SandRidge Energy, Inc.
Q1 2013 Earnings Call Transcript

Published: 8 May 2013

[Operator:]

Good day, ladies and gentlemen, and welcome to the First Quarter 2013 SandRidge Energy Earnings Conference Call. My name is Tiesha and I will be your operator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Kevin White, Senior Vice President, Business Development. Please proceed.

[Kevin White:]

Thank you, Tiesha. Welcome everyone, and thank you for joining us on our first quarter earnings conference call. This is Kevin White, and with me today are Tom Ward, Chairman and Chief Executive Officer; James Bennett, President and Chief Financial Officer; and David Lawler, Executive Vice President and Chief Operating Officer. Keep in mind that today’s call will contain forward-looking statements and assumptions, which are subject to risks 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 any non-GAAP measures we discuss can be found in our earnings release and on our website. Please note that this call is intended to discuss SandRidge Energy and not our public royalty trusts. Finally, you can expect to see our first quarter 10-Q filed after the market close today. Now, I would like to turn the call over to Tom Ward.

[Tom Ward:]

Thank you, Kevin. Welcome to our first quarter earnings and operational update. I will keep my remarks relatively brief as the quarter speaks for itself. Our Mississippian play continues to exceed expectations. We have now surprised consensus estimates for earnings per share in each of the last five quarters and EBITDA and production and for the last five including this quarter. Not only do we continue to beat our production guidance but we have been able to maintain our best in class operational results by averaging only $3.1 million per well [drilling] [ph] the Mississippian wells and continue to believe our cost will trend down the remainder of this year. The company has diligently built one of the world’s largest saltwater disposal and electrical systems over the last three years to create a play that has very high rates of return. The Mississippian execution is our highest priority; in our execution we focus on efficiency gains and high grading our large acreage position to give us the most growth for the least amount of capital expenditure. In our 2013 budget we are concentrating on more development locations within known geological focus areas and infrastructure. Our 2013 budget is 90% of our drilling and development locations. We now have over 700 wells that we have drilled covering more than 200 miles of land in Oklahoma and Kansas. This experience gives us an edge in taking the best locations and drilling our wells at the lowest cost. However the 10% of the capital that’s invested in our appraisal areas continues to be important. We now have six focus areas that all started out as appraisal areas. We continue to have success in all areas of the play; it's important to note that our type curve is one that has been created across more than 200 miles of area that we have drilled and not just in the focus areas where the majority of the wells are that we drilled today are located. Therefore we will continue to drill mostly development wells but open new focus areas across the vast acreage position the company enjoys. We have also moved to test deeper locations within the Mississippian play section on the acreages within our existing saltwater disposal system. Our SWD and electrical system continues to allow us to lower our operating cost and give us competitive advantage over other producers. The SWD well ratio has moved from 3.5 to 1 in 2011 to our initial goal of 10 to 1 by the end of this year. The saltwater disposal system combined with the electrical system allow SandRidge to use ESPs without dramatically increasing operating cost which also drives our rate to return higher. We have over $2 billion of liquidity in a Mississippian asset base that has increased its oil content to 46%. However we also have a large areas of acreage in the Mississippian that have upside to natural gas. Our operations team continues to perform very well as we curtailed only 100,000 Boe from the two major storms that hit Oklahoma and Kansas during the first quarter where we had one time over 400 wells offline. I will now turn the call over to James.

[James Bennett:]

Thank you Tom. Our 2013 financial and operating results has started on a very positive note, with production, EBITDA and EPS all exceeding consensus for the quarter and our run-rate CapEx coming in below guidance. Before discussing more detail of the first quarter results I think it would helpful to give some context and review of the few recent changes being implemented. As we have outlined in recent press releases the management team and our Board of Directors have been examining our business plan including how to best develop our asset base and the appropriate pace of spending. As a result of this review we have made some changes to our development plans which entails a high grading of our Mississippian drilling, focusing our capital and highest return projects, reducing our funding gap and reducing overhead cost and G&A spending. In addition the Board is finalizing a number of governance and compensation changes including a new executive compensation program that will incorporate objective performance measures into incentive pay. It’s our belief these actions will enhance the link between compensation and performance and assure alignment of management and shareholder interests. We realize an advantage from a number of our strength right now, first our employees and teams at SandRidge continue to perform exceptionally well. Things like maintaining best in the industry well cost, reducing our infrastructure spending and overall fostering a culture of continuous improvement. We cannot be more pleased with the talented employees we have across all our lines of businesses. Second is our asset base, the Mississippian play is exceeding expectations and the offshore business is delivering consistent results. Mississippian production continues to excel with 10% quarter-over-quarter growth and this growth is not limited either geographically or geologically. In the first quarter we had three wells in two counties that yielded 30 days IPs of over 1000 barrels of oil equivalent per day; also as Dave will discuss in more detail we have some deeper (Miss) [ph] zones and stacked pay tests and are encouraged by their early results. These zones offer the potential to significantly increase oil and gas recovery on our leasehold. In addition these wells can be brought on stream for substantially lower operating capital cost by utilizing existing well pad sites and infrastructure networks. Third, as noted in our earnings release, we have high-graded our Mississippian development plan. Part of our normal process of reviewing and managing the business is to constantly look at our planned levels of capital expenditures, where do you get better turns and what are the appropriate levels of spending and leverage and sources of capital. After probing this review in the first quarter, we made the decision to reduce our 2013 CapEx by one-third versus 2012 and 17% versus prior guidance to $1.45 billion. This lower level of CapEx will shrink our funding gap and extend the duration of our $2.1 billion of liquidity. However, we won’t be sacrificing growth or the continued assessment of our Mississippian assets by reducing CapEx. By adjusting our development plans, we are able to focus on improving our capital efficiency and reduce our infrastructure, land, midstream, and other spending while still maintaining a robust E&P program. Under the revised guidance, we plan to drill 425 wells in 2013 and deliver Mississippian production growth of approximately 60%. We anticipate 90% of our E&P CapEx in the Mississippian will be concentrated in high-graded focus areas. After drilling over 700 wells in the play over the last three years, we have identified six of what we consider focus areas, 3 in Oklahoma and 3 in Kansas, where we have significantly de-risked a large number of drilling locations. In these 6 areas, they cover 2.8 million acres and span a 130 miles from Grant County, Oklahoma to Comanche County, Kansas. We have over 550 producing wells and are seeing on average better than type curve results. By concentrating in these areas, we believe we can achieve better rates of return, capitalize on our prior investments and infrastructure, and begin converting our portfolio mix to a lower risk and higher return drilling. As we continue to assess the play in our appraisal areas, we plan to spend approximately $100 million or 10% of our Mississippian E&P project to test and evaluate our acreage and over time convert these appraisal areas into new focus areas. You will hear us repeating these themes many times in the call today, but all of these moves we are outlining are designed to improve the rates of return on our invested capital. We have all begun to reduce our Mississippian rig count which peaked at 32 in the first quarter. Currently, we have 28 rigs running and expect to average 25 rigs in the play in 2013. Beyond 2013, we have an asset base that can for many years comfortably support double-digit production growth and anticipate targeting an annual CapEx level in the similar range to our updated 2013 guidance. Finally, with $2.1 billion of liquidity and 2.25 times leverage ratio, our balance sheet and financial flexibility provides us running new room to develop our assets over the next several years. Couple this with having no bond maturities until 2020 and over 37 million barrels of oil hedged through 2015 we are in the best financial position in the company’s history. Now, getting into some of the specifics for the quarter. Production totaled just under 100,000 BOE per day, which included two months of production from the Permian assets we divested late February. Pro forma for the divestiture production totaled 87,200 BOE per day which represents 4% sequential production growth and 9% ore growth over the fourth quarter 2012. Adjusted EBITDA for the quarter totaled $270 million, representing a 40% increase from the year ago period and net income was $2 million. Operating cash flow was $182 million or $0.32 per share. Recall, we don’t adjust operating cash flow for any one-time items. Notably, we have $30 million of one-time realized hedging losses associated with the sale of our Permian asset. This impact alone would increase cash flow per share by approximately $0.05. On per BOE unit measures, lease operating expenses of $14.73 was within our guidance range. G&A expense totaled $8.84 per BOE for the quarter, but includes several one-time items that can be found on pages 3 and 10 of our earnings release. Excluding these non-recurring expenses, total G&A was approximately $6 per BOE. I will cover a little more in G&A in a moment. Reductions in our Mississippian well cost and efficiencies in our infrastructure were evident in the first quarter CapEx which totaled $389 million, a 32% decrease from the first quarter of ‘12. The following example highlights our focus on this increased CapEx efficiency. In the first quarter 2012, we spent $220 million in the Miss and drilled 68 wells and their associated infrastructure. In the first quarter of ‘13, we spent $235 million and drilled 122 producing wells. So, in Mississippian, we spent 7% more capital this quarter, but drilled 80% more producing wells. This speaks to our improved well cost, the capital efficiency we are experiencing and leverage we have from our prior investments in infrastructure. We issued updated guidance, it can be found on page 8 of the press release and on our website. The primary adjustments to guidance reflect our new development plans and adjustments to our G&A. These changes in our capital expenditures will have minimal impact on our production rates as we reduced drilling in the appraisal portions of the Mississippian. 2013 production is now projected at 32.7 million barrels of oil equivalent. This represents a 60% growth rate in Mississippian production and pro forma for the Permian divesture and offshore acquisition, 30% organic production growth and 19% organic oil growth. We have also been focusing on reducing general and administrative expenses and expect G&A to be an annual run-rate of a 150 million by the fourth quarter of this year. This is approximately 30% below our first quarter 13 run-rate, 25% below 2012 levels. I should note that given the recent consent process, ongoing litigation and employee severance charges we do expect several onetime G&A items this year and are not including those in our guidance. Debt at the end of the quarter totaled 3.2 billion, 1.1 billion below year end levels, recall that recently reduced our total debt in connection with our Permian asset sale regaining 1.1 billion of senior notes. The debt reduction resulted in annual interest expense savings of nearly 100 million extend on maturity profile and resulted in a reduction of overall cost of debt. Our 20

[Dave Lawler:]

Thank you James and good morning to everyone joining us on the call today. As indicated in our press release the Mississippian offshore and Permian business units delivered strong results during the quarter, in particular the Mississippian business unit continue to drive our production growth achieving a record average production rate of 39,500 Boe per day. This rate is a 105% improvement over the first quarter of 2012. This performance was fueled in part by exceptional 30 day IPs. The 109 wells delivered to sales on the quarter reached 330 Boe per day or 21% above expectation. This level of production performance reflects our strategy of drilling primarily within our established infrastructure and working within six focus areas. It also reflects a rapidly expanding subsurface knowledge base and expertise in selecting the most prolific intervals. Along with strong production performance our operating teams continue to efficiently drill incomplete wells. We drilled 122 wells and completed 130 wells for an average of $3.1 million. Of the total number of wells drilled in the quarter 76 were either first or second wells in the section and 46 were either third or fourth wells in the section. Approximately 50% of these wells were equipped with ESPs. Given the cost structure and production performance today we are currently projecting a rate of return of approximately 40% based on recent strip pricing. In addition to delivering industry leading operational metric we have been working to reduce capital expenditures related to infrastructure, part of this initiative is focused on the cost associated with handling produced water. Performance tested large diameter and high angle injection wells in order to gain great exposure to the disposal formation. This initiative paid dividends this quarter, the new well designs when combined with high volume injection pumps and the new fluid management system allowed us to eliminate 12 planned disposal wells that were previously required to support the development program. The CapEx saved by this initiative totaled $16 million just in the first quarter alone. For comparison, the high rate wells on average cost approximately 1.5 times the original design, yet are capable of injecting up to 300% more fluid than the original specifications. The full benefit of these new systems will be discussed in more detail as part of our updated capital plan. Beyond the base development plan of the Mississippian, we are continuing to pursue opportunities that we believe will increase the net asset value of the company. As we shared during our Analyst Day presentation in February, we have initiated a testing program to identify new productive intervals and to assess the potential of stacked pay intervals within our exiting leasehold. This quarter, we are encouraged with the results of four test wells in three different counties. Together these wells delivered an average 30-day IP of 462 BOE per day. Of this rate, approximately 45% was oil or 201 barrels of oil per day. These wells tested the Chester Sandstone, Middle Mississippian, and Lower Mississippian intervals. Due to the sustained performance of these wells, we have immediately identified and scheduled two Chester wells, 40 Middle Mississippian wells and 4 Lower Mississippian wells. There is additional economic upside with this program since the majority of the wells are located within our existing infrastructure. In some cases, we project that these new stacked pay wells can be drilled from the same pad as an existing Upper Mississippian well. In terms of operating cost, we decreased our unit LOE by 4% from $9.59 per BOE in the first quarter of 2012 to $9.18 per BOE in the first quarter of 2013. This unit cost was consistent with our expectation. The first quarter is typically our higher cost period due in part to the significant use of methanol to minimize freezing in our production systems. With winter behind us, we are now operating at a lower LOE than in the first quarter and in line with our expectations. Our offshore business unit also delivered strong production during the quarter. As noted in our press release, the average daily volume was 32,400 BOE per day. This rate was supported by two key projects. The first was a side track from Ship Shoal 301, well A1. A1 came on stream January 8 pulling over 1,800 barrels of oil per day at 1.1 million cubic feet per day of gas. It is still delivering robust rates. The second project was an uphold re-completion of South Pass 60, well number B15. This well flowed 450 barrels of oil per day and 300 Mcf per day and is also currently producing at strong rates. Given the success of these projects, we are planning to lead or participate in 19 additional re-completions between now and the end of the year. We are also planning to drill seven projects and participate in two non-operated joint projects by year end. Our capital expenditures for the offshore in 2013 will be approximately $160 million. The Permian business unit is continuing to deliver production for expectation. You may have noticed that our LOE was higher in the quarter than in prior quarters. The key reason for this increase is linked to the sale of our non-trust Permian assets. Although the sale of these assets was effective December 31, 2012, we continued to operate and conduct work-overs at the request of the buyer. All costs incurred were adjusted at closing. Lastly, we wanted to highlight the key aspects of reduced capital plan for the Mississippian business unit. We now plan to drill 425 horizontal wells in 2013 instead of the previously planned 581 wells. Even with this new well count, our Mississippian production will grow 60% over 2012. The reduced horizontal well count will allow us to eliminate some of the previously planned disposal wells. With the combination of fewer disposal wells needed for the new well program and fewer disposal wells needed due to our optimization efforts mentioned earlier, we have significantly reduced our infrastructure budget. From our previous plan, the disposal well and facility cost program has been lowered by $80 million. The new disposal well count is now 44% or 27% below 2012. The new producer to disposal ratio for 2013 is 9.7 to 1. In closing, we are very pleased with our results this quarter. Production is on track and our capital expenditures are trending below expectations. Our operational efficiency was maintained on all key metrics even with periods of severe winter weather. Most notably, we have had multiple successes with our new interval and stacked pay well test program. Going forward, our team has confidence in our new development plan and we are quite optimistic about the prospects we have in our portfolio. I would also like to extend a sincere thank you to all of our employees, they have been professional and diligent and they work and they have maintained a genuine commitment to safe operations. They have also been laser focused on delivering high rates of return and that focus is evident in our first quarter performance. Thank you again for your time this morning and I will now turn over the call to the operator for questions.

[Operator:]

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

[Neal Dingmann:]

Tom just a question I was pleasantly surprised by how well the offshore is holding up. Just your thoughts maybe for you or James I guess or even David just as you see that going forward an idea of you know if you can give us any idea of kind of what you’re assuming just with production guidance there and is that largely attributable through lot of workovers you’re having or do you see a number of new well opportunities but again it's just again that production looks extremely solid, I was wondering why.

[Dave Lawler:]

I will take the question, the basis of acquiring the properties I think we shared at that time there is just a significant number of up haul opportunities and these are zones that you need to potentially wait for until you drain the lower zone and then you can up haul and so we do have a significant number of these in the queue that we are going to working on through the years so that’s really what I kind of alluded to in my earlier comments. In terms of the drilling programs, we have high hopes for those we have several that are kind of working through the systems right now and we think those have the potential to move the needle for us as well.

[James Bennett:]

And Neal on the guidance we said before we’re going to spend previous guidance about $200 million and keep the production flat at about 30,000 a day. We took that CapEx down a bit with this focused CapEx program in the neighborhood of 160 million so I think this year we’re probably looking at 10% or 15% decline in the Gulf of Mexico business with this lower level of CapEx. Does that answer your question?

[Neal Dingmann:]

That does, and then just one last follow-up and I will turn it over, just as far as kind of I don’t know if it's high grading is the right word when you look at kind of the horizontal Miss as you kind of look at some more of the core locations. Based on obviously the reduced drilling rig count there going forward, what do you see over the next I don’t know 12 or 24 months as far as lease expirations I mean are you going to let I mean guess now you still have around 1.9 million acres or so I’m just wondering what you would think either at the end of this year or at end of next year number one sort of what that acreage count would be, and then number two I guess Tom’s point was you’re going to be closer to that 10 to 1 sort of area as far as on disposal wells. What would you see on average well cost maybe David also.

[Tom Ward:]

I will take the [HBP] [ph] question it's a relatively new concept, the way of in the industry that we need to hold our acreage by production. So let’s take a step back and say what we have done, we have bought over 2.3 million acres, we have a little over $400 million invested in that, we made sales of $2.33 billion and kept nearly 1.9 million acres. So we have no basis in the acreage that we have and now we have developed a system that we have in place that you can drill the least expensive wells because of infrastructure in and around the system and that’s if you look at our focus areas you can see six focus areas that are all fairly tightly together even though that covers nearly 2.8 million acres as James said. So once you build your infrastructure in place you have access now just even within our focus areas of 2.8 million acres that potentially could be ours because we have a great infrastructure in place. So to lose acreage outside of your infrastructure should really be looked at which is more efficient. If you can buy acreage in the $200 to $300 an acre range outside of that there is plenty of acreage to buy or should you be spending your capital inside your infrastructure and that’s what we have chosen to do as the most efficient way but it's really around building the infrastructure that makes a difference.

[Dave Lawler:]

I can just add a little bit to what Tom said this year-to-date we have added about 35,000 acres within our infrastructure and focus areas at about $400 an acre. So as Tom said, we can add in these areas, we have competitive advantages that others don’t. So, as acreage expires we can let, some acreage we don’t want expire and add in areas we like also of the acreage, it does expire this year, over half of it, we have extensions on. So, and those extensions are at $130 an acre on average. So, if we wanted to – we could easily extend a large amount of that acreage, but [HVP] [ph] is just not something that we worry about.

[Tom Ward:]

And competitors’ acreage will be expiring early and late this year going forward and remember again, if you have acreage that isn’t within an infrastructure system, it makes it very expensive to drill those wells. And that’s why we feel like that these 2.8 million acres of land, a large part of that could be ours if we chose to.

[Neal Dingmann:]

Okay. And then just very, very quickly, just lastly James, are you assuming any of the guidance that any of those LOE that cost over in the Miss, are going down other than around the infrastructure?

[James Bennett:]

No, we have come up with guidance for our Miss LOE and we are sticking with that.

[Neal Dingmann:]

Okay, very good, thank you all.

[Operator:]

Your next question comes from the line of Dave Kistler from Simmons & Company. Please proceed.

[Dave Kistler:]

Good morning guys. Real quickly, looking at that adjusted Permian number of production in Q1 about 87,000 BOE a day, and then looking at your full year guidance of 89,500 BOE a day, what would full year be if you extract the Permian divestiture and maybe can you guys give us an expectation for quarterly ramp in that production just so we have a sense for what’s truly happening on that growth rate, if you could go as far as breaking that out to the Miss that will be great?

[James Bennett:]

Yes, the Permian produced about 1.15, 1.2 million barrels in the time we – sorry, the Permian produced 1.2 million barrels in the first two months of the year we owned it, so you could back that 1.2 off the full year to get a pro forma number. In terms of the rate for the first quarter that 87.2. So, we will be bringing down our rig count as we said from a high 32 to averaging 25 for the full year of ‘13. So, I think you can expect a little slowdown in that production, as the new completions from that higher rig count come on, but throughout the back part of the year we will start to grow in the Miss again. So, while we don’t give quarterly guidance, I think you can from those numbers probably get a pretty good bead on where we will be for the next few quarters.

[Dave Kistler:]

Okay, appreciate that. And then maybe looking at the reserves a little bit, as you concentrate the drilling more in sort of your core known areas, does that change any of the estimates with respect to the PUDs that you previously saw into maybe areas outside of the core, and how should we think about that kind of going forward will be. Will those PUDs quickly be replaced by additional offsets on the drilling you are doing, or just trying to get a handle on how to think about reserves changing?

[David Lawler:]

Yeah, Dave, I will just focus really on the PUD aspect of the question. The program the way we have it lined out at the moment drills kind of 40% to 50% PUDs somewhere in that range, and so although some of the wells are inside specific sections that have a first and second well potentially, we are drilling on the perimeter of that as we are extending the play. So, we don’t see situation where we are drilling all PUDs, if that’s helpful.

[Tom Ward:]

And we don’t have a large amount of PUDs outside the focus areas.

[Dave Kistler:]

That’s very helpful. I appreciate it. Then one last one, with the reduced CapEx, I would imagine that, that extends kind of the time that your JV carries promotes you on a number of wells, I think previously you talked about at the Analyst Day expiring in 1Q ‘14, any kind of additional guidance on when you see that expiring?

[James Bennett:]

Sure, Dave. Right now, or is at the end of the quarter, we had about $490 million left on the carries. We think that will carry us into the third quarter of ‘14 now.

[Dave Kistler:]

Okay, I appreciate that guys. Thank you for the added color.

[Tom Ward:]

Thank you.

[Operator:]

Your next question comes from the line of Joe Allman from JPMorgan. Please proceed.

[Joe Allman:]

Thank you. Good morning everybody.

[Tom Ward:]

Good morning.

[Joe Allman:]

Going just to back to the lease expiration issue based on your 10-K you’ve got about 550,000 net acres expiring this year, and I know it’s not necessarily the focus for you guys, but I think a lot of investors focus on it, so how much of that 550,000 net acres do you plan on holding and then next year it’s 810,000 net acres, how much of that you plan on holding?

[Tom Ward:]

We have in our budget Joe a $100 million for leasehold and seismic, of which a vast majority that’s for leasehold.

[Joe Allman:]

Okay. So Tom can you just equate that to an amount of acreage that you would expect to hold, do you expect to hold more than 50% of the acreage that’s expiring this year, next year or what you think you will be able to hold less than 50% and more than 50%.

[Tom Ward:]

We could hold however much of that acreage we wanted to or we can buy new acreage within our existing infrastructure. So the question then back to you is it better for you to renew acreage outside of the infrastructure or buy other acreage inside the infrastructure and my opinion is that it's best to pick your best locations and let other acreage expire and be a natural progression of a company to have acreage coming in and going out every year like it has been for decades.

[David Lawler:]

Do you remember all that acreage listed that’s obviously not all the Miss, some of that is in the WTO and offshore that’s across our entire asset base and the Miss explorations this year are really not material?

[Joe Allman:]

Got you, and then so is it safe to assume that a bunch of Miss acreage is going to expire and you’re just going to let it expire, and Tom I do agree that if you have two choices one is to let bad acreage go and buy good acreage then of course you want to buy good acreage but I’m not sure if you guys can afford to buy the good acreage, I’m not sure you only have two choices there, so if you can just comment.

[Tom Ward:]

I think we can afford to spend a $100 million of leasehold a year if we choose to, we haven't even spent - we have been under that spend very currently and as James has mentioned earlier you have now an infrastructure system in place that has 2.8 million acres of land within our infrastructure that we can focus on if we choose to or as you have other appraisal wells that are drilled then you focus on that acreage. So to tell you today where we are going to spend on our acreage money over the next two years is impossible and I just don’t think it's prudent.

[Joe Allman:]

Got it, so is it safe to assume that you’re buying all that bunch of Mississippian acreage go just because you’re not going to focus on it.

[Tom Ward:]

Well I think all that acreage go and I think we will add other acreage.

[Joe Allman:]

Okay that’s helpful and then back to the production issues so based on our model just preliminary it appears that on a pro forma basis second quarter overall production is higher than first quarter but then you see sequential declines from second quarter to third quarter, third quarter to fourth quarter. So if you can just confirm that and then does that continue on in the 2014 as well? And the decline appear to be both on gas and oil. So it's just not the WTO I mean as you said earlier some of its Gulf of Mexico but is the (inaudible) declining too from second to third, third to fourth?

[Dave Lawler:]

So Joe we don’t give quarterly guidance, I think we have given enough where you can get a beat on it and given what the Permian did for the first quarter and what the pro forma and while we see the full year. So we’re not giving quarterly guidance but look into in terms of the miss and I said in my remarks that we get 60% production growth out of the miss and going forward we can target about 30% production growth in the miss with our CapEx level similar to 2013. So with that CapEx level we can get double digit, double digit production growth and about 30% growth in the miss, so no the miss is not declining at all in fact it starts to accelerate later this year once we stabilize a rig count.

[Joe Allman:]

Got you so to average the 25 rigs for the year I mean I think if you ended I know it's companywide you ended the first quarter 32 rigs on an average of 26 and I think we are estimating roughly 20 in the fourth quarter is that and can you grow the miss with 20 rigs and can you just confirm that number and what number rig do you need to keep in this flat basis?

[Dave Lawler:]

Sure the rig count peaked at 32 in the first quarter and we’re going to average 25 so you’re right we take it down just below 25 but we do have a flexibility with our layered (ph) on rigs to bring those on and back off so it will get below 25 but I think then stable at that mid-20s rate and we can still achieve as I said a nice very robust miss growth rate in total production growth rate with that kind of mid-20s rig count.

[Operator:]

Your next question comes from the line of Scott Hanold from RBC. Please proceed.

[Scott Hanold:]

Actually on those same lines in terms of like activities going into 2014 so it does look like you did a little bit lower by the end of the year in terms of your rig activity and when you talk about spending roughly what you did in 2013 is that implying some a little bit of ramp in the 2014 or is that just the benefit of the JV moving off obviously requires more of your own CapEx?

[James Bennett:]

You are talking about production ramp or a CapEx ramp?

[Scott Hanold:]

Well, the production. I am sorry I am talking about production year-over-year you said it can be roughly flat is that – is that’s the plan, right. And so if you are actually looking to rig count activity level, where are you at and the fourth quarter appears to run under a rate below that, so is the increase the relative flatness of the CapEx relative to the JV falling off where do you plan on increasing your rig count in 2014?

[James Bennett:]

So, when I said flat from 2013, I am talking about CapEx. So, in the 2014 we estimate or we are not giving 2014 guidance, but to give you some goal for this we estimate it will be in the range of what we spent what we will spend this year. Our rig count will average 25 this year, it will dip a little below 25 into the later part of the year, but we think in ’14 will average about mid-20s rig count as well. And that will be able to deliver double digit production growth and over about 30% growth in the Miss.

[Scott Hanold:]

Okay and so that ’14, ’15 obviously assumes that the JV rolls off by the end of the year, is that correct?

[James Bennett:]

Yes, that’s correct.

[Scott Hanold:]

Okay, that’s working. Thanks.

[Tom Ward:]

Thank you.

[Operator:]

You next question comes from the line of David Deckelbaum from KeyBanc. Please proceed.

[David Deckelbaum:]

Good morning guys. I think that this question might be for David and guys as focus you talk a lot about high grade in today’s, you focus on this focus areas with 25 rigs more or less throughout the remainder of the year, is there you have experienced some better results there, is there sort of a percentage wise number that you use on top of your base case type curve in that focus area?

[David Lawler:]

No, David this is Dave Lawler we don’t make any kind of adjustment I think this is the key theme for us is that we did spend significant amount of money testing the play and we’ve found some very good areas and we have infrastructure there, so we are just going to continue to use our CapEx where we can get the greatest return like Tom was mentioning. So, we still wanted to go out and test the appraisal areas we are doing that, but where we are right now we just want to be as efficient as we can do with the CapEx.

[Tom Ward:]

I think it is a little bit rare that a company uses the whole field across every well that’s been drilled to come up with a type curve. I think that’s fairly conservative in the business today where most companies use the better areas to drill within different plays and then look at that as being achievable for a type curve. So, I think we didn’t choose more conservative way to come up with a type curve for the Miss.

[David Deckelbaum:]

Sure. And then are the costs relatively the same for focus area versus appraisal area because it looked like I mean updated guidance that cost per well was going up. I didn’t know if that was just the function of timing of completions or some other things that was is that number if it was actually higher well cost on the wells that you intend to drill going forward?

[David Lawler:]

From a drilling and complete standpoint, the well cost is essentially the same, what you see the challenge for us really is more on the OpEx side. So, if you are in a remote area you may have to put the well on the diesel generator or we may have to truck water. So, what you see are just kind of ongoing costs David that it makes it expensive for us if you don’t have the infrastructure. But in general D&C cost, we have a pretty efficient machine at this point, so it about the same.

[James Bennett:]

Let me comment on the CapEx, if you just look at the CapEx, taking times of working interest and divided by the number of wells it might look up it went up versus our prior guidance for the Mississippian but it didn’t. We are still in that same $3.1 million-$3.2 million range per well. What you see there by doing that math is we have about of $100 million of CapEx in our Mississippian program this year. That is geared towards the appraisal areas and we don’t have a well count associated with it, so that’s for testing analysis, geological work we formed, we call it an IPT, an integrated project team with our partner Repsol with some of their best carbonate scientists from around the world. We are going to study and evaluate the play. So, I think note with in that Mississippian CapEx there is $100 million that doesn’t have well count associated with it for to represent our continued work on the area. So, that’s why your per well number looks a little higher.

[Tom Ward:]

And David we try to leave some room, so if we want to do a core of a section and delayed testing period we might do some of those things, so we just want to have funds available to do that.

[David Deckelbaum:]

Sure and what dollar amount is included in that for testing sort of the other stacks pay intervals throughout the remainder of the year.

[Dave Lawler:]

What was the question one more time?

[David Deckelbaum:]

Is there a specific dollar amount in your CapEx now for testing some of the other intervals other than the Mississippian some of these other stacked pays?

[Dave Lawler:]

It's just within our $100 million program.

[James Bennett:]

And Dave laid out the number well we’re going to stack to test those wells and you can just see normal well cost and normal working interest for those.

[Operator:]

Your next question comes from the line of Ryan Todd from Deutsche Bank. Please proceed.

[Ryan Todd:]

If I can just ask you on the 6th core areas, the six focus areas that you’re talking about right now have you said how much that acreage do you have associated with those areas and how much of that is held by production?

[Dave Lawler:]

The area encompasses a total about 2.8 million acres, we have SandRidge net about 925,000 acres in this area and I don’t have exactly how much is HBP.

[Ryan Todd:]

And in terms of level I guess we have already talked about the HBP issue quite a bit up to this point. If we could take a step back I guess at the like from a broader view in terms of what’s changed and what’s happening on a good forward basis now, I mean you still, (inaudible) the spend remains quite significant in going forward and growth is reduced and so I mean when you look longer term and what’s the longer term story for digging yourselves out of this hole. Is it just an extension of liquidity that gives you a lot longer to eventually get out of it or you still consider at some point JVs or slowdowns of additional assets to help close that gap more quickly? How should we think when we think about the large strategic vision over the next three years what do you want us to come away with?

[Dave Lawler:]

Sure I think we approach it in three ways as you see with the reduced CapEx plan we are very focused on narrowing that GAAP between CapEx and free cash flow. So we have taken some measures to shrink it this year and I think as our productivity continues to improve and our infrastructure utilization continues to improve we will chip a way at it even more. Also within our production growth that we talk about a double digit growth next year, oil growth is higher than that so our oil growth outpaces our gas and that’s where we generate most of our cash flow. So we’re going to see improvements in CapEx efficiency and improvements in return on capital which is going to translate in the cash flow which will help shrink our funding (ph) gap. So that’s for one side, we have over 2 billion of liquidity which we think extends us through 2015 which is a very long time and we’re very comfortable with that window and third we do have assets that we can monetize. We have mentioned them before whether it's our saltwater business, joint ventures, asset sales, royalty trust unit sales those are all options available to us. I think the urgency to do any of those right now has been lessened because of our reduced CapEx plan and because of our strong liquidity position but we constantly evaluate all those options and it's a valuation and cost to capital tool for us. We can get robust valuations for any of those; we would look to monetize those to further improve that funding short fall.

[Tom Ward:]

And keep in mind that this is just over the last year we have increased three new focus areas from drilling appraisal wells and we’re still drilling appraisal wells so as you and more than likely the new focus areas are in Kansas and that allows you to just have more time to do either a joint venture or a sale if you choose to on additional acreage, we still have a lot of time on acreage we have and we have a budgeted amount of acreage we can buy in $100 million that can keep us for many, many years to come drilling on the acreage that we own or the additions that we will have and all within the infrastructure that we have in place. So I don’t think to make the assumption that we’re through with adding focus areas is a correct one.

[Ryan Todd:]

Okay but from in terms of additional, this is you have taken some fairly significant steps I guess at this point from a strategic point of view in terms of capital efficiency refocus, should we expect additional strategic changes if that’s going forward or is this kind of where we are. I guess the question is it feels a little bit and on our numbers and granted like we have talked about a lot of uncertainty around future how these things will model and in future you have certain pushed out any liquidity crunch for quite some time, but it feels like a very, very slow process even under the current plan to close that funding gap?

[Tom Ward:]

I wouldn’t consider it the slow processing. We have got teams of hundreds of engineers here that are constantly looking ways to improve well costs, well design and salt water efficiency. So, we are going to continue to try to drive the cost down and drive the productivity up, increase returns on capital and generate more cash flow. So, I think we will continue make moves and as you have seen in the first quarter that’s not going to stop.

[Ryan Todd:]

Okay, great. Thank you.

[Tom Ward:]

Thank you.

[Operator:]

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

[Charles Meade:]

Good morning gentlemen. Just one quick clarification to start off James your discussion of – or your kind of guideline of double digit production growth going forward that is from a 2013 pro forma base ex-Permian?

[James Bennett:]

Yes, surely.

[Charles Meade:]

Okay, great. Thank you. And then going on to the focus areas, looking back at your Analyst Day, it feels like a long time ago, but it’s really just a couple of months ago, you had seven focus areas, three in Oklahoma and four in Kansas. And if I heard correctly earlier in the prepared comments you said you now have three in Kansas and so I was curious if maybe you kind of collapsed the Gray and Ford areas into one or if one of those kind of fell off the roster?

[Tom Ward:]

Yeah, good question. Actually Ford and Gray I wouldn’t say it fell off the roster, but we’ve high graded down into really Comanche and Southern Kansas. So, it’s really a question – it really comes on infrastructure we had better infrastructure down in Comanche County. So, those two counties are really off the list. Right now not being that doesn’t mean we will pick them back up at some point, but we have moved a little further south.

[Charles Meade:]

Right and so the three focus areas in Kansas then would be – fall in what counties?

[Tom Ward:]

So, Harper, Barber and Comanche.

[Charles Meade:]

Got it. Okay. Thank you, Tom. And then going to those the additional zones, the Chester, the middle and the lower Mississippian, if I think if I heard this right it was well plans for 240 and 4 in each of those zones and others 2013 well count?

[Tom Ward:]

Yes that’s correct, that’s what we have identified at this point Charles.

[Charles Meade:]

Got it and so can you talk about I guess David maybe the process or that the evolution of your view on this is a perspective interval and where on your acreage you see that what lead you know for the acreage where you do see it what are the characteristics that lead you to uncover this potential and how far it might go?

[Tom Ward:]

Sure, I think it really started as we when we drill our one of the benefits of having an SWD system as we do penetrate kind of all the zones in the section as we go down to the (indiscernible). And so we have a pretty large database that shows the intervals that appear to be productive, so it was something that our exploration is that it kind of always had an eye on and we are focused on pursuing probably after kind of this first layer but we started to see some different success in different parts of the plays both in our own business and in some of our competitors that may try different zone in the general area. And so kind of pulling in all of our data all our subsurface data our production along with our SWD logs we have been able to start categorizing where these sections can be. So, as you may remain unknown just that the whole section is a historical producer of oil and gas particularly the Chester on the western side of the play and so we’ve just started this program and we are kind cautious as we start off here we are not trying to expand too quickly or over, so we are just taking a measured approach. But we were very encouraged by seeing the strong results from these different tests. So, what we will do is to continue to test those and we will even put some lows on top of each other this quarter so just for reference, we will spud (ph) three wells this month that will be off the same path going to different zones. So we’re pretty excited about what we have seen so far the data supports the program and we just think this is a way to increase our NAV.

[Operator:]

Your next question comes from the line of Richard Tullis from Capital One Southcoast. Please proceed.

[Richard Tullis:]

What would be growth be overall if you only spent your cash flow per year?

[Dave Lawler:]

We don’t really run that case, we can always cut back our CapEx if we needed to live within cash flow but it's not really a business plan that we look at.

[Richard Tullis:]

Okay. And just for clarification the $3.1 million - $3.2 million well cost for miss line wells in 1Q that excludes the allocation for the any saltwater disposal wells that were drilled.

[Dave Lawler:]

That’s correct.

[Richard Tullis:]

And how does that compare to fourth quarter same parameter?

[Dave Lawler:]

It's about flat at this point but as I mentioned at the analyst day we have three or four key initiatives that we are working, we have seen some early success in those. So we’re not ready to advertise lower cost yet but we’re certainly optimistic about what we are seeing. So we are continuing to pursue various initiatives to get that down.

[Richard Tullis:]

Okay and I know James you mentioned that oil would grow at a quicker pace than the double digit potential for next year and what percentage do you think oil could account for total production in 2014?

[James Bennett:]

I don’t think we’re ready to give that kind of detailed 2014 guidance yet Richard sorry.

[Richard Tullis:]

Okay and would the Gulf decline at a similar rate next year 10% to 15% under the same sort of CapEx level?

[James Bennett:]

Yes I think that’s a fair assumption.

[Richard Tullis:]

Okay and then just lastly what were the cost of this four test wells in the Chester and in the middle and lower miss?

[James Bennett:]

They were in that $3.1 million range.

[Operator:]

Your next question comes from the line of Duane Grubert from Susquehanna. Please proceed.

[Duane Grubert:]

Yeah can we start off talking about the saltwater disposal system, you mentioned in passing that you’re going to get up to almost 10 producers per disposal well. Should we still regard that as your target to be full or are you finding you might be able to squeeze few more wells per disposal well.

[Dave Lawler:]

Yes that’s a great question, we do see that significantly increasing overtime. We have made those design changes that we have talked about and the team has spent a significant amount of time trying to figure out how to manage this water more efficiently and so you know we are very pleased to be at the 10 ratio and we see that going as high as maybe 15 or 20. I’m just going to give an example we have got two wells that normally would take kind of 15,000 a day, 20,000 a day and they are taking 60,000 a day. So it's a pretty significant run-up and ejection capability.

[Duane Grubert:]

And then in the revelation today about the Chester, I was surprised you didn’t say anything about the Woodford, I know you had mentioned a couple of wells there, is that a subzone or sub-development theme that you’re continuing to pursue as well?

[Dave Lawler:]

Yes absolutely it's one of the objectives that we’re looking at and so again it's the total area what we’re excited about is, there are significant number of producing horizons that we can capture and so we’re just kind of stepping into it at a measured pace but absolutely Woodford has potential.

[Tom Ward:]

And Duane others have drilled Woodford wells we didn’t – we have not drilled Woodford gas so that’s why we didn’t mention that.

[Duane Grubert:]

And then on wet gas realizations, you guys had changed the Atlas arrangement and so forth, can you talk a little bit about how we might think about your wet gas prices improving going forward?

[Kevin White:]

The gas prices, this is Kevin. The gas prices the dry gas prices were actually overtime show a little bit of decrease as we take the liquids out of it. So that’s a building volume over the course of the year because it's just new wells drilled under the Atlas contract until mid-year next year but I think we’re modeling realizations on NGLs of somewhere around 30% to 35% of WTI and then we’re expecting our dry gas to still sell at a little bit of a premium to the panhandle eastern versus Henry Index.

[Duane Grubert:]

Okay. And then finally a different theme, you have had some middle managers leave the company recently, what are you doing you mentioned in passing connecting performance to pay, are there other things you are doing in terms of instilling a different philosophy at the company, in that you have made some rather big changes. So, maybe I guess my question is in the context of James Bennett maybe mentioning keeping the team together and so forth, what are you doing to integrate these new managers and are they all internal candidates so far on our operating team?

[Tom Ward:]

Just in terms of the plan going forward, I think you will see some more details of that outlined in that proxy which will get filed later this month, so keep your eye on that in terms of incentive based plans, but the people that have moved into these new roles have all been at the company for years and have been integral part of our teams and key to the success here. So, these are an external candidates, these are folks who have been on the teams for quite some time and have moved in these positions that are working very effectively. So, it’s not something that’s we are concerned about.

[Duane Grubert:]

And but just in terms of a shift in philosophy, are you guys getting everybody together and saying we are making a turn here or is it just sort of business as usual at the operating level?

[Tom Ward:]

Well, our operating teams have always been focused on keeping costs down, optimizing, well performance and saw our disposal infrastructure. That hasn’t changed I think. The shift you are seeing is just from a corporate level where we are allocating our capital and let’s focus on some of the higher return projects right now and shrink our funding gap. So, the operational themes are doing the great jobs that they have been for the past couple of years. That hasn’t changed.

[Duane Grubert:]

Okay, thank you very much.

[Operator:]

Your next question comes from the line of John Nelson from Citigroup.

[John Nelson:]

Thanks for taking my question. Just to follow-up on that last question or the last point, some of our disposal wells versus producers the ‘15 to ‘20 target can you give some sort of timeframe on that? Is that maybe 2015 or is that more of a 3 to 5-year target?

[Tom Ward:]

I think it’s probably achievable in the next three years. We are not again, not trying to be too aggressive with it, because many times that the water rate can fluctuate in these wells. We see a pretty significant spread. So, we are really, I had also mentioned, we have a kind of a dynamic management system and model that we use. And so in many cases, we can divert fluid to SWDs with capacity and it just depends on how strong some of the wells come in. So, it’s almost a life type adjustment. And as wells falloff, they may falloff quicker on the water rate. So, it opens up capacity in that well. So, I do think over the next three years, we will see it expands possibly up to the ‘15 but I couldn’t give you an exact target.

[John Nelson:]

No, that’s helpful color. Thanks. And then just one other question, I was curious in this new strategic direction proposed, was that proposed by the new TBG board members or was the plan sort of already in the works that perhaps maybe we should expect further or rather incremental changes still going forward?

[James Bennett:]

We have been working on this plan since the start of the year. We start to reduce our rig count a little bit in February. So, it’s a plan that we have been focused on. I wouldn’t call the board, the new members or the old members, it’s one board and we have worked with them to make and implement some of these decisions the stuff we started in the February timeframe.

[John Nelson:]

Okay. Just to come with that, I guess, another way, was there broad agreement from the board then on this plan?

[James Bennett:]

Yes, but I am not going to speak to what the Board talks about in board sessions or agrees to, but the boards have been very supportive of the all measures we have taken.

[John Nelson:]

Okay, great. Thanks. Congratulations in the quarter.

[James Bennett:]

Thank you.

[Operator:]

Your next question comes from the line of Adam Duarte from Omega. Please proceed.

[Adam Duarte:]

Good morning guys. On the saltwater disposal system, can you help us quantify some of the numbers around that given the lower CapEx plans? Can you tell us sort of what the system would look like by year end in terms of volumes in geographic location and how the system fits into the new plan and potential monetization and if you can, can you put some numbers around what if this was owned by a third-party entity what sort of EBITDA the system would be able to generate?

[James Bennett:]

Adam, let me given you a couple of stats about 123 saltwater injectors right now producing about injecting about 850,000 barrels of water a day. By the end of the year, it will be – the system will be over a million barrels a day. We will have invested in about $600 million. In terms of EBITDA, we are not going to calculate an EBITDA that this would bring a third party, it depends a lot of things their operating cost but also what the charges are per barrel, so I don’t think we are going to calculate a number, an EBITDA number of that for you and then Dave laid out in his remarks kind of the amount, the number of saltwater disposal wells we’re going to drill this year as we have taken that down from the original estimate.

[Adam Duarte:]

Okay is it safe to say that given the potential buyer universe for an asset like this that it would be of value accretive event on a net basis to you guys if you were to monetize this.

[Tom Ward:]

Yes absolutely we wouldn’t - certainly wouldn’t monetize this; it's something lower than our EBITDA multiple where we are trading as a company and if you look at where are these mid-stream type assets trade it's certainly at a premium to where an independent EP (ph) company trades.

[Adam Duarte:]

Okay thanks and then one other question, it was a little unclear on the new production guidance from the Mississippian, are we using the existing type curve across the new focus areas or are we using I guess an incrementally higher type curve on the new focus areas because those are I guess theoretically better than the extension areas.

[Tom Ward:]

I think Adam for now we’re sticking with our year-end type curve, we will update that as part of the normal year-end process in the fourth quarter this year but right now we’re staying with the year-end type curve. What we did say in the March is that we have drilled over 500 wells over 550 in these focus areas and are seeing better than type curve results but we are not prepared to make any changes to our type curve assumptions right now.

[Adam Duarte:]

Got it. Sorry one last question around the hedges, we have hedged a little bit of our gas here this year, is that a sort of a commentary around your view on gas prices or is that more driven by trying to solidify the cash flow around the new CapEx plan?

[James Bennett:]

It's more of the latter; we’re still fairly bullish on natural gas. We’re at 740 Bcf a day, or 740 Bcf behind last year if we inject, if we have an 85 injection tomorrow. So we have 181 days left of injection to get 3.7 Bcf and I think cheaper gas than today would have a difficult ability to fill. So we continue to be somewhat bullish on natural gas, you can see that the out years don’t have any gas hedged and I still think that we have some room here that we might see in the summer time for higher prices.

[Operator:]

Your next question comes from the line of Dan Shanra from DW Investment Management. Please proceed.

[Dan Shanra:]

I just wanted to ask you about the G&A, you said in your press release that your target was a 150 million by the end of this year run-rate, that seems set in the right direction it's still relatively high for a company of this size. Can you talk about where you see that going in 2014?

[Tom Ward:]

Sure Dan if you look at full year 2012 we are at about 200 million, I think a 198 million of total G&A, our initial guidance in November call for 2016. We made some changes in the January, February time frame and some reductions in the mid-point of our guidance then got us down to 194. Now we have made some further reductions and we’re down to 180 for the full year targeting a 150 exit rate, I think we always look to make improvements in all of our cost structures and it will keep an eye on G&A but I think we feel pretty good about the 25% reduction we have made so far.

[Operator:]

Your next question comes from the line of Michael Schmitz from Ladenburg. Please proceed.

[Michael Schmitz:]

All budget I assume you have the benefit of about 550 million of drilling carries this year, what did you assumed in the new budget and then any preliminary parameters that you think funding gap will be next year?

[Tom Ward:]

Sure in the new budget we have about 440 million of JV carries that we will use this year and we’re not coming out with full 14 guidance, we really can’t give you an EBITDA or funding gap number for next year.

[Operator:]

Your next question comes from the line of David Snow from Energy Equities. Please proceed.

[David Snow:]

I’m wondering that Chester is a sandstone, is that a blanket deposition sort of like the shale or is it more discreet?

[Tom Ward:]

It's a sandstone in this particular area, it turns into a lime stone as it moves to further south what’s called the Sahara play was always a Chester limestone area but it is blanket it's the erosional feature that sits above the Mississippian. So if you think of the Central Kansas uplift with the Mississippian and eroding into the Central Kansas uplift the Chester is just the younger rock a very upper part of the Mississippian that sits behind the south of the Mississippian before it erodes over the Mississippian.

[David Snow:]

Okay and which of those zones in your four well seem to give you the best results, the middle or lower Mississippian or the Chester?

[Dave Lawler:]

They are all pretty comparable; our take is that we are going to see strong results really through each moment that was reason for blending them together.

[David Snow:]

Did you produce them together?

[Dave Lawler:]

No we just blending the data for presentation purposes.

[David Snow:]

And I’m wondering as we see they have an average of four, 62 barrels a day and your overall average and the focus area was 330, so does it sound like these might end up being more promising targets to go after in time?

[Dave Lawler:]

That’s what we hope, I mean that’s the goal is to continuously improve the EUR (ph) and the type curve performance. So we hope if we get another quarter underneath here that we can provide more data.

[David Snow:]

Is there same amount of water content in these zones?

[Dave Lawler:]

We saw varied water content, in the Chester there was a lower water cut so that was encouraging.

[David Snow:]

Okay and the Chester you said the western half what that they like half of your focus areas or what amount of focus areas that historically been.

[Dave Lawler:]

Yes Chester is set in the focus areas that we have, it's a younger rock, so it's eroded over the focus area so that’s in an area outside of the focus areas.

[David Snow:]

That’s like new focus area I guess.

[Dave Lawler:]

Well it could be.

[David Snow:]

And in general though what portion of your acreage might be exposed to these additional zones?

[Dave Lawler:]

Well the other zones the middle Mississippian and the lower Mississippian is under all of our existing areas including the Chester so the Chester is younger and they will sit below.

[David Snow:]

Okay and how far part of these are in communication or are you pretty well separated?

[Dave Lawler:]

Are you talking about zones?

[David Snow:]

Yes.

[Tom Ward:]

They are pretty well separated.

[Dave Lawler:]

Yes there are shale barriers between each of these.

[Operator:]

Your next question comes from the line of Anne Cameron from Hetco. Please go proceed.

[Anne Cameron:]

Sorry for asking the same question as some of the other analysts but I’m just a little confused about your guidance. To me it looks like just as it looks like some of the others that your quarter-over-quarter growth in the back half of this year is well it's flat or declining slightly and you have told us the Gulf of Mexico should decline about 10%, the miss should grow about 30% and then I know you have about 8000 barrels per day of other and I assume that’s declining. Can you just clarify is the Gulf of Mexico declined exit to exit or year-over-year and for same question for the miss.

[Tom Ward:]

Yeah the Gulf decline would be exit to exit or fourth quarter to fourth quarter kind of fourth quarter of ’12 to fourth quarter of ’13 and miss we have said you know our growth this year is going to be about 60%.

[Anne Cameron:]

60% exit to exit or year-over-year?

[Tom Ward:]

I think it's year-over-year really.

[Anne Cameron:]

Okay because it's hard to reconcile those numbers with the flat sequential growth in the back half of the year because those numbers if you add them all up would imply growth for the corporation.

[Tom Ward:]

Well keep in mind that we’re taking a recount down in the miss which peaked at 32 down too little below 25 averaging 25 for the year, so that’s going to that will impact it as well.

[Anne Cameron:]

Sure but isn't that in your baked into your numbers of 60% for the year?

[Tom Ward:]

Yes it is.

[Anne Cameron:]

Okay so how can you get flat quarter-over-quarter growth with such great production increase in the miss?

[Tom Ward:]

If you take the exit rate for the miss for last year and where we are going to exit this year that growth is close to 60%, we just happen to get a – have a higher production here in this first and second quarter from that higher rig count.

[Anne Cameron:]

I’m sorry for keeping asking these questions it's just really confusing because you flat got flat growth this year but you’re talking about double digit growth next year. If you’re not increasing the rig count how does that happen?

[Tom Ward:]

Because the Mississippian is growing so even at a low mid-20s rig count we can still grow the miss production and so we’re not giving quarterly guidance but I think we have given enough pieces to piece it together.

[Anne Cameron:]

Yeah but 39,000 barrels a day to grow 60% should plenty more than offset declines a 10% on 30 and whatever it is on the remaining eight. So if that were true why aren’t your growing this year like (inaudible) that up.

[Tom Ward:]

I’m not sure I follow you maybe we should take this offline and get some detailed modeling discussion if you would like to?

[Anne Cameron:]

Yes that would be great. Second question could you just give us the oil number for the Mississippian for this quarter without NGL?

[James Bennett:]

For this quarter Anne was that your question?

[Anne Cameron:]

Yes that would be super.

[James Bennett:]

It was for the quarter it was 1.5 million barrels of oil.

[Operator:]

Ladies and gentlemen that concludes the Q&A portion of the conference. I would now like to turn the conference over to Mr. Tom Ward for any closing remarks. Please proceed.

[Tom Ward:]

Thank you for joining us on the call this morning, as always we welcome any additional questions you might have, so thank you for your continued interested in SandRidge.

[Operator:]

Ladies and gentlemen that concludes today’s conference. Thank you for participation you may now disconnect. Have a great day.