SandRidge Energy Inc (SD) 2015 Q2 法說會逐字稿

Good morning, my name is Chris, and I will be your conference operator today. Thank you for standing by and welcome to SandRidge Energy second-quarter 2015 conference call.

(Operator Instructions)

I would now like to turn the call over to Mr. Duane Grubert, Executive Vice President of Investor Relations and Strategy, please go ahead.

Thank you, operator.

Welcome everyone, thank you for joining us on our conference call. This is Duane Grubert, EVP of Investor Relations and Strategy here at SandRidge. With me today are James Bennett our President and Chief Executive Officer; Steve Turk, EVP and Chief Operating Officer; and Eddie Leblanc, EVP and Chief Financial Officer.

We would like to remind you that, in conjunction with our earnings release and conference call, we have posted slides on our website under investor relations that we'll be referencing during the call. Keep in mind, today's call contains forward-looking statements and assumptions which are subject to risk and uncertainty and actual results may differ materially from those projected in these forward-looking statements.

Additionally, we will make reference to adjusted net income, adjusted EBITDA and other non-GAAP financial measures. A reconciliation of the discussion and those measures can be found on the website. And please note the call is intended to discuss SandRidge Energy and not our public royalty trust.

Now let me turn the call over to CEO, James Bennett

Thank you everyone for joining us.

I plan to give an update on the quarter, liquidity and balance sheet, and how we're positioning the Company in this market. Steve will then provide an operations update. We plan to keep these prepared remarks pretty brief and then turn it over to Q&A.

First, let me express my thanks and appreciation to Eddie for his two years of service and dedication in the CFO role. As announced in the press release yesterday, Eddie will be retiring later this month and we wish him all the best. Eddie, thank you. Eddie's successor, Julian Bott, will be starting in August, ensuring as smooth transition with no gaps in the role.

We posted an excellent quarter operationally. Let we highlight some of the points that are summarized on slides 3 of the presentation that was posted this morning. At 89,000 barrels of oil equivalent per day for the second quarter, production was up 27% year over year and 1% quarter over quarter. And our average IP rates were again above our PUD type curve.

As a result of project high grading and excellent execution in the field, production has been towards the higher end of expectations. Therefore, we're raising the midpoint of guidance 500,000 barrels of oil equivalent, increasing the full-year midpoint from 29.3 million barrels of oil equivalent to 29.8 million, while leaving our CapEx unchanged at $700 million. An increase in the visibility of our primary asset, we've introduced standalone Mid-Continent production LOE guidance, a practice we will continue going forward.

Another positive during the quarter, we received a private letter ruling from the IRS on our saltwater gathering midstream business, CEBA Midstream LP, providing a revenue as qualifying income. Earlier this year, both in our year-end and first-quarter conference calls, we were very clear that liquidity was paramount and said look to us to maintain a strong liquidity position. In keeping with that, in June we raised $1.25 billion of second lien financing and amended our credit facility to include very flexible maintenance covenant package, ensuring us years of liquidity even in the low oil price environment.

As illustrated on slide 4, at the end of the quarter we had $1.5 billion of liquidity, including cash of just under $1 billion. I've also been very clear that our intent is to reduce debt, which still holds true. We need to solidify the Company's longer-term financial position and are actively considering many alternatives to reduce total debt.

However, I don't plan to signal on this call or answer the question on our specific intentions on what paths we will take to achieve this debt reduction. There are lots of ways to get there and many options being pursued and evaluated every day.

In terms of capital allocation and how we weigh the various alternatives, I will say that the way we invest our capital over the next several quarters of the years will determine our level of success. We have more diverse and greater set of options available to us now than in the past, ranging from development drilling to appraisal and new ventures activity, to CEBA Midstream investment and balance sheet deleveraging transactions. These all exist with the backdrop of a very dynamic and fast-moving market.

This holds true for the underlying commodities, for the pricing of our various securities and the declining costs associated with our resource conversion. Thus, internal capital allocation has taken on new prominence and we are concurrently prepared for multiple capital allocation scenarios, depending on how these opportunities unfold. For now our moderated capital plan continues to focus on high graded Mid-Continent development, with an eye on also appraising new zones in our multi-pay resource based, particularly the oilier Chester, where we expect to have increased focus going forward.

Slide 5 shows our most recent well performance continues to be right in line or better than type curve expectations. Both on a 30 day IP and 180 day cumulative basis. This continued improvement in production results come from a combination of well selections and zone targeting, more customized completion methods, use of 3-D seismic and better overall understanding of the play.

But it's important to note that we are not chasing rates and IP at the expense of value. For example, in some areas we're downsizing our artificial lift methods and purpose facilities to save capital. Even if that means slightly lower IP rates. We are looking at the full cycle value of the project, not just chasing early life production.

On well costs, highlighted on slide 7, in February we put out a goal of getting our per lateral well cost to $2.4 million for the back half of 2015. Through the great efforts of our team, we achieved that goal of full quarter early and are introducing a new target of $2.3 million per lateral. I believe SandRidge is already the cost leader in the play, with the lowest well costs and look for us to continue this going forward.

Production guidance is highlighted for the full company on slide 9, now within a midpoint of 8% production growth in 2015. And aiding in the analysis of our Mid-Continent focus, today we've introduced Mid-Continent specific guidance shown on slide 10. We provide more detail for both the full company and the Mid-Continent on the last two sides, 11 and 12. You'll also see, along with raising the range for full-year guidance, we've introduced lease operating expenses and production tax guidance, both lower on a per Boe basis.

In conclusion, together with the whole industry, SandRidge is in the midst of a challenging period for commodities. The tone of the market and pricing is much different today than it was a month ago or a month before that.

That said, first we must execute as an oil and gas company. Our teams are doing that across the board on production, field up time, LOE, well costs, targeting new zones and innovation. And our recent financing transaction provides us a long runway of liquidity and time to execute these initiatives.

In the current dynamic and fast-moving market a string of 90 day tactics, taking into account market movements will be more executable than trying to stick with a single one or two year plan. So look for us to remain nimble and move as opportunities become available.

Now let me turn the call over to our COO, Steve Turk

Thank you, James, and good morning to everyone joining us on the call.

Five months ago, I joined SandRidge with several specific objectives. These objectives including reducing well and lease operating costs, improving efficiencies, improving our multilateral technologies and developing an additional competitive play for our portfolio. Our second quarter is representative of the exceptional progress our teams have made in all of these areas.

Let me share some of the details with you. We delivered 89 laterals to sales during the second quarter, which beat our estimates. This in combination with positive results from the development program provided an average daily production rate of 88.9 thousand barrels of oil equivalent a day, up 1% from the prior quarter. The Mid-Con region averaged 79.3 thousand barrels of oil equivalent a day, up 2% from the prior quarter.

As depicted on slide 5, the quality of our Mississippian drilling program continually improves year over year. Quarter two Mississippian laterals that went to sales, produced an average 30 AIP of 390 barrels of oil equivalent per day, a 111% of type curve. Due to confidence in our well performance, we increased the lower range of 2015 guidance by 1 million barrels.

Lease operating expenses improved 11% quarter over quarter, contributing reductions include a 25% decrease in chemical costs and a 44% decrease in generator rentals. We continue to avoid water hauling in generator costs by strategically locating wells near our extensive infrastructure.

A 21% field staff reduction completed early in the quarter and improved reliability of our facilities also contributed to reduce costs. We expect further reductions as we employ a new operations center for production monitoring and water hauling. These steps allow us to reduce our lifting cost guidance on a dollar per Boe basis for 2015.

Our continued focus on capital efficiency and cycle time shown on slide 6 provide an unprecedented per lateral cost of $2.4 million, therefore realizing our second half 2015 target. As shown on slide 7, we have achieved $600,000 of savings per lateral during 2015, half of which comes from durable efficiency gains. Because of this, we fully anticipate achieving our Mississippian program average per lateral cost of $2.3 million in the second half of the year. Achieving well cost reduction targets ahead of plan resulted in $14 million of savings in the first half of 2015.

We decreased our rig count from 13 rigs at the end of quarter one, to 6, exiting quarter two. During the quarter, we spud 37 laterals, 54% using our multilateral design.

As depicted in slide 8, our multilateral program delivered 99% of the 90 day type curve production, for only 79% of the cost of a single lateral. Our technical teams are currently working on a new design for full section development that preserves stimulated lateral length, allows for improved completion designs and should substantially reduce costs. We expect to update you with results next quarter.

Multilateral performance continues to show encouraging results, with a Q2 30 day average IP of 332 barrels of oil equivalent per day, per lateral, or 95% of type curve. In the Chester play, our team spent Q2 refining geo-science work and further defining target areas delineated by Q1 appraisal wells. This is a multi-bench oil play with as many as five zones available for development. These wells require less costly infrastructure and artificial lift.

Because of this, Chester well costs are approaching traditional Mississippian costs. We continue to be bullish on Chester development and we're allocating two of our existing rigs to Chester activity for the remainder of the year.

In summary, this has been a very good quarter from an execution perspective. The team did an exceptional job managing costs during a time of depressed commodity prices. We expanded, and more importantly, improved our multilateral technology and continue to see improved well results. Successful Chester development establishes the play as a key part of our portfolio, complementing our steadily improving Mississippian play.

I anticipate the continuing commitment of our team -- I appreciate the continuing commitment of our team and look forward to sharing their contributions in the second half.

I will now turn the call over to the operator. Thank you.

Thank you.

(Operator Instructions)

Neal Dingmann, SunTrust.

Good morning guys.

Good morning, Neal.

Just a question as far as the drilling focus going forward a couple things one, just on the success you've had on that multilateral, your thoughts about doing more of these versus just sort of the traditional?

I think in the quarter we had about 50% multilateral, we're saying for the year that 40% of the program will be multilaterals, and we say that we mean you know full section development, dual co-planers and also long laterals. I'm not sure what it's going look like in 2016 yet Neal, we'll come out with that with 2016 guidance, but we're at 50% for the quarter and 40% for the full-year 2015.

Okay and then just one last one. Just again when you look at kind of the Miss versus the Chester and Woodford, you know, you've had success on all percentage or just big picture how do you see focusing on the three?

Yes. Steve mentioned it in his prepared remarks. He give you some IP rates for the Chester, you know, Chester is a little more oily. We're going to move the one rig that was drilling Miss to Chester so now we'll have two rigs drilling Chester for the remainder of the year. So that program is getting more focused. It's a stacked play, so we think there's more than one bench there, it's less, a little less infrastructure spend, so we like that. The Woodford we did not have -- we only had one well that was bouncing between Woodford and Chester. We did not have a Woodford well spud in the second quarter, but look for more Woodford towards the end of this year. So going forward it will be a balance, but I think you see a little more, little bit more non-Miss, non-pure Miss activity.

Great, thanks guys.

You're welcome.

Adam Leight, RBC Capital Markets.

Good morning Adam.

Good morning, everybody. Couple of quick questions here. On the multilateral development, what if any constraints are there in terms of how many you think you can do relative to your total position and relative to existing infrastructure?

Like I said Adam, for 2015 is going to be 40% of the plan. Some of it depends on your land position, you know drill two mile laterals, you need to have two stacks 640 sections, to drill a full section development you need to have a full section. So if you've drilled one well in the section, and by section I mean you square mile in Oklahoma, you won't go in to do a full section you'll just do a co-planer or two.

So there's no reason you can't to this across the play and everywhere, it's just sometimes it's limited by land or limited if you have one well in a section. I will say if you step out into new area or step out several miles, you might choose to drill a single lateral to test or a couple of single laterals to test the areas as opposed to spending $6 million to $8 million on a full section development. There's no reason this can't be applied across our play.

Yes. I guess the first part a question was, given the least geometry, are there any significant constraints and how many of these you can fit? And then secondly, with the current costs, I presume that implies no additional saltwater disposal wells or other infrastructure. How much of this development can you do the next year or two without adding to the infrastructure?

Adam we'll come out with that in our 2016 guidance. I think it will be a material part of the program, whether material is a third or half, we're not really ready say that over a multi-year period, but as you can see 50% of the quarter, 40% of the year. We like it, it is performing very well and gets a very good return versus drilling a single lateral.

And segueing to that question, I guess we haven't seen a return estimate given the reduction in the strip, particularly on the oil side and your lower well costs and operating costs adjustments. What do you think that today's curve, your IRRs look like?

We do have those, Adam. So at the July 27 strip, which is just when we locked it down, it keeps moving every day, so a little bit of a moving target, at the $2.4 million well cost that we had in the second quarter, $2.4 million D&C, that's a 33% rate of return. I guess that $2.4 million D&C, at $2.3 million which is the plan for the back half of the year, that's a 37% rate of return. And if I burden it with infrastructure costs and we laid out the math earlier this year on how the infrastructure cost across the portfolio is about $220,000 per well. So add that into that $2.3 million Adam, and that takes your IRR to 30%. So again that July 27 strip, $2.3 million D&C plus $220,000 of infrastructure at that strip is a 30% rate of return. So still, I think is very competitive across most onshore E&P plays.

That's great, thanks. And you've tons of available capacity at the moment and you alluded to, that you're looking to various alternatives but in terms of a fall redetermination, any initial thoughts on what kind of impact you might be looking at?

Yes. Our year-end 2014 reserves, we laid out some math at the early May call on what the PDP and how the coverage works, so let me roll through that. The year-end reserves at the bank sensitivity strip, which was I would say, again this is our March redetermination, $35.15, $43 and then inching up to $50 and $52 by 2020. So that's a deck that's more than $10 below the strip, so again the bank sensitivity deck in March, our PDP only is $1.2 billion.

That gives no credit for the hedges, that's the PB9 of that and no credit for reserve as between now and a fall redetermination. So a simple way of saying that I believe that at a conservative stress case price deck, that $1.2 billion of PDP PD9, more than covers our $500 million borrowing base and I don't see a lot of risk to the borrowing base in the fall redetermination. Keep in mind with $1 billion of cash, we won't be anywhere near into the borrowing base, but again I see very little risk to that number coming down.

That is great. Lastly any additional update on potential assets?

No update now Adam with our with the second lien financing. I think the urgency to sell assets in a pretty choppy, volatile market has lessened. We still do want to execute some asset sales but don't have to get that done right now in a tough market and don't need to do anything at firesale prices. So no update, no.

That's great, thanks.

You're welcome.

Tarek Hamid, JPMorgan.

Good morning.

Good morning.

Taking a look at some of the lower well costs as well as some of the multi-drilling, you know really question on just maintenance CapEx, sort of maintain production in 2016, how much do you think that comes down from the 2015 run rate, any sort of initial thoughts on what it would take to hold the production base flat going forward?

Yes, we have done some analysis around that. People define maintenance CapEx a lot of different ways. What we've done and we ran through some similar math earlier this year. But if you pick our average rate for 2014 which is about 76,000 Boe per day, so not picking today's rate or the second quarter rate, but to keep production flat at 76,000 Boe per day, would require about $375 million of D&C spending; and that's down from the $400 million we quoted earlier this year, predominately because of our well cost savings.

On that $375 million I assume about a 30% multilateral and about an average of $2.4 million well costs. So for D&C, $375 million to keep production flat at that rate. I think you would have a minimal amount if you are in a very tough market, like today, you'd have a minimal amount of infrastructure and very minimal amount of land on top of that. So that should give you an idea of how we think about maintenance CapEx again at the average rate for 2014.

That was really helpful. Thank you. And then, touch on a little bit, but with saltwater gathering system kind of any update on the process there, how are you thinking about that particular asset now? Do you think a spinout or IPO is more likely at this point or an outright sale?

You know, we think that is a valuable midstream gathering asset, it's gathering water instead of hydrocarbons but we've got a big footprint and a lot of capacity in that system. We did receive a positive PLR from the IRS which we had been waiting for about a year for. But given that's in registration with the IRS I can't really comment on the specifics of any IPO or any timing around that.

Fair enough. Last one for me you know, you touched on sort of ultimately reducing debt in your opening comments, without asking you about source specifics, how do you think about the sort of proper debt capacity for this business and for this acid base going forward?

Sure we've been specific about saying we need to reduce debt. I have my eyes on $1 billion of debt reduction for now, we will see after that what the market looks like and what plays out. But you know, I think we need to take at a minimum $1 billion of debt off the balance sheet.

Got it, thank you very much.

You're welcome.

Sean Sneeden, Oppenheimer.

Thank you for taking the questions.

Morning, Sean.

Just on the Mid-Con, it looks like just kind of based on the guidance provided that volumes are going to drop off somewhat sharply in the second half of the year. And so it looks like a Q4 to Q4 decline would be roughly around 20%, if I'm doing my math right, is that kind of consistent with what you guys are thinking about?

Yes, that is consistent. What we said that Q4 2014 to Q4 2015 it for the entire company is a mid-teens decline, but we've also said that our corporate decline rate if we were stop drilling is about, with a little bit of rounding, 35%, 25%, 15% in years 1, 2 and 3. The decline on the Mid-Continent is a little bit steeper than that. I would say 40% the first year. So yes, the exit, exit decline in the Mid-Con be about in that 20% range and the whole company would be in the mid-teens. Your math is right.

Great. That's very helpful. You know, I guess one of the things I think some folks have been wondering, perhaps as a follow-up to Tarek's question there, but I think you briefly talked about up to $1 billion of value to the midstream system, can you just kind of given what looks could be flattish (inaudible) in the Mid-Cons? How does that change the value proposition of a potential equity investor, at least in your mind?

You know I can't comment on anything around the midstream as it relates to an MLP or and IPO, I have to point people towards the prospectus for that. I will say that growth rates across the entire midstream industry, particularly gathering and processing guys, have come down across the board, so I think where people maybe were targeting a low-teens growth rate right now are going to settle for a low single-digit, across the board, given the commodity and E&P landscape and rig count. But I can't comment specifically on the assets that we have in the S-1.

Okay, that's helpful. And then maybe just kind of one last housekeeping question, there here seems to be a little bit of confusion in the market about how much secured debt capacity you guys have. Is it your understanding that you're basically limited to a total of $950 million first lien and, call it $250 million additional second lien, or what you think that total number is?

Yes, I don't want to get into the details of the indentures, but yes, if you look at the first lien debt capacity, that would be about $950 million, again we have a $500 million lower (inaudible), and then second lien, and I believe we're allowed to incur another $250 million. So I think your numbers are correct on both of those.

Great. I really appreciate it, thank you.

You're welcome.

Owen Douglas, Baird.

Hi guys. It looks like a good quarter there. I had a few questions with regards to how I should think about Q3 and going forward. You guys dropped down from 13 rigs down to 6 rigs, give a sense now for the number of laterals you expect to turn sales in Q3?

Yes. This is Steve Turk. In Q3 we should, we should put 39, 40 laterals to sales.

Got you. That makes a lot of sense. How do you think about that 6 rig program on a go-forward basis, is that really the right rate I should be thinking about it in terms of sales, about 39, 40 laterals?

We having come out with the 2016 guidance yet so if you're asking what is going to be in 2016, we'll come out with that later. But, Steve, I think on a six rig program is that about the right quarterly pace if we were to keep that level?

Yes, roughly in that neighborhood.

Okay sounds good, and as far as working capital, do you foresee any swings as a result of switching down from that 13 rig program?

I believe we've already seen the swings in the working capital. If you look year to date we've had right around $100 million of working capital use, as you go from 32 rigs down to 6. But I believe the impact of working capital change we've already seen in the business year to date.

Got you, and that should be fairly muted on a go-forward basis to reflect that move down from 13 to 6?

Yes.

Okay, and finally for me, so you talked about there being a depressed price environment for assets. Given that you guys have $900 million of cash on the balance sheet and it sounds like quite a few levers for liquidity, have you guys been looking around for opportunities? And if so, how should I think about your, I guess priorities? Is it about trying to find adjacent acreage or is it really just about what the best available assets are, wherever they may be in the country?

Well, we do have a Mid-Continent focus, but I can't comment on specific deals. We take a look at of a lot of things that are for sale, particularly if they're in our neighborhood or in the Mid-Continent, but we're making capital allocation decisions, you know, across the board whether that's development, drilling, appraisals, new ventures, CEBA Midstream, deleveraging transitions, or acquisitions. We weigh all those on the risk-adjusted return and liquidity basis, but you can't comment on specifics on deals on where we're looking at, or what size.

Okay, thanks. I'll hop back in the queue.

Thank you.

Jeff Robertson, Barclays.

Thanks. Can you talk a little bit about the performance history of the Chester and the wells you have on in terms of the decline, and water cut? And then secondly, are there any issues with the rate you can dispose of water in Oklahoma, just given some of the concerns around earthquake stuff?

I'll take the latter part of that and let Steve comment on the Chester. We have no material volume restrictions under our disposal wells. There was recently some wells curtailed, several wells curtailed in Logan County, we don't have any operations in Logan County. We have no material curtailment on our disposal capacity.

On the Chester, the Chester is a different play, certainly than the Mississippian; it's water cuts are much lower, it's in oilier play, and obviously because of the lower water cuts it requires less water infrastructure at less cost. And we are drilling along an area in southern Alfalfa County into Woods County, but the bulk of our experience was early on was in northern Woods County. And now we're expanding that play along about 100 mile horizon to capture the value in the five benches, so that it provides for development.

Is your Chester drilling dovetailing with where you have existing infrastructure?

To some degree it does. But both for electric and water hauling, but it moves further south of that.

And I know you don't have 2016 outlooks, but are you, can you comment at all about how much of the 2016 program that Chester might represent versus the Miss Lime?

I don't think we are prepared to be specific on the amount of Chester that we'll do next year. It's going to depend on a number of factors and certainly on the second half Chester drilling program. However, I will say it probably will be somewhat increased percentage over what we've done this year.

And lastly, what's the cost of a Chester well and do you try any of the multilateral well construction designs in that formation like you do in the Miss Lime?

Good question. First of all, the costs are just below $3 million now. We've had in our more recent wells the cost structure for those are improving. And then as far as multilateral technology, we already have a multi-plan for the latter half of this year in the Chester. The multilateral technology is not specific to Mississippian, it certainly can be applied in other plays and frankly we are very early in the learning curve, obviously, but I think it's going to be extremely beneficial going forward, not only in the Miss but in the Chester and other plays that we get involved with.

Thank you.

Thank you.

Greg Brody, Bank of America.

Good morning, Greg.

Good morning guys. James, you mentioned the $1 billion debt reduction target which you had clearly articulated last quarter. I'm just curious, when you think about that number is it an additional $1 billion plus of debt, do you think about, is that part of the number too? Or would it effectively be a $2 billion deduction or in your mind your basically pre-funding additional spending that you're expecting. I'm just trying to get a sense of that sort of the $1 billion language you gave last quarter and the one you just said today.

Yes, very fair question. We did add $1.25 billion of debt but we also $1.25 billion of cash to the balance sheet, so I'm probably talking on a net basis. The ultimate answer to that longer-term, how much debt should be off the business or what the leverage level should be is going to depend on what commodity price environment we're in. If we're in a $45 price environment that's going to give you different answer than at a $60 or higher price environment. But for right now, I've got my eye on of $1 billion and after that we'll evaluate, but again that $1 billion we just added we also added $1 billion of cash to balance sheet too.

I appreciate that. And I also appreciate the decisions you have to make in a difficult commodity price environment. So if we play this through, let's say we get to, you know, a couple of years, year plus from now you reduce $1 billion of debt net. How do you think about your budget as to grow from here? As you pointed to there being relatively good returns at strip for your assets, but once you get to that state and let's say we some, a reasonable [revalue prove], you know it's $50 or $65. What's the decision you make, do you grow the asset base or do you still continue to focus on deleveraging.

Looking at this a couple of ways. The execution of the asset continues to improve every quarter. The teams are driving down well costs, 180 day IPs are going up, LOE is going down, infrastructure spend is going down, so if you look forward, we are going to continue to improve those every year.

Look where we were two years ago versus where we are now; I think will be in a lot different place operationally and execution-wise, what Steve and John and the teams are doing in two years from now. So I think we'll get even better returns on the assets then. But at that time we will have to weigh the alternatives. If we're at a $60 higher price environment in two years from now, we will have to make those decisions.

We don't need to grow for growth sake, we need to ensure the long term stability of the balance sheet at some point, and we need to protect the enterprise and protect our liquidity, so we will balance all of those. But to say exactly what we'll do in two years from now, I think it's going to depend on a lot of circumstances on what the market looks like. But look for us to continue to improve operationally. That's what's going to make the business work. We can make some balance sheet moves and protect our liquidity, but driving down the well costs, drilling better wells, finding new areas, deploying a multilateral technology, appraisal new venture success, those are the things that will really make us successful.

As you weigh the asset sales it sounds like it's not the best time to sell, which makes a lot of sense. But when you weigh that versus proceeds from assets sales fees to reduce debt is there, how do you think about that? I should appreciate it is difficult.

Yes. What gives me some comfort and why I don't have to rush to a firesale asset sale now is because we have time. We put in place one of the most flexible covenant packages of our peers or the industry and with the $1 billion of cash, no bond maturities until 2020 and that flexible covenant package, I have some time. And yes, selling some assets now I can reduce some debt, but in this volatile market with a $45 front month WTI, not the best time to sell some assets, so I'm going to be a little patient there because I can.

Right, and just two quick ones just to follow up. The returns you gave, when you give those returns for the Miss, do you have assumptions about work overs in there in year two, or is that ex those numbers?

That would be ex those numbers, so you would have, you know, small amount of work over expense on top of that. One thing I mentioned, go ahead.

No, I cut you off. Sorry.

One thing I mentioned in the prepared remarks, we are very focused on full lifecycle returns. So when we propose wells and AFE wells, we do look at infrastructural requirements, artificial lift requirements, and future work over needs. But that number I mentioned is just the upfront D&C, that $2.3 million and then another couple hundred thousand of infrastructure on average.

As you quantify it, what's the average work over for Miss wells?

We have not. I have not. We have not quantified that.

One thing, excuse me, this is Steve Turk. One thing you are to be careful about too, is that we have looked at specific areas within the Miss where we are applying a lot less costly gas lift. The other benefit of gas lift is that you don't go through pump changes at any kind of regular basis, so it eliminates costly work overs in year two, year three.

And then when do you expect 10-Q to be out?

End of the day today. After the market today.

Thank you guys, I appreciate the time.

Thanks for your questions.

Paul Bloom, RBC Wealth Management.

Good morning guys. My question has to do with, you mentioned that you increased your liquidity by about $1.4 billion and that should buy you quite a runway going forward. I'm also reading a report that's saying that the company's outspending cash flow, because of the current price of oil and whatnot, can you comment on that please?

Yes, we do have a $1.5 billion of liquidity at the end of the quarter and at this commodity price environment, yes, we are outspending cash flow. We don't have multiyear guidance to say what that's going to be every year, but we are outspending cash flow this year in the neighborhood of $500 million

Right and when we refer to a long runway, can you kind of expand on that?

I can't give an exact day or specific time, it's going to depend on commodity prices, what kind of asset sales we do between now and then, and what our level of capital spend is. The most obvious lever for us to turn would be to dialback our CapEx program, if we need to even further, you know, we took it down about 60% this year to $700 million. If it was a very tough environment, we need to dial it back further, but we could do that. We make those decisions every week and every 90 days on what should the capital program be going forward and we adjust based on our returns and market conditions.

So you have other alternatives that you may look at, but that's going to depend on prices of commodities and market conditions and so forth, is that correct?

Yes Sir, yes.

Okay thank you.

Gary Stromberg, Barclays.

Hello, good morning.

Good morning, Gary.

Most of my questions were asked and answered, just a couple more. I know the Oklahoma Corporation commission announced new rules Monday, requiring operators and I think two counties to reduce the amount of saltwater they inject. I think it's 38% over the next 60 days. I just wanted to confirm those aren't counties that you're in and there's no risk to limiting injection in counties that you operate in?

Yes Gary, the lion's share of the curtailments were in Logan County, I think there were some in Oklahoma County as well. The lion's share were in Logan County, we have no operations in Logan County so we were not impacted by that.

Okay. And then just a couple of -- I appreciate the updated IRR numbers at current strip prices. Do have the PV-10 for the entire company at July 27 strip?

We don't, Gary, given that PV-10 was at year end 2014, I think eight months into the year, probably won't keep updating if for every strip. We gave out a strip number in May and then you've got end of the year, but look for us to update our reserves at the end of 2015.

Okay. And then final one for me on cost, you know first half LOE was $10.71 to barrel, guidance for the year is $11.50 to $12.50, so at the midpoint it implies think around 12% increase in costs in the second half. Is that just a function of production falling or is that conservativism, or both?

It's -- could you state your question again please?

I guess I'm just thinking about full-year LOE guidance which at the midpoint is $12 a barrel, first half was $10.71 a barrel, so it implies a pretty large uptick in the second half of the year. I just wanted to think about why such a sharp increase.

It has to do with the fluctuation in production, you are correct.

You've got your fixed-price component of LOE and as your production declines a bit back half of the year, that fixed component becomes a bigger on a per Boe basis.

Some of our most -- we're not doing anything in Permian and the Permian does impact our lifting cost materially, so with the decline that we have there, that impacts that number.

Okay great, that's all I have.

Thank you.

David Silverstein, Kildonan.

Hi guys. If you could just go through the first lien [basket] again. You mentioned $950 million and I remember when you marketed the second lien deal you had suggested that $950 million was the capacity. However, it also suggests that the amount of first lien capacity or prior to lien debt is the greater of $950 million, 30% raise [ATT] or the borrowing base? Borrowing base Is set at 65% of the ACNTA. So the greater of the three would actually be the third option of the borrowing base. As just wondering if you agree with that interpretation or not?

I'm not sure, I'm not really in a position to get into the weeds on the indentures on this call. If we had a follow-up off-line or something, but we're not prepared to get into the details of the indentures on this call.

Thank you. And then just as a follow-up on the disposal system, does this have at all, an impact in your view on the ability to spin or MLP the saltwater disposal system with the incidence of earthquakes going up in Oklahoma? And also some of the new restrictions that are being placed in different areas where there's a higher level of seismic activity?

Our system is pretty diverse and broad across Oklahoma, Kansas, and even the Texas Panhandle. So I think it's a big enough and diverse enough system that it can withstand any of those curtailments in the individual areas. Again, we haven't been impacted to date.

Great, thank you.

Jim Stahl, Pine River.

Can you hear me?

Yes.

Great, just one question, given your substantial liquidity do you have any intent to buyback bonds on the open market? I think your ability to do so, you know, is limited in the second lien indenture to about $250 million, depending on your pro-forma liquidity which, you know, is a much lower number. Are you going to try to take advantage of some of these lower bond prices?

Yes, I can't comment on any specific transactions that we're going to do or perspective deals.

Okay. Did you buy any back in the second quarter?

If we buy any back we would have to disclose that.

Okay. All right, great. Thanks.

Thank you

(Operator Instructions)

Owen Douglas, Baird.

Hi, just wanted to follow up a little bit to inquire about the non-E&P parts of the business here. So, at the moment are there any rigs from the drilling and oil field services business that are currently being utilized?

Yes. We have some of our rigs are drilling for us, Steve just gave a number four, four Lariat rigs are drilling for us.

Okay, but there no third-party customers?

No, not at this time.

Okay, understood. And as far as thinking about the cash G&A number, it looks like it's a tick down, I guess about $1 million from the first quarter level, in line with that $100 million number, which I believe, is provided on the prior quarter for the year. How should I think about that, is there any more room to improve upon that $100 million cash G&A number?

We're always looking to improve all of the cost G&A, LOE, CapEx, I think our total G&A of about $375 million for BOE is right in line with peers. Depend on our activity level, commodity prices, how many rigs we're running, and how robust of a program we have. But for now I think that $100 million is a good estimate.

Okay and as far as thinking about that drilling and oil field services business, the Lariat business, is there a view to whether or not it makes sense to continue to, I guess run that as a third-party operator, with the infrastructure that that operation would require?

Sure, very fair question. We've scaled back that business quite a bit year to date. Earlier this year we closed our West Texas operation for Lariat, we've sold several rigs for Lariat, so we have shrunk that business quite a bit from where it was start of the year. We will continue to look at that, if there's a point where Lariat can pick up some third-party business, if not we will continue to look at right sizing it or what's the right size, number of rigs, and scope of that business.

Okay and how about the midstream services business. Can you speak to its strategic importance or its value contribution to the company on a go forward basis?

Yes, midstream services, I think that would be really our CEBA saltwater gathering business. We have some small gathering lines that are hydrocarbon-based but the majority of that business is going to be our water gathering business; so that there's not another midstream component of the business.

Okay, and just to make sure I got this all straight my head, the electricity distribution business, where does that fit?

That is in the midstream business, yes. That is in midstream.

Okay, and does that have third-party customers or is that entirely SandRidge?

Other than our working interest owners and other owners in the well, there are no third-party customers in that.

Okay, I see, thank you very much guys.

Yes, you're welcome.

We have no further questions at this time, I'll turn the call back over to our presenters.

Thank you, this is James. We're wrapping up. The teams did an excellent job this quarter and I keep saying executing our oil and gas business, that's what we have to do first. We are an E&P business.

The teams are driving down well costs, they're perfecting the multilaterals, they're drilling long laterals, our appraisal new venture program is working. LOE costs are down. Our field up-time is up, we're optimizing our artificial lift, we are doing all the right things in the field. We've got $1.5 billion of liquidity, so we have time to keep driving these improvements through the business and our capital allocation process has taken a much more prominence in the business.

Looking across the board, where is the best return with keeping liquidity and leverage in mind. So I think a very good quarter, look for us to continue to execute going forward and do what we need to do. Thank you everyone for your time.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.