SandRidge Energy Inc (SD) 2009 Q2 法說會逐字稿

Good day, ladies and gentlemen and welcome to the second quarter 2009 SandRidge Energy earnings conference call. My name is Josh and I will be your coordinator for today. At this time all participants are in a listen-only mode. We'll be facilitating a question-and-answer session towards the end of this conference. (Operator Instructions)

I'd now like to turn the presentation over to our host for today's call, the Chief Financial Officer. Dirk Van Doren, you may proceed.

Thanks, Josh. Last night the Company issued a press release detailing SandRidge's financial and operating performance for the second quarter of 2009 and also filed a 10Q. 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 detail in the Company's filings with the SEC.

Today's presentation will include information regarding adjusted net income, adjusted EBITDA and other nonGAAP financial measures. As required by the SEC rules a 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.

Thank you, Dirk, and welcome to our second quarter conference call. We also have on the call today Matt Grubb, our COO. I'll have a few brief remarks and then turn the call back over to Dirk to discuss the quarters financial results. During the first half of 2009 SandRidge has raised almost $1 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 million cubic feet equivalent of production per day by 2012. We can now focus on the completion of our Century Plant Phase I in June 2010 and ramping up our drilling program and Pinon Field leading to the start date.

Our plan is to move from our current five 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 four 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 I, when full, will process 400 million cubic feet per day of high CO2 gas resulting in an incremental 100 million per day of methane gas net to SandRidge. Therefore, we will be aggressive in the development of our Pinon infield drilling program and build out of the Century Plant.

We are also simultaneously working on Century Phase II which will be completed in 2011. Phase II will give SandRidge an additional 100 million per day of net methane gas. Therefore, the capital raised 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 million during the first six months and 292 million a day during the second quarter. We shut in approximately 15 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 million cubic feet a day.

We anticipate our capital spending for 2009 projects will be about $600 million. That is the mid-range of our $500 million to $700 million guidance, and approximately 70% of this budget is drilling-related primarily the Pinon Warwick Thrust. We've also pre-purchased nearly $100 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 projected CapEx of $700 million and anticipate 2011 CapEx of $750 million. Typical drilling and completion costs 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 to 18-month agreements with several service providers in the areas of cementing, stimulation, directional tools and open hole logging that will ensure load drilling and complete 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 that has nearly 1300 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 six exploratory wells across the WTO on prospects that are six to ten-- 6,000 to 10,000 feet in depth on structures we can map as Pinon sized fields. We have budgeted $18 million for exploratory drilling in 2010. The size of the prize is the Pinon Field at 5.7 Tcf of methane gas within the area of known gas and an additional two 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 premiere gas plays. Our drilling finding cost is approximately $1 per Mcf of methane even though we give away 60% of our gas as CO2. This field will be producing over 1.-- over one Bcf of total gas per day by 2012, putting it in elite status. In fact, according to the EI published data from 2007, there were only six filed in the lower 48th that produced one 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 US.

Also the cost structure is comparatively low as the field can be developed with vertical wells and 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 of the Warwick Thrust reservoir we will need only eight rigs running in the Pinon Field to keep the Century Plant Phase I 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've hedged our 2009 and 2010 production and have hedged the basis portion of our 2011 and 2012 production. Our belief that it is still too early to the hedge past 2010 and we will wait for the decline in US drilling to take effect on pricing before we actively hedge our production beyond 2010.

From a liquidity standpoint we have less than $10 million drawn on our borrowings base of nearly $1 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 outlined. With that I'll turn the call over to Dirk.

Thanks, Tom. I will focus on a few financial highlights in the second quarter. Our adjusted EBITDA for the quarter was $144 million above the Street consensus numbers. Our production taxes were low on a unit basis because of some large 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 million for the second quarter and $444 million for the first half of the year. We use GAAP numbers in our internal model. We had $120 million accrual at the beginning of the year which had declined to $40 million at the end of the second quarter, making our capital expenditures numbers flowing through 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 million of net proceeds. That capital permitted to us reduce the revolver to $18 million at the end of the quarter on an approximate $1 billion credit line. Currently our net revolver position is $17 million as the yesterday. During the quarter we completed two-- 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 a second swap extended that for an 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 [PV9] at mid-year 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 a Johnson Rice Energy Conference in New Orleans on October 7. We also plan to release our third quarter numbers on Thursday, November 5th, after the market closes and have an investor call the following day. That ends our prepared remarks, Josh. We are happy to open up the call for questions.

(Operator Instructions) And our first question comes from the line of Dave Kistler from Simmons & Company. Dave, you may proceed.

Good morning, guys.

Good morning.

Quick question for 2010, uptick in CapEx. Can you give us any kind of additional color on the CapEx, how it'll be directed and what you guys see as far as a rig count uptick in 2010?

We should not have a rig count uptick. We have scheduled for 25 rigs in 2010, 20 of those drilling in Pinon, that does have those five discretionary rigs outside of Pinon does require us to basically look at a $6 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 CapEx it would be flat at $7.50 across the board for 2010, 2011 and 2012, except we've already pre-bought some of the-- spent some of that money. So I think that there's really not an 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 I, which starts early in the first quarter of 2010. And that's drilling 20 rigs in the Pinon Field.

That's helpful. I appreciate it. Can we tie in the service agreements that you locked down on long-term contracts for cementing, et cetera? Can you kind of talk about the term of those and kind of the thought process of locking those down at this point?

Sure, I'l talk a little bit about the thought process and 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 has done a great job. I'll let him address it now.

Yes, Dave, one of the very positive things that's being the outcome of this downturn is the service cost-- driving the service cost down. What we're going to do is lock into various services for 12 to 18 months which will take us certainly through the middle of 2010 and in some cases all the way through the-- to the end of 2010. And I-- I'm not going to talk about the costs specifically because of competitive purposes, but I'll tell you the percentage decrease that we've locked into. For example, on hydraulic fracturing, our cost now are 67, yes 67% below what they were a year ago, open hole logging is 53% below, mud cost 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 we'll be able to realize from now until the end of 2010.

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 the other companies aren't working. So you-- in other words, if we were to try to do this in our East Texas play if were drilling Cotton Valley wells we couldn't lock in this type of price today.

And just thinking about that in terms of okay rigs and the services that you've locked, what percentage of that $2.2 million well cost do you guys think you've effectively insulated for the next 12 to 18 months, with the pipe as well that you've prepurchased?

I think probably what could be a variable cost is the diesel cost, 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 at $3.3 million, about $750,000 of that was for hydraulic fracturing. Now the same three stages of hydraulic fractures costs 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 the bulk, I'm going to say probably, I don't know exactly, I'm going to say probably 70%, 75% of that total well cost is locked in long term.

Great. That's very helpful. And then last question and I'll hop off. When we start thinking about the exploration drilling you're doing looks primarily focused outside of Pinon, do you think about putting a little bit of focus in to trying to develop Frog Creek a bit more, or get more information on Frog Creek during that period?

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 two 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-a-likes in size. We have 30 leads. We've-- we're in the process of picking six of those out which I think we're well into the process. That's why we narrowed it down from ten to six. 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're 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 prize, the ultimate prize we'd be looking for.

Great, well thank you so much for the additional color, guys.

Thank you.

And our next question comes from the line of David Heikkinen from Tudor, Pickering, Holt. David, you may proceed.

Thank you and good morning, guys.

Good morning.

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

Yes, David, this is Matt Grubb. On the-- currently we do have 315 million a day of treating capacity and we are running it at capacity. The capacity breakdown comes from three plants. We are at about 145 million at Grey Ranch and then 85 million a piece at Pikes Peak and the Mitchell plant.

We are working on an existing piece of equipment at Grey Ranch called thermal oxidizer and what that allows us to do is burn off the volatile organic compounds that come off the stack, so that we can be within our permit, environmental permit. The TO, we purchased TO for basically $7.5 million. That's was a Cap--that's one of the CapEx-- capitalized item. However, the repair work is taking care of by the manufacturing. There's a guarantee on this TO that it should work to spec and it's not. So the repair costs are on them right now. We expect to have this TO repaired and operating probably in the first week, maybe by mid-September. And that will drive the Grey Ranch plant capacity up to from 145 to about 180 million-- 180 a day, bringing the total trading capacity up to 350.

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 up to 200 million a day. And that cost is probably in the order of $2 million, $2.5 million.

Okay.

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

And then as you think about the ramp to 20 rigs and owning those rigs and staffing them internally, it seems like you'd 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?

Yes, the-- well the ramp-- we're projecting June to fill Century.

Okay

But what we'll do is obviously we'll be moving gas from the existing plants over to Century so-- because of higher efficiencies. So you start by filling up Century and then filling the existing plants. We when-- 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 those-- that work is already in progress and we don't see that being an issue.

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

Actually really well. We-- we're only 17 million into the line of 985 as we project going out, we don't have any covenant issues. We're actually in, we're actually 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.

All right, thanks, Dirk. That was it.

And our next question comes from the line of Matthew Lemme from Highland Capital. Matthew, you may proceed.

Good morning, gentlemen. Dirk, a quick question for you actually dove tails from the question that was 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 guys would prefer drawing down on the line of credit. And then in terms of terming that out, would you-- is your preference to do another bond deal or would you consider issuing additional equity?

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 half-- by the end of 2010, and we don't assume the line goes up. So--

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

Sure, no understood. Okay, great. And then the same question I had was on differentials. You guys have been talking about a $0.70 level for awhile and I noticed in the updated guidance that it's now closer to $0.80. And I was wondering if you could talk to that and what's happening there and if you expect that to creep higher or revert back to the, sort of mean revert back to the $0.70 level. that to creep higher or revert back to the 70 cents

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

Great. Thanks a lot, guys.

Thank you.

(Operator Instructions) And our next question come from the line of [Adrel Askew] from Hartford Investment. Adrel, you may proceed.

Thank you and good morning. The five discretionary rigs that you're talking about, where would those be focused? And can you kind of talk through the scenarios as to where kind of the break evens are related to you making use of those five rigs?

Sure. We have several other plays at a $6 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, those are the Cotton Valley vertical wells are very, very good projects to drill in a higher price environment, the mid-continent's a great place to drill in the higher price environment. And then we have the oil play in Ector County Texas. We're-- but I mean right now what we would focus on is having a couple of rigs running in East Texas, a rig in mid-continent and probable two in the oil play in Ector.

Okay, very helpful. And then the 40 days that you are, drilling days that you're talking about, is that spud to TD or spud to spud or what metric is that?

That's spud to TD.

Okay.

And that moved from--

It's now 26--

Down to 26.

Yes, it's now 26 days.

It's down to 26?

Yes, it was 40 days was Q2 of 2008.

Okay.

And now we are down to 26 days for the same well in the Warwick Thrust.

Okay. Great. Can you see any further improvement in that, is that--

I think we're pretty much there.

Okay. All right.

We started out-- 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.

Okay. As it relates to the 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?

No tricks up our sleeves. I think our completion techniques have-- 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, I'm going to say the last two quarters we pretty much kept the same techniques. We are fraccing with anywhere from 40% to 70% CO2 energized frac fluids and that's worked real well for us.

And the way I think of that is that we're drilling 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 fractured porosity and that's how come you get 7.5 Bcf per well on a vertical well. So we-- I think the difference if you think about us getting to $1 finning cost versus some of the great shale plays that to get to $1 finning 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 bore put into it. But on the flip side, we have to give away 60% of our reservoir because of CO2.

Okay, that's very helpful. And then on the 7.5 Bcf EUR, what's your terminal decline rate and what's the years of production assumed there?

I think terminal decline now is around 10%.

Okay.

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. That's an easy way to think about it. If you get into more details exactly, you could have a little bit more hyperbolic at the front, but it's not dramatic. And the point is is that you're doing it at a reservoir that only declines about 13.5% a year across the life of the well.

Okay. All right that's very helpful. Thank you.

Thank you.

And our next question comes from the line of Jeff Robertson from Barclays Capital. Jeff, you may proceed.

Thank you. Tom, 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 decided to-- if you had success that needed to be delineated?

Yes, Jeff if we find another five to ATC 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'd have to, we'd have to look at some different alternatives.

And then secondly just in terms of where those prospects might be located, are there infrastructure requirements or when you drill them do you think you'll be able to tie them in if there's a success and get at a test going?

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 and you-- that we'd have to deal with.

Okay. Thank you.

You bet.

And our next question comes from the line of Ryan Kelly from Prudential. Ryan, you may proceed.

Good morning. Two quick questions. When you say no capital into 2010, does that include debt capital?

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

Got it. And then as it relates to the line, do you have a redetermination in September?

October, and 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.

Okay. Great. Thanks, guys.

And the other thing is is that market, just like all the other capital markets, is better. I mean people feel better. We've had a few banks come through here in the last two weeks. It definitely feels better, feels better just like your market does because spreads have tightened. So that shouldn't be an issue.

And at this time, we are showing no further questions available. Mr. Ward, you may proceed.

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

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a great day.