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Executives

Dirk Van Doren - EVP and CFO

Tom Ward - Chairman, President and CEO

Matt Grubb - EVP and COO

Analysts

Joe Allman - JPMorgan

Scott Hanold - RBC Capital Markets

Brian Singer - Goldman Sachs

David Heikkinen - Tudor, Pickering

Dave Kistler - Simmons & Company

Sylvia Chan - Wells Fargo Bank

SandRidge Energy, Inc. (SD) Q3 2008 Earnings Call November 7, 2008 9:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the third quarter 2008 SandRidge Energy Earnings Call. My name is Eric, and I will be your coordinator for today. (Operator Instructions)

I would now like to turn your presentation over to your host for today's call, Mr. Dirk Van Doren, Chief Financial Officer. Please proceed.

Dirk Van Doren

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

Before I turn 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 detailing SandRidge's financial and operating performance for the third quarter of 2008, and we also filed our 10-Q.

If you do not have a copy of the release, you can find it at the company's website, www.sandridgeenergy.com. Also, you can sign up for releases that will be automatically sent to you, and this is located under the Investor Relations tab. Today, we will use a few slides that are also available on our website.

Now, for the forward-looking statements. Please keep in mind that during today's call, the company will make forward-looking statements, which are subject to risks 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 financial measures. As required by SEC rules, a reconciliation of the most directly comparable GAAP measures are available on our website under the Investor Relations tab.

Now let me turn the call over to Tom Ward. Tom?

Tom Ward

Thanks, Dirk, and welcome to our third quarter earnings conference call. We have in office today Matt Grubb, our Chief Operating Officer, 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're aware, the world is focused on access to capital. SandRidge is also focused on access to capital and has made this our number one priority in the last 90 days. We have cut our 2009 budget to $1 billion from the $2 billion budget guidance in the second quarter conference call.

We started the process of selling our East Texas assets during the second quarter and are now working with several interested investors to include the selling in the fourth quarter. We plan to completely pay down our revolver by the end of this year and are currently reviewing additional avenues of funding, including further asset allocation and developing a capital plan that will fund us through 2010.

SandRidge continues to grow the Piñon field. We drilled 76 wells in the quarter, and our company reserves grew to over 2.1 Tcf 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, the well work in the Gulf Coast and hurricanes Ike and Gustav 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 shut-in in the Gulf due to the storms. 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 our 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 3-D seismic over the Piñon field, and our geoscience team has been working with this dataset for about 90 days. As a result, we're continuing to find new areas to explore and further expand the Piñon field, which I believe is fast becoming one of the better fields onshore in the U.S.

The field has more than tripled in the amount of wells drilled since June of 2006 and has grown over 10 times in the amount of 3-D 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 real. 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 a clear understanding of the depositional environment and the multiple thrust systems.

For example, until we had our first interpretation of our proprietary 3-D seismic over the Piñon field in July of this year, we did not even realize that the Frog Creek or the [Haymond] thrust existed. This realization has increased the potential for continued expansion of the Piñon field across the West Texas Overthrust.

For example, the 5.1 Tcf of our 3P net reserves are located primarily in the Dugout Creek and the Warwick thrusts, while the Frog Creek thrust is proven to be commercially productive. We have not yet to begun to materially book any reserves in this thrust. The Haymond looks promising from the standpoint of structural development and depth, but we have not yet drilled a test into this thrust.

The knowledge of these thrust systems gives us the ability to manage our drilling program in a way that will minimize finding costs and maximize production and reserve growth.

Our first slide shows the Dugout Creek thrust is the deepest, and the thrust that's been pushed to furthest north. We continue to drill sweet gas wells within this thrust. And in fact, this is 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 built, we will not be able to develop this thrust as aggressively as we would like. We do continue to find sweet gas wells within the Warwick thrust on the east side.

However, 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 7 Bcf of gas per well at an average of 6,000 to 8,000 feet.

The variable of producing this zone is the CO2 content of the 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 operations at the Century Plant in 2010.

The third thrust is a known producer in the Piñon field is the Frog Creek thrust. This thrust does not have a 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 are drilled 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 had very encouraging results.

We are in the process of mapping this thrust with geological information from the few penetrations we have and tying into 3-D seismic data to high-grade locations as we prepare to drill more Frog Creek Caballos wells in 2009. We've provided the type curve for the Piñon field in slide 2 that takes into consideration about 600 wells drilled in the field since 1984. We model and give guidance based on this type curve of $1.70 per Mcf finding costs.

We've been able to keep our finding costs below the $1.70 per Mcf. And so far this year, we are at $1.40 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 Piñon field and incredible upside for production and reserve growth. The future growth of this company is substantiated by past performance as our ability to continue to expand Piñon field and not be dependent on finding any additional reserves outside of Piñon.

Our third slide shows production growth that we will experience in 2010 and 2011 with the 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 to discuss in detail at this point.

The point we try to emphasize is that SandRidge is growing by drilling sweet gas wells, while this amount of low-risk CO2 natural gas sits within our field just 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 yearend 2011, with just the addition of the Century Plant. This is truly a company-changing event, and we are fortunate to have such a unique reservoir that is so prolific that you can give away half of the gas streams 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 all-in finding 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 outside of the Piñon field. The Big Canyon 121-1a is drilling at 15,400 feet, and we believe we are now in the Warwick thrust, based on regional seismic work, and tying back to the Piñon field. We don't expect to have evaluation [long-term] test results until the end of the year, but we are encouraged by the shows that we see.

The other two wells that we previously discussed in the South Sabino prospect do produce sweet gas, but initial rate is below 500 Mcf a day. However, this production on those two wells is not from the overthrusted cherts that we have found in the Big Canyon well.

The presence of the sweet natural gas outside the Piñon field is very important to our goal of finding additional Piñon fields on more than 650,000 acres in the West Texas Overthrust.

I'll now turn the call over to Dirk.

Dirk Van Doren

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 because of shut-ins, while costs were within our guidance with the exception of G&A, again, as a result of the shut-in of production. 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 that I get a lot of questions on, we were in full compliance with all of our covenants at the end of September.

Additionally, since our last call, we've got into our hedge position. We are now 72% hedged for the fourth quarter of 2008 at an equivalent price of $9.20 per MMBTu. And for the full year 2008, we will have been hedged 77% at $8.97 per MMBTu. Looking at 2009, we've 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 that was presented 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 through the reminder of the fourth quarter, we will be at two conferences in November. So, please see our website for the times and dates of these presentations. We also included in the press release that we plan to release our fourth quarter and yearend results on February 26th, and we will file the 10-K that day with our conference call the next day at 9 A.M.

Our second annual investor analyst meeting will be on Tuesday, March 3rd, in New York at 8 A.M. at the Grand Hyatt. So, please mark the calendars.

That ends our prepared remarks. Eric, we're ready to open the call for questions.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from the line of Joe Allman with JPMorgan.

Joe Allman - JPMorgan

Yes, thank you. Good morning, everybody.

Tom Ward

Good morning.

Dirk Van Doren

Hey, Joe.

Joe Allman - JPMorgan

Hey, Tom, maybe you said this, but how many wells at this point have you drilled in the Frog Creek thrust and where are those located?

Tom Ward

The Frog Creek thrust is mainly if you look north to south on that slide we presented. The Dugout Creek is the furthest north. The Warwick is the center. And that's on page three. And the Frog Creek sits south of that.

So, by definition, the Frog Creek wells are at the south end of the field. We're not going to get into specifics of how many wells were drilled, but you can see on our website where we are drilling wells and can maybe come to some conclusions.

We have several wells that have penetrated Frog Creek and several that wells that have tested the Frog Creek. We don't know today 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 that they will meet or exceed our PUD average type curve.

Joe Allman - JPMorgan

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

Tom Ward

Yes.

Joe Allman - JPMorgan

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

Tom Ward

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

Joe Allman - JPMorgan

Got you. And then lastly, the Big Canyon well is drilling. I know it's still drilling. But what are your thoughts so far as you are drilling that and what are you seeing?

Tom Ward

We're pretty encouraged that of the three exploration wells, this is the only one that's hit our targeted zone in the overthrusted chert. We have good shows, and we'll test them out in the year.

Joe Allman - JPMorgan

Okay. Thank you.

Tom Ward

Thank you.

Operator

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

Scott Hanold - RBC Capital Markets

Thanks. Good morning.

Tom Ward

Good morning.

Scott Hanold - RBC Capital Markets

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

Tom Ward

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.

Dirk Van Doren

Yes, I can get into some more details. Let me walk you through from where we ended the quarter to where we are now on the revolver. We ended the quarter at $166 million on the revolver. We also had some one-time items that created cash that during the quarter if we didn't have those we really would have ended the quarter at $212 million. So, let's say the quarter really should have ended at $212 million.

We had a big interest payment in October of 34. We bought the Well Participation from Tom for $67 million. That gets you up to $313 million. We had a $10 million type deposit during the quarter. That's $323 million. 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 shortfall based on CapEx over EBITDA.

These are rough numbers. We've pushed accounting pretty hard on that. We're not going to have the real numbers for another week, but that's a rough idea. That gets to us $405 million at the end of the month. It says $415 million, $416 million in the Q on page 45, but you get hit with some [AP] checks early in the month.

So, we are in pretty good shape. We are certainly tracking where we thought we'd be on the revolver. And we plan to be out of it by the end of the year.

Scott Hanold - RBC Capital Markets

Okay. Thanks. And, Tom, I'm going to 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 is a few packages out there at this point in time. And can you kind of give a little bit of color how that process is going now that, I guess, the data room is closed?

Tom Ward

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

Scott Hanold - RBC Capital Markets

Okay. And then moving to some of, I guess, the step-out activity out in South Sabino, you said, I guess, you didn't hit the chert zone. And was that basically because you didn't have the seismic available and do you plan on drilling some step-out wells in that area again with the different areas targeted?

Tom Ward

That's a good question. When we drilled all three of these wells, when we started those, we did not have the seismic shoot over the Piñon field. So we didn't know how the thrust systems were laying on top of each other. What the wells have done is give us indications of where we should go.

For example, in the furthest well east in South Sabino, we actually drilled very far down depth in the Warwick thrust. And so, we could actually move to the south and cross over into Frog Creek thrust or we could go to the north and drill at 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 the seismic that was shot before we shot the Piñon 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 can hit the [Woods hollow] sands and still have production, even though it's not economic to drill those wells for that depth for that amount of production.

The key point is that there is 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, the overthrust in the Warwick especially. If we can find that outside of the Piñon field in 100% sweet position, we feel like that would be the biggest prize we could find.

Scott Hanold - RBC Capital Markets

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

Tom Ward

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 Piñon field. It's very important for us to get well control. We believe we are in the Warwick thrust, because we're 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 to 100 feet. So that's very encouraging, and it ties us back into the Piñon field.

Scott Hanold - RBC Capital Markets

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 date and then becoming more surgical. Is that a fair statement?

Tom Ward

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

Scott Hanold - RBC Capital Markets

Okay. Got it. I appreciate it. Thanks.

Tom Ward

Thank you.

Operator

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

Brian Singer - Goldman Sachs

Thank you and good morning.

Tom Ward

Good morning.

Brian Singer - Goldman Sachs

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

Dirk Van Doren

This is Dirk, Brian. On page 45 of the Q, the revolver as of November 3rd is $415.6 million. 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're probably going to come pretty close to where we are as far as you're plugging the price, you're plugging the EBITDA. You've got what our CapEx is. You sort of 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 certainly way under 600.

Brian Singer - Goldman Sachs

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

Dirk Van Doren

No.

Brian Singer - Goldman Sachs

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

Tom Ward

Sure. It was 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, now we've tested a few Frog Creek wells. We are 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 at Frog Creek. What we have to offset is it's better to have a wellbore 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 are very restricted on our CO2. I hope that's helpful.

Brian Singer - Goldman Sachs

It is. Thank you.

Tom Ward

You bet.

Operator

(Operator Instructions). Your next question comes from the line of David Heikkinen with Tudor, Pickering. Please proceed.

David Heikkinen - Tudor, Pickering

I'm always going to be Heineken.

Tom Ward

It might not be a bad thing.

David Heikkinen - Tudor, Pickering

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?

Dirk Van Doren

Dave, I think you are asking how many wells we are --.

David Heikkinen - Tudor, Pickering

Drilling, yes, exactly. Number of wells there, that would be perfect.

Dirk Van Doren

For '09, we'll start ramping up drilling for the high CO2 gas. We will ramp up from 4 rigs to about 11 rigs. 4 rigs starting out in January, it goes to 11 rigs drilling high CO2 gas.

The first phase of the Century Plant is expected to start up in the second quarter of 2010. You're looking at about 75 wells there in '09. And then we have 400 million (inaudible) come in at 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. It will be another 100 wells in 2010.

David Heikkinen - Tudor, Pickering

Okay.

Dirk Van Doren

That would be to keep all of our plant flat. All our capacity is running flat at any given time, plus ramping up for the second phase at Century.

Tom Ward

And then once we fill the plant, it only requires us to keep six rigs running to maintain.

David Heikkinen - Tudor, Pickering

Okay.

Tom Ward

And we have all of that in our model of drilling these wells in our CapEx and still growing at 20% in 2009.

David Heikkinen - Tudor, Pickering

Okay. Thinking about on the services side and your non-SandRidge-operated rigs, are you seeing any slowdown on the services side, any rigs being put back to you? What are your expectations for '09 for that business?

Dirk Van Doren

Well, we are obviously looking at our budget from an earlier guidance of $2 billion to $1 billion in '09. So, we are certainly rolling off our rigs. We will try to aggressively market our rigs out there. But --.

Tom Ward

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

David Heikkinen - Tudor, Pickering

Okay.

Tom Ward

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 this last quarter and going into next year as people start to adjust their budgets.

Dirk Van Doren

The news I have heard is it's anywhere from 300 to 800 rigs being rolled off in '09.

David Heikkinen - Tudor, Pickering

Just trying to think about how you guys are going to market or do they just sit on the sideline just from kind of a broader picture of West Texas competitive nature and not just West Texas, but where those rigs are?

Tom Ward

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.

David Heikkinen - Tudor, Pickering

I know.

Tom Ward

I think that you could just assume we will have rigs sitting out.

David Heikkinen - Tudor, Pickering

Okay. Thank you.

Dirk Van Doren

And to put some numbers on it, David, that business probably does everything we do out there. It 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 probably won't be losing too much.

David Heikkinen - Tudor, Pickering

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

Tom Ward

Thank you.

Operator

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

Dave Kistler - Simmons & Company

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

Tom Ward

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 an Mcf 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 our own locations.

I don't see much of a change with that, because we will continue to do. But where we see our savings is on the things that 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. In places that we do have outside rigs, such as East Texas, I think we are seeing the day rates come off there.

Dirk Van Doren

I think being vertically integrated, we do have the most savings as one processor in a high-cost environment, not in a low-cost environment. So I think 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.

Dave Kistler - Simmons & Company

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 we try to model out, if we see costs slipping in, say, 20%, based on a portion of your business, it's first vertically integrated, which won't see as much of that, what would be kind of ratio of service costs coming off versus what you guys would likely recognize as far as costs coming off? Am I making myself clear on that?

Tom Ward

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

Dirk Van Doren

Yes, I think pressure pumping will continue to go down. That's a big part of our cost component on the drilling and completion side. And steel cost and diesel costs, we have about 800 gallons a day of diesel. So, I think there will be additional savings for us.

When we go to a $1 billion 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, and we get both on our rigs with a roll off.

Tom Ward

And then the other savings will be on the oil field 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 in.

Dave Kistler - Simmons & Company

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 there, at least be the type curve and the [RORs] and F&D is implied from the Warwick thrust wells.

Over time, it looks like that will trend down. But as (inaudible) 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?

Tom Ward

Absolutely. We drill statistical wells. So, basically every well we drill in the Piñon 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 Piñon field.

And if we do no worse than the average or that type curve, we will be under $1.70. And so, we run our model at $1.70 finding cost. And therefore, if we beat that in any way, we will come in under our model. So, I think that that's the best way to look at it is just to assume we're going to find $1.70 finding costs.

Dirk Van Doren

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, but I wouldn't call it dramatic. I think similar to what you saw in there from the all-in cost is we had a couple of land acquisitions in there which clearly, as Tom mentioned, those are going away. So --.

Tom Ward

Again, to hit on it, there is nothing really changing. Some quarters will be higher and others will be lower.

Dave Kistler - Simmons & Company

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

Tom Ward

Thank you.

Operator

Your next question comes from the line of Sylvia Chan with Wells Fargo Bank. Please proceed.

Sylvia Chan - Wells Fargo Bank

Good morning, gentlemen. A quick question on your hedge portfolio right now. The last two months, looking at the natural gas strip price has been in the low 8s and probably 7 from a certain period. I'm wondering how are you guys able to lock in the $8.88 and also any particular provisions to hedges such as lockout and if can you kind of review through the number of counterparties you guys had in the hedge facility.

Tom Ward

I'll take the first part and let Dirk talk about the counterparties. Our hedge position, we were fortunate to start with a high 19% and over $10. So, I think the way we have averaged down instead of $8.88 is we started with a high number, and then we, each quarter or each month, tried to hedge whenever there is a movement in price.

So, upside rather than the downside. It's really we're 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. And I can tell that you there is 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.

Dirk Van Doren

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 those swaps. So, it's a pretty clean program. And we really sort of look at it as if that gas has been sold. The other thing is we're not looking to trade that position either.

Sylvia Chan - Wells Fargo Bank

Great.

Dirk Van Doren

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

Sylvia Chan - Wells Fargo Bank

Thank you.

Operator

And your next question is a follow-up question from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets

Hey, one quick question for you. If you look at the current presentation that you posted yesterday and compare it to, I guess, the prior one you had out there, looking at the high CO2 gas pricing capacity, it looks like it's been expanded from your prior update. Can you give us a little bit of color on that?

Tom Ward

I'll let Matt here. Everyday, we try to find a way to expand.

Matt Grubb

If you look at the overall number, I think we brought up from 1.1 billion to 1.15 billion a day. And really that 50 million of incremental is what we think we can squeeze out of our two legacy plants that we own now. And we're going to work with Anadarko on the Mitchell plant to maybe squeeze a little more out of their Mitchell plant.

We're hoping for that to happen in Q1 where you see we're going from our yearend of 300 to Q1 '09 of 350. That's where the additional capacity is going to come from.

Tom Ward

And, Scott, looking at the slide, that assumes that we can't grow; our other production just stays flat. I haven't hit on that, but in the past we've been able to grow it at very high rates on our overall production. So, I think this should be a very conservative case.

Scott Hanold - RBC Capital Markets

Okay. Okay. Got it. This is somewhat optimization of your existing plants.

Tom Ward

Also, we're trying to show what happens when the Century Plant comes on if we do not grow our existing production from today.

Matt Grubb

Yes, the incremental [treating] is optimization of existing plants.

Scott Hanold - RBC Capital Markets

Okay. Thank you.

Tom Ward

Thank you.

Operator

We're showing no more questions in queue at this time. I would like to turn the call over for closing remarks.

Tom Ward

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

Operator

Thank you for your portion in today's conference. This concludes our presentation. You may now disconnect. Have a good day.

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Source: SandRidge Energy, Inc. Q3 2008 Earnings Call Transcript
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