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SandRidge Energy, Inc. (NYSE:SD)

Q2 2009 Earnings Call

August 7, 2009 9:00 am ET

Executives

Dirk Van Doren – Chief Financial Officer

Tom Ward – Chief Executive Officer

Matt Grubb – Chief Operating Officer

Analysts

Dave Kistler - Simmons & Company

David Heikkinen - Tudor, Pickering, Holt

Matthew Lemme – Highland Capital

Adrel Askew - Hartford Investment Management

Jeff Robertson – Barclays Capital

Ryan Kelly – Prudential

Operator

Welcome to the second quarter 2009 SandRidge Energy earnings conference cal. (Operator Instructions) I would now like to turn the presentation over to our host for today's call, the Chief Financial Officer, Dirk Van Doren.

Dirk Van Doren

Last night, the company issued a press release detailing SandRidge's financial and operating performance for the second quarter of 2009 and also filed the 10-Q. If you do not have a copy of the release, you can find one on the company's Web site, www.SandRidgeEnergy.com. Also, you can sign up for releases that will automatically be sent to you and this is located under the Investor Relations tab.

Now, for the forward-looking statement. Please keep in mind that during today's call, the company will be making 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, adjusted EBITDA, and other non-GAAP financial measures. As required by the SEC rules, the reconciliation of the most directly comparable GAAP measures are available on our Web site under the Investor Relations tab.

Now let me turn the call over to our Chairman and CEO, Tom Ward.

Tom Ward

Welcome to our second quarter conference call. We also have on the call today Matt Grubb, our COO. I will have a few brief remarks and then turn the call back over to Dirk to discuss the quarter's financial results.

During the first half of 2009 SandRidge has raised almost $1.0 billion of capital. This achievement was made through five different transactions that allow us to move forward with our goal of producing more than 500.0 million cubic feet equivalent of production per day by 2012.

We can now focus on the completion of our Century Plant Phase 1 in June 2010 and ramping up our drilling program in the Pinon field leading to this start-up date.

Our plan is to move from our current 5-rig program to 25 rigs in the first quarter of 2010, with 20 of those rigs working in the Pinon field drilling developmental wells. Currently there are 4 rigs working in the Pinon field.

The Pinon field Warwick Thrust continues to deliver outstanding results. We find approximately 7.5 Bcf per well, averaging 60% CO2 and are drilling within the developed area of the field. The Century Plant Phase 1, when full, will process 400.0 million cubic feet per day of high CO2 gas, resulting in an incremental 100.0 million per day of methane gas net to SandRidge. Therefore, we will be aggressive in the development of our Pinon in-field drilling program and build-out of the Century Plant.

We are also simultaneously working on Century Phase 2, which will be completed in 2011. Phase 2 will give SandRidge an additional 100.0 million per day of net methane gas, therefore, the capital raise during the first six months of 2009 was paramount to SandRidge as we implement our growth plan for the next three years, beginning in 2010.

Our production averaged 306.0 million during the first six months, and 292.0 million a day during the second quarter. We shut in approximately 15.0 million per day during the quarter, to perform various planned and unplanned plant maintenance, compression maintenance, and pipeline projects.

We believe that this period will prove to be an opportune time to reduce production as we anticipate higher prices this winter and through 2010. We continue to target production above 110 Bcfe for the year and expect to exit 2009 above 300.0 million cubic feet a day.

We anticipate our capital spending for 2009 projects will be about $600.0 million. That is a mid-range or a $500.0 million to $700.0 million guidance and approximately 70% of this budget is drilling-related, primarily the Pinon Warwick Thrust.

We have also pre-purchased nearly $100.0 million of pipe that is now allocated to 2010 and 2011 drilling programs. Having the pipe in hand, as many of the mills have shut down, will be critical for us as we ramp up our drilling program to fill the Century Plant in early 2010.

In 2010 we have projected capex of $700.0 million and anticipate 2011 capex of $750.0 million. Typical drilling and completion cost is $2.2 million for a Pinon Warwick Thrust well. We continue to be more efficient in drilling these wells and have now reduced the number of days to drill a Pinon well to 26 days on average, down from 40 days this time last year.

On another positive note regarding capex, we have entered into 12-month to 18-month agreements with several service providers in the areas of cementing, stimulation, directional tools, and open-hole logging that will ensure low drilling and completion costs through 2010.

This, coupled with owning 31 drilling rigs makes us well hedged on the cost side of our business through 2010.

We have over 600,000 acres of unevaluated land in the West Texas Overthrust (WTO) that has nearly 1,300 miles of 3-D seismic shot across it. We are now in the evaluation stage of our 2010 exploration program. During 2010 we plan to drill 6 exploratory wells across the WTO on prospects that are 6,000 feet to 10,000 feet in depth on structures we can map as Pinon-size fields. We have budgeted $18.0 million for exploratory drilling in 2010.

The size of the prize is a Pinon field at 5.7 Tcf of methane gas within the area of known gas and an additional 2 Tcf of potential reservoir expansion based on our 3-D interpretation.

There is no geological reason to not expect other Pinon fields located across the WTO. In fact, we see all of the right geological and geophysical features to believe we will find additional Pinon-type fields in this exploratory phase of our company.

The Pinon field is one of the United States' premier gas plays. Our drilling finding cost is approximately $1.00 per Mcf of methane, even though we give away 60% of our gas to CO2. This field will be producing over 1 Bcf of total gas per day by 2012, putting it in elite status. In fact, according to the EIA published data from 2007, there were only six fields in the lower 48 that produced 1 Bcf a day or more.

The other unique characteristic of the Pinon field is that SandRidge does not have any competition or need to drill wells to maintain our leases. We believe this puts us at a competitive advantage against almost any other play in the U.S.

Also, the cost structure is comparatively low as the field can be developed with vertical wells at a small number of frac stages.

This field would have been produced decades ago if not for the CO2.

Also, due to the flatter decline profile, the Warwick Thrust reservoir will need only 8 rigs running in the Pinon field to keep the Century Plant Phase 1 full and about 12 rigs running to keep both trains full.

We believe by 2012 SandRidge will be in a position to generate a sufficient amount of discretionary cash to either pay down debt or to implement our continued growth strategy outside of Pinon.

We have hedged our 2009 and 2010 production and have hedged the basis portion of our 2011 and 2012 production. Our belief is it is too early to hedge past 2010 and we will wait for the decline in U.S. drilling to take effect on pricing before we actively hedge our production beyond 2010.

From a liquidity standpoint, we have less than $10.0 million drawn on our borrowing base of nearly $1.0 billion. Through our capital raises and with the hedges in place, we are in a great position to implement our strategy of growing production and reserves over the next few years and can be cash-flow positive within the time frame we've outlines.

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

Dirk Van Doren

I will focus on a few financial highlights in the second quarter. Our adjusted EBITDA for the quarter was $144.0 million, above Street consensus numbers.

Our production taxes were low on a unit basis because of its enlarged natural gas severance tax rebates. The rebate process is time consuming and it's hard to know exactly when the rebate will be received which makes it difficult in terms of guidance.

Turning to capital expenditures, our GAAP expenditures were $148.0 million for the second quarter and $444.0 million for the first half of the year. We use GAAP numbers in our internal model. We had $120.0 million accrual at the beginning of the year, which had declined to $40.0 million at the end of the second quarter, making our capital expenditure numbers flow into the cash flow statement higher.

Since our last conference call, we've been busy adding to our basis swap book for 2011 and 2012. As shown in the press release, since our last call we have built positions up to 104 Bcf in 2011 at $0.47, an increase of 11 Bcf from our last call. Additionally, we have added 88 Bcf since May to our 2012 position, which is now 113 Bcf at $0.55.

Moving to the capital structure, we had a very busy second quarter in terms of raising capital, with four transactions raising over $700.0 million of net proceeds. That capital permitted us to reduce the revolver to $18.0 million at the end of the quarter, on an approximate $1.0 billion credit line. Currently, our net revolver position is $17.0 million as of yesterday.

During the quarter we completed a two-year interest rate swap on our floating rate notes which mature in 2014. We had a swap in place from April 2008 to April 2011 and the second swap extended that for additional two years to April 2013. The blended rate on our interest rate swaps is now 6.43%.

We have our next bank redetermination in October and this should not be an issue for us. We reviewed the analysis at our investor meeting in March and at low bank prices, which are currently slightly less than March, our PD9 at midyear comfortably covers the revolver, if it were fully drawn.

Additionally, our repayment of the line, based on producing PDPs only, is much less than one year.

We are also in compliance with all of our covenants at the end of the second quarter.

Looking forward to our conference schedule, we will be attending the Barclays Energy Conference in New York on September 9, the Deutsche Bank High Yield Conference in Phoenix on September 30, and the Johnson Rice Energy Conference in New Orleans on October 7.

We also plan to release our third quarter numbers on Thursday, November 5, 2009, after the market closes and have an investor call the following day.

That ends our prepared remarks. We are happy to open up for questions.

Question-and-Answer Session

Operator

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

Dave Kistler - Simmons & Company

For 2010, uptick in capex, can you give us any kind of additional color on the capex, how it will be directed, and what you see as far as a rig count uptick in 2010.

Tom Ward

We should not have a rig count uptick. We have scheduled for 25 rigs in 2010, 20 of those going in Pinon. That that does have those 5 discretionary rigs outside of Pinon, does require us to basically look at a $6.00 NYMEX. We don't want to drill hyperbolic decline wells in a very low-price environment and that's why we don't have any drilling today.

So I don't think with the pipe that we already have bought and we could probably look at a capex that would be flat at 750 across the board, for 2010, 2011, and 2012, except we've already spent some of that money.

So I think that it's really not a uptick other than what we've always planned to do and why we raised the capital we did in 2009 was to get ready to fill Century Phase 1, which starts early in the first quarter of 2010. And that's drilling 20 rigs in Pinon field.

Dave Kistler - Simmons & Company

Can we tie in the service agreements that you locked down on long-term contracts for cementing, etc. Can you talk about the term of those and the thought process of locking those down at this point?

Tom Ward

Sure. I'll talk a little bit about the thought process and then turn it over to Matt.

Our thought process is that we have a rig count that is probably bottoming and as prices move up next year, might increase just a bit. I don't see it really ramping up tremendously but that we have moved down to a price of $2.2 million per well and we wanted to lock that in as long as possible, and Matt's done a great job and I'll let him address it now.

Matt Grubb

One of the very positive things that's been an outcome of this downturn is driving the service calls down. What we're going to do is lock into the various services for 12 months to 18 months, which will take us certainly to the middle of 2010 and in some cases all the way through to the end of 2010.

I'm not going to talk about the costs specifically because of competitive purposes but I will tell you the percentage decrease that we've locked into. For example, on hydraulic fracturing, our costs now are 67% below what they were a year ago. Open-hole logging is 53% below, mud costs has dropped 46%, bit costs are down 60%, and directional tools down 53%.

So I think these are all very low prices, very low costs that will be realized from now until the end of 2010.

Tom Ward

I think another thing that you can see in this is that we have rigs that will be operating in areas that a lot of other companies aren't working. In other words, if we were to try to do this in our East Texas play, if we were drilling Cotton Valley wells, we couldn't lock in this type of price today.

Dave Kistler - Simmons & Company

Just thinking about that in terms of rigs and the services that you've locked down, what percentage of that $2.2 million well cost do you think you've effectively insulated for the next 12 months to 18 months, with the pipe as well that you've pre-purchased?

Matt Grubb

I think probably what could be a variable cost is diesel costs, labor costs go up. We operate our own rigs so there's going to be a minimal increase there, even if activity starts picking up. So I think the bulk of that $2.2 million is locked up.

Let me give you an example, when we're up $3.3 million, about $750,000 of that was for hydraulic fracturing. Now those same three stages of hydraulic fractures cost about $220,000. So that's $0.5 million that's locked in for the next 18 months. Open-hole logging for example, would run $40,000 to $50,000 per well. Now they're in the $15,000 range. That's locked in through the end of 2010.

So I'm going to say probably—I don't know exactly—but I'm going to say probably 70%, 75% of that total well cost is locked in long term.

Dave Kistler - Simmons & Company

When we start thinking about the exploration drilling you're doing, it looks like primarily focused outside of Pinon, do you think about putting a little bit of focus into trying to develop Frog Creek a bit more, or get more information on Frog Creek during that period?

Tom Ward

We are getting information on Frog Creek as we drill in the southern portion of Pinon and we do believe that is perspective but can be probably developed as we expand the Pinon field out into this next 2 Tcf of reserves that we have in the Warwick Thrust.

So what our focus is going to be on the exploration side is trying to find new structures that are Pinon look-alikes in size. We have 30 leads. We are in the process of picking 6 of those out, which I think we're well into the process. That's why we narrowed it down from 10 to 6. We have good prospects in place and while we aren't going to say today exactly where those are, you can be assured that we are honing them down to where we want to drill.

The real caveat will be not only if we find the Warwick Thrust producing gas but what type of CO2 gas. I mean, can we find a Pinon field that is all methane? If so, obviously that would be the ultimate prize we would be looking for.

Operator

Your next question comes from David Heikkinen - Tudor, Pickering, Holt.

David Heikkinen - Tudor, Pickering, Holt

On CO2 treating capacity, currently 315, talk about the repairs and timing at Grey Ranch and then the expansion at Grey Ranch. Can you give some granularity of what's going on there and then the cost of repairs and who bears them and then the cost of the additional recycled compression that expands some capacity.

Matt Grubb

Currently we do have 315.0 million a day of treating capacity and we're running at capacity. The capacity break down comes from three plants. We're at about 145.0 million at Grey Ranch, and then 85.0 million a piece at Pike's Peak and the Mitchell Plant.

We are working on an existing piece of equipment at Grey Ranch called thermal oxidizer (TO)and what that allows us to do is burn off the volatile organic compounds that come off the stack, so it means we can be within our environmental permit.

The TO, we purchased TO for basically $7.5 million. That's one of the capitalized items. However, the repair work is taken care of by the manufacturer. There is a guarantee on this TO that it should work to spec and it's not. And so the repair costs are on them right now.

We expect to have this TO repaired and operating maybe by mid-September and that will drive the Grey Ranch plant capacity up from 145.0 million to about 180.0 million a day, bringing the total treating capacity up to 350.0 million.

And then what we're contemplating right now is in the fourth quarter we would add additional recycle compression at Grey Ranch plant, bringing that 180.0 million up to 200.0 million a day. And that cost is probably in the order of $2.0 million to $2.5 million.

Tom Ward

So you can see that what we look at quarter to quarter are ways to keep on expanding the ability to get out more high CO2 gas opinion. We have, obviously, more gas available to produce than what even we will be able to produce with Century and our plant. So our focus is always trying to expand our existing plants.

David Heikkinen - Tudor, Pickering, Holt

And then as you think about the ramp to 20 rigs and owning those rigs and staffing them internally, it seems like you would be able to do that pretty quickly. Is that a reasonable expectation as far as ramping in and then trying to fill Century Plant for April/May time frame next year?

Tom Ward

We're projecting June, to fill Century. What we'll do is obviously we will be moving gas from the existing plants over to Century because of higher efficiencies, so you start by filling up Century and then filling the existing plants. It should not take us long to ramp up and won't take us long because we're already preparing to do that and we have a six-month lead time before we want to spend the capital. So that work is already in progress and we don't see that being an issue.

David Heikkinen - Tudor, Pickering, Holt

And as you look forward, just ask the question people always ask us on all the covenants and everything. How do you look at your financial outlook relative to covenants and your current position?

Dirk Van Doren

Actually, really well. We're only $17.0 million into the line of $985.0 million. As we project going out we don't have any covenant issues. We are actually in probably in the best shape on the balance sheet side we've been in in over a year. So we feel really comfortable on that side of the business.

Operator

Your next question comes from Matthew Lemme – Highland Capital.

Matthew Lemme – Highland Capital

This actually dovetails from the question just asked, in terms of funding capex going forward, to the extent that you can't cover it with cash from operations, it sounds like you would prefer drawing down on the line of credit.

And then in terms of terming that out, is your preference to do another bond deal or would you consider issuing additional equity?

Dirk Van Doren

Good question. From our standpoint, we don't see ourselves by the end of 2010 being—we see ourselves being into the line by less than half the line, so right now, internally, we don't project any capital raises for the next call it 17 months.

I think the way we think about it is if you get into the line by more than half, you start thinking about doing something. Right now, we're not in the line by a half, by the end of 2010, and we don't assume the line goes up.

Tom Ward

And with price recovery, if you project price recovery, too, you might not ever need to do anything more than just use your line.

Matthew Lemme – Highland Capital

And on differentials, you have been talking about a $0.70 level for a while and I noticed in the updated guidance that it's now closer to $0.80. Could you talk to that and what's happening there and if you expect that to creep higher or revert back to the mean or revert back to the $0.70 level.

Tom Ward

We think as you look forward at our basis we are able to hedge basis below the $0.70 level so we think that level will be lower. Also, in conjunction with the mid-stream deal we did, we had a little higher basis, what goes into basis, a little bit of the cost of coming over from mid-stream. So that was the reason for the move from $0.70 to $0.79.

And then looking forward, if you see where our basis levels are, we project those to be under $0.70. We still are modeling, that probably will change just a little bit going forward to be lower than $0.70.

Operator

Your next question comes from Adrel Askew - Hartford Investment Management.

Adrel Askew - Hartford Investment Management

The 5 discretionary rigs that you're talking about, where will those be focused and can you talk to scenarios as to where the break evens are, related to you making use of those 5 rigs.

Tom Ward

Sure. We have several other plays at a $6.00 price environment NYMEX that we would want to put rigs to work, or could put rigs to work. We focus on the East Texas assets. The Cotton Valley vertical wells are very good projects to drill in a higher price environment. The mid-continent is a great place to drill in a higher-price environment.

And then we have the oil play in Ector County, Texas. But right now what we would focus on is having a couple of rigs running in East Texas, a rig in mid-continent, and probably 2 in the oil play in Ector.

Adrel Askew - Hartford Investment Management

And the 40 drilling days that you are talking about, is that spud to TD or spud to spud or what metric is that?

Matt Grubb

That's spud to TD.

Tom Ward

And that moved from—it's down to 26 days.

Matt Grubb

Yes, it's now 26 days.

Adrel Askew - Hartford Investment Management

It's down to 26 days?

Matt Grubb

Yes. 40 days was Q2 2008 and now we're down to 26 days for the same well in the Warwick Thrust.

Adrel Askew - Hartford Investment Management

Can you see any further improvement in that?

Matt Grubb

I think we're pretty much there. You've got to remember, we started out in 2007 drilling those wells in about 55 days. We moved down to 40 a year later, and now we're down to 26 days.

Adrel Askew - Hartford Investment Management

As it relates to completion techniques, what have you done there recently that is working the best for you and do you have any other tricks up your sleeve to improve IPs?

Matt Grubb

No, no tricks up our sleeves. I think our completion techniques, the biggest changes were made in 2007 and going into 2008 on how to frac and what kind of fluids to frac these wells. In the last two quarters we've pretty much kept the same techniques. We're fraccing with anywhere from 40% to 70% CO2 energized frac fluids. And that's worked real well for us.

Tom Ward

And the way I think about it is that we're doing vertical wells with fairly small fracs. What we've been blessed with is a reservoir that doesn't need a lot of treatment, so in other words we're not drilling in a shale, we're drilling in a reservoir that has great permeability and fracture porosity and that's how come you get 7.5 Bcf per well on a vertical well.

So I think the difference, if you think about us getting to a $1.00 finding cost versus some of the great shale plays to get to a $1.00 finding cost is that we drill conventional wells, so we have to have a reservoir that is superior and doesn't have to have a horizontal well board put into it.

But on the flip side, we have to give away 60% of our reservoir because of CO2.

Adrel Askew - Hartford Investment Management

And on the 7.5 Bcf, EUR, what's your terminal decline rate and what's the years of production assumed there?

Matt Grubb

The terminal decline now is around 10%.

Tom Ward

If you think of this, you can have a little bit of hyperbolic in the front part of the well and a little bit less decline in the end, but we kind of look at a 13.5% exponential across the life of the well. It's an easy way to think about it. If you want to get into more details exactly, you could have a little bit more hyperbolic at the front but it's not going to be dramatic. The point is that you're doing it at a reservoir that only declines at about 13.5% a year across the life of the well.

Operator

Your next question comes from Jeff Robertson – Barclays Capital.

Jeff Robertson – Barclays Capital

In the 2010 budget have you all included any contingent development dollars that would follow any exploration success or would that be incremental capital if you had success that needed to be delineated?

Tom Ward

If we find another 5 Tcf to 8 Tcf field, we're going to need to have a partner or do something differently. Obviously if we wanted to go in and have another program of the size of Pinon, that is a game changer to the company and we would have to look at some different alternatives.

Jeff Robertson – Barclays Capital

And secondly, in terms of where those prospects might be located, are there infrastructure requirements when you drill them, or do you think you will be able to tie them in if there is success and get a test going.

Tom Ward

If you're all sweet gas, there's not very much infrastructure requirement at all. If it has a high amount of CO2, then there would be some infrastructure requirements that we would have to deal with.

Operator

Your next question comes from Ryan Kelly – Prudential.

Ryan Kelly – Prudential

When you say no capital into 2010, does that include debt capital?

Dirk Van Doren

No. I will be clear, any shortfall will go onto our line but we don't think we will need to be in the capital markets, meaning raising a high-yield deal, doing a preferred deal, or moving down this capital structure doing an equity deal. It will just go onto the line.

Ryan Kelly – Prudential

As it relates to the line, do you have a redetermination in September?

Dirk Van Doren

October. And it won't be an issue, given the fact that I would expect to end the quarter not too far away from where we are right now.

And the other thing is, that market, just like all the other capital markets, is better. People feel better, we've had a few banks come through here in the last two weeks, it definitely feels better, just like your market does. Because spreads have tightened, so that shouldn't be an issue.

Operator

There are no further questions in the queue.

Tom Ward

As always, we're thankful for each person that's on, and if you have any additional questions, feel free to give us a call.

Operator

This concludes today’s conference call.

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Source: SandRidge Energy, Inc. Q2 2009 Earnings Call Transcript
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