Duane M. Grubert - Executive VP-Investor Relations & Strategy James D. Bennett - President, Chief Executive Officer & Director Steve Turk - Chief Operating Officer & Executive Vice President.

Neal D. Dingmann - SunTrust Robinson Humphrey Adam Leight - RBC Capital Markets LLC Tarek Hamid - JPMorgan Securities LLC Sean Sneeden - Oppenheimer & Co. Owen Douglas - Robert W. Baird & Co. Jeffrey Woolf Robertson - Barclays Capital, Inc. Gregg Brody - Bank of America Merrill Lynch Gary W. Stromberg - Barclays Capital, Inc.

David Silverstein - Kildonan Castle Asset Management LP Jim Stahl - Pine River Capital Management.

Good morning. My name is Chris, and I'll be your conference operator today. Thank you for standing by, and welcome to SandRidge Energy's Second Quarter 2015 Conference Call. 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 of 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 a 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 a smooth transition with no gaps in the role. We posted an excellent quarter operationally. Let me highlight some of the points that are summarized on slide three 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 mid-point of guidance 500,000 barrels of oil equivalent, increasing the full-year mid-point from 29.3 million barrels of oil equivalent to 29.8 million while leaving our CapEx unchanged at $700 million.

An increase of visibility of our primary asset, the Mid-Continent, we've introduced standalone Mid-Continent production and 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 the 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, assuring us years of liquidity even in a low oil price environment.

As illustrated on slide four, 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 are being pursued and evaluated every day.

In terms of capital case allocation and how we weigh the various alternatives, I will say that the way we invest our capital over the next several quarters and years will determine our level of success.

We have a 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 seed the midstream investment and balance sheet deleveraging transactions. These all exist with a 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 base, particularly the oilier Chester where we expect to have increased focus going forward.

Slide five 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 selection and zone targeting, more customized completion methods, use of 3D seismic and better overall understanding of the play. But it's important to note that we're not chasing rates and IP at the expense of value.

For example, in some areas we are downsizing our artificial lift method and surface facilities to save capital, even if that means slightly lower IP rates. We're looking at the full-cycle value of the project, not just chasing early-life production.

On well costs, highlighted on slide seven, in February we put out a goal of getting our per-lateral well cost to $2.4 million for the back half of 2015. Due to the great efforts of our team, we achieved that goal a 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 nine, now with 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 also see along with 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 in 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 uptime, 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-year 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 88,900 barrels of oil equivalent a day, up 1% from the prior quarter. The Mid-Con region averaged 79,300 barrels of oil equivalent a day, up 2% from the prior quarter.

As depicted on slide five, the quality of our Mississippian drilling program continually improves year-over-year. Quarter two Mississippian laterals that went to sales produced an average 30-day IP of 390 barrels of oil equivalent per day, or 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 and 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 reduced cost.

We expect further reductions as we employ a new operation 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 times, shown on slide six, provide an unprecedented per-lateral cost of $2.4 million, therefore realizing our second half 2015 target. As shown on slide seven, 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 a 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 six rigs exiting quarter two. During the quarter, we spud 37 laterals, 54% using our multilateral design. As depicted in slide eight, our multilateral program delivered 99% of the 90-day type curve production, 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 geoscience 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 are 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 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. Your first question is from Neal Dingmann with SunTrust. Your line is open..

Good morning, guys..

Good morning, Neal..

Hey. Just a question as far as the drilling focus going forward, a couple of 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 multilateral, and when we say that we mean full-section development, dual co-planars 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 again 50% for the quarter and 40% for the full year of 2015..

Okay. And then, Jim, just one last one. Just again when you look at kind of the Miss versus the Chester and Woodford, you've had success on all.

What percentage or just big picture how do you see focusing on the three?.

Yes, Steve mentioned in his prepared remarks. He gave you some IP rates for the Chester. Chester is a little more oily. We're going to move the one rig that was drilling Miss to Chester, so and now we'll have two rigs drilling Chester for the remainder of the year. So that program is getting more focused.

It's a stack play, so we think there is more than one bench there. It's a little less infrastructure spend, so we like that. The Woodford, 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 there will be a balance. But I think you'll see a little bit more non-pure Miss activity..

Great. Thanks, guys..

You're welcome..

Your next question is from Adam Leight with RBC Capital. Your line is open..

Good morning, Adam..

Good morning, everybody. Just a couple of quick questions here.

Just 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 it's going to be 40% of the plan. Some of it depends on your land position, 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 a square mile in Oklahoma – you won't go in to do a full section, you'll just do a coplanar or two.

So there's no reason you can't do 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 let's say step out into a 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 area as opposed to spending $6 million, $8 million on a full-section development. So there's no reason this can't be applied across our play..

So, yeah, I guess the first part of that question was, given the lease geometry, are there any significant constraints in 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?.

Yeah. I think, 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, I'm not really ready to say that over a multi-year period. But as you can see, 50% of the quarter, 40% of the year. We like it.

It's 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 potential operating cost adjustments.

What do you think, at today's curve, your IRRs look like?.

Sure. 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.

Again, 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 7/27 strip, $2.3 million D&C plus $220,000 of infrastructure, at that strip is a 30% rate of return. So I think still very competitive across most onshore E&P plays..

That's great, thanks. And you've got plenty 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 an impact you might be looking at?.

Yes, Adam. 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 in 2015, $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 a PV9, 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 PV9 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.

And lastly, any additional update on potential asset sales monetizations?.

No update now, Adam. 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 fire sale prices. So no update, no..

That's great. Thanks..

You're welcome..

Your next question is from Tarek Hamid with JP Morgan. Your line is open..

Good morning..

Good morning..

Just taking a look at some of the lower well costs, as well as some of on the success you've had on the multi-pad drilling, just really a question on just maintenance CapEx, sort of maintaining production in 2016.

How much do you think that comes down from kind of 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 I am 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 cost. 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 Adam touched on this a little bit, but with the saltwater gathering system kind of any update on the process there, how are you thinking about that particular asset now? Do you think a spin-out 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 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. Just last one for me, you know, you touched on sort of ultimately reducing debt in your opening comments.

Without asking you about sort of specifics, how do you think about the sort of proper debt capacity for this business and for this asset 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 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..

Your next question is from Sean Sneeden with Oppenheimer. Your line is open..

Hi. Thank you for taking the questions..

Morning, Sean..

Maybe just to start off on the Mid-Con, it looks like just kind of based on the guidance you provided that volumes are going to drop off somewhat sharply in the second half of the year. And so it looks like kind of 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. We said that Q4 2014 to Q4 2015 for the entire company is a mid-teens decline. We've also said that our corporate decline rate if we were to stop drilling is about, with a little bit of rounding, 35%, 25%, 15% in years one, two and three. The decline on the Mid-Continent is a little bit steeper than that.

I would say 40% the first year. So, yes, the exit decline in the Mid-Con would be about in that 20% range and the whole company would be in the mid-teens. Your math is right..

Okay, great. That's very helpful. 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 previously talked about up to $1 billion of value for the midstream system.

And just kind of given what looks like could be flattish volumes out of the Mid-Con, how does that change the value proposition of a potential equity investor, at least in your mind?.

I can't comment on anything around the CEBA Midstream as it relates to an MLP or an 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 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 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 call it a total of $950 million of first lien and call it $250 million of additional second lien, or what do 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 loan (26:52) now. And second lien, 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, guys..

You're welcome..

Your next question is from Owen Douglas with Baird. Your line is open..

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.

As you guys talk drop down from 13 rigs down to six rigs, do you have a sense now for the number of laterals you expect to turn to sales in Q3?.

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

Got you. That makes a lot of sense.

And how do you think about that six-rig program on a go-forward basis? Is that really the right rate I should be thinking about it, turn to sales about 39 laterals, 40 laterals?.

We haven't come out with 2016 guidance yet, so if you're asking what it's 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?.

Yeah. Roughly in that neighborhood, definitely..

Okay. Sounds good.

And as far as the 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 used as you go from 32 rigs down to six rigs. 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 rigs to six rigs?.

Yes..

Okay. And finally from 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 sort of priorities? Is it about sort of 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 a lot of things that are for sale, particularly if they are 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 transactions or acquisitions. We weigh all those on a risk-adjusted return and liquidity basis, but 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..

Your next question is from Jeff Robertson with Barclays. Your line is open..

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 the 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 the earthquake stuff?.

I will 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 several wells curtailed in Logan County; we don't have any operations in Logan County. But we have no material curtailment on our disposal capacity..

On the Chester, the Chester is a different play certainly than the Mississippian. Its water cuts are much lower. It's an 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 early on was in northern Woods County. And now we're expanding that play along about a 100-mile horizon to capture the value in the five benches it provides for development..

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

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

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

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 line?.

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 planned for the latter half of this year in the Chester. The multilateral technology is not specific to the 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..

Your next question is from Gregg Brody with Bank of America. Your line is open..

Good morning, Gregg..

Good morning, guys. Had to switch off mute. 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, since you issued an additional $1 billion-plus of debt, do you think about – is that part of the number, too? Would it effectively be a $2 billion reduction, or was it in your mind you're basically pre-funding additional spending that you were expecting? I'm just trying to get a sense of sort of the $1 billion line which you gave last quarter and the one you just said today..

Yes, very fair question. We did add $1 billion in the quarter of debt, but we also added $1 billion in the quarter 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 at a $45 price environment, that's going to give you a different answer than at a $60 or higher price environment.

But for right now, I've got my eye on $1 billion. After that we'll evaluate, but again, that $1 billion we just added we also added $1 billion of cash to the balance sheet, too..

to grow the asset base, or do you still continue to focus on deleveraging?.

As we said, a couple of ways. So the execution of the asset continues to improve every quarter. The teams are driving down well costs, 180-day IPs are going up, LOEs going down, infrastructure spends going down. So if you look forward, we're going to continue to improve those every year.

Look where we were two years ago versus where we are now, I think we'll 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'll have to weigh the alternatives.

If we're at a $60 or higher price environment in two years from now, we'll have to make those decisions. We don't need to grow for growth's 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 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 the 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 asset sales could be used to reduce debt, how do you think about that, which I can appreciate is difficult?.

Yes. What gives me some comfort and why I don't have to rush to a fire sale, asset sale now is because we have time. I think we put in place one of the most flexible covenant packages of our peers or the industry. And with the billion dollars of cash, no bond maturities to 2020 and that flexible covenant package, I have some time.

And yes, selling some assets now I could 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 then 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 workovers in there in year two or is that ex those numbers?.

That would be ex those numbers, so you would have small amount of workover expense on top of that. One thing I mentioned in the – go ahead..

No, I cut you off. I'm 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 workover needs.

But that number I mentioned is just the upfront D&C, that $2.3 million, and then another couple of hundred thousand of infrastructure on average..

Have you quantified what's the average workover for Miss wells?.

We have not. I have not. No, we've not quantified that..

And my last question, when do you have to file your 10-Q?.

One thing – excuse me, this is Steve Turk. One thing we want 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 workovers in year two, year three..

Great.

And then when should we expect your 10-Q to be out?.

End of the day today. After the market today..

Thank you, guys. I appreciate the time..

Yes. Thanks for your questions..

Thank you..

Your next question is from Paul Bloom with RBC Wealth Management (40:44). Your line is open..

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 is outspending cash flow because of the current price of oil and whatnot.

Can you comment on that, please?.

Yes, we do have $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 you 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 dial back our CapEx program if we need to even further. We took it down about 60% this year to $700 million.

If it was a very tough environment and we needed to dial it back further we could do that, but 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..

Got you.

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, sir..

Your next question is from Gary Stromberg with Barclays. Your line is open..

Hi, 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 in I think two counties to reduce the amount of saltwater they inject. I think it's 38% over the next 60 days.

Just wanted to confirm those aren't counties that you're in and there is 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 on IRs, I appreciate the updated IR numbers at current strip prices.

Do have updated PV-10 for the entire company at July 27 strip?.

We don't, Gary, given that PV-10 was a year-end 2014. I think eight months into the year you probably won't keep updating it 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 costs. First-half LOE was $10.71 a barrel; guidance for the year is $11.50 to $12.50. So at the midpoint it implies I 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..

Yes. You've got a fixed-price component of LOE and as your production declines a bit the 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 the Permian and the Permian does impact our lifting costs materially, so with the decline that we have there that impacts that number..

Okay. Great. That's all I have. Thank you..

Thank you..

Your next question is from David Silverstein with Kildonan. Your line is open..

Hey, 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 suggested that the amount of first lien capacity or prior lien debt is the greater of $950 million 30% raise (46:10) or the borrowing base. Borrowing base you said is at 65% of ACNTA. So the greater of the three would actually be the third option of the borrowing base.

And I was just wondering if you agree with that interpretation or not..

Yeah, I'm not really in a position to get into the weeds on the indentures on this call. If we need to follow-up offline or something, but not really prepared to get into the details of the indentures on this call..

Understood. Thank you.

And 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 to 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 individual areas..

Great..

Again, we haven't been impacted to date..

Great. Thank you..

You're welcome..

Your next question is from Jim Stahl with Pine River. Your line is open..

Yes, hi.

Can you hear me?.

Yes..

Great. Yeah, just one question, given your substantial liquidity do you have any intent to buy back bonds in the open market? I think your ability to do so is limited in the second lien indenture to about $250 million depending on your pro forma liquidity, which is a much lower number.

So are you going to try to take advantage of some of these lower bond prices?.

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

Okay.

Did you buy any back in the second quarter?.

If we bought any back we would have to disclose that. And you'd see it in the disclosure..

All right, great. Okay. Thanks..

Thank you..

And your next question is from Owen Douglas with Baird. Your line is open..

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 the oilfield services business that are currently being utilized?.

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

Okay.

But there are 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 was provided in 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 per Boe is right in line with peers. It's going to depend on our activity level, commodity prices, how many rigs we're running, 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 sold several rigs for Lariat. So we have shrunk that business quite a bit from where it was start of the year.

So we'll continue to look at that if there's a point where Lariat can pick up some third-party business. If not, we'll continue to look at right-sizing it and 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?.

Yeah. Midstream services, I think you just alluded, 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. I see.

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

That is in the midstream business. Yes. That is in midstream..

Okay, I see.

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. Well, thank you very much, guys..

Yeah. 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. 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. So 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 is taking on much more prominence in the business, looking across the board where is the best return, 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..