SandRidge Energy Inc (SD) 2008 Q3 法說會逐字稿

Good day ladies and gentlemen, and welcome to the third quarter, SandRidge Energy earnings conference call. (OPERATOR INSTRUCTIONS) I would now like to turn the call over to Mr. Dirk Van Doren, Chief Financial Officer.

Thank you, Eric. Good morning, this is Dirk Van Doren.

Before turning the call over to Tom Ward, our Chairman, CEO and President, I need to make a few opening remarks. Last night the Company issued a press release, announcing, SandRidge's operating performance and we also filed our 10-Q. If do you not have a copy of the release, you can find a copy of it at the Company's web site, www.SandRidgeEnergy.com. Also you can sign up for the releases that will be automatically sent to you and this is located under the investor relations tab. Today we will use a few slides also available on our website.

Now for our forward-looking statement. Please keep in mind that the Company will make forward-looking statements subject to risk and uncertainties. Actual results might differ materially from those projected in these forward-looking statements. Additional information concerning risk factors that could cause such differences is detailed in the Company's filings with the SEC. Today's presentation will include information regarding adjusted net income and adjusted EBITDA and other non-GAAP measures. As required by SEC rules a reconciliation of the most directly comparable GAAP measures is under the investor relations tab.

Now let me turn the call over to Tom Ward.

Thank you Dirk, and welcome to the their quarter earnings conference.

We have in our office, Matt Grubb, our COO with Dirk and me. As you have read, we had another very good quarter executing our business plan. I will now quickly run through the highlights of the quarter and turn it over to Dirk. As you are aware, the world is focused on access to capital. SandRidge is also focused on access to capital and has made this our number one goal in the last 90 days. We cut the 2009 budget by $1 billion from the $2 billion budget set in the second quarter conference call. We started the process of selling our East Texas assets during the second quarter and are working with several interested investors to include selling in the fourth quarter.

We plan to completely pay down our revolver and are reviewing additional avenues of funding, including further asset allocations and a capital plan that will fund us through 2010. SandRidge continues to grow within the field. We drilled 76 wells in the quarter, and our Company reserves grew to over 2.1tcf of gas. Our production was curtailed by about 33 million cubic feet a day on average, and at times as much as 60 million cubic feet a day was shut in during the third quarter because of the fire at Grey Ranch, our CO2 plant, from well work in the Gulf Coast and hurricanes Ike and Gustov in the Gulf of Mexico. We restored production at the Grey Ranch plant earlier this month but currently still have about 20 million cubic feet a day due to the storms in the gulf.

The total estimated production loss in the third and fourth quarters of 2008 is 5.5 Bcf of gas. With that said, we still project to make our production guidance of 100 Bcf this year. This guidance was issued at the first quarter conference call and it is an increase of 56% over our 2007 production. We averaged 275 million cubic feet a day in the third quarter, and are currently producing 305 million cubic feet a day with $20 million a day shut in.

As we discussed in our second quarter call, we have now shot 3D seismic over the Pinon Field and our geo science team has been working with this data set for about 90 days. As a result, we are continuing to find new areas to explore, and further expand Pinon Field, which I believe is fast becoming one of the better fields onshore in the US. The field has more than tripled in the amount of oil drills since June of 2006 and has grown over 10 times in the amount of 3P reserves given to the field. When I first became involved with the Company, we were always asked questions about the field, and how or if it was viable.

We now receive very few questions about the validity of the field because we have proven the growth potential. We do not yet know how big the field is, but we do see additional drilling opportunities with the clear understanding of the definitional environment and the multiple thrust systems. For example, until we had our first interpretation of our proprietary 3D seismic over Pinon Field in July of this year, we did not even realize that the Frog Creek or the Hammond thrust existed. This realization has increased the potential for continued expansion of Pinon Field across the West Texas Overthrust. For example, the 5.1 Tcfe of our 3p net reserves are in the dugout creek and Warwick thrusts and while the Frog Creek has been proven to be commercially productive, we have not yet to begun to materially book any reserves in this thrust.

The Hamman looks promising, in terms of structural development and depth, but we have not drilled a test into this thrust. The knowledge of these thrust systems gives us the ability to manage our drilling program that will minimize finding costs and maximize production and reserve growth. Our first slide shows the Dugout Creek thrust at the deepest thrust and the thrust that's pushed furthest north. We continue to drill sweet gas wells within this thrust, and, in fact, in the thrust where the vast majority of production growth has happened in the last two years. The Warwick thrust sits on top of the Dugout Creek thrust, and it's the most prolific producer in the field. However, we believe the majority of the natural gas in the Warwick thrust contains a high amount of CO2 and until our Century Plant is rebuilt, we will not be able to develop this thrust as aggressively as we like.

We continue to find sweet gas wells within the Warwick thrust on the east side. Even transition wells with low amounts of CO2 are not able to maximize production because of a lack of processing capacity for the CO2. This thrust is one of the keys to the future of our Company, as it represents the best reservoir for capital spent of any large scale play that I'm aware of. We now have over 125 tests in this zone, that show a consistent pattern of producing an average of seven Bcf of gas per well at an average of 6,000 to 8,000 feet. The variable to producing this zone is the CO2 gas as we mentioned before. However, even if we average 50% CO2, we will still have finding costs of less than $1.50 per Mcf, needless to say, we look forward to commencing the Century Plant in 2010. The third thrust is a known producer in Pinon Field as the Frog Creek thrust. This thrust does not have the production history of the other two thrusts and we do not have a good type curve yet established, however, we do know that the Frog Creek does have the capability of producing significant wells at depths between 3,000 and 5,500 feet.

The Frog Creek sits on top of the Warwick thrust and most of our tests have thrilled through the Frog Creek into the Warwick. Therefore, we have several penetrations but not much individual production history. We have started to drill wells targeting specifically the Frog Creek Caballos and have very encouraging results. We are in the process of mapping this thrust with geological information from the few penetrations we have and tying into 3D seismic data to high-grade locations as we prepare to drill more Frog Creek and Caballos wells in 2009. We provided the type curve of Pinon Field in slide two that takes into consideration about 600 wells drilled in the field since 1984. We model and base guidance on this type curve of $1.70 per Mcf finding costs. We have been able to keep our finding costs below the $1.70 per Mcf and so far this year we are at $1.49 per Mcf of gas.

Our production has grown by 72% last year and we are guiding to 56% production growth this year. It is our belief that the West Texas Overthrust is a tremendous asset which provides for low risk drilling in the Pinon Field and incredible up side for production and reserve growth. The future growth of this Company is substantiated by past performance as our ability to continue to expand Pinon Field and not be dependent on finding any additional reserves outside of Pinon. Our third slide shows production growth that we will experience in 2010 and 2011 with completion of the Oxy Century Plant. Please remember that we have a 30-year contract with Occidental to take our CO2 while we strip off the methane to sell to consumers.

The high volume of gas is considered to be only from the Warwick thrust and it is a catalyst for stable growth for many years. We believe that there are additional reservoirs containing high CO2 gas that can be developed once this plant is full but that's a bit too far out for us discuss in detail at this point. The point we try to emphasize is SandRidge is built by drilling sweet gas wells while this vast amount of low risk CO2 natural gas sits within our field, waiting to be drilled once the plant capacity becomes available. We have now moved up our projected start date of the Century Plant to the second quarter of 2010. If we only keep our existing production flat, from 2009, through 2011, we will grow our production from our current $305 million a day to about $525 million cubic feet a day by year-end 2011, with just the addition of the Century Plant.

This is truly a company-changing event and we are fortunate to own such a unique reservoir that's so prolific that you can give away half the gas stream and still have finding costs under $1.50 per Mcf. Furthermore, as we have now acquired virtually all the leases in the West Texas Overthrust and shot most of our seismic, our costs will start to mirror our drilling finding costs. Lastly, we are now about to finish drilling our Big Canyon exploration well located in the West Texas Overthrust, about 30 miles out of Canyon field. The Big Canyon, 121-1a is drilling at 15,400 feet and we believe we are now in the Warwick thrust, based on recent seismic work and tying back to Pinon Field. We don't expect to have valuation long for test results until the end of the year but we are encouraged by what we see. The other two wells that we discussed do produce sweet gas initial rates lower than 500 Mcf per day. The production on these two wells is not from the overthrust that we have found in the Big Canyon field.

The presence of the sweet natural gas outside the Pinon Field is very important to our goal of finding additional Pinon Fields on our more than 650,000 acres in the West Texas Overthrust. I will now turn the call over to Dirk.

Thanks, Tom.

I will focus on a few third quarter highlights, our confidential position and projections. The key things we look at are production operating costs, EBITDA, free cash flow, and funding needs. Production was flat as a result of the shut ins, while costs were within our guidance with the exception of G&A, again as a result of a shut-in of product. Adjusted EBITDA was $180 million for the third quarter which is above our guidance and our internal model. Our quarterly capital expenditures were $675 million and the shortfall was covered by our cash position, cash flow and borrowing on our revolver.

Something I get a lot of questions on, we are in full compliance with all of our covenants at the end of September. Additionally on the last call, -- since our last call, we've added to our hedge position. We are now 72% hedged for the fourth quarter of 2008, and equivalent price of 920 per MMBtu, for the full year 2008 we will have been hedged 77% at 897 per MMBtu looking at 2009, we added significantly in the past three months to our hedge position and we are now 57% hedged for 2009 at $8.88 per MMBtu. In August, we were 19% hedged for 2009 at $10.50 per MMBtu.

Let's look at our guidance in the press release. For 2008, the only change was a mix of capital expenditures and for 2009, we had previously changed production and capital expenditures in early October, and have made some minor changes to costs. Looking into the reminder of the fourth quarter, we have two conferences in November, and so please see our web site for the times and dates of these presentations. We also included in the press release that we plan to release our fourth quarter and year end results on February 26th.

We will file the 10-K that day with our conference call the next day at 9 am. Our second annual investor analyst meeting will be on Tuesday, March 3rd in New York City at 8am at The Grand Hyatt. Please mark your calendars. That ends our prepared remarks, Eric, we're ready to open the call for questions.

Thank you very much. (OPERATOR INSTRUCTIONS) Your first question comes from the line of Joe Allman with JP Morgan.

Thank you, good morning, everybody. Tom, how many wells at this point have you drilled in the Frog Creek thrust and where are those located?

The Frog Creek thrust is mainly south of -- if you look north to south on that slide we presented, the doug out creek is the farthest north and the Warwick is the center and that's on page 3 and the Frog Creek sits south of that. By definition, the Frog Creek wells are south end of the field. We are not going to get into specifics of how many wells were drilled but you can -- you can see on our web site, in the -- where we are drilling wells and can maybe come to some conclusions, we have several wells that have penetrated Frog Creek and several that have tested Frog Creek. We don't know what type curve to put with the Frog Creek wells on whether they are a dugout creek type curve or a Warwick type curve. We feel comfortable they will meet or exceed our pud average type curve.

But in all the wells, you are seeing sweet gas?

Yes.

Okay. And then in your prepared remarks, you mentioned further asset allocation. Could you elaborate on that some?

Oh, I won't elaborate very much other than to say that we do have assets that we -- that we have available to us, if we need to, we can monetize. We'll talk to several different types of companies that might want to -- for example, if someone wanted to look at our midstream system, but where we had -- still had control of that, because it's very important to us, we're -- we're thinking that we could monetize some value there.

Got you and then lastly, the big canyon well drilling, what are your thoughts as you are drilling that and what are you seeing?

We are pretty encouraged. Of the exploration wells, this is the only one that has hit our targeted zone in the overthrusted chert. We have good shows.

Thank you.

Next question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed.

Thanks, good morning.

Good morning.

Tom, you indicated obviously you are looking at plans to have full availability of your credit facility by the end of the year. Can you -- I don't know if this is for Dirk as well, just address where we are at right now and the most likely options to get there.

The most likely option is the sale of assets, and that should be done by the end of the year. I'll let Dirk hit on anything else.

Yes, I can get into some gory details. Let me walk you through where we ended the quarter until now. We ended the quarter at $166 million on the revolver. We also had some one-time items that created cash that if we didn't have those, we would have been -- during the third quarter, we really would have ended quarter at 212. Let's say the quarter really should have ended at 212. We had a big interest payment in October of 34. We bought the wealth participation from Tom for 67. That gets you up to 313. We had a $10 million pipe deposit during the quarter, that's 323. We had $25 million of working capital as the business is slowing down, some working capital should be coming out of the business. That makes sense. And we had $57 million cash flow short fall, based on CapEx over EBITDA. These are rough numbers. We have pushed accounting pretty hard on that. You know, we are not going to have the real numbers for another week, but that's a rough idea. That gets to us 405 at the end of the month. Instead of 415, 416 on the q on page 45. You get hit with some AP checks early in the month. We are in pretty good shape. We are certainly tracking where we thought we would be on the revolver and we plan to be out of it by the end of the year.

And Tom, I will push a little bit harder here but on the potential sale of East Texas, how should we think of it in terms of how confident you feel you can get something done? Obviously, there's a few packages out there at this point in time. Can you give us a little bit of color as far as how that process is going now that the data room is closed.

Sure. Like I said, we plan to be out of our revolver by the end of the year and at zero. I think the data room process went well. We had a lot of interest and that's -- we plan to close out our revolver.

Okay. And then I guess the step up activity in south. You said you didn't hit the chert zone was that because you didn't have the seismic available and do you plan on building step out wells again, with the different areas targeted?

That's a good question. We did not have -- we drilled all three of those wells. We didn't have the seismic shoot over the pinion field, and so we didn't know how the thrust systems were laying on top of each other. What the wells had done is give us indications of where we should go, for example, in the furthest well east in south cavino. We actually drilled very far down dip in the Warwick Thurst and so we could actually move to the south and cross over into Frog Creek thrust or go to the north and drill a better structural position inside the Warwick.

So we did not have the seismic control that we needed to start those initial wells and that was based off seismic that was shot before we shot the pinion field. So today, using that well control is very helpful. It's encouraging that even though you didn't have the chert sections there, that you could hit the sands and still have production, even though it's not economic to drill those wells, that depth for that amount of production. The key point is that there's gas saturation all the way across the West Texas Overthrust and now all we have to do is find where the potential chert zones are or the overthurst and the Warwick, especially. If we can find that outside of the pinion field in 100% sweet position, we feel like that would be the biggest prize we could find.

When looking at the 3D, can you identify on that 3D, where chert may or may not be?

You can see thrust, and you cannot isolate down less than about 200 feet -- so what you look for are packages and then the well control is very important for you to determine back to the seismic on which package you are in. So, for example, in the big canyon area, you are over 30 miles away from the pinion field. It's very important for us to get well control. We believe we are in the Warwick thrust, because we are offsetting another well that was drilled by Conoco in 1992. The confirmation is correct that we were able to move up dip from this well and hit our pay zone at approximately the same spot that we thought we would, within 50 feet to 100 feet. So that's very encouraging. And it ties us back into the pinion field.

Okay. So this is just a process of basically sticking a lot of holes in the ground and using your seismic and reading a lot of the data and then becoming more surgical. Is that a fair statement?

Well, if you find the thrust that's productive, you don't have to do much more searching, because once you like the pinion field, once you find the productive thrust, all the wells are productive from that point forward.

Okay. Got it. Appreciate it. Thanks.

The next question comes from the line of Brian Singer with Goldman Sachs. Please proceed.

Thank you and good morning.

Good morning.

To push even further in terms of the revolver and the asset sale process, if it $445 million is currently the number, should we just -- what is your expectation for CapEx, versus cash flow for the remaining two months of the quarter? And should we take that difference, versus 445 as expectation for assets --

This is Dirk, Brian. On page 45 of the Q, the revolver as of November 3rd is 415.6. Okay? I don't know if we want to get into monthly cash flow statements. I don't know if anybody models on a monthly cash flow statement. I would just say if you run your model, you will become pretty close to where we are. You plug in the price, you plug in the EBITDA and you know what our CapEx is. You know where we are now, the business is slowing down. You can get through probably a pretty good number. You will certainly get to a number on the line if it was drawn at the end of the year of under -- certainly, way under 600.

Okay. And would there be any taxes paid on the East Texas sale?

No.

Great. On the Frog Creek, can you think about how you are thinking about additional drilling there over the next couple of quarters and how you think about prioritizing the various pinion thrusts and wells throughout each one.

It's important for us to drill through the Frog Creek, because we continue to want to explore for the Warwick which is our most prolific reservoir. However, that we tested a few Frog Creek wells, we're now comfortable to go to some rigs just drilling for the Frog Creek, and keep in mind it doesn't take very many rigs to drill wells there because of how shallow the zone is. So right now, we do have one rig that is getting ready to start drilling Frog Creek. What we have to offset is it's better to have a well bore that drills to 7,500 feet and combines the two reservoirs or is it better to have one reservoir that's shallow, and we know we can produce it, because it's sweet, and even if the Warwick produces 10% or 15%, CO2, we can't produce it. So that's the kind of things we wrestle with, is where is the best use of our capital and once we get the century plant on, that will all change because we can drill every well and determine whether it goes through the plant or doesn't. So the CapEx allocation during 2009, is going to be a little bit dicey just because we have been very restrictive on the CO2. I hope that's helpful.

It is. Thank you.

You bet.

Your next question comes from the line of David Heikkinen with Pickering Energy Partners.

I might need one tonight. Just thinking about the century plant commitments, how much capital do you need to invest between now and the middle of 2010 to meet the commitments?

Are you asking drilling?

Yes, exactly, number of wells. That would be perfect.

For 2009, we'll start ramping up drilling for the gas, we will ramp up from four rigs to 11 rigs and four rigs starting out in January and 11 rigs to high CO2 gas. The first phase of the century plant is expected to start up in the second quarter of 2010. You are looking at about 75 wells there in 2009, and then we have another $400 million that will come in in the second quarter of 2011. So between starting that up in 2010, and 2011, we are looking at about 75 to maybe 95 wells in 2009, and probably 200 wells -- it will be another 100 wells in 2010.

Okay.

That would be to keep all of our plants flat, all of our capacity is running flat, at any given time and ramping up for the second phase at century.

And once we ramp up -- once we fill the plant, it requires us to keep six rigs running to maintain. And we have all of that in our model of drilling these wells in our CapEx, and still growing at 20% in 2009.

Okay. Thinking about the -- on the services side, and your non-SandRidge-operated rigs, are you seeing any slow down on the services side in any rigs being put back to you? What are your expectations for 2009 for that business?

Well, we are obviously, we are changing our budget from $2 billion to $1 billion. We will try to roll off our rigs. We will try to aggressively market our rigs out there but --

I think we are going to have some rigs that are sitting out.

Okay.

No doubt about that. And we see other people that are doing the same thing. I think it will be a very aggressive roll off in that last quarter and going into in next quarter as people start to -- into next year as people start to adjust our budget.

I have heard anywhere from 300 to 800 rigs being rolled off in 2009.

I'm just thinking how you are going to market or do they sit on the sideline, from just a broader picture of West Texas, competitive nature of -- not necessarily West Texas but where those rigs are.

If oil prices were to increase, we would try to be competitive, but, we are not the best people to hire out as our focus is on our own stuff.

Yeah, I know.

I think you can assume we will have rigs sitting out.

To put some numbers on it, David, that business probably does -- everything we do out there, does about $36 million of EBITDA for us in 2008, so from a cash flow standpoint, while it's important strategically, since we use so many of rigs ourselves from an EBITDA standpoint, we won't be losing too, too much.

Not a big hit to SandRidge, just more of an industry thought. Thank you, guys.

Thank you.

And your next question comes from the line of Dave Kistler, with Simmons & Company. Please proceed.

Good morning, guys. Thinking about the vertical integration within SandRidge and services, as we see rig count potentially fall off here, and likely fall off pretty dramatically and corresponding services cost fall off, how are you thinking of more vertically integrated company than some of your peers, what cost savings will look like?

Well, on the vertical integration part of it, we only look at it from our side as a savings and finding cost and we model $0.06 to $0.10 per mcf from our -- for finding cost savings by having our own services. It's really from the way I look at services internally, is that it's a good thing to have our own rigs out in one place, where we are working in one field, because we have our own employees working on locations. So I don't see much of a change with that, because we will continue to do, that but where we see our savings is on the things that we -- we don't have of our own, pipe and we are seeing pipe costs come off really dramatically now. We are seeing pumping costs come off fairly dramatically. And if we -- in places that we do have outside rigs, such as East Texas, I think we are seeing the day rates come off there.

I think being vertically integrated, we do have the most savings, as a processor in a high cost environment, not in a low cost environment. So as rigs get rolled off, everybody is going to benefit on the cost side. Steel costs, are going down. Diesel costs are going down. Stimulation costs will go down.

I guess the way I'm thinking about it is more specifically from the standpoint of because a portion of your business is vertically integrated, you will get the same cost savings as other folks, obviously, as you guys have outlined, but as I -- as we try to model out, if we see costs slipping in, say, 20%, based on a portion of your businesses, first vertically integrated which will not see as much of that, what would the kind of ratio of service costs coming off, versus what you guys would likely recognize as far as costs coming off be? Am I making myself clear on that?

I -- I mean from my standpoint, you know, the guidance is out there. We are not looking for -- we haven't modeled any savings in. Could we get something? I mean, pressure pumping or something like that?

I think pressure pumping will continue to go down. That's a big part of our cost component on the drilling and the completion side. And steel cost and diesel costs, we have about 800-gallons a day of diesel. I think there will be additional savings for us, when we go to our budget and kind of estimate how many wells that's going to be and how much that's going to cost, that's just really based on historical cost analysis. We haven't factored in what savings we might get, if we get 400 or 500 rigs that might roll off.

And then the other savings will be on the services side which we have a wholesale in. As we drive hundreds of trucks and have our own rigs, there are savings on their side also, just from the pricing standpoint and if the labor prices go down, they will benefit from that also. I think there are potential savings. We just don't model it.

Okay. Great. I appreciate that. And then stepping over to F & D a little bit. That's crept up over the last quarter and just trying to understand the base drivers of that. One would look at the results that -- at least the type curve and the F & D is implied from the Warwick thrust wells over time looks like that will trend down, but as Warwick thrust and going after these wells, probably won't be as aggressive as you can be in the future. Can you talk about, over the next year or two, where you guys see F & D going? And just what was the majority driver of it popping up this quarter?

Absolutely. We drill statistically wells. So basically every well we drill in the pinion field is productive, some wells are better than others, and you will see fluctuations, quarter to quarter statistically and that's why we put out a type curve that goes back to 1984, that shows every well that's basically been drilled in the pinion field and if we do no worse than that type curve, we will be under $1.70. We run our model at $1.70 finding cost and therefore if we beat that in anyway, we will come in under our model. So I think that that's the best way to look at it, is to assume we are going to find $1.70 finding costs.

Just from a numbers standpoint, through the six months, we were at just drilling only $1.43, and for the nine months, we were at $1.49 so it's up a little bit. I wouldn't call it dramatic. Similar to what you saw in there from the all-in cost, you know, we had a couple of land acquisitions in this, which clearly as Tom mentioned, those are going away.

And just to be -- again, to hit on it, there's nothing really changing. Some quarters will be higher and others will be lower.

Great. That's very helpful. Thanks so much for the clarification, guys.

Thank you.

Your next question comes from the line of Sophie Chen with Wells Fargo.

A quick question on hedge portfolio. The last two month looking at the natural gas strip price was in the low eights and maybe sevens for most of the period. I wonder how you can lock in the $8.88 and any particular provisions to the hedges such as knockout and can you kind of review through the number of counterparties you guys have in the hedge facility.

I will take the first part and let Dirk talk about the counterparties. Our hedge position, we will fortunate to start with a high -- at 19% and over $10. So I think the way we have averaged of $8.88, is we started with a high number and then we tried to each quarter, or each month, tried to hedge whenever there's a movement in price. So the up side, rather than to the down side. It's really we are just fortunate to be where we are, and have been aggressively hedging in the last three months. So I don't think there is anything outside -- well, I can tell that you there's nothing other than straight swaps. We don't have any knockouts. We have done nothing to maneuver the prices higher. So all of our transactions are straight swaps.

Sylvia, for 2009, we have 11 counterparties. Nobody has more than 25% of our swaps. We don't own our bank group, and because of that, we don't have to post collateral on any of the swaps. So it's a pretty clean program and we really look at it as if that gas is sold. So we are not looking to trade that position either.

Great.

We really want to protect our cash flow and that's sort of the way we look at it. So it's a pretty clean way of doing business. We also have basis in as well.

Thank you.

Your next question is a follow-up question from the line of Scott Hanold of RBC capital markets.

If you look at the presentation that you posted yesterday compared to the prior one you had out there. Looking at the high CO2 gas processing capacity, it looks like it was expanded from the prior update. Can you give us a little bit of color on that?

I will have Matt answer that. Every day we try to expand.

Yes, I think we -- you look at the overall number. I think we brought up from 1.1b a day to 1.15b a day. And really that 50 million of incremental is what we think of the squeeze of our two legacy plants and we'll work with Anadarko to squeeze a little bit more out of their Mitchell plant. We hope for that to happen in Q1, where you see we're going from a year end of 300 to Q1 2009, of $3.50 and that's where the extra capacity will come from.

That assumes that we can't grow our other production, just stays flat. And so that's -- I haven't hit on that, but, in the past we have been growing it at very high rates over our production. I think this should be a very conservative case.

Okay. Okay. Got it. So this is somewhat optimization.

We are trying to show what happens with the Trenturery plant comes on if we do not grow the additional plants.

Okay. Thank you.

Thank you.

We are showing no more questions in queue right now. I would like to turn the call over for closing remarks.

No closing remarks here. We just appreciate everybody being on. Thank you.

Thank you for your participation in today's conference. You may now disconnect. Have a good day.