariani – RBC Capital Markets

Okay. And in the Haynesville, are you guys participating in any Bossier [ph] wells with Chesapeake? Is any success that are factored into your guidance?

Doss Bourgeois

We have all the same Bossier exposure that Chesapeake does. We just have 20%, they have 80%. We have all the acreage and we are very excited about it. The Bossier is one of the extras in Haynesville that we held when we got in the deal. We actually didn't know it was there. So the aspect of the two wells that we drilled with Chesapeake have been very successful. It is a huge add on the reserve value. The question is when do you get it out of the ground? If you put it behind the Haynesville development, the PV value is muted by that discount of time. But if we go into a dual program and that will be after 2011, I am sure once we get the Haynesville all HVP, then we'll just decide how we are going to develop all of the HVP areas. But to have the reserves increase significantly with the addition of the Bossier for our Haynesville field is nothing short of spectacular from our standpoint.

Leo Mariani – RBC Capital Markets

Okay. Thanks guys.

Jim Flores

Thank you.

Operator

Your next question comes from the line of Nicholas Pope of Dahlman Rose.

Nicholas Pope – Dahlman Rose & Co.

Good morning.

Jim Flores

Good morning.

Nicholas Pope – Dahlman Rose & Co.

I don’t know if I missed this, but did you talk about timing of when the Blueberry Hill, that first well might be able to be started up in terms of production?

Scott Winters

We talked about fourth quarter 2010, that’s where we had modeled. McMoRan may be a little different but that's what we are thinking.

Nicholas Pope – Dahlman Rose & Co.

Do you know, have you set up like the facilities and everything, do you all know where it will be produced into now or –

Scott Winters

If it's just the one well we'll tie it back to the existing infrastructure, there's tons around there. But if the #2 well works like we think then we have to do something a little more dramatic. That's what we are waiting on for that infrastructure which direction to go. And we are talking about 10 feet, 15 feet of water. So it’s not like it’s any – it’s not a tough decision, we just want to spend good money.

Nicholas Pope – Dahlman Rose & Co.

Okay. And then just following up a little bit on Leo’s question. With that increase in CapEx in California, what do you all anticipate California production can go with that ramp-up? Early 2010 and throughout the year, what do you see the growth profile looking like in California?

Scott Winters

We got to be cautious a little bit because remember, California, you spend money this year and you see the production two years from now. Okay? And some of the CapEx we are spending is on our dynamite development where it’s more a construction spending, putting in the steam generation, putting in the facilities and everything else and then you drill the wells and then you have to steam them by the time the production really shows up in late 2011 and 2012. So I would continue to model California production up 1% or 2% (inaudible), just let it swell, and if we surprise it 3% to 4% one year because these projects, you'll have plenty of heads up on that stuff. 1% to 2% is probably the right thought process.

Nicholas Pope – Dahlman Rose & Co.

Okay. And then – I appreciate that. And then just looking at a little more in depth in California, was every that OXY is showing in these conventional targets that they have had realized production from – what kind of exposure or effort do you think you are going to make in that area going forward?

Scott Winters

When OXY has it all leased. They leased it all. They have got a huge investment out there to do it. We have not been active and expanding our footprint in California. I know we got questions on the Monorail [ph] shale onshore and so that is not something we want to do. Our strategy is to continue to drill wells in the Haynesville and catch this in Louisiana and leverage off our California assets. We are looking at our California situation continuing to mine it, continue to invest in the projects that we have on our field acreage or HVVP [ph] acreage and not expand our footprint in California because every time we try to expand our footprint, it continues to become a soap opera and becomes something that the company is more known for versus production and reserve growth in our performance.

So we want everybody to focus on what the basic business is of our company and we are interested in expanding in California. That’s just a policy issue from our standpoint. If we very get T-Ridge, T-Ridge is going to be around forever. We got a platform right next to it. Okay? It’s always been forever. And California is going to be broke for the foreseeable future. So it is always going to be an issue. It’s always going to be in the news. Yes, we lift the pot in July 24 on my 50th birthday, this summer where we almost got the vote to the legislature, but you got to remember it is not going away because it’s all still there and our platform is going to be there for a number of years. And California is always going to be the revenue. So, at some point in time, we all hope it comes about, but from a standpoint, we won’t look at California as the amount of capital we put in California and the amount of capital we take out and we put in areas that are growing successfully where we don’t have these types of issues to deal with.

Nicholas Pope – Dahlman Rose & Co.

Very well. Thank you.

Scott Winters

That’s more than you asked but it needed to be said.

Nicholas Pope – Dahlman Rose & Co.

Yes, I appreciate it. Thank you.

Operator

Your next question comes from the line of Marshall Carver of Capital One Southcoast.

Marshall Carver – Capital One Southcoast, Inc.

Yes, just a couple of quick question. CapEx increase for this year from $1.4 billion to $1.55 billion, what amount of that is due to increased drilling and what is due to the lower than expected declines and service costs? Just wanted to get a break down between those two.

Scott Winters

Well, I’ll take the service cost, it maybe $20 million, $25 million, small. It’s really all the non-operated activity in the Haynesville that surprised us. When I say non-operated, non- Chesapeake operated. That 16 extra rigs running, which we have various interest in.

Marshall Carver – Capital One Southcoast, Inc.

Okay, thank you. And one other question. The uptick in 2010 production from midpoint of 88 to 90, is that basically all Haynesville or there are some other areas that are better worth –

Scott Winters

It’s really Panhandle, Southeast Texas, lot of things we’ve idled and a lot of it is offset in the decline in California. When we took all the capital out last year on drilling our stuff [ph] because we were participating in the Chesapeake carry and unwinding the carry, we took the money from the carry and we budgeted it to spend on our own assets. And really what we are doing is arresting the decline of our own assets and so you get the full brunt of the production increase for the Haynesville when you’re not having to offset your base decline. So the model works pretty well when you just – and that's why we have a lot of confidence in it because we are drilling wells we have existing infrastructure and we’re well set up, we've had an extra year to study these projects. We’ve done a lot of internal work. We have a lot of high confidence on what we are doing, seismic interpretation. So that’s where it comes from.

Marshall Carver – Capital One Southcoast, Inc.

Okay, thank you. That’s all from me.

Operator

Your next question comes from the line of Adriel Asque [ph] of Hartford Investment.

Adriel Asque – Hartford Investment

Yes, couple of questions on Blueberry Hill. You said that the wells there 25 million to 75 million a day. What’s the total reserve potential on the well?

Scott Winters

McMoRan is close to 500 BCF of reserve potential. That’s exploratory potential for the standpoint. We will see what that number is after the #2 well.

Adriel Asque – Hartford Investment

Okay. Very helpful. And then the Northwood exploration project, can you discuss in more detail what happened there? What was your working interest and what was the total well cost there?

Scott Winters

Our work interest iswe have 27.5% work interest and we spend about $55 million on that. We drilled the dry hole there. We are kind of bound by confidentiality with the operator. We can't disclose any of the well results other than we’ve drilled 35,950 feet almost 36,000 feet, one of the deepest wells in the Gulf of Mexico. And that was an engineering success. But an economic failure.

Adriel Asque – Hartford Investment

Okay. Are there any positive takeaways there?

Scott Winters

There is always lot of positive takeaways, but we can’t discuss them at this point. We are still pulling together the data and figuring out what happened. But we will take Chevron’s our operator’s lead on that.

Adriel Asque – Hartford Investment

Okay. I understand. Do you expect to layer any additional hedges for 2010, or 68% is where you planned to stay for now?

Scott Winters

For 2010, we’ve looked at we might increase the floors on our puts. We’ve looked at some of that. We will see – we are going to think in the fourth quarter if we see another spike in oil prices we might do something. We are not actively doing it. The hedge unwind that we executed in March, we think is working pretty effectively. We probably made $300 million, $400 million on that trade. We are looking at gas – we are worried like everybody else by gas prices long term, but we continue to believe that – so we might do some – next year in gas. So we are just going to wait because we think there is no point in doing it right now. We don’t think we are going to be able to get enough gas in 2010 all the way through 2010 at these low gas prices. You are going to have to encourage more rigs going out in the field and I think that’s going to happen to the price. I don’t know when but –

Adriel Asque – Hartford Investment

Okay. All right. What’s your long range target on LOE? You have made some progress there.

Jim Flores

Well, we had some structural cuts in LOE. We’ve done very well on natural expense and also on efficiency side. The long-term target for us is lower trending because of the CapEx and we have our spending at – in more efficient gas prone areas. So we actually having more gas molecules that will lower getting this LOE. I would caution you though the one variable in our LOE is gas prices since we burn gas in California to cook our oil. This year with low prices our LOE was representative of those low gas prices. We make a tremendous amount of money in this company when oil is $80 and gas is $3. And that’s where our numbers are showing. We also are forecasting a $6.50 gas price in our LOEs next year, which is $2 higher than what the script is right now. So just want to make sure that everybody understands or at least $1.50 higher that the script is right now. Now we’ve got a high gas price in our LOEs and if gas prices stay low our LOEs will be low. If gas prices hit the strip, our LOEs will be higher next year. But since we have so much gas production as a natural hedge, we actually – we make more money with higher gas prices. So we are fine there as well. So that’s the LOE volatility that we enjoy, especially as the hedge against low gas prices versus oil production.

Adriel Asque – Hartford Investment

Okay. That’s very helpful. Thanks, gentlemen.

Operator

(Operator instructions) Your next question comes from the line of Phil McPherson of Global Hunter Securities.

Phil McPherson – Global Hunter Securities

Hi, good morning gentlemen. Congratulations on the production growth. You’ve talked about California oil production being up 1% to 2% in 2010. Can you tell us what it is kind of the range it’s at right now to give us a figure to start with.

Scott Winters

Yes, we can help you out, just a second. I will take a second to get that. Do you have any other questions?

Phil McPherson – Global Hunter Securities

Maybe update on Friesian, in the project. What’s kind of going on.

Scott Winters

Yes. As far as onshore production in California, we are looking at about 30,000 barrels a day. And offshore we are looking at about 10,000 barrels a day. So that would give you a starting point there. On Friesian, we are working with our partner and working with people with infrastructure close by and enterprise toward developing the production scenario at Friesian. We are going to be working with the regulatory agencies to figure out the development plan going of forward next year. We will probably have some comments on that in the first quarter or with our fourth quarter results on what we think we are going to be going forward on. But right now, we are all systems go.

Operator

And at this time, there are no further questions.

Scott Winters

Okay, operator. Well, thank you very much everyone for the call. I know it is busy day and really appreciate you guys turning in. We will see you at the year-end call.

Operator

Thank you. This concludes today’s conference call. You may now disconnect.

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