Duane Grubert – EVP of IR and Strategy James Bennett – President & CEO David Lawler – COO Eddie Leblanc – EVP & CFO.

Charles Meade – Johnson Rice & Company Lee Cooperman – Omega Advisors Richard Close – Capitol One Jamaal Dardar – GPH & Company Amy Stepnowski – Hartford Shawn Needham – Oppenheimer & Co. James Spicer – Wells Fargo Securities.

Good day, ladies and gentlemen, and welcome to the second-quarter 2014 SandRidge Energy earnings conference call. My name is Tawanda and I will be your coordinator for today. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Mr.

Duane Grubert, EVP of Investor Relations and Strategy. Please proceed sir..

Thank you operator. Welcome, everyone and thank you for joining us on our conference call. This is Duane Grubert, Executive Vice President of Investor Relations and Strategy here at SandRidge.

With me today are James Bennett, President and Chief Executive Officer; Eddie Leblanc, EVP and Chief Financial Officer; and David Lawler, Executive Vice President and Chief Operating 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.

Keep in mind that today's call contains forward-looking statements and assumptions which are subject to risk and uncertainties, 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 these measures can be found on our website. Please note that 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 Duane. I'm very pleased with the progress we're making on our mid-continent focus business particularly in the areas of our drilling program, cost reductions, new zones, and innovations.

I want to spend some time on this call clearly walking you through some of the production challenges we faced in the field this quarter, and how that impacts our full year, how we're remedying these challenges, highlight some of the very encouraging results we have seen from our mid-continent development program, and reiterate the reasons why I still have confidence in our 3-year plan to grow production in the 20% to 25% compound annual growth with a CapEx spend of approximately $1.5 billion per year and quickly close our cash flow to CapEx delta.

For the quarter, the Mid-Continent production was up 11% from the first-quarter at 19% from the same quarter in 2013.

Total company grew 8% quarter over quarter pro forma for recent divestitures, and as we noted in our earnings release, second-quarter production was challenged by a couple of very specific items, mainly late in the quarter that Dave will discuss in more detail.

These were power delivery disruptions in the Mid-Continent and disappointing Permian Trust drilling results. The teams are making adjustments by adding and modifying field infrastructure in the Mid-Continent and the Permian Royalty Trust drilling has been shifted to better-performing areas.

As a result, oil volumes are down and we're modifying our full-year guidance and introducing a guidance range with 21% production growth at the midpoint of this range. Notwithstanding these temporary production challenges, the Mid-Continent is working. It's working in terms of IP rates. New areas are performing.

Other zones are being [derisked], costs are coming down, and we're still having innovation breakthroughs. On production, we brought online 122 wells for the quarter with a 30 day IP, the second highest in the history of the company, and supporting north of 65% drilling returns at strip prices.

We had 7 wells with 30 day IPs of over 1,000 BOE per day and those were spread over 4 counties. In our most recent addition to our focus area, Northern Garfield County, Oklahoma, we continue to see very consistent outcome results and in the second quarter added another 21 wells with above-type curve production IP results.

This success is not just in the [Mids] but we're seeing successful development in other zones. On the Chester, recall the SandRidge was the first company to drill horizontal chester wells in Oklahoma. We completed our initial well in the first quarter of 2013 and program to-date drilled 15 Chester wells.

The second quarter saw continued strong IP rates and importantly almost a 70% crude content. Due to this success, we're expanding our Chester program to approximately 40 wells in 2014. On the Woodford, we're 8 wells into this 9 well test program.

In the second quarter, we had a commercial and technical success with the well in Grant County, Oklahoma delivering on 30 day IP of over 300 barrels of oil per day.

We're encouraged with this result as it validates our new geologic model and are continuing our Woodford test program with this revised geologic targeting method, and we will report more in the coming quarters.

Stepping back to talk about the Mid-Continent, we rolled out this view with our mission statement in January of this year and then again in much more detail at our analyst day in March.

One of the primary reasons we prefer operating in this Mid-Continent region is because of the opportunities it presents for many oil-rich zones and the ability to expand our resource base.

This is an area of the country with decades of production from multiple prolific zones and we are uniquely positioned to apply our learnings, our large land position, and our infrastructure to unlock these zones, which is exactly what we’re doing in the Chester and I think we will ultimately do in the Woodford.

Our leadership and innovation continues on our multilaterals. To recap this program, this is an approach that SandRidge developed in 2013.

We deployed our first prototype in late 2013, further tested in the first quarter of this year with very encouraging results, and the program continued to gain traction with another 4 multilateral wells completed this quarter at a cost per lateral of approximately 85% of a typical well while delivering just over 105% of the production in the peak 30 days.

These multilaterals were not concentrated in one area of the play, but were spread across 3 different counties. We developed this multilateral approach to further advance our industry-leading cost per well and more efficiently develop a section in the Mid-Continent, and this is working.

Think about this, we're able to put laterals in the ground right now at $500,000 less than our standard well, which is already the lowest cost in the industry. Multiply that savings by hundreds of wells and it's a step change in the business for us. We see this application as transformative to our well cost structure and returns on invested capital.

With the success of this, we're expanding our multilateral program and will drill approximately 50 laterals using this method in the back half of 2014. Further, we'll be looking forward to 2015 for broader sanctioning of this as our standard development method. One other note on costs.

Recall in our 3-year plan, we set a goal to get cost to $2.7 million per well or per lateral by 2016. We also have a stretch goal to get these costs to $2.3 million in the same timeframe.

As you can see by our team's second-quarter performance of under $2.9 million per lateral and achieving $2.5 million on multilaterals, we are well on our way to achieving both of these goals.

And remember, with costs under $3 million per well, every $100,000 of well or lateral cost savings represents 10 percentage points or a 1,000 basis points of incremental return. So, importantly we're making these decisions based on return, not just hitting a growth target for growth's sake.

In closing, while the quarter was light due to production challenges, not well results, we drilled 122 high return wells. The challenges in the first half of the year were specific to production challenges that we are addressing.

Our results continue to be solid, I'm confident we have the teams, the projects in place to deliver strong back half of 2014 with momentum into 2015 and remain confident in our 3-year plan because the Mid-Continent's working. We're seeing very strong rates on our drilling program.

Our newest focused areas yielding consistent results, other zones working notably a horizontal Chester oil, costs hit a record low in the quarter and innovation efforts particularly multilaterals are gaining a broader application. Now let me turn the call over to Dave Lawler..

David Lawler:.

Thanks, Dave. Thank you all for joining our call. My brief remarks today will cover 3 topics. Our pro forma EBITDA, our liquidity position and leverage ration, and our current hedge position.

First, pro forma announced referred to in this discussion are removing the effects of the sale of the Permian assets in the first quarter of 2013 and the Gulf assets sold in the first quarter of 2014.

On a pro forma basis the second-quarter of 2014 EBITDA of $210 million was an increase of $48 million, a 30% improvement over the second quarter of 2013. This is an EBITDA increase of $4.71 per BOE to a total of $33.10 per BOE.

For the 6-months ended June 30, the 2014 EBITDA of $387 million was an increase of $113 million, a 41% improvement over the same period in 2013, for an increase of $6.08 per BOE to a total of $31.86 per BOE. Additionally, Dave informed you earlier of the 350,000 BOE anticipated shortfall of Permian production which is primarily oil.

It is important to note that shortfall in production has a diminished effect on SandRidge EBITDA as we have less than a 25% net revenue interest in those wells. Second, we closed the second quarter with $919 million of cash and a fully undrawn borrowing base of $775 million resulting in current liquidity of $1.7 billion.

The debt covenant leverage ratio was a comfortable 3.2 times. And finally, to update on our hedging, the remainder of 2014 is 97% hedge for anticipated liquids revenue and 60% hedge for anticipated natural gas revenue. In July, for the first time in over a year we experienced an approximate 9% upward movement in the middle of the oil curve.

We took that opportunity to add to our 2015 oil hedges and to begin to layer on 2016 hedges. All are very attractive collars from $90.00 to $104.00. Since the end of the first quarter we have added oil hedges for 2015 of 1.66 million barrels, giving us a total of 10.2 million barrels of oil hedge for 2015.

2015 natural gas hedges include swaps on 15.4 BCLs at $4.50. We were also able to hedge 1.82 million barrels of oil for 2016 at prices similar to our 2015 hedges. With the market backward-dated like it is, we prefer using collars and 3-way collars as we maintain downside protection we keep the upside to the very attractive near $105.00 level.

We run a lot of our economics here at $90 forward oil. And we're very comfortable hedging at or above that level. As in the past, we will look forward to our selected period of strength in the market to add to our out-year hedges. Operator, that concludes my remarks, please open the call for questions. .

(Operator Instructions) Your first question comes from the line of Neal Dingmann with SunTrust. Please proceed..

Hey, guys. This is Will for Neal. A couple of questions, looking at the MidCon at the miss, obviously you guys have had some pretty good results in different zones.

Kind of curious how you will look at allocating capital across the Chester and with the multilaterals, and then stepping out into newer areas?.

Yes. I would say that the capital allocations is pretty real-time. You'll notice we took our Chester count up for the remainder of the year to 40 wells, so as we continue seeing success in the Chester, we're adding a rig to that.

We're seeing a very tight distribution and results into new areas in Northern Garfield, so we've upped the effort in Garfield. So the capital allocation is real-time between the existing [missed] play and some of the newer emerging areas.

Then on the multilaterals, as Dave mentioned, 18% of our rig count for the remainder of the year is going to be dedicated towards multilaterals. So we've upped that program so we'll be delivering about 50 laterals in the back half of the year under that program. We're constantly moving capital around where we can get the best risk adjusted return.

We don't just wait for the year-end budget process to do that..

Also on – noticed on the LOE, there was a pretty big reduction.

What caused that and how should we look at that going forward?.

Yes Will, the lower LOE is linked largely to reduced chemical use from the first quarter but then also just a continual focus on the efficient operations. We have an amazing team in place and again, it's the small issues that add up to that amount but the biggest delta from Q1, again, is chemical use..

Okay. Great, thanks. .

Thank you. .

Your next question comes from the line of Charles Meade of Johnson Rice.

Hey. Good morning, gentlemen. If I could dig into what's going on in the Permian a bit. I understand that you have, I think it was 50 more wells that you're obligated to drill, but you also said earlier in the prepared remarks that you've shifted your activity from this area where you encountered the higher water saturation to another area.

My question is, are you going to be forced to go back to that area with the higher water saturation or can you fulfill your obligation for those 50 wells and not have to go back into that other area?.

Great, appreciate the question. The way the trust was set up is it was this predefined lease position. So we only have so many areas or locations that we can drill within that boundary. We will not have to go back to the area that was poor.

Again, think of it as maybe two sections, one section that was available that was left for us to develop and that was the poor well result. So we're finishing the trust obligations in a stronger area. In any case, we would have been boxed in to this [answer], so we would have been drilling them now or in the second quarter.

But in any case it's a fixed amount of wells on a fixed position. So we're thankful that this will wrap up..

Okay, so – you would've had to drill these wells one way or another, it just happens you drilled them now and they're behind you now, is the key thing?.

Yes, that's correct. There are other portions in the Permian that are other zones that are not trust-related that we think are strong. We're doing horizontal Clearfork wells later in the last half of the year that we're excited about, we talked about those at Analyst Day.

But in terms of the trust itself, we're down to 5-acre wells and just on what's available to drill..

Got it. And Apache's drilled some great horizontals on the central basin platform. They're really the only other company that's done that, you should be excited about that, I think.

Going back to the Mid-Continent, and on the change in your guidance, it seems to me that if I take the two pieces, one, you guided down on oil volumes but gas volumes stayed flat. But some of your [guidance] was related to the Mid-Con.

So if I put those two things together it seems to me that had you not had these – this underground electrical issue that you would've been in position to maybe be outperforming on natural gas volumes.

Is that a fair conclusion?.

Yes, that is Charles. Remember, on the reduction in the guidance 350,000 of that was related to the Permian which is drilling at about 90%, close to 90% oil, so that's one of the big reasons for the oil decline in the revised guidance..

Right. But the 250 I think was in the Mid-Con, there you're maybe half gas or something like that. And even though you lost that, your guidance is essentially flat there. So it sounds like I'm putting that together. And just one more cleanup.

On Eddie's comment, I maybe didn't hear this correctly or I got confused, but I think I heard Eddie say something along the lines of, you're only 25% NRI on the volumes in the Permian maybe that had the issues? But just to clarify, these, the 350 in the Permian and the 250 in the Mid-Con, those are net to you.

Am I correct?.

So, the Permian, remember we sold the net royalty interest. So we do have less than the 25% net royalty interest, but we consolidate those volumes. When we report production, yes, it's net, but it's consolidated, we consolidate the trust. So the fact that Permian was down for the year about 350,000 barrels, the cash impact of that is small.

Again, while we consolidated, so the production all of it shows through, the cash impact of that (inaudible) only 25% net revenue interest.

Does that make sense at all?.

Thanks for straightening me out on that, James. I appreciate it..

Cool..

Your next question comes from the line of Lee Cooperman with Omega Advisors. Please proceed..

Yes. Thank you. Thank you. Good morning, James.

How are you?.

Good morning, Lee. Good. Thank you..

Yes. Just so I can kind of – I fly at 30,000 feet, but at the Analyst Day if I recall correctly, you expressed your view that you thought the NAV of the Company was something between 9 and 15 and is currently trending I guess a little bit over 5.

I'm assuming that on these new wells, interpreting what you've said and what you actually have said that you're generating 75% to 100% returns.

I'm just curious with the stock selling at less than half of what you think the NAV, how do you and the Board think about stock repurchase as an alternative to drilling lots of wells? Or maybe having a mixture of a program of creating value for the shareholders assuming you're right on NAV, buy buying stock back at half of NAV, as opposed to just drilling up all the money?.

Yes Lee. Our drilling returns are in that 60% to 100% range so for multilaterals Dave mentioned it's about 100% for standard well strip prices it's about 60%, so very good returns on that invested capital. But look yes, we make capital allocation decisions. We've talked about moving wells into Chester, into Garfield and in the multilateral program.

Another capital allocation decision issue we repurchase any of our securities with that capital? We're looking for the best risk-adjusted returns.

What comes into our mind when we think about that is what return can we get on that capital? And what kind of risk are placing on the business? Look, as the stock price trades off I think people are focused on 1quarter and maybe not paying attention to the broader program and the things that our teams are doing here in the MidContinent, driving costs down, record well results, new areas, multilaterals.

But as the stock price trades down yes, that's a capital allocation decision that we'll make and we will look at hard. And at the right time and right price we'll think very hard about that, yes. .

All right. Thank you..

Your next question comes from the line of Richard Close with Capital One. Please proceed..

Hey, thanks. Good morning, everyone.

James I'm not sure if you touched on this, but could you update us on your current thoughts on potentially monetizing your midstream water handling business?.

Yes, Richard, we continue to explore the options there. We're doing the background work necessary for the options including things like forming a legal entity, preparing financial statements, file the PLR with the IRS. That's really all I can say right now. Otherwise we can't really comment on it.

We're doing all of the background work necessary to unlock the value there..

And any expected reserves impact from the Permian operational issues and how many wells were involved with the issue?.

We'll update reserves at year end, Richard. On the number of wells, about 80 wells were impacted by the drilling in this high water saturation area..

Okay. Moving on to Garfield County where you guys are showing some really nice results there.

Can you talk about the infrastructure needs, your costs there going forward, take away, et cetera?.

We've built into our plan the ramp-up in the Garfield. So we have in our infrastructure and water disposal spend the necessary capital to connect those wells. That's in our CapEx guidance. I'll let Dave talk to some of the takeaways in Garfield..

Sure. We are developing this area quickly but as James mentioned, we do have the budget allocated to the area so we don't anticipate any issues there. In terms of just speed, we're working with our gas take away provider to ensure that everything goes smooth.

We've ran into a few cases where we've had to put wells on generator so we are plowing ahead and at this point we are keeping up but it is a high-impact area for us so we're watching it close to make sure nothing gets off-track..

That's one of the things, when we look at the low end of our guidance, as we try to put all the risks that could happen in our business in the back half of the year, frankly, in there's a little sliver for take away delays as we ramp up some of this Chester and multilaterals in Northern Garfield, there's the potential for take away delays so we built some of that risk when we came up with this guidance range.

.

Okay.

And then just lastly, as you look into 2015 does the Permian issues, how does that impact your oil production growth outlook and are you able to overcome that maybe by shifting more capital to the higher oil component, Garfield area in Chester?.

Yes. If you'll recall we will be completed with our Permian trust obligation at the end of this year. So we'll drill about 50 more wells. And this year we will have spent over $100 million drilling Permian trust wells, in 2015 we will reallocate that capital back to our MidContinent play.

So the impact of the Permian drilling, the Permian high water saturation is this $350,000 this year but doesn't impact longer-term the growth of the business..

All right. Thanks so much. That’s all for me..

Thank you, Richard..

Your next question comes from the line of Jamaal Dardar with GPH and Company. Please proceed..

Hey, good morning, guys. I had a few questions. I remember last lease you gave us an update on Sumner County.

We didn't see any updates in this release so I was just wondering if you had any new information there, some longer-term data?.

Yes. Jamaal, this is Dave. In terms of Sumner activity we finished up quite a few wells in Q2 but we've also shifted a significant number of rigs into Woods County. So into the Chester and into the lime results we've seen in Woods County and also in Garfield.

The primary reason for that, I think when we talked earlier we had said that this area is dominated by significant fracture patterns. We've seen that become more and more true over time and so what we've done is scheduled a fairly large seismic shoot that we anticipate getting in here in a few months.

And what we're going to do is process that seismic and then target where we think we can get the most prolific wells. For us we have the luxury of having a large portfolio and we feel like at this time if we channel that CapEx into some of these higher rate of return projects while processing seismic, ultimately we'll do much better up there.

So we've kind of deemphasized Sumner until we get that seismic in..

Great. Thanks for that. Had another question on – we've seen a lot of 30 day rates so far.

I'm just wondering if you had any color on medium to longer term data?.

We try to avoid looking at that until the year ends. We try to concentrate just are we getting what we expect with the drilling program? And that's certainly happening. I think that'll be addressed really in our year end reserves program..

And just one more from me.

Are you going to be reducing the Mississippi completion count this year with the reduced guidance?.

No I think for now we'll keep the same completion count which I think was about on a gross basis about 450 wells this year. We've not changed that..

Okay. And with the well costs trending downward, didn't see any change in CapEx.

Do you think that CapEx could also drift down for the remainder of the year?.

We'll keep revisiting that. If you think about the math on 50 wells at multilaterals, even if you say on the 50 wells, if you save $500,000 per well, if we have about a 70% working interest, that's about an 18% – $18 million CapEx savings on to $100 billion budget. Not material. We'll keep looking at that, looking at our D&C costs.

Look the team did a great job of driving costs down as Dave mentioned, we're a year ahead of what our goal was in terms of getting the single well cost down. We're really looking forward to 2015 and beyond.

Where if we can take a meaningful portion of the drilling program and apply these multilaterals, that's when you can see real impactful changes in CapEx, when you have hundreds of wells that you're drilling using this multilateral program with the savings of $0.5 million of lateral. That's when you'll see the real impact, Jamaal..

Okay. Yes. That makes sense. Thanks guys. That's it for me..

Thank you. .

Your next question comes from the line of Amy Stepnowski with Hartford. Please proceed..

Hi. Thanks for taking the question. I was wondering, in your release you talked about 112 of the MidCon wells that are coming in at 30% above type curve care.

Can you give us an idea of – that's 112 out of how many, and is this something that causes you to look and potential for reassessing the type curve?.

I believe we said 122..

Sorry..

That's alright. 122 and these are all the wells. So these are all the wells with the 30 day IP in that quarter. So, on the type curve we'll reevaluate it at year end. We update our type curve at the end of every year and will do that at the end of this year..

Okay.

And the on the guidance for the midstream EBITDA, does that include more than just the saltwater disposal business?.

And are you talking about on the earnings release? Our MidContinent EBITDA, the midstream EBITDA and that?.

Yes..

No. That' s actually, that's not the water disposal business. It's important to note, that's our midstream gathering business where we gather some volumes and have some marketing and make a small margin on that. No, that is not the water disposal business..

Have you given any disclosure around the size of the EBITDA of that business?.

We have. We talked about it a little bit at Analyst Day and a couple of other times but I'm happy to revisit it. That business is doing about volumes of 950,000 or so, BOE per day.

But what we've said is that business, net to SandRidge, but the entire water disposal business, we own about 72% of that, will generate about $135 million of EBITDA this year. That's largely in our Company the SandRidge, we do have some other customers but it's about $135 million 8H business..

Okay. Thank you very much for the clarifications..

Welcome. .

(Operator Instructions) Your next question comes from the line of Shawn Needham with Oppenheimer & Co. Please proceed.

Hi. Good morning. Thanks for taking the question. James, I think in your opening remarks you talked a little bit about closing the cash flow gap.

Just given some of the capital efficiencies that you've seen or at least highlighted in your prepared remarks, can you talk a little bit about how this might change, if at all, your plans on cash flow neutrality?.

Yes. No, it doesn't change the plans. We laid out a plan to grow production at 20% to 25% CAGR over the next 3 years and that grows EBITDA in the 25% to 30% a year range. And we haven't changed our 3 year outlook.

We're disappointed to take guidance down from 26% to 21% but we've addressed all the issues with the business and the base asset's performing. So our 3 year outlook for the business has not changed at all. And that 3 year outlook causes us to close that gap in that 3 year timeframe.

No, that hasn't changed and that's still a very important goal of ours to shrink that deficit every year..

That's helpful.

When you talk about the debt [indiscernible] just to be clear, are we talking about operating cash flow less the CapEx or are you including asset sales or other stuff in that?.

No, good point. I'm not including asset sales. If you want to include asset sales we have $800 million almost, or $750,000 from the sale of the Gulf of Mexico business this year so we would be neutral. I'm just talk about real operating cash flow from the business. Any asset sales or other proceeds would just be additive to that program..

Okay. That' s helpful. And then maybe just one last one on the balance sheet. Can you remind me, just given your current cash balance of over $900 million.

How you think about approaching the 8 3/4 bonds that become callable early next year?.

Sure. We've looked at that, the math on those and given where our bonds are trading, I'm going to call it roughly 6.5%, it doesn't make sense to do anything with those now. We'll keep running the math and doing the numbers on that.

We don't have any maturities until 2020, this being the first maturity, but we're constantly looking at what – does it make sense to call, or tender, or refi anything in the capital structure and as rates move and our bonds trade and that gets closer to call date, we'll continue to look at it..

Sorry, just to squeeze one last one in here.

Can you remind me how many royalty units you have left to monetize at this point?.

Let's see. We've got 3 different trusts, and for SandRidge, Mississippian Trust I, we have 528,000 common units. For the Permian trust and we actually just had 7 million subordinated units flip in the common units so it'd be about 7.5 million.

The Permian trust we have no common units but 13 million subunits and for SandRidge Mississippi II we have 6.2 million common units and 12. 4 million subunits..

Okay, great. Thank you very much..

You’re welcome. .

Your next question comes from the line of James Spicer with Wells Fargo. Please proceed..

Yes. Hi. Good morning. Just back on the Permian for a minute here.

The disappointing well results that you had, did you guys know ahead of time kind of that this acreage was going to be an issue? And what data are you looking at to tell you that this next area is going to be better?.

Sure, James. We really just started to notice some of the wells weren't coming in like they should early in the quarter. That impact, the 350,000 is projecting those wells to the end of the year. So this was, as we moved into that final area had no indication at all that we would be disappointed.

And as quickly as it became apparent that it wasn't going to work for us we moved as fast as we could into what was available remaining. That's really just kind of the nature of it, not a complex story. It's just what was available and we were disappointed and that's all that was there..

And the second part of my question was this area that you're moving into, do you have additional wells already producing there that give you some confidence that the results are going to be better?.

Yes, there is production in the area on larger spacing positions. So 20-, 40-acre spacing, so there's reasonable confidence that we'll get the kind of results that we expect..

Okay. Great.

And then second question was, are there any material costs involved with the upgrading of the power structure that you talked about earlier, the substation, the automatic restart capabilities, et cetera?.

No, not material. It' s pretty straightforward. Just have to order the equipment and put it in but in the larger facilities CapEx budget it won't be significant..

Great. And then finally, as you wrap up your drilling operations for the trust – or I guess most of them are already wrapped up this point, I presume that you're distributions going out the door going to track declining, the production from those trusts, along the natural declining rates.

Have you provided any guidance as to how we should think about distributions going out the door for you guys?.

We haven't. The trust has put out its own release on each trust on what the production is, as you mentioned, when they reach the end of their drilling commitment they'll largely be on a decline. I think someone could put a reasonable decline on those based on decline curves and come up with their own estimate.

We haven't given updated distribution or production estimates for the trust specifically..

Okay. Thanks a lot..

James Bennett:.

You’re welcome.:.

With no further questions I would now like to turn the conference over to Mr. James Bennett for closing remarks..

Thank you operator. Look in closing, while we had some specific, very specific production challenges in the quarter, our asset base in the Mid-Continent is working. Our focus on this play is delivering results. The wells are performing. We've had the second-highest IP in the history of the Company.

Many wells over 1,000 barrels a day in 4 different counties, our new areas such as Northern Garfield are working exceptionally well. We're finding new zones other than just in Mississippi such as the Chester and the Woodford. Our LOE and CapEx both hit record results for the quarter and very, very importantly, this innovation is working.

These multilaterals are going to be very transformative to the Company as we move forward. So keep all those things in mind and we'll talk to you on the next call. Thank you very much..

Thank you for joining today's conference. That concludes the presentation..