SandRidge Energy Inc (SD) 2013 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first quarter 2013 SandRidge Energy earnings conference call. My name is Tahitia, and I will be your operator for today. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session.

(Operator Instructions)

As a reminder, this conference is being recorded for replay purpose. I would like to turn the conference over to your host for today, Mr. Kevin White, Senior Vice President Business Development. Please proceed.

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 defer 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 web site. Please note that this call is intended to discuss SandRidge Energy and not our public royalty trust. Finally, you can expect to see our first quarter 10-Q filed after the market close today. Now I'd like to call -- like to turn the call over to Tom.

Thanks, Kevin. Welcome to our first quarter earnings and operational update. I'll keep my remarks relatively brief, as the quarter speaks for itself.

Our Mississippian play continues to exceed expectations. We have now surpassed consensus estimates for earnings per share in each of the last five quarters, and EBITDA and production in four of the last five, including this quarter. Not only do we continue to beat our production guidance, but we've been able to maintain our best in class operational results by averaging only $3.1 million per well drilling Mississippian wells and continue to believe our costs 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 hydrating 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 picking 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's been created across the more than 200 miles of area that we've drilled, and not just in the focus areas where the majority of the wells are that we drill today are located. Therefore, we will continue to drill mostly developmental wells, but open new focus areas across the vast acreage position the Company enjoys.

We've also moved to test deeper locations within the Mississippian pay section, on the acreage that's within our existing saltwater disposal system. Our SWD and electrical system continues to allow us to lower our operating costs 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 this year. The saltwater disposal system, combined with the electrical system, allows SandRidge to use ESPs without dramatically increasing operating costs, which also drives our rates of return higher.

We have over $2 billion of liquidity in the Mississippian asset base has increased its oil content to 46%. However, we also have 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 at one time over 400 wells offline. I'll now turn the call over to James.

Thank you, Tom. Our 2013 financial and operating results have 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 in more detail the first quarter results, I think it would be helpful to give 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've made changes to our developmental plans, which entailed the high grading of our Mississippian drilling, focusing our capital on the highest return projects, reducing our funding gap, and reducing overhead costs 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 is our belief that these actions will enhance the link between compensation and performance and assure alignment of management and shareholder interests.

We are realizing the benefits from a number of our strengths right now. First, our employees and teams at SandRidge continue to perform exceptionally well. Things like maintaining best in the industry well costs, reducing our infrastructure spending, and overall fostering a culture of continuous improvement. We could not 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-day IPs of over 1,000 barrels of oil equivalent per day. Also, as Dave will discuss in more detail, we have deeper miss 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 lease hold. In addition, these wells can be brought on stream for substantially lower operating capital costs by utilizing existing well pet site 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 plan levels of capital expenditures, where to get the best returns, and what are the appropriate levels of spending and leverage and sources of capital. After performing 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're 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 on high-graded focus areas. After drilling over 700 wells in the play over the last three years, we've identified six of what we consider focus areas, three in Oklahoma and three in Kansas, where we have significantly de-risked a large number of drilling locations. In these six areas, they cover 2.8 million acres and span 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 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 budget 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 on the call today, but all of these moves we're outlining are designed to improve the rates of return on our invested capital. We've already 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 a 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 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, that we're 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% oil 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 that we don't adjust operating cash flow for any one-time items. Notably, we had $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 included 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'll cover a little more on G&A in a moment.

Reductions in our Mississippian well costs 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 the Mississippian, we spent 7% more capital this quarter, but drilled 80% more producing wells. This speaks to our improved well costs, the capital efficiency we're experiencing, and the leverage we have from our prior investments in infrastructure.

We issued updated guidance that can be found on page 8 of the press release and on our web site. 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 reduce 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 rated in Mississippian production and pro forma for the Permian divestiture and offshore acquisition, 13% organic production growth, and 19% organic oil growth.

We've also been focusing on reducing general administrating expenses, and expect G&A to be an annual run rate of $150 million by the fourth quarter of this year. This is approximately 30% below our first quarter '13 run rate and 25% below 2012 levels. I should note that, given the recent consent process, ongoing litigation, and employee severance charges, we do expect several one-time 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 we recently reduced our total debt in connection with the Permian asset sale, redeeming $1.1 billion of senior notes. The debt reduction resulted in an annual interest expense savings of nearly $100 million, extended our maturity profile, and resulted in a reduction in our overall cost to debt. Our 2020 senior notes now represent our nearest bond maturity.

Our liquidity position remains excellent, $2.1 billion at quarter end, consisting of $1.3 billion in cash and our undrawn credit facility. In mid-March, following the divestiture of the Permian assets, our credit facility was reaffirmed, and the borrowing base was maintained at $775 million. Based on our new drilling plans, we expect our existing liquidity and cash flow to be able to fund CapEx through 2015. Our consolidated leverage ratio within the quarter was 2.26 times, which is more than 1.5 turns lower than the level a year ago. We are very pleased with our liquidity, leverage, and overall financial profile right now.

The earnings release contains our updated hedge position through 2015. We have 9.5 million barrels of oil hedged with swaps through the remainder of this year at an average price of $99 per barrel, and nearly 24 million barrels of oil hedged in 2014 and 2015. We also took advantage of the recent gas rally, and began hedging natural gas in March, adding 43 bcf of swaps for the remainder of the year at an average of 4.10 per MCF. Our gas production beyond 2013 is essentially unhedged, as we feel it's prudent to retain exposure to increases in the back end of the natural gas curve.

In summary, we're focused on three key initiatives in 2013. First, executing a capital development plan that targets high rates of return in our most prolific areas. Two, improving our NAV by testing stack pay intervals and new productive zones and continuing to lower costs in the play. And three, decreasing the gap between our cash flow and CapEx. I've shared recently with our team that there are a few things we must get right in the near term in order to accomplish these initiatives. We need to keep our teams of highly talented people together and functioning as a cohesive group. We need to achieve or exceed all of our guidance numbers, and we must communicate and be transparent, both to our employees and to our external stakeholders. There are obviously a lot of details around these points, but if we can do these three things, our Company employees and shareholders will enjoy success. That's it from our March. Let me turn the call over to 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 continued to drive our production growth, achieving a record average production rate of 39,500 BOE per day. This rate is 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 in 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 and complete 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 to date, we are currently projecting a rate of return of approximately 40% based on recent strip pricing.

In addition to delivering industry-leading operational metrics, we have been working to reduce capital expenditures related to infrastructure. Part of this initiative is focused on the costs associated with handling produced water. We have performance-tested large diameter and high-angle injection wells in order to gain greater exposure to the disposal formation. This initiative paid dividends this quarter. The new well designs, when combined with high-volume injection pumps and a new fluid management system, allowed us to eliminate 12 plants and 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 existing leasehold. This quarter, we were 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 four 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 expectations. 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 sidetrack from Ship Shoal 301, well A1. A1 came on stream January 8, pulling over 1,800 barrels of oil per day and 1.1 million cubic feet per day of gas. It is still delivering robust rates. The second project was an uphole recompletion 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 recompletions between now and the end of the year. We also plan to drill seven projects and participate in two non-operated drilling 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 per 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 the 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've had multiple successes with our new interval and stack 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 in their 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. I will now turn over the call to the operator for questions.

(Operator Instructions)

Neal Dingmann from SunTrust.

Solid quarter. Say, 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 -- if you can give us any idea of what you're assuming, just with production guidance there. And is that largely attributable through a lot of work-overs you're having, or do you see a number of new well opportunities? But again, it's just -- again, that production looks extremely solid there, I was wondering why.

This is Dave. I'll take the question. The basis of acquiring the properties, I think we shared at that time, there's just a significant number of up-hole opportunities. And these are zones that you need to potentially wait for until you drain the lower zone, and then you can come up-hole. And so we do have a significant number of these in the queue that we're going to be working on through the years. So that's really what I'd alluded to in my earlier comments. In terms of the drilling programs, we have high hopes for those. We have several that are working through the system right now. And we think those have the potential to move the needle for us, as well.

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 a 10% or 15% decline in the Gulf of Mexico business with this lower level of CapEx. Does that answer your question?

It does. And then just one last followup, and I'll turn it over. Just as far as -- I don't know if high grading is the right word, when you look at the horizontal Miss as you look at some more of the core locations. But based on, obviously, the reduced drilling rig count there going forward, what do you see over the next 12 or 24 months as far as lease expirations? Are you going to let -- I 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 end of next year. Number one, 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 area as far as on disposal wells. What would you see on average well cost? Maybe David also.

Yes, I'll take the HBP question. It's a relatively new concept that we have in the industry that we need to hold our acreage by production. So just -- let's take a step back and say what we've done. We've bought over 2.3 million acres. We had 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've developed a system that we have in place that you can drill the least expensive wells because of infrastructure in and around this system. And that's -- if you look at our focus areas, you can see of six focus areas that are all fairly tightly together, even though that covers nearly 2.8 million acres, as James says.

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 that -- 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, you -- there's plenty of acreage to buy. Or should you be spending your capital inside your infrastructure? And that's what we've chosen to do as the most efficient way. But it's really around building the infrastructure that makes a difference.

Neal, I can just add a little bit to what Tom said. This year to date, we've added about 35,000 acres within our infrastructure and focus areas at about $400 an acre. So we're -- as Tom said, we can add in these areas, we can -- 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 that does expire this year, over 50% of it we have extensions on. So if we want -- 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 HBP is just not something that we worry about.

And competitors' acreage will be expiring, really, in 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 this 2.8 million acres of land, a large part of that could be ours if we chose to.

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

No. We've come up with guidance for our Miss LOE, and we're sticking with that.

Okay. Very good.

Dave Kistler, Simmons and Company.

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 would be great.

Yes. So the Permian produced about 1.15 million to 1.2 million barrels in the time we own -- I'm sorry, not the Miss, 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 million 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 of 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 half -- the back part of the year, we'll 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'll be for the next few quarters.

Okay. Appreciate that. And then, maybe looking at the reserves a little bit, as you concentrate the drilling more in your core known areas, does that change any of the estimates with respect to the PUDs that you previously signed to maybe areas outside of the core? And how should we think about that going forward? Will it be -- those PUDs quickly be replaced by additional offsets on the drilling you're doing? Or just trying to get a handle on how to think about reserves changing.

Dave, I'll just focus, really, on the PUD aspect to the question. The program, the way we have it lined out at the moment, drills 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're extending the play. So we don't see a situation where we're drilling all PUDs, if that's helpful.

Yes, an we don't have a large amount of PUDs outside the focus areas.

That's very helpful. Appreciate it. Then one last one. With the reduced CapEx, I imagine that that extends the time that your JV carry promotes you on a number of wells. I think previously you talked about at the analyst day it expiring in 1Q '14. Any additional guidance on when you see that expiring?

Sure, Dave. Right now, 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.

Okay. Appreciate that, guys.

Joe Allman, JPMorgan.

Back to the lease expiration issue, based on your 10-K, you have 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. 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 do you plan on holding?

We have in our budget, Joe, $100 million for lease hold and seismic, which the vast majority of that is for lease hold.

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 would you think it be -- you'll be able to hold less than 50% or more than 50%?

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, 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.

Joe, remember, all that acreage listed, that's obviously not all in the Miss. Some of that's in the WTO and offshore. That's across our entire asset base. And the Miss explorations this year are really not material.

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. So I'm not sure if you only have two choices there. So if you can just comment (multiple speakers).

I think we can afford to spend $100 million of lease hold a year if we choose to. We haven't even spent -- we've been under that spend rate currently. And as James 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're going to spend on our acreage money over the next two years is impossible. And I just don't think it's prudent.

Got you. But -- so is it safe to assume that you're probably going to let a bunch of Mississippian acreage go, just because you're not going to focus on it?

I think we'll let acreage go and I think we'll add other acreage.

Got it. Okay. That's helpful. And then turn -- back to the production issue. So based on our model, just preliminarily, 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 just -- if you can just confirm that. And then, does that continue on into 2014, as well? And then -- the declines appear to be both on gas and oil. So it's not just WTO. As you said earlier, some of it's Gulf of Mexico. But is the Miss declining, too, from second to third, third to fourth?

So Joe, we don't give quarterly guidance. I think we've given enough where you can get a bead on it, given what the Permian did for the first quarter, and what the pro forma is and where 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 can get 60% production growth out of the Miss, and going forward, we can target about a 30% production in growth in the Miss with our CapEx level similar to 2013. So with that CapEx level, we can get double-digit total -- 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 the rig count.

Got you. So to average the 25 rigs for the year, I think you ended -- I know it's Company-wide -- you ended the first quarter with 32 rigs, you're going to average 25. I think -- we're estimating roughly 20 in the fourth quarter. Is that -- and can you grow the Miss with 20 rigs? And could you confirm that number and can -- what number rigs do you need to keep the Miss flat, basically?

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 the flexibility with our Lariat-owned rigs to bring those on and back off. So we'll dip below 25, but then I think stable at that mid-20s rate. And we can still achieve, as I said, a nice, very robust Miss growth rate and total production growth rate with that mid-20's rig count.

Got you. Okay. I've got some more, but I'll get back in the queue.

Scott Hanold, RBC Capital Markets.

Actually, on those same lines in terms of activities going into 2014. So it does look like you dipped down 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 into 2014, or is that just the benefit of the JV moving off, obviously requires more of your own CapEx.

You talking about a production ramp or a CapEx ramp?

The production -- I'm sorry, I'm talking about production, year over year you said you're going to be roughly flat. Is that -- that's the plan, right? And so if you actually look at your rig count activity level, where you're at in the fourth quarter appears to run under a rate below that. So is the increase -- or the relative flatness of the CapEx relative to the JV falling off, or do you plan on increasing your rig count in 2014?

When I said flat from 2013, I'm talking about CapEx.

Right.

So into 2014, we estimate, although we're not giving 2014 guidance, but to give you some goal posts, we estimate it will be in the range of 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, we'll average about a mid-20s rig count, as well. And that will be able to deliver double-digit production growth and over -- about a 30% growth in the Miss.

Okay. And so that $14.50 obviously assumes that the JV rolls off by the end of the year? Is that correct?

Yes. Sure does.

That's where I was getting to.

David Deckelbaum, KeyBanc.

I think the question might be for Dave. Guys, as you focus, you talked a lot about high grading today. As you focus on this focus area with 25 rigs, more or less throughout the remainder of the year, is there -- you have experienced some better result there. Is there a percentage-wise number that you use op top of your base case type curve in that focus area?

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

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 did choose a more conservative way to come up with a type curve for the Miss.

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

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

And let me comment on the CapEx. If you just look at the CapEx, taking times of working interest and divide it by the number of wells, it might look like it went up versus our prior guidance for the Mississippian, but it didn't. We're still in that same 3.1 to 3.2 range per well. What you see there by doing that math is, we have about $100 million of CapEx in our Mississippian program this year that is geared towards the appraisal areas. We don't have a well count associated with it. So that's for testing analysis, geologic 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 where we're study and evaluate the play. So I think note that within that Mississippian CapEx, there's $100 million that doesn't have a 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.

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

Sure. And what dollar amount is included now for testing the other stacked pay intervals throughout the remainder of the year?

What was the question one more time?

What -- 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?

It fits within our $100 million program.

Okay.

And Dave laid out the number of wells we're going to use to test those wells. You can just assume normal well costs and normal working interests for those.

Great.

Ryan Todd, Deutsche Bank.

If I could just ask you, on the six core areas -- the six focus areas that you're talking about right now, have you said how much net acreage do you have associated with those areas? And how much of that is held by production?

The area encompasses a total of about 2.8 million acres. We have -- SandRidge net about 925,000 acres in this area. And I don't really -- I don't have exactly how much is HBP.

Okay. And so -- in terms of level, I guess we want -- we've already talked about the HBP issue quite a bit up to this point. If we could take a step back, I guess at the -- from a broader view in terms of what's changed and what's happening on a go-forward basis now, you're still -- the outspend, despite the reduced cash flow, the outspend remains quite significant going forward. And growth is reduced. When you look longer term, 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 will you still consider at some point JVs or sell downs of additional assets to help close that gap more quickly? Or how should we think -- when we think about the larger strategic vision over the next three years, what do you want us to come away with?

Sure. I think we approach it three ways. As you see with the reduced CapEx plan, we're very focused on narrowing that gap between CapEx and free cash flow. So we've taken some measures to shrink it this year. I think as our productivity continues to improve, and our infrastructure utilization continues to improve, we'll chip away 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 out-paces our gas. And that's where we generate most of our cash flow. So we're going to see improvements in CapEx efficiency, improvements in return on capital, which is going to translate into cash flow, which helps shrink our funding gap.

So that's from 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've 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 need -- 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 evaluation and cost of capital tool for us. If we can get robust valuations for any of those, we would look to monetize those to further improve that funding shortfall.

And then keep in mind that it's just over the last year we've increased three new focus areas from drilling appraisal wells, and we're still drilling appraisal wells. So as you -- 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 chose 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 the $100 million that can keep us for many, many years to come, drilling on the acreage that we own or the additions that we'll have. And all within the infrastructure that we have in place. So I don't think to make an assumption that we're through with adding focus areas is a correct one.

Okay. But from a -- in terms of additional -- this is -- you've 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 or steps going forward, or is this where we are? I guess the question is, it feels a little bit on our numbers -- and granted, like we've talked about, there's a lot of uncertainty around future -- how these things are modeled in the future. You've certainly pushed out any coming 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.

I wouldn't consider it a slow process. We've got teams of hundreds of engineer here that are constantly looking at ways to improve well costs, well designs, saltwater efficiency. So we're going to continue to try to drive the costs down, drive the productivity up, increase returns on capital, and generate more cash flow. So I think we'll continue to make moves, and as you've seen in first quarter, that's not going to stop.

Okay. Great.

Charles Meade, Johnson Rice.

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

Yes, sure is.

Okay. Great. 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 collapsed the Gray and Ford areas into one, or if one of those fell off the roster.

Good question. Actually Ford and Gray, I wouldn't say it fell off the roster, but what we've high graded down into really Comanche and southern Kansas. So it's really a question -- it really comes down to infrastructure. We had better infrastructure down in Comanche County, so those two counties are really off the list right now. Not being -- now that doesn't mean we won't pick them back up at some point. But we've moved a little further south.

Right. And so the three focus areas in Kansas, then, would fall in what counties?

Yes, it's Harper, Barber, and Comanche.

Got it. Okay. And then going to the -- going to those -- the additional zones, the Chester, the Middle, and the Lower Mississippian, I think if I heard this right, it was well plans for 240 and 4 in each of those zones in -- and are those 2013 well counts?

Yes. That's correct. That's what we've identified at this point, Charles.

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

Sure. I think it really started as we -- when we drill our -- one of the benefits of having the SWD system is that we do penetrate all the zones in the section as we go down to the Arbuckle. And so we have a pretty large data base that shows these intervals that appear to be productive. So it was something that our explorationists had always had an eye on, and were focused on pursuing probably after 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 a different zone in the general area. And so 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 or may not know, just that 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're cautious as we start off here. We're not trying to expand too quickly or over sell, we're just taking a measured approach. But we were very encouraged by seeing the strong results from these different tests. So what we'll do is continue to test those, and we'll even put some wells on top of each other this quarter. So just for reference, we'll spud three wells this month that will be off the same pad going to different zones. So we're pretty excited about what we've seen so far. The data supports the program, and we just think this is a way to increase our NAV.

Great. That's great detail, David.

Richard Tullis, Capital One Southcoast.

Dave or James, what would the growth be overall if you only spent your cash flow per year?

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

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

That's correct.

And how does that compare to fourth quarter, same parameter?

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

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 of total production in 2014?

I don't think we're ready to give that kind of detailed 2014 guidance yet, Richard. Sorry.

Okay. And would the Gulf decline at a similar rate next year, 10% to 15% under the same CapEx level?

Yes, I think that's a fair assumption.

Okay. And then just lastly, what were the costs of those four test wells in the Chester and the Middle and Lower Miss?

Yes. They were in that $3.1 million range.

Okay.

Duane Grubert, Susquehanna.

Can we start off talking about the saltwater disposal system? You mentioned in passing that you were 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 a few more wells per disposal well?

Yes. That's a great question. We do see that significantly increasing over time. We have made those design changes that we've 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 we're very pleased to be at the 10 ratio, and we see that going as high as maybe 15 or 20. Just to give an example, we have got two wells that normally would take 15,000 a day, 2,000 a day, and they're taking 60,000 a day. So it's pretty significant run-up in injection capability.

Wow. 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 sub-zone or sub-development theme that you're continuing to pursue, as well?

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

Duane, others have drilled Woodford wells. We didn't. We have not drilled Woodford yet, so that's why we didn't mention that.

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?

I think we've --

Yes. Duane, the gas prices -- this is Kevin. The gas prices -- the dry gas prices will actually, over time, show a little bit of decrease as we take the liquids out of it. So we'll -- 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 the 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.

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're doing in terms of instilling a different philosophy at the Company in that you have made some rather big changes? So basically 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 your operating teams?

Just in terms of the plan going forward, I think you'll see more details of that outlined in a 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 the new roles have been at the Company for years, and have been an integral part of our teams, and key to the success here. So these aren't external candidates, these are folks who have been on the teams for quite some time, and have moved into these positions and are working very effectively. So it's not something that we're concerned about.

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

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

Okay.

John Nelson, Citigroup.

Just to follow up on that last question, or that last point on saltwater disposal wells versus producers, the 15 to 20 target. Could you give us some sort of timeframe on that? Is that maybe 2015, or is that more a three- to five-year target?

I think it's probably achievable in the next three years. We're not -- again, not trying to be too aggressive with it, because many times the water rate can fluctuate in these wells. We see a pretty significant spread. So we really -- I'd also mention we have 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 live-type adjustment. And as wells fall off, they may fall off quicker on the water rate, so it opens up capacity in that well. So I do think, over the next three years, we'll see it expand, possibly up to 15. But I couldn't give you an exact target.

No. That's helpful color. And then just one other question. Was curious in this new strategic direction proposed, was that proposed by the new TBG Board members, or was this a plan already in the works that perhaps maybe we should expect further, or rather incremental change still going forward?

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

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

Yes, but I'm not going to speak to what the Board talks about in Board sessions or agrees to. But the Board's been very supportive of all the measures we've taken.

Okay. Great. Congratulations on the quarter.

Adam Duarte, Omega.

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 what the system would look like by year end in terms of volumes and 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?

Let me give you a couple of stats. We have about 123 salt water injectors right now producing about -- or injecting about 850,000 barrels of water a day. By the end of the year it will be -- that system will be over a million barrels a day, and we'll have invested in it about $600 million. In terms of EBITDA, we're not going to calculate an EBITDA that this would bring to a third party. That depends on a lot of things, their operating costs, but also what the charges are per barrel. So I don't think we're going to calculate a number -- an EBITDA number on that for you. And Dave laid out in his remarks the amount -- the number of saltwater disposal wells we're going to drill this year, as we've taken that down from the original estimate.

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

Yes, absolutely, we certainly wouldn't monetize this at something lower than our EBITDA multiple where we're trading as a Company. And if you look at where these midstream-type assets trade, it's certainly at a premium to where an independent E&P company trades.

Okay. 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?

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

Got it. Sorry, I have one last question around the hedges. We've hedged a little bit of our gas here this year. Is that 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?

More of the latter. We're sill fairly bullish on natural gas. We're 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 to 3.7 tcf. 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're -- we have some room here that we might see in the summertime for higher prices.

Okay.

Dan Chandra, DW Investment Management.

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

Sure, Dan. If you look at full-year 2012, we're at about $200 million, I think $198 million of total G&A. Our initial guidance in November called for $216 million. We made some changes in January/February timeframe and some reductions in the mid point of our guidance, and then got us down to $194 million. Now we've made some further reductions, and we're down to $180 million for the full year. Targeting at $150 million exit rate. I think we always look to make improvements in all of our cost structures, keep an eye on G&A. But I think we feel pretty good about the 25% reduction we've made so far.

Michael Schmitz, Ladenburg.

Whole budget assumed you'd have the benefit of about $550 million of drilling carries this year. What is assumed in the new budget? And then any preliminary parameters around what you think the funding gap will be next year?

Sure. In the new budget we have about $440 million of JV carries that we'll use this year. We're not coming out with full '14 guidance yet, so we really can't give you an EBITDA or funding gap number for next year.

Okay.

David Snow, Energy Equities.

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

Sure.

I was going to say, it's a sandstone in this particular area that turns into a limestone as it -- as you move 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 eroding into the Central Kansas uplift, the Chester is just the younger rock, very upper part of the Mississippian, that sits behind or south of the Mississippian before it erodes over the Mississippian.

Okay. And which of those zones in your four wells seemed to give you the best results? The Middle or Lower Mississippian or the Chester?

They were all pretty comparable. Our take is that we're going to see strong results, really, through each of them, and that was the reason for blending them together.

Did you -- you produced them together?

No, we just -- blending the data for presentation purposes.

Yes. And I'm wondering, is the -- I see they have an average of 462 barrels a day, and your other -- your overall average in the focus area was 330. So does it sound like these might end up being more promising targets to go after in time?

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

Is there the same amount of water content in these zones?

We saw varied water cut in the Chester. It was a lower water cut. So that was encouraging.

Okay. And the Chester, you said the western half. Would that be 50% of your focus areas, or what amount of the focus areas historically have been a --

Yes, the Chester doesn't sit in the focus areas that we have. It's a younger rock that -- so it's eroded over the focus area. So that's in an area outside of the focus areas.

So it might become a new focus area, I guess.

Well, it could be.

In general, though, what portion of your acreage might be exposed to these additional zones?

The other zones, the Middle Mississippian and the Lower Mississippian is under all of our existing areas, including the Chester, so the Chester's younger, and they will sit below.

Okay. And how far apart are these? Are they in communication, or are you pretty well separated?

You talking about zones?

Yes.

Are you going to take it?

They're pretty well separated.

Yes, there are shale barriers between each of these.

Okay.

Anne Cameron, HETCO.

Sorry for asking the same question as some of the other analysts, but I'm just a little bit confused about your guidance. To me it looks like it, just as it looked like to some of the others, that your quarter over quarter growth in the back half this year is -- it's flat or it's declining slightly. And you've told us the Gulf of Mexico should decline about 10%, the Miss should grow about 30%, and then I know you have 8,000 barrels a day of other, and I assume that's declining. Can you clarify, is the Gulf of Mexico decline exit-to-exit or year over year? And same question for the Miss?

Yes, the Gulf decline would be exit-to-exit or fourth quarter-to-fourth quarter, fourth quarter of '12 to fourth quarter of '13. And Miss, we've said, our growth this year is going to be about 60%.

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

I think it's year over year, really.

Okay. 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.

Keep in mind that we are taking the rig count down in the Miss, which peaked at 32, down to a little below 25, averaging 25 for the year. So that's going to -- that will impact it, as well.

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

Yes. Yes, it is.

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

If you take the exit rate for the Miss for last year, and where we're going to exit this year, that growth is close to 60%. We just happen to peak -- we happened to hit -- have a higher production here in this first and the second quarter from that higher rig count.

Okay. It's just -- I'm sorry for keeping asking these questions. It's just really confusing because you 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?

Because the Mississippian's 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've given enough pieces to piece it together.

Yes, but 39,000 barrels a day to grow 60% should plenty more than offset the declines of 10% on 30, and whatever it is on the remaining 8. So if that were true, why aren't you growing this year? It -- the math just doesn't seem to add up.

Yes, I'm not sure I follow you. Maybe we should, Anne, take this off line and get into some detailed modeling discussions, if you'd like to.

Okay. Yes, no, that would be great. Second question, could you just give us the oil number for the Mississippian for this quarter? Without NGLs?

Volumes -- six --give us just a second.

For this quarter, Anne? Was that your question?

Yes, that would be super.

Yes, it was -- for the quarter, it was 1.55 million barrels of oil.

Okay. Great.

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.

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 interest in SandRidge.

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