SandRidge Energy's CEO Discusses Q2 2013 Results - Earnings Call Transcript

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SandRidge Energy, Inc. (NYSE:SD) Q2 2013 Earnings Conference Call August 7, 2013 9:00 AM ET

Executives

James Donald Bennett - President and Chief Executive Officer

David C. Lawler - Executive Vice President and Chief Operating Officer

Eddie M. LeBlanc III – Executive Vice President & Chief Financial Officer

Kevin R. White – Senior Vice President, Business Development

Analysts

Neal Dingmann - SunTrust

Charles Meade – Johnson Rice

Dave Kistler - Simmons & Company

David Deckelbaum – KeyBanc Capital Markets

James Spicer – Wells Fargo

Duane Grubert - Susquehanna

Adam Leight – RBC Capital Markets

Craig Shere – Tuohy Brothers

Joe Allman - JPMorgan

Operator

Good day, ladies and gentlemen, and welcome to the Second Quarter 2013 SandRidge Energy Earnings Conference Call. My name is Tahisha and I’ll 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 of Business Development. Please proceed.

Kevin White

Thank you, Tahisha. Welcome everyone, and thank you for joining us on our second quarter call. This is Kevin White. With me today are James Bennett, President and Chief Executive Officer; Eddie LeBlanc, Executive Vice President & 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 James Bennett

James Bennett

Thank you, Kevin, and welcome everyone. I also want to welcome the newest member of our senior management team, our Chief Financial Officer, Eddie LeBlanc. Eddie brings to us over 30 years E&P finance and CFO experience and we are excited to have him here.

Now that we’re more than halfway through 2013, I feel confident saying that the course we laid out earlier this year is delivering results. In the first quarter we made changes to our business plan to high grade our capital program, focus on returns, exercise capital expenditure and overhead cost discipline and lower the risk profile in the business. And our second quarter results are evidence that these changes are taking hold. Highlighting the recent successes to come out of this plan are the fact that our production continued to set new highs and our costs new lows.

Since building our Mississippian position starting in 2010, we have emerged as a dominant operator in the play and we continue to make improvements, exploit our knowledge base and create better returns. Quarter over quarter, we grew our Mississippian production by 20% and Mississippian oil production by 30%. We grew total company production, adjusting for the Permian sale by 5%, even taking into account expected declines in our Gulf of Mexico business.

Our well performance continues to improve, with 111 second quarter Mississippian wells producing an average peak 30-day IP of 377 barrels of oil equivalent per day. We had six wells with 30-day IPs over 1000 barrels of oil equivalent per day. Recall that we high graded our drilling program to concentrate in our six county focus areas, where we’re seeing more consistent results and can better utilize our infrastructure. This year we anticipate 90% of our drilling to be concentrated in these areas where we have 925,000 gross and 615,000 net acres and approximately 3,000 drilling locations.

With the progress made during the first half of 2013, we were able to raise our full year production guidance by 2% or 600,000 barrels of oil equivalent, 100% of this increase being comprised of oil and liquids. Importantly, we’re able to do this while maintaining the same $1.45 billion CapEx budget. This updated guidance delivers a very robust organic production growth, taking into account all the A&D activity of 25% of liquids and 15% in total production.

In terms of the quarterly production trends in our full year guidance, recall that in reducing our CapEx budget earlier this year, this called for a gradual decrease in our rig count, from a high of 32 to a low of 22 with an average of 25 rigs for the year in the Mississippian. In the first quarter, in the Mississippian we averaged 32 rigs. In the second quarter 26 rigs and from end of the year we’ll average approximately 22 rigs. This was our plan all along. This 33% rig count decline from the first quarter to third quarter will cause the Miss growth rate to temporarily slow, but this is completely a function of the one-time decline in rig count.

Looking forward to 2014, we plan to begin to increase our rig account again to the 25 range and spend a similar, approximately $1.5 billion of capital. With this level of spending, we are confident that we can maintain a double digit, total company production growth rate, a high oil growth rate and approximately 30% year over year Mississippian production growth.

The stacked pay in deeper zones that we mentioned in our Analyst Day and then again in our first quarter are showing positive results and have the potential to open up vast areas of the play with multiple zone development. Our Mississippian teams are doing excellent work developing new opportunities for us in the play. We’re still early in this program and we’ll continue to report our findings in the coming quarters. But initial results we’re seeing are very encouraging.

Again our strategy of focusing on a high-graded capital plan is paying off. Let me walk through a few examples to showcase our focus on capital efficiency and accordingly value. In terms of CapEx. Back in the second quarter of 2012, we spent 2016 million in the Mississippian. This includes drilling completion cost, salt water disposal, facilities and workovers. And with this capital we drilled 91 producing wells. In the second quarter of '13, we spent $224 million and drilled 127 producing wells. So year-over-year we spent 4% more CapEx and delivered 40% more or 36 additional horizontal Mississippian producing wells.

The same trends extends to our salt water disposal facilities where we are gaining efficiencies. The 40% more horizontal wells in Q2 were brought online with 50% less salt water disposal spending. As a consequence, our ratio of producers to salt water disposal wells drilled during the quarter has increased to 12.5:1 from 4.5:1 in the same last year. In total, we are drilling more wells with approximately the same amount of capital. These wells are requiring less infrastructure and production rates are coming in at above our type curve expectations.

On infrastructure, these 2011 and 2012 early investments in both electrical and salt water disposal infrastructure are paying off. At year-end, we will have approximately $650 million invested in this infrastructure, which is proving to be a material competitive advantage in the play in terms of our lowering our cost, consolidating leasehold within our focus areas and offsetting our best producing wells. We have said before that this infrastructure is a potential source of capital in the future, but for now we intend to continue building out the system and leverage the competitive advantages that provides us the economies of scale and lowering our cost structure.

Our Gulf of Mexico business, our strategy of low risk recompletions, augmented by selective PUD drilling opportunities is delivering consistent returns on production. While we had some pipeline shutting issues that impacted the second quarter, we still expect this asset to average around 28,000 barrels of oil equivalent per day for the full year, approximately 10% decline from 2012 production of 31,000 barrels of oil equivalent per day for the year. Eddie will walk through some of the G&A numbers in greater detail. But in the second quarter our G&A, adjusted for onetime items, was approximately $45 million. We are confident that we will achieve the $150 million run rate later this year through reducing non-critical and non-E&P spending.

As we outlined in our first quarter call, a primary reason for our change in the capital program for 2013 was to lessen our cash flow shortfall and provide clear funding visibility for two years. We believe this is the right position to be in, as we can fund our growth from current liquidity and predictable cash flows from operations with limited variability due to our strong hedge position. Reducing this gap further in the coming years is a major focus of ours, and beyond 2014 we have talked before of the funding options we have available. Joint ventures, monetizing our infrastructure assets or selling royalty trust units. We constantly evaluate all these options and in the coming year we will be more concrete on our plans there.

Currently we have $1.8 billion of liquidity and a leverage ratio of 2.4 times which is a very comfortable place for us. Also highlighting the great work of our teams are improvements in well cost and LOE. Where in this quarter we achieved record lows for both. It's the combination of these efforts that’s making us successful in the play. Lower cost, improved capital efficiency, better well results, and testing new zones. And as these results repeated over time, that would drive our performance and significantly improve our net asset value.

Another thing about the Mississippian I think that’s often overlooked and not given proper attention, is that to be effective in this play requires size and scale, contiguous acreage position, infrastructure and low costs, all of which we have. We have seen many others players have a couple of these pieces but not all, fail to be successful in the play. And as these move out or shift their focus, that provides more opportunity for us.

Looking forward to the remainder of the year and through 2014, our vision for SandRidge is to continue to capitalize on our position in the Mississippian play, where we are undoubtedly the best operator. Have the lowest cost and the most infrastructure and an attractive leasehold position. We will exploit these competitive advantages in the Miss to increase our critical mass of production, expand our focus areas, find new zones and opportunities and bring an additional capital to accelerate and grow our net asset value.

Finally, we intend to accomplish all this by being predictable and consistent in terms of the capital we invest, the volumes we will produce, the expenses to produce these volumes and the overhead to run the business. It's critical that we meet or beat our goals consistently. And we believe that over time the market will reward our shareholders for this.

Now let me turn the call over to Dave Lawler.

David Lawler

Thanks, James, and good morning to everyone joining us on the call today. As outlined in our second quarter earnings release, the Mississippian offshore and Permian business units continued to deliver strong results. And while we are pleased with the numbers themselves, we are also pleased with our progress on three key initiatives which are serving as the catalyst of the improved performance. First, we have significantly increased our production in the Mississippian business unit. As James pointed out, we delivered 111 wells to first sales with an average 30-day IP of 377 BOE per day. This rate is 39% above expectation. If you recall from our Q1 earnings release, our average 30-day IP was 21% above expectation. So we are pleased with this sequential increase.

We attribute this production improvement to our sub-surface characterization and modeling efforts. Our model is based on the data collected from over 850 horizontal wells, 126 disposal wells, 13 hole cores, horizontal formation image logs, and recently acquired 3D seismic covering 183 square miles. We’ve analyzed this data and formulated seven value enhancing variables that help plan our well planning process. One of these variables for example centers on the natural fracture systems and enhanced hydrocarbon recovery. When combined, these seven variables allow us to high grade our projects during the well selection process and by identifying the specific area, depth, zone and artificial lift technology required to maximize value.

Second, we have significantly reduced our drilling and completion costs. As highlighted, we decreased our well cost from $3.1 million to $2.95 million during the quarter. This $150,000 improvement increases our rate of return from 44% to 50% and increases the number of wells in our development portfolio since more projects now exceed our capital investment threshold. Approximately $100,000 of these savings was achieved through the redesign of our well site production facility and is a permanent reduction in our structural costs. The additional $50,000 is linked primarily to pad drilling operations and the continued focus on safely improving drilling speed. As an example of this focus, we drilled eight wells in less than 12 days and five of the eight wells using rotary steerable technology.

Well cost reductions have become significant and impactful. Over the last two years, the Mississippian business unit has decreased costs of our wells approximately $900,000 each. In some areas we’re drilling for 50% less than our competitors. During the same period of time, we have established cost control measures and processes that have narrowed the variance between the field estimates and the actual invoices of our wells to less than 1.5%.

The $2.95 million average well cost also includes the installation of 62 electric submersible pumps or 49% of the total well count for the quarter. ESPs typically cost around $250,000. So without any ESP, well costs are around $2.7 million. We believe we can secure additional gains in the next six to 12 months. The only caveat we would add to our drilling and completion costs going forward is that it may fluctuate due to the number of ESPs employed, pad wells drilled and the number of stages required to adequately stimulate the type of reservoir we are developing.

In addition to improved production and capital efficiency, our operating cost is now at a record low and is our third key initiative. Due to significant front end engineering and field management expertise, we have eliminated almost all trucked water in the field, except for appraisal wells and have materially reduced the number and switched the type of generators needed to support the operation. As such, lease operating expense decreased to $7.38 per BOE or 22% below the second quarter of 2012. This translates into savings of $8.8 million for the quarter.

Beyond production, CapEx and OpEx improvements, our stacked pay testing program achieved success during the quarter. We drilled five horizontal Mississippian wells in new zones in areas directly offsetting existing primary production. These five wells delivered an average 30-day IP of 255 BOE per day, which is in line with expectation. Three additional test wells were drilled and completed with mixed results. We continue to monitor the production of these wells and have modified several future projects based on the individual outcomes observed.

As discussed in the past, we have developed the upper zone of the Mississippian as our primary target. With the expanded appraisal and stacked pay testing program, we have confirmed that the middle Mississippian is highly prolific in certain areas of our lease position. As such, we drilled and completed a number of middle Mississippian wells in the quarter as the first zone developed. Eight of these wells delivered an average 30-day IP of 708 BOE per day. And as part of the drilling and evaluation process, we identified development potential in the upper Mississippian zone. We believe the infrastructure -- with the infrastructure already in place, the upper zones may be added for minimal cost. In addition to the Mississippian task, we finished drilling a third horizontal Chester well, which is expected to achieve first sales later this month.

In our Kansas focus areas, we aggressively applied our subsurface model in targeted areas with natural fracture systems for development. To date we have installed 15 open hole packer systems that will allow enhanced production contribution from the natural fractures. In addition, we installed ESPs at 90 degrees to decrease flowing bottom hole pressure as low as possible and maximize oil recovery. To complement the open hole packer systems and horizontal ESP in installation, we pumped alternating fracture stimulation cycles to increase the fracture density around the horizontal well bores. We are encouraged with the early results of this program and look forward to sharing more information with you in the coming months.

During the quarter, the development teams continued securing additional leases in our project areas. Through a combination of the pooling process, strategic acquisitions, and acreage trades, we were able to gain control of 48 highly productive sections. As each operator in the Mississippian continues to delineate their position, it allows us trade opportunities wherein we exchange acreage outside our focus areas for acreage inside to take full advantage of our existing infrastructure. This activity is leading to our dominance in multiple focus areas.

Beyond the Mississippian growth engine, our offshore business unit continued to generate strong production cash flow. The asset delivered an average rate of 28,743 BOE per day with 53% liquids. We achieved this rate in spite of deferring 70,000 BOE related to pipeline curtailments. The team performed six low risk recompletions delivering 630 barrels of oil per day and 6.2 million cubic feet of gas per day. In addition, we finished drilling Green Canyon Block 108, Well #A21. The well found pay in the upper Pliocene (inaudible) with no apparent water contact observed. The final phase of the completion is underway and we expect to achieve first sales by the end of this month.

We were also a 25% non-operative working interest partner in a discovery well targeting Miocene age reservoirs that were identified with 3D seismic and AVO technology. The well encountered commercial quantities of hydrocarbon and we anticipate first sales in early 2014. We planned to operate two rigs in the Gulf during the third quarter, one rig will remain on the Bullwinkle platform and is scheduled to drill two wells by the end of the year. And the other rig will drill two wells, one in High Island and one in South Marsh Island. We also plan to operate or participate in another 10 recompletions.

The Permian asset also continues to improve results. Since the beginning the year, the team has decreased drilling and completion cost from 700,000 to 600,000 per well by continuing to optimize each step of the well delivery process. In summary, we are making steady improvements across the business and we are working to generate additional value from our Mississippian asset through the stacked pay testing program. Our business units have delivered strong results during the quarter, so I would like to thank the entire team for their laser focus on safety and bottom line results.

Thank you again for joining us today. I will now turn the call over to Eddie LeBlanc, our Chief Financial Officer.

Eddie LeBlanc

Thank you, Dave. This being my first earnings call as a member of the SandRidge team, I am extremely fortunate that our Mississippian production and our execution on operating cost savings [initiatives] have not only allowed us to exceed consensus estimates in each category, but have also provided strong financial results for me to discuss.

Our second quarter adjusted EBITDA of $268 million is basically flat not only with the $270 million of the first quarter of 2013, but is also flat with the $269 million of adjusted EBITDA reported in the second quarter of 2012. However, it compares very favorably with those periods on a pro forma basis considering the divestiture of the Permian assets in the first quarter of 2013 and the acquisition in April of 2012. On a pro forma basis, the $268 million of adjusted EBITDA in this quarter exceeded both the $219 million in the first quarter of 2013 and the $186 million for the second quarter of 2012, a 22% and 44% increase respectively.

Our last 12-months pro forma adjusted EBITDA is $897 million. Our adjusted net income of $44.6 million for this quarter results in adjusted net income per diluted share of $0.08 as compared to $37 million of adjusted net income or $0.07 per diluted share for the second quarter of 2012.

Adjusted operating cash flow for this quarter is $176 million as compared to the $182 million for the first quarter of 2013 and $223 million for the second quarter of 2012. It is important to remember that in calculating adjusted operating cash flow, we only adjust for cash received or paid on certain commodity derivatives and for changes in operating assets and liabilities and not for the effect of one-time items. The admirable operational performance that Dave has reviewed with you is the primary cause of these improved financial results.

Our overall company performance is best illustrated by the 5% oil and NGL production increase in the second quarter over the first quarter of 2013 on a pro forma basis. Additionally, the 20% increase in Mississippian production over that same period added $45 million of revenue to the second quarter of 2013. 20% decrease in LOE per BOE in the Mississippian illustrates benefits realized from planning and engineering well locations and availability of infrastructure.

In addition to our operational improvements, our hedging activities and redemption of debt earlier this year also benefited our results. Realized gains on derivative contracts totaled $17 million for this quarter, with all hedges adding 450 per barrel or 5% to realized price.

Interest expense was approximately $25 million lower than the first quarter as a result of the redemption of the 2016 and 2018 senior notes following the closing of the Permian divestiture. The recent changes in personnel and strategy of our company have resulted in a large amount of charges for one-time items in this quarter. We expect these types of charges to subside in the third quarter and be at least substantially complete by the fourth quarter of this year.

Noteworthy adjustments used to arrive at adjusted EBITDA for this quarter were severance expense of $107.7 million, $14.7 million of expense associated with the new incentive compensation plan, $15.6 million of impairments of midstream inventory as well as write downs of drilling and other corporate assets held for sale, $7.4 million of solicitation expense, and unrealized derivative gain of $85.9 million and various other smaller items totaling less than $2 million.

Capital expenditures were $387 million for the quarter, which is a decrease of over 30% from the amount incurred in the second quarter of 2012. This quarter’s capital expenditures illustrates our advancement in capital efficiency as a greater percentage of this quarter’s capital is invested in assets that will directly generate revenue. Only 27% of the first six months capital was dedicated to leasehold and infrastructure as compared to a 52% dedication in the first half of 2012.

Our financial position remained strong, with net debt of approximately $2.1 billion, consisting of $3.2 billion of senior notes, offset by $1.1 billion of cash. Liquidity remained solid at $1.8 billion as our credit facility availability is at $746 million, net of outstanding letters of credit. Our leverage ratio to net debt to pro forma last 12 months adjusted EBITDA at June 30th is 2.35 times. Although our net leverage will be increasing over the coming quarters, we are comfortable with where leverage will trend over the next couple of years given our liquidity, our strong oil hedge position, our growing Mississippian production and cash flows and our lack of near term maturities.

We took advantage of the recent rally in crude prices and added hedges of just under 500,000 barrels at an average price of just under $98 per barrel in 2013 and 2014. Our gas position remains essentially unhedged after 2013. You already heard, we have updated our guidance for 2013. Our strong well performance and lower well cost encouraged us to increase our projected oil and liquids volumes by 5%. Our projected gas volumes decreased by 1% due to higher volumes of natural gas being processed and liquids extracted. Combined, this results in an increasing guidance to 33.3 million barrels of oil equivalent.

Our improved drilling and completion efficiencies allow us to maintain our prior capital expenditure guidance of $1.45 billion. Additionally, we updated our differential forecast widening our oil assumption to $9.50 per barrel, reflecting an increase in NGL recoveries and tighter LLS differentials relative to WTI for our Gulf of Mexico business.

G&A adjusted for onetime items totaled $45 million for the quarter or $5.40 per BOE. We remain confident in our expected $150 million run rate by the fourth quarter as this second quarter adjusted G&A included approximately $5 million of compensation to personnel that are no longer with the company and will not likely be replaced. This encouraging decline as compared to the second quarter of 2012 combined with our increased forecast for production volumes, allowed us to lower our guidance range for G&A by $0.10 per BOE. Additionally, we lowered our per unit guidance range for interest expense by $0.20 per BOE to reflect the increased forecast of production volumes.

While our LOE per BOE of $14.03 was below the low range of guidance and does reflect our improve operating efficiency, we have not adjusted guidance for LOE per BOE. We remind you that in the fourth quarter, we will accrue for a CO2 under-delivery for the Century Plant that will likely be between $29.5 million and $36 million. This will result in an increase in LOE per BOE of about $1. Also please keep in mind that as a part of our strategic direction review earlier this year, we will continue to reduce our Mississippian rig count to average 22 rigs running for the second half of the year, which is below our second quarter rig count of 26.

At this time, Tahisha, we would like to open up the question and answer period of the call.

Question-and-Answer Session

Operator

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

Neal Dingmann - SunTrust

Say, you guys, James for you or David, just wondering on the -- obviously great results on this middle horizontal Miss, was wondering just if you would look at the acreage, any idea of just kind of what percent or total acreage you might have potential for this type of grade play.

David Lawler

Hi, Neal, this is Dave. We won't give a number at this time because we are still kind of in the early portion of developing the different zones and the testing program. But we found one area that seems to be pretty strong and so we are just continuing to push the envelopes of that particular region.

Neal Dingmann - SunTrust

Okay. And then obviously, you had mentioned Dave that type curve obviously, just on the average is now at the -- or it looks like the 30-day IP was up to 377. I guess what I am wondering, will you put out any time soon, you know had the type curve overall improved or just your thoughts on average type curve value improvement.

David Lawler

Neal, we won't comment on kind of type curve at this juncture. Every year kind of at the end of the year is when we kind of revise or make an edits that are needed. So at this point we are just encouraged and we will just continue to watch the wells and then as we kind of close out the year, we will go through a formal process with our team and our auditors and come up with that answer.

Neal Dingmann - SunTrust

Okay. And then just....

James Bennett

Just on the stack pay, if you look on our presentation that we have up on the website, we have kind of detailed map in there where we show the different members of the Miss, upper, middle, lower and how that extends across the play. So while we don’t have specific acreage, I can give you an idea of the stack potential that we see really across most of our leasehold.

Neal Dingmann - SunTrust

That helps. And then lastly, just again now, kind of with Eddie and James that you had mentioned about cutting the cost I guess a little bit, or just overall spending. Just wondering on any thoughts you could give on potential acreage you think you will keep between sort of now and sort of on a end of the year exit rate?

James Bennett

In terms of acreage that we will keep?

Neal Dingmann - SunTrust

Yes.

James Bennett

Yeah, let me give you -- let me just talk about acreage for a second, give you a few stats. You know with about a 425 well program, we can hold between 200,000 and 250,000 acres annually. Kind of depending on how many second and third laterals we are drilling. So that’s on an annual basis. And on the total play, in 2013 we have 250,000 acres that are expiring. We have extensions on 60% of those at $131 an acre. And we think we will extend probably 75% of that 60% if that makes sense. So if we extend it all that would be $20 million. In 2014, for the whole play, we have 740,000 acres expiring, but we have extensions on 80% of those at $127 an acre. That would be $75 million. We think our budget next year in land will be in a similar zip code of $100 million.

In terms of what we’ve HBP’d because we get that question too, for the total play we’ve HPB’d about 17% of the acreage, 40% in Oklahoma and 7% in Kansas. And so that’s the total play, Neil. So let me just talk about the focus areas for a minute where we have a 925,000 gross with 615,000 net acres and that’s roughly 200,000 on a net basis in Kansas and 420,000 in Oklahoma. We’ve HBP’d 42% of the focus areas, 48% in Oklahoma and 28% in Kansas. In 2013 we have 170,000 acres expiring in the focus areas again. We have extensions on 42% of that at $162 an acre and we anticipate we’ll extend probably 80% of those. In 2014 we have 150,000 acres expiring in the focus areas. 42% again we have extensions on and that’s $271 an acre and that would be $17 million if we extended it all.

So between the acreage that we’re going to HBP by drilling, the extensions that we have which are very reasonable again in the $130 million range and the land budget we have which we’re very comfortable about our land position ability to keep what we want. Now we will let some land expire that we don’t plan to drill or is not prospective or we haven’t had positive results. But what we’ve also been able to do is add in acreage. Year to date in our focus areas, we’ve added 35,000 acres at about $700 an acre. So about $23 million and these are in the best areas of the play that we like, offsetting our best producing wells. So while we’ll let some acreage expire, we’ll renew acreage that we like and we’ll add in even better acreage. So I know it’s a long answer, but I hope that gets some of the acreage and HBP and extension data out there.

Operator

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

Charles Meade – Johnson Rice

I’d like to ask a little more about the middle Mississippian zone and try to decompose that 710 BOE average. And specifically one, could you give us the product split on that average? And then the second thing I’m wondering there is what the variance behind that average is and specifically if there’s one well that’s really bringing, pulling that average up or if alternatively those wells are pretty tightly clustered around that average.

David Lawler

Hey Charles, this is Dave. Just the first part of that question, the split is approximately 45% oil. So consistent with what we’ve seen with the rest of the play. And then in terms of just overall delivery, what we’re seeing is just when we target this part of the zone as we’ve expanded, naturally the primary interval is the one that we want to target first. So as we started the play, we started at the top and then as we started looking at the C and seeing the results that were coming in, we started moving more in that direction. So again what we’re seeing is very strong production. In terms of the repeatability, we are seeing some very tight performance. So overall it looks like it’s very strong and of course we’ll have to watch over time how the other wells come in. but at this point it’s a pretty tight band. We don’t have that production dominated by a single well by any stretch.

Charles Meade – Johnson Rice

That’s great color David and of course it’s early, but it looks like it could be a step change. But the second thing I think you just touched on briefly, but I just want to make sure I understand the nomenclature you use when you’re talking the middle zone. It sounds like what you’re talking about is the Warsaw C and you’re targeting that in areas where that’s not the member right below the unconformity. Is that correct?

David Lawler

That’s correct, Charles. I can see you’ve done a little research on it. Yeah, we use the middle Miss, but that can also – you can use the term C to explain it. But yes, what you see are different process intervals within the Miss itself and even within the different benches. So when we talk about middle Miss, just for clarity we try to break it really into upper, middle and lower, but in this case we are talking about the C.

Unidentified Analyst

Got it. And this will be the last thing I try on this, so if I look at your [sub-crop] map here, what it looks like is that you have got a stretch. Perhaps, it looks like you made right through your core of Woods, Alfalfa, and Grant where that C would be the member that’s not immediately below. So is that kind of your fairway at this point you think?

David Lawler

That’s an area that we are certainly interested in. But you are correct in that as you move to different parts of the play what could be characterized as middle is different than the C. But in particular what we are talking about here, you have identified correctly that the C is the middle in that portion and that’s something we are excited about.

Operator

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

Dave Kistler - Simmons & Company

Kind of want to focus a little bit on the 3D that you have done. Can you talk a little bit about what that’s done for increasing the probability of identifying better performing wells? And kind of on that landscape, talk about it in terms of what that does to inventory? Is that taking up aggregate inventory or is that also identifying areas you don’t want to go to and reducing a section of inventory. Just trying to get a better picture on that?

David Lawler

Okay. Thanks, Dave. I think kind of the key issue with 3D, I think we have always said that as we started the play, we felt like there was sufficient historical production to be able to target the best intervals, the most prolific intervals. And we have found that really to be the case. But as we progress through the play, we are adding in kind of all the tools available to us. So in Q2 we picked up pretty significant 3D survey in one of our project areas. And how we have used that, at least initially there are pretty large fault zones that you can lose circulation in, and so we have been able to avoid drilling some wells that may have been problematic for us.

But we have also seen some trending and some success where production has been higher around some of those fractures. So we are starting to integrate that data and see if maybe we can repeat that performance. Still a little bit early for us to claim success associated with the 3D itself in terms of higher rates but our scientists have been looking hard at it. We have avoided a few wells that are in the area of those lost circulation zones and it does look like we are going to be able to pick some stronger production perhaps off that data. So we see it really as another tool available to our teams and we are going to continue to expand our inventory of 3D.

Dave Kistler - Simmons & Company

Okay. I am just trying to digest that, I know it's pretty early days. In aggregate you feel confident that that’s reducing statistical variability between the wells that you are drilling. Is that a fair statement or....

David Lawler

I think it's fair that I could, Dave. But we wouldn’t say that at this moment but it's our intent that that would be the outcome.

Dave Kistler - Simmons & Company

Okay. And then just looking at the 111 wells that you guys drilled this last quarter. Can you talk a little bit about the statistical variability? Was it tighter than it's been in the past? Any color there would be helpful?

David Lawler

We have reduced the variability. Since within our project areas we have more data, our teams are getting much better. I had mentioned the seven variables. All those things are contributing to kind of tighter performance band. So, yes, we are seeing kind of the result that we had hoped for.

Dave Kistler - Simmons & Company

Okay. And on that 111 wells, it looks like there was little bit of a mix shift of drilling. More Kansas wells versus Oklahoma that probably ties to the [HBP] comments that James made earlier. But was there any kind of statistical deviation in terms of well results in the Kansas area versus the Oklahoma area, of your kind of six core areas.

David Lawler

Typically no. With these focus areas, even if we are on the Kansas side we are seeing strong production as well. So I would say it's fairly typical to what we have seen in the past and would be consistent across the board.

Dave Kistler - Simmons & Company

And then just one last one on the aerial extended at middle Miss, it also looks like that works its way up into Kansas pretty dramatically, but it doesn’t look at least in the map that you’re laying out that that’s as stacked oriented pay zone. Is there a performance deviation because you get shallower up there if you not tested up there yet? Just any thoughts on that.

James Bennett

I think our program in Kansas to date has been very broad. So we haven’t been specific enough to make that conclusion. But as you know that middle member, that specific zone or the C, whatever term we may use for it, it does cross the border and we do think that there’s production in that interval along the whole trend.

Operator

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

David Deckelbaum – KeyBanc Capital Markets

A couple of my questions just to start off is, what's your outlook for the Gulf of Mexico right now as you go into 2014? And given just some the clients that you're seeing so far, what run- rate CapEx do you think you need to put on those assets to keep production flat?

James Bennett

Sure. We did talk about a couple of those of pipeline curtailments and other things we had in the second quarter that impact our production a bit. But we still see year-over-year about a 10% decline in the Gulf of Mexico business. You’re averaging about 31,000 barrels of equivalent per day last year. We averaged about 28,000 this year. We do have the well that Dave mentioned that's about to come online. So again we think we'll average about that 28,000 a year. So I wouldn't extrapolate our first quarter to second quarter decline as how the rest of the year is going to progress. Into '14, I think we'll have a similar you call it $150 million to $200 million CapEx plan. We haven't gone through our full 2014 budgeting process yet. We're doing that now. So we'll come out with an exact plan in the November timeframe. But I would expect something in the $150 million to $200 million range and keep that production relatively flat. If we're at the low end of that we may a small amount of decline in the Gulf of Mexico.

David Deckelbaum – KeyBanc Capital Markets

Could you just remind me how much downtime are you baking in your guidance right now for hurricane season this year?

James Bennett

About 250,000 barrels of oil equivalent in the July, August, September timeframe. August, September, October timeframe.

David Deckelbaum – KeyBanc Capital Markets

My last one just on the successes in this quarter on the IP rate improvements. There was a discussion about the introduction of ESPs and someone else brought up EUR is changing and obviously it's early. But is the conclusion at least from your perspective other than being in the focus area and perhaps there is a little bit more energy there that the increased IP rates are more related to the introduction of ESPs or do you think it's more geological?

David Lawler

Yeah David. We think it's a combination. We've ran a significant number of ESPs in the last 19 months. So just for reference we have 285 in the ground as of today. So there wasn't say it was a slightly higher concentration of ESPs this quarter, but not significant. So really what we're seeing is high grading of the technology that we're using, our sub-surface model coming together and then meeting up the appropriate artificial lift technology for the reservoirs that we're in. So I've heard that and just wanted to spell that that's not the driver. We did have some very, very strong wells come on in the gas lift. One of our 1000 BOE per day wells with on gas lift. So there’s no concentration or overweight of particular performance set that's ESP linked. There’s certainly appropriate in parts of the field and in other parts they're not. So it's just really the correct application in picking the right zone for development.

Operator

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

James Spicer – Wells Fargo

I have a question on your guidance. It looks like your full year guidance implies a slight decline in production during the second half of the year. Your rig counts drops to 22 rigs from an average of 26 in the second quarter. And then in 2014, you are projecting double-digit production growth with an average of 25 rigs. Am I understating that correctly?

James Bennett

That’s right. You got it right.

James Spicer – Wells Fargo

So you are adding three more rigs from the second half of the year and your production is going from flat to declining to a double-digit growth?

James Bennett

Well, keep in mind in the Miss this year, with our new guidance, we will have 70% of liquids growth and 66% total production growth. And that’s averaging that 25 rig count. So if you think about next year averaging similar 25 rig count, again that’s just the Miss, we have slight declines in some of our legacy Permian assets and a slight decline in Gulf of Mexico. But, yes, we can get to double-digit production with that 25 rig count next year.

James Spicer – Wells Fargo

Okay. Great. And you talked about this for the Gulf of Mexico in terms of how much CapEx you thought you might need to spend to just keep production flat. What do you think that number would be for total corporate production?

James Bennett

You know it's not really a model that we run. We are trying to grow our production and net asset value and deploy our capital to get the best return for the shareholders. So we don’t really have a number that would be a case that would be flat production. It's not something we look at it this time. If the world would change and commodity price environment to change, or capital availability would change, it's something we would look at but it's not something we have right now.

James Spicer – Wells Fargo

Okay. My final question is, your net leverage is obviously going to be increasing here over time. Just wondering what your comfort level is in terms of how high you would like to see it go before you would want to address that.

Eddie LeBlanc

We are pretty comfortable at 3.5 times. I think we get nervous as it exceeds that and we would only do it for a short period of time. And we would address the issue directly prior to getting the 3.5 times.

James Bennett

And you know the leverage, you have to take a lot of variables into account there. When your debt maturities are coming up, we don’t have any until 2020, how hedged you are. If I am completely unhedged, I am pretty nervous at 3, 3.5 times. If I am completely hedged for a couple of years, it gives me a little more cushion. So I think there is a few other variables that go into that. It just depends on those.

Operator

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

Duane Grubert - Susquehanna

You guys are doing a lot of really interesting experimentation in use of stuff like the [rotary steerables] and all that. I have heard somewhere that some operators are trying vertical wells. And I would like you guys just to comment on, is there any applicability of vertical in the foreseeable future.

David Lawler

Yeah, Duane, this is Dave. We don’t see the primary development as vertical. We do see segmentation or compartmentalization of the reservoirs and we think that you get the highest rate of return from a horizontal development. That said, there may be parts to the field where verticals could work. We have drilled some verticals, we will probably drill some in the future. But as you can see by our CapEx program and where it's being spent, primarily we think it's the horizontal play. But we do know people have drilled some verticals and done well and we might drill some as well just depending on the situation.

Duane Grubert - Susquehanna

And then in terms of sub-zones, Devon's out there this morning revealing its Woodford development. I know you guys in the past have acknowledged that there is some Woodford potential out there. What's your thinking specifically on the Woodford as where you are at in terms of gathering it into your thinking?

David Lawler

Okay. Great. I am glad you asked the question. We do have significant amount of Woodford acreage in our play. Very much similar to Devon's, particularly in Grant County. So we are actually a partner with Devon on one of those wells, or at least one of their wells in the area. And we actually spud our first Woodford well this week. So obviously it's very early and not something we really want to talk about until we get further down the path. But as we see this area is certainly prospective for Woodford.

James Bennett

And Duane if you remember, we talked about the Woodford potential is part of the stacked pay program at our Analyst Day back in February. So it’s something we've been working on for quite a while, getting it mapped out, getting the locations together and it’s something the team has done a great job putting together. And as Dave mentioned, we're starting on that program this quarter.

Duane M. Grubert – Susquehanna Financial Group

And then finally, in the Gulf of Mexico where you have chosen to do some exploration work, how might we think about you doing a proportion of your Gulf of Mexico program as exploration? How do you make that allocation choice? And might we see you do incremental acquisitions given a lot of property acquisition activity out there lately?

David Lawler

Sure. So we'd caution the investor group that we're not out drilling sub-detachment wells by any means. But we do have a significant amount of acreage that we have 3D seismic on. And so we will participate in exploratory wells that are in and around our existing production. They may or may not be of our own, but they could be others. And so we'll be conservative with that exploration program. But certainly where we feel like it's a lower risk opportunity we would pursue that. In terms of acquisitions, the team does look at small bolt-on acquisitions and certainly there is room for expansion as those make sense. So James, did you want to follow up on that?

James Bennett

We do look at deals, Duane, in the Gulf of Mexico. They also have to compete with capital for the Mississippian and the rest of our program. We could boost our production quite a bit if we just wanted to do bolt-on acquisitions in the Gulf. But we want to make sure that we're deploying capital in the best way and developing out the Miss in a balanced program with the Gulf.

Operator

Your next question comes from the line of Adam Leight from RBC Capital Markets. Please proceed.

Adam Leight – RBC Capital Markets

A lot of stuff has been covered, but I'll just maybe tidy up. If I missed it, just want to get a sanity check on when you thought the production would bottom out and start to turn up again. Are we looking at second quarter next year?

James Bennett

Next year or this year, Adam?

Adam Leight – RBC Capital Markets

Well, if we're looking at declines based on your guidance, for this year. We start -- do we bottom out end of year, early next year and then start to creep back up again?

James Bennett

I see a question Thank you. Sorry. Yes. We hit the trough in production this year and start growing again certainly in the first quarter of next year. That's correct.

Adam Leight – RBC Capital Markets

Okay. And on the -- if I missed this also on the middle Miss zone, did you A, give D&C cost? Is it pretty similar?

James Bennett

It is. It's right in that 29 to 30 range with submersible pumps.

Adam Leight – RBC Capital Markets

And what about water, is that also looking to be similar to what you're seeing in the other zones?

James Bennett

Yes.

Adam Leight – RBC Capital Markets

And then more on water, you've increased your ratio of producers to water wells. What's the maximum you've seen so far and what do you think is an optimal ratio if there is a consistent?

David Lawler

We're clearly over 10. There may be areas where we’re a little bit higher than that. But I think just ultimately the system is going to serve us well in that all of the SWDs or a good portion of the SWDs are connected together. So even as you extend the field you can continue to add wells and put it into the existing systems. So we've got two opportunities here. There is one of drilling additional wells within the focus areas and themselves. And then as we expand out, acquire others in the area, and then we can also flow back to that set. So I really think that 20 horizontals to one producer is possible and really perhaps higher than that as we proceed with the development and the water rates fall off over time. So it's a valuable system to have.

Adam Leight – RBC Capital Markets

And then have you gone anywhere on the monetization effort? Have you had any interest? Have you had any discussions or is that just on holed for a while?

James Bennett

We have discussions, Adam, but it's really on hold. We think right now that the value that that system gives us in terms of keeping our cost low and consolidating the best acreage positions in the play offsets any need to monetize it right now. We're still investing capital in it. And we’ve still got it set up where we could monetize it at some time, but not something we are going to do right now.

Adam Leight – RBC Capital Markets

Okay. And then on the land acquisitions, particularly in the Miss. Is this more in the six core counties, is it tuck-in acreage?

James Bennett

Yes, it is. We have added about 35,000 acres in the focus areas. We have about another 30,000 acres that we have added year-to-date in the rest of the play. A lot of that was just rollover acreage from the leasing activity last year that closed this year. But going forward, a vast majority of this tuck-in acreage, whether it's pooling or buying leases, has been in the six county focus areas.

Adam Leight – RBC Capital Markets

Okay. And then lastly, just remind me, what you think your inventory is on drilled locations in the six core counties at this point.

James Bennett

It's about 3000, roughly 3000 locations. That’s about 615,000 net acres.

Operator

(Operator Instructions) Your next question comes from the line of (inaudible). Please proceed.

Unidentified Analyst

Just wanted to ask, most of my operating questions were answered, but from a general perspective, cash flow, you talk about you are comfortable at 3.5 times leverage and if we sort of project it out next year, the Street has you burning around $1 billion of cash. You have around $1 billion of cash now and that gets you to about 3.5 times leverage if your EBITDA goes up a little bit. So what happens in 2015? Do you burn another billion in 2015 or how should we think about that year? And if so, what's your strategy to bridge that funding gap? And then my second question is, if that’s the case, should you find a larger partner out there to either merge or sell to? Thanks, again.

James Bennett

You are welcome. Let me address in a couple of ways. Yes, we do have a billion of cash right now but we also have an unused revolver of $775 million. We think we could even expand that revolver if needed. So it's that liquidity that gets us through 2015. So we think we have got 2015 covered as well. Also our EBITDA and cash flow will be growing over this time. So our funding gap is shrinking every year. That being said, funding past '15 is something that we think about often and we have talked about the other monetization tools we have. Which would be, maybe our infrastructure system that could be sold or MLPd or monetized. There is possibility still to do more joint ventures in the play. And we have royalty trust units that we can sell and there are other options available.

So post '15, we do have several levers that we can use to fill that gap. I think we are comfortably funded between now and then with our available liquidity. And in terms of longer-term, should we merge into another partner? We will do the best thing for the shareholders. We think the right course right now is to take this capital and deploy in Miss where we are seeing very good returns.

Unidentified Analyst

But I mean you would have to -- drawing on the revolver wouldn’t help you keep your leverage at 3.5 times, right. So I guess that’s -- as a bondholder I am just trying to figure out, in 2015, how you stay within your guidance of 3.5 times leverage. I mean you have to get your EBITDA up 25%-30% if you are adding a billion of revolver debt and you are spending your cash in 2014. So just from that perspective as a bondholder, I am thinking maybe this is better off in the hands of a larger company or maybe, or I am missing something. So if you could just address that.

James Bennett

No, I think you have missed anything. All I would say is, you know 3.5 times is a comfortable spot to be and should we bump up against a little higher than that for a short period of time, that would be okay. Again, it’s going to depend on our hedges, our bond maturities, commodity price environments, other things. Keep in mind that as our production grows, our oil is growing at a higher rate than our total production. So we do get some pretty good growth in EBITDA. So I would think that between 3.5 and 4, we are comfortable with that depending on our hedge position. And as we get closer to that, we will look at ways to bring that down, whether it's monetizing, selling something, bringing in some additional capital.

Unidentified Analyst

Or selling, right. I mean just the whole company to a larger company, right?

James Bennett

That’s always an option.

Operator

Your next question comes from the line Craig Shere from Tuohy Brothers. Please proceed.

Craig Shere – Tuohy Brothers

Congratulations on the quarter. A couple of questions, first 3000 locations and the 650,000 net acres. You're still assuming close to three wells per section, not four. Is that correct?

David Lawler

No, we're assuming four, but we have about 550 wells drilled in that focus area. So I'm rounding a little bit. I think if you do the exact math you get the 3800 locations back off 550. So you'd be at 3200 locations. I'm just calling it approximately three.

Craig Shere – Tuohy Brothers

Okay that's fair. And of course -- then of course we have stacked pay potential.

David Lawler

Yes. So I'm just talking about single zone locations here when I say 3000. If you've got multiple zones or stacked pay that obviously multiplies that number.

Craig Shere – Tuohy Brothers

Fair enough. I want to understand a little more of this 25 average rig count this year and next. That's one way to look at it in terms of HBP’ing a specific amount of property that maybe you're comfortable with annually and having an equal average between the years. Another way of looking at it is we're ramping down very hard and then we're ramping up a little bit. And I wonder if this is more tracking the drilling liabilities on the trough. So as those dissipate and run out and more and more of your drilling is cash flowing to the C core, that you have more and more comfort raising that rig count. In other words I'm asking about will the direction of an uptake in '14 likely lead to uptake again in '15?

James Bennett

Yeah, it's a good question, Craig. And you're right on the numbers. We can tell you're focused on it. So we finished our drilling obligation for SDT in the second quarter. So that's three rigs that we'll continue to drill, all things being equal, but they will be drilling SandRidge wells, not SDT wells. So while our total production won't change because it's consolidated, they're going to be drilling 100% working interest, give or take obviously our revenue interest wells versus net SandRidge 20% working revenue interest wells. So that, while it's not going to change your production again because it's consolidated, it has a very positive impact on your cash flow. It's go forward to next year.

The SDR Trust I think fulfill its drilling obligation in the first or second quarter. Similarly, you'll have three rigs that would have been drilling SDR wells that will now be drilling SandRidge wells. To go forward to the end of '14, the Permian Royalty Trust will finish its obligation. So again those three rigs we'll be drilling SandRidge wells with a full revenue interest and not a 10% or 20% revenue interest. So you're right. As those rigs roll off the trust, we finish the trust capital obligation. We get a lot more earnings power and cash flow from those rigs than they would have been drilling Trust wells.

Craig Shere – Tuohy Brothers

So there’s two ways of thinking of this. One, staying flat with rigs. You're actually increasing that to SD’s account. Two, as you are increasing that to SD’s account, in other words cash flowing better and better, do you have more and more comfort deploying more and more rigs?

James Bennett

Yes we do. We will always have -- we have comfort now deploying many more rigs and we were at 32 earlier this year. We could deploy more rigs and we have plenty of locations to drill and the infrastructure and resources and team here to do that. It's really a balance between growth rates and our capital allocation, keeping a couple of years of liquidity and keeping our funding in check. So we could certainly deploy more rigs. It's just a matter of capital.

Craig Shere – Tuohy Brothers

Understood. That dovetails pretty well for my next question. You've laid out a very good plan of where the money is coming from for three years forward, two and a half years. But one question is long-term, would you be interested in being opportunistic with the Gulf of Mexico or do you now see that as core?

James Bennett

All of our assets are for sale at some price. We're capitalist. We're here to maximize the share price. If the best -- if the valuations in any part of the business, Gulf of Mexico, Mississippian are high, if people are willing to pay us a good price for those, more than we think they’re worth in our enterprise then, we would certainly look at selling those, any of those, yes.

Craig Shere – Tuohy Brothers

Well, but more specifically, you have repeatedly and appropriately emphasized the need to have financial bandwidth to invest appropriately in the highest return Mississippian opportunity which you seem to be improving quarterly. So given the Gulf of Mexico was originally kind of bit of a 90 degree turn, at some point if you can get out at similar or better pricing than you got in over a two, three year period, would that be an interest or do you just enjoy the free cash flow for the foreseeable future unless somebody gives much better pricing than you paid, you are going to keep it.

James Bennett

I think it's probably somewhere in the middle. We will weigh this option, the Gulf of Mexico with other options, monetizing our saltwater disposal system or joint venture. We will look at all those as we do every month and every quarter. And whichever one is the best option for the company and for the funding, we will look at it. But, yes, is that one of the options available to us to fill the gap post '15? Sure. It's not on the agenda right now, it's not the plan right now, but it's one possibility we have to fill that gap post '15.

Operator

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

Joe Allman - JPMorgan

In terms of the higher rate average well that you drilled in the second quarter, does that also lead to a higher EUR than for the wells in prior quarter?

David Lawler

Hey, Joe, this is Dave. You know we are not going to project at this point kind of an extension to EUR. As you know we just need an amount of time to evaluate a well's performance before we could that. So even with the ESPs, our hope is that we can take the bottom hole pressure down lower over time and ultimately achieve greater returns from the well. But at this time we are not trying to project an EUR increase.

Joe Allman - JPMorgan

Okay. Thanks, Dave. And then in terms of these higher rate wells, how many of those do you have left in your inventory versus the lower rate wells?

David Lawler

Well, I think I would just speak to it from a program point of view. As James mentioned we have close to 3000 wells in our project areas and we would envision that those 3000 wells would match our existing type curve performance.

Joe Allman - JPMorgan

And is the intention to use ESPs on pretty much all the wells going forward?

David Lawler

No. We think we will probably be at that consistent level between 40% and 50% and if we overweigh it in a particular area because we find it's very rich, we could go up to 60%-65%. But I think just kind of going forward from what we see today, it would kind of be a 40% to 50% distribution for the foreseeable future.

Joe Allman - JPMorgan

Got you. And then on the cost side, you lowered the cost from $3.1 million to $2.95 million. If you include infrastructure, what would the apples to apples cost be?

David Lawler

If you include infrastructure?

Joe Allman - JPMorgan

Yes.

David Lawler

We dropped back a significant number of disposal wells for the quarter as well. So I think we would probably layer in another 200,000-250,000, if you wanted to make it apples to apples.

James Bennett

Joe, we would as a round number, $200,000, which is a 10:1 salt water disposal ratio in a $2 million disposal well. I think our wells are a little bit higher than $2 million because we are drilling some deviated to high angle wells, as well as larger well bores. But our ratio is a lot higher, 14:1 in the first quarter, 12.5:1 in the second quarter. So it would be somewhere in that zip code of $150,000-$200,000.

Operator

Ladies and gentlemen that concludes the Q&A portion of this conference. I would now like to turn the conference back over to James Bennett for any closing remarks.

James Bennett

Thank you. In summary, we are pleased with the progress we have made this quarter and think we are set up very nicely for the remainder of 2013 and 2014. I want to thank the excellent work and dedication of our talented teams of employees. Thank you for joining us on this call and we will see you on our third quarter call.

Operator

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

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