SandRidge Energy Inc (SD) 2013 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the fourth-quarter 2013 SandRidge Energy earnings conference call. My name is Genata and I will be your operator for today.

(Operator Instructions)

As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Mr. Duane Grubert, Executive Vice President of Investor Relations and Strategy. Please proceed.

Thank you, operator. Welcome, everyone, and thank you for joining our call. This is Duane Grubert, EVP of Investor Relations and Strategy here at SandRidge. And with me today are James Bennett, President and Chief Executive Officer; Eddie LeBlanc, EVP and Chief Financial Officer, and David Lawler, our EVP and Chief Operating Officer.

Keep in mind today's call contains 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 the discussion of these measures can be found on our website.

Please note that this call is intended to discuss SandRidge Energy, and not our public royalty trust. Now let me turn the call over to our CEO, James Bennett.

Thanks, Duane. Closing out 2013 and entering 2014, we are delivering the plan we laid out to shareholders last May. The changes that we have made to the business and the asset base are clearly taking hold. I think, in summary, we are executing. I will recap some of the significant improvements and steps forward we have taken the business in the last 12 months, and then tie that in to how that positions SandRidge going forward.

So first, we made the Mid-Con the focus of the business. We sold non-core assets, and we redirected our intellectual capital in dollars into Mid-Continent. Second, we significantly reduced our cost structure. We, for example, our G&A expense in 2012 was $200 million, 2013 was $170 million, and this year it is going to be about $135 million. Third, we reduced the overall level of risk in the business. We took our CapEx from $2.3 billion down to $1.5 billion, kept our leverage under three times, and we high-graded our drilling efforts with significantly less drilling capital and rigs in the extension areas of the play.

Importantly, we improved our capital efficiency and returns. This derisked development plan allowed us to greatly improved our results, both IP rates, reduced variability of well performance, and increasing our PUD type curve.

Operationally, the teams have reduced risks, reduced LOE and well costs every quarter. Taking $50,000 or $100,000 out of our well costs every couple of quarters may not sound like a lot. But when you do that over a couple of years and drill over 400 wells a year, it is very impactful.

And let me walk through on this capital efficiency theme, an example I like to use. In 2013, in the Mid-Continent, and you can get this a number of page 7 of the earnings release, we spent $844 million in the Mid-Continent. That is all in well costs, including all D&Cs, saltwater disposal, infrastructure, workovers, capitalized interest.

So it was $844 million to drill 434 wells. And that compares to 2012, when we spent $927 million to drill 396 wells. So in this improved capital efficiency theme, we spent 9% less capital, and drilled 10% more wells.

Growing our reserves, we had a good year in terms of reserves adds. You will need to bear with us and pro forma out the Gulf of Mexico and Permian for our two divestitures we have done in the last 14 months. But taking those into account, we grew proved reserves to 377 million barrels of oil equivalent, up from 301 million at year end 2012. We produced again, on a pro forma basis, 23 million barrels of oil equivalent, but we added approximately 100 million barrels oil equivalent, net of revisions. That is over 425% reserve replacement. We did that all at under a $12 per Boe finding cost.

Our PV-10 has $4.1 billion, That's up from $2.9 billion. Again, this is all with assets that we own today.

And finally, we expanded our opportunity set by adding to our focus areas. We added over 100,000 acres in a new county, Sumner County. It is a great work of our geology engineering teams to set up a test program, that now turned into full development program. So this target appraisal program we talked about has worked.

So recapping 2013, I won't go into all the details. Dave and Eddie will give you some more in a minute, and you can find it all in the earnings release. But I couldn't be more pleased with the execution of our teams this year. We have exceeded our targets for the quarter and the year, while coming under our CapEx budget.

The Mid-Continent's production is growing. Fourth quarter grew 8% quarter-over-quarter. Our IP rates and production results continue to improve. We are having success in six different zones in our Mid-Continent area. Our 2013 production, again pro forma for the asset sales, was 22.5 million barrels of oil equivalent, and that is a 35% growth on this pro forma production for 2012, which would have been 16.5 million barrels. So again, 35% production growth pro forma year-over-year.

Our PUD type curve improved. The EUR is up 3% total. Oil component is up10%, and the rate of return on the wells improved over 60%. Now each PUD location we have, has a PV of about $2.4 million.

We have continued to optimize our salt water disposal infrastructure. For the full year, the ratio of producers to disposals was 16 to 1, in 2013 that was 7 to 1. We now dispose of over 1 million of produced water a day, and we view this system is a very valuable midstream assets within SandRidge's E&P business. And finally, our costs keep coming down every quarter.

So in looking back at 2013, why is it important to reflect on what we did in 2013? I think that, a past success I believe, is a leading indicator of future performance, and I think we executed and had a very successful 2013.

So looking ahead to 2014 and beyond. Right now, we have got over 670,000 acres in our focus area position in the Mid-Continent, over a 10-year inventory of high return drilling locations, an industry-leading cost structure that allows us to drill these shallow wells for under $3 million each, a 2014 plan where we can deliver over 25% production growth, and a similar growth rate in proved reserves. Given the operating leverage in the business, that is going to translate into approximately a 35% growth in EBITDA year-over-year. And we have visibility into a multi-year plan that is going to deliver similar growth rates.

And terms of what to expect next week at the Analyst Day, I think will have a lot of forward-looking discussion and analysis. Importantly, we are going to have an out multi-year outlook that is going to give longer-term visibility in our asset development and multi-year growth plan. You will hear more detailed innovations coming out of operational teams. You get to meet, and hear from our next layer of management.

Additional thoughts I am going to give on our salt water disposal positions, and asset, sizing this asset and our thoughts on unlocking the value there. It is a formative day next Tuesday, New York, and I hope you will join us in person or either on the webcast.

So in closing from me, here forward we are going to be focused -- very focused on the following: first and most important, profitably growing our cash flows by converting our resource base into cash and asset value; capitalizing on our competitive advantages as our infrastructure and our knowledge base in this Mid-Continent area; continuing to improve our per unit cost measures, that is LOE, G&A, and well cost, just to name a few; driving innovation and creating more upside, just like we did in 2013; finding new zones; success in the appraisal program; well designs and cost innovations. I think our salt water disposal business falls into the same quarter of innovation. We identified a roadblock early in the play which produced water, and invested early in this infrastructure and built a very valuable asset; improving our leverage and balance sheet, we are going to do that through growing our cash flows and asset base; and driving shareholder returns.

Our job as managers is to allocate your capital in the highest risk-adjusted returns and we are doing that. I am confident that if we execute on the things above, our business and our shareholders will enjoy success.

Let me turn the call over to our COO, David Lawler. Dave?

Thank you, James, and good morning to everyone joining us on the call. As we look back on our 2013 performance, it is clear we have made significant progress across the business. We are improving capital efficiency, and creating value by expanding our resource base through a multi-zone appraisal program.

Most importantly, we hit our targets. Not only do we exceed our year end production guidance by 200,000 Boe, delivering a total of 33.8 million Boe, but also spent $26 million less than our $1.45 billion capital budget. The production delivered during the fourth quarter, followed two consecutive quarters of increased guidance.

These outcomes can be linked to a theme shared by the entire organization, that success is measured by meeting or exceeding our corporate targets. With this theme in mind, I would like to thank all of our employees for their exceptional work, and their continual focus on running a safe operation.

Beyond the guidance metrics, we also materially improved our Mid-Continent horizontal well costs and lease operating expense. In the fourth quarter, we delivered 80 wells for an average cost of $2.9 million. This cost was achieved with 85% of the wells being equipped with electric submersible pumps, which typically cost around $250,000.

The latest round of cost reductions are primarily due to redesigned well site facilities and synchronized pad drilling. Looking back eight quarters to the first quarter of 2012, we have lowered total well costs by $1 million or 26% per well. This is a tremendous accomplishment by our teams, and reflects the emphasis we place on rate of return.

In addition to well cost reduction, fourth-quarter operating expense decreased to $6.91 per Boe. This is an all-time low for the Company, and highlights the effectiveness of our development model and front-end engineering. As most wells are connected to local power at start-up and produced water disposal systems are installed prior to the completion date, operating cost is not burdened with the long-term water hauling-- with long-term water hauling or expensive diesel generators.

We are also pleased to report that our year end 2013 PUD type curve for the Mississippian increased by 3% to 380,000 Boe, with the oil volume increased by 10%. At $90 oil and $4 gas, a type curve drilled for $2.9 million yields an NPV of $2.4 million and a 50 -- 57% rate of return.

As discussed on earlier calls, well performance is steadily improving by targeting key reservoir characteristics, and drilling in areas with high frequency of natural fractures. The impact to this refined process can be observed in the average 30 day IP for the quarter. This average was 386 Boe per day or 22% above the 2013 type curve.

In terms of expanding our resource base, our subsurface teams continue to deliver significant value through our appraisal program. As you know, we have been focused efficiently on testing our vast acreage position.

One area of particular interest is the eastern portion of the broader play in Sumner County, Kansas. To date, we have drilled five appraisal wells in this area. The wells delivered an average 30 day IP of 601 Boe per day. This rate is 90% above the 2013 type curve, and establishes the significant potential of the county. As a result, we are planning to drill 45 wells, adding 117,000 acres of high rate of return projects to our focus area. Combined with our previous Mississippian location count, we have many years of drilling ahead.

The Chester program delivered strong results during the quarter as well. We now have five wells online, with an average 30 day IP of 337 Boe per day at 58% oil. To clarify, we brought one Chester well online in the quarter, which delivered a 30 day IP of 589 Boe per day. We have moved three rigs into the area, and expect to have 12 additional wells online by the end of the second quarter. SandRidge is the first mover on horizontal Chester development targeting oil, and we are now moving at full speed to capture value from this new resource.

Aside from the Chester, we have completed two additional Woodford wells. The second tranche of test wells show a marked improvement above the first tranche. One well delivered a 30 day IP of 96 Boe per day at 67% oil, and the second well delivered an average 30 day IP of 190 Boe per day at 85% oil.

More important than the individual rates, our subsurface teams have developed a geologic model that correlates the rock to the increased production. We believe this model will further enhance Woodford performance during the next tranche of wells. We expect to have a total of nine wells online by the end of the second quarter.

As we have shared previously, what makes our asset base compelling is that we have multiple formations to drill, and these opportunities are within our existing lease position. In addition, these formations can be developed with minimal infrastructure costs, since our produced water disposal and electric power distribution systems are already in place.

Shifting now to our 2014 program, as outlined in the presentation linked to our earnings release, we are planning to increase production by 26% year-on-year on a pro forma basis with a capital program of $1.475 billion. The plan includes 460 horizontal wells and 50 produced water disposal wells in the Mid-Continent, and 180 vertical wells in the Permian targeting San Andres formation. This vertical well count will finish the obligation of wells for the Permian Royalty Trust.

In closing, we wanted to share that due to the exceptional work of our field teams, we have been able to overcome most of the serious challenges posed by the winter weather in the region, and we are leaving production guidance unchanged. The primary issue facing our team during the storms was the delay in securing rig [move] permits, but we have adjusted our program accordingly and believe we can overcome most of this nonproductive time. We look forward to sharing more about our appraisal results and capital efficiency programs at our Analyst Day in New York on March 4. I will now turn the call over to Eddie LeBlanc, our Chief Financial Officer. Eddie?

Thanks, Dave. Once again, it is great to be here to provide a financial summary for another good quarter, and a very good year. First, I want to remind everyone that when we speak of adjusted EBITDA, it is net of non-controlling interest. And when we refer to pro forma amounts, we are removing the effects of assets sold, which are primarily the Permian and Gulf assets.

Since it is important to understand that performance of the assets we retained, let's discuss pro forma results. For the fourth quarter 2013, pro forma adjusted EBITDA was $166 million, versus $130 million for the same period in 2012, and the improvement was due to a 27% increase in pro forma production to 6.1 million barrels of oil equivalent.

The fourth quarter of 2013 also included a $32.7 million expense for an under-delivery penalty in connection with the Century Plant. Pro forma adjusted EBITDA for the full year 2013 was $609 million, a 67% increase over the $365 million for 2012, primarily due to a 35% increase in production to 22.5 million Boe, and additionally to our cost reduction efforts such as with G&A expense.

Total capital expenditures for 2013 were $1.424 billion, which was 2% better than guidance, and were also 35% less than 2012. Furthermore, in early 2013, we divested ourselves of the Permian assets, and still we had growth in year-over-year production.

At year end 2013, we had $815 million of cash on hand. Another $737 million was added from net proceeds after working capital adjustment when we closed the Gulf asset sale. So on a pro forma basis, year end 2013 cash was $1.551 billion.

We have made no draws on our bank credit facility. Currently, we only use the facility to cover -- support letters of credit. So the unused portion of our revolver borrowing base is $746 million. Pro forma liquidity at year end 2013 is $2.3 billion. Total debt is $3.2 billion, with the earliest principle reduction due in 2020, and our pro forma net debt at year end 2013 was $1.6 billion.

Our leverage ratio at year end 2013 on a pro forma basis is 2.7. The details of our consolidated hedge position for 2014 and 2015 are included in our earnings release that was published last evening. However, I would like to mention that we have hedged 94% of our 2014 anticipated liquids production volumes, which equates to 95% of 2014 estimated liquids revenue. And we have hedged 65% of our 2014 anticipated natural gas production volumes, which also equates to 65% of net estimated gas revenue.

We are making no changes to our current guidance, which was issued when we announced the sale of the Gulf assets. Although for purposes of clarity, we are now including guidance for adjusted EBITDA for non-controlling interest. After we close the first quarter of 2014, we will have further information regarding our ongoing D&A rates, and if appropriate we will publish any new guidance when we distribute first quarter 2014 earnings information in May.

Operator, that concludes my remarks. Please open the question and answer period of the call.

(Operator Instructions)

Your first question comes from the line of Neal Dingmann with SunTrust. Please proceed.

Good morning. Good report. Say, I just wanted, James on the wells that you outlined, I think the 4 and 60 plus wells, could you give me an idea, of again versus kind of the current quarter versus Sumner County I guess, number one, kind of regionally where are you going to be drilling these? And then number two, I think David mentioned, maybe even Dave want to take this -- mentioned a lot of the - couple of the Chester wells, a couple of new Woodford wells. I wondered in that group how much was just sort of the original core wells you will focus on versus some of these new newer plays?

Okay, Neil. This is Dave. Yes, we are planning as mentioned to do the 45 wells in Sumner. It is really a terrific area. And so, we will push that really as much as we can, and will let the well results guide where we ultimately end up. So we have got -- targeted the 45. But if we see significant success beyond what we are expecting, we will channel more rigs in there.

In terms of the broader play, we are pretty well-balanced. We have about a $50 million appraisal program to look at different sections like the Woodford, the Chester and others, the Marmaton that we have mentioned in the past. So it is really a mix of opportunities. And then, we are pretty efficient at channeling the CapEx in the right direction. So like the Chester, when we see repeated success, then that is where we start flowing the CapEx to.

Okay. And then, what I going to say, I was wondering just on kind of where the plans are to drill in Kansas, where it may be, might be a bit more gassy? I was trying to reconcile that with kind of the guidance that is out there, as far as how much you expect for both the, just overall growth, but also then on just the oil and liquids volumes? How you, I guess, potentially will see that expanding?

Right. Well, the ratio of states is probably around 3 to 1. But we have identified several parts of Kansas that are high oil production. We are the number one producer of oil in Kansas at this point. So it is -- I couldn't speak exactly to product mix changing, but I can tell you that we are trying to get as much oil in the system as we can. And we can give you a little more clarity on that, next week in New York

Okay. And then just lastly real quick, just on the Permian, you mentioned the 180 as sort of, round out or close out the trust. Beyond that then, I know there is some potential there that you all could start continue or to drill some what I would call more so on your own. Will you continue that right on the heels of that, or is that something you will evaluate and then go forward?

We are planning to continue on with the Permian. We have got a great team there, and we will talk a little bit more about that at Analyst Day as well. But there is a significant number of horizontal Clear Fork opportunities and additional San Andres wells to drill. So we do have a machine that is working well for us in the Permian. We have got a great team delivering. So we will continue on.

Perfect. Thank you.

Your next question comes from the line of Amir Arif with Stifel. Please proceed.

Thanks. Good morning. Just a couple questions. First on the water side, the lower salt water disposal drilling that you are doing, is that change due to water cuts, or are you simply just delaying the need to drill some of these wells? Or is the disposal to [producer] ratio changing over time here?

Sure. The water cut is not changing. This is not a water drive reservoir, so we see a consistent water to oil ratio over the life of the wells even as they decline. It's more -- it's a function of us getting more efficient with the system, changing some of the designs, drilling some lower-cost disposal wells, and really just being more methodical about how we develop the assets in advance of, and in conjunction with developing our producing wells.

So what do you think that ratio will be on a sustained basis, in terms of the need of salt water disposal versus producer wells?

A couple years ago, we said we wanted to get to 10 to 1.

Yes.

But we are clearly past that now. I think in this 15 to 20 or 1 range is a place we are comfortable with. I would caution though the group though on just using a producer to disposal ratio measure. We have got a new design of a disposal well, we will talk about next week. It is called the low cost alternative, where it is a much more inexpensive well. But we will probably only just connect 3to 6 producers to it, but it is very, very cost effective. So I think going forward, we are going to talk about it as a percent of CapEx. We will probably get away from this producer to disposal ratio, just because it is going to be a little bit less meaningful, as we use this low cost alternative. So last year our salt water disposal CapEx as a percent of D&C CapEx -- sorry in 2012 was 24% -- in 2013 it was 12%. So we are going to talk about as a percent of spending going forward. But look, we couldn't be more pleased with the results of our salt water, and our engineering and operational teams working together and optimizing that system. They have done a great job.

Okay. As a second question on your improved EUR type curve. The higher oil EUR, is that better IPs, or has the decline rate outlook changed on your oil side?

I think it is an IP increase, which results in about an 8% increase in the [cumn] over the first year. So I don't think it is a change in the ultimate band, than an IP and the first year production increase.

Okay. And then just a final question on the core acreage is obviously increasing in terms of what you like. When do you have to make a decision on the remainder of your Mississippian Lime acreage, in terms of expirations or renewals?

We are in a good spot there. Let me just give you the stats, and I have given these before. I think it is helpful to give people a full picture of the expirations. So in the total play, we have 1.8 million acres. In 2014, I am talking about the total play now, and not just the focus area, and I will give you the focus area as well. We have [715,000] acres expiring, but we have extensions on 75% of that at $117 an acre. We have in the whole play, 21% HBP. That is 53% [can] in Oklahoma and 8% percent in Kansas. So specifically on the focus areas, we have 670,000 acres net. That's 300,000 in Kansas, 370,000 in Oklahoma -- I am rounding just a hair there. 45% of that is HBP, 64% in Kansas -- I am sorry, 64% in Oklahoma, and 25% of Kansas is HBP.

In 2014 again, the focus there, we have 180,000 acres expiring, with extensions on about 40% of that, at $350 an acre. So in summary, we have got extensions on a lot of our acreage. We will extend some of that. We will let some expire and replace with some better acreage when we drill these good wells. Well comes in at 300, 500, 700 barrels a day, we go in and block up acreage around it. So we will let some acreage expire, and will add in our better areas. In 2013, we added over 130,000 acres in our focus area, at a cost of between $300 and $400 an acre. So we can still pick up acreage at reasonable costs.

Okay. Thanks for the color.

You're welcome.

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

Good morning, gentlemen. If I could go back to the Sumner focus area, I was wondering two things. One, if you could share the oil gas split for those first five wells there? And then second, given that this was not part of your original focus area, does this indicate that there may be some shift in your interpretation going forward, or is this -- was it just the next area to test?

Yes. Let me just hit the last part of that, and then I will let Dave get on the details of those wells. Charles, remember, we had this extension program to test the rest of the acreage. And in the first quarter, really early second quarter last year, refine that extension program, and said look, this is not working to develop all the way up into northwestern Kansas horizontally. Let's refocus that, and we shrunk our extension program quite a bit.

We had on average we had 2.7 wells -- rigs drilling extension wells in the first quarter of the year. That average was 1.1 in the last quarter of 2013. So again, we really refined the program. And the teams pulled it back into areas kind of closer to our focus, and saw some success in an appraisal well -- a appraisal well they drilled in Sumner. They had a theory on the geology and the engineering around that, and did a great job evaluating it, testing it with several more wells. So this is the perfect example of our, what I think is a very balanced appraisal program. We are going to spend in the neighborhood of $50 million to test and appraise some of these areas, and this example where it worked. I think that was capital very well spent and it added over 100,000 acres. So we will continue to do that, have this balanced appraisal program with PUD drilling, and with some additional step outs. And Dave, I will let you give the data on the wells if you have it?

Yes. Charles, we will provide the distribution at Analyst Day next week. We don't have that in front of us at the moment, or we can call you back. But what I will say is that it is a very high oil rate area. This is not a gas field, is why it wasn't in there. This is -- it's prolific oil production.

Got it. That is --you -- that's what I was after. And then shifting over to the Chester, can you talk about what kind of formation that is, and how you selected those locations? And I imagine this is -- I don't want to steal from your Analyst Day next week at all. But the big question, and I think what -- I am sure it is your mind and it is on the mind of other people following you, is how much acreage might be prospective for results like this?

Sure. The Chester is part of the Mississippian package, but it is not present across the entire play. It subcrops on the Western portion of our acreage position. We haven't disclosed the exact acreage position, but it is pretty significant. And we have a pretty innovative team of geoscientists that have been mapping this, and have identified the zone early. And they launched it last year and we are very, very excited about this. It is a new concept. If you pull state records, you will see there is not very many horizontal Chester wells at all, and those that are in there are gas wells. And so, we are one of the leading edge of this, and very impressive results. So we will go into more detail next week, but it is a significant opportunity for us.

And Charles, I think this is a great example to me, and you will hear directly from the guys and the team next week, of us taking the learnings from our -- from this Mid-Continent experience we have, and horizontal -- horizontal oil applications, and applying that to new formation and new zone within our focus area. So I think it is a great example of kind of the innovation and the work that the teams are doing, that we hope to continue.

Got it. Got it. And then Dave, what county were those -- were those two Chester wells in the same county or like Woods?

Yes. And we have five total -- there is one in the quarter, and those are all -- those are in Woods County.

Got it. Thanks.

Your next question comes from the line of Curtis Trimble with Global Hunter. Please proceed.

Thank you. Good morning, everyone. Just wanted to see if I couldn't get some granularity on the changes in the type curve, and maybe a breakdown of what was attributed to better initial well performance? Was it these -- the tail end of the curve hanging in there better, if you could just aggregate that for us?

Curtis, could you repeat for me? It was just a little bit hard to hear.

Sure. Just trying to get some granularity on the change in the type curve? How much was attributed to better initial well performance vis-a--vis for the legacy wells that have been on production for some time? The tail end of the curve hanging in there better than originally estimated?

I got it. We have mentioned that earlier. Be happy to repeat it. It is mostly due to higher IPs and a higher cumn in the first year. So our IP rate is up, and the first year cumn is up about 8%. So that is predominantly the change. It is not much change in the band, or the ultimate declines of the wells. I think that is what you are asking.

Actually, and this is -- exactly and this is across all oils, the majority of your PUD locations. It is just not for that 600,000 plus focus area?

Correct. But I would say, that most of the PUDs are in that 670 focus area.

Sure, sure. But you just haven't high graded and taken out the crappy wells then, in order to produce your type curves is what I am getting at?

Right. Correct, correct. And as we noted, we did write off some PUDs. We high graded our PUD inventory, and wrote off the PUDs that were at the bottom end of the economics, and we wouldn't have hit in a five year drilling plan. So we do have better PUDs than we did last year, and we did write off some of those PUDs that we won't get to in five years.

Good deal. I very much appreciate it

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

Good morning. Just a quick question on the balance sheet. Given the state that the balance sheet is in, and the EBITDA growth that you expect, and it sounds like maybe some -- I guess monetization or some value creation through the salt water disposal. How do you think about what you have on the balance sheet in terms of proceeds, and the use of those proceeds and splitting that between drilling more wells, adding it to your extension areas, either paying down debt, or buying back stock?

Sure. Let me answer -- let me break that into two parts. Adam, on the balance sheet, with our $2.5 billion of liquidity, and even embedded in that liquidity I think we are under-utilized in terms of senior credit capacity. So we use this term, $2.5 billion liquidity. It could easily be higher than that today if we wanted to. No reason to increase our revolver size today, sitting on our cash balance, so plenty of liquidity.

As we grow for the next few years, I told you our EBITDA growth this year will be in the 35% zip code. As in, we are going to continue to grow at this similar 20% to 25% production growth rate, and higher than that EBITDA. As you roll that forward for a couple few years, you get a lot of EBITDA growth, which allows you to very comfortably grow into the balance sheet, and keep your leverage in very -- in check. You won't hear me talking a lot about -- two years ago, that is all we spent our time talking about, was funding deficits and leverage.

Now that is all under control. It is not one of the top five things we are worried about. In terms of what to do with the capital, in terms of our capital allocation decisions, one is size, what is the right of amount of capital to spend? We think in this $1.5 billion zip code is a very comfortable place for us. It is efficient for our operating teams, and allows us to -- Dave and his team to keep costs under control and keep things running smoothly.

Also it affords us, I think a reasonable growth rate, growth in terms of production and growth in terms of reserves and value. And given, where we are right now in terms of outspend, in the returns that we are seeing on these assets, over 60% drilling Mississippian wells, that is our PUD, PUD IRR. I think the best outcome for shareholders for right now is for us to deploy this capital into the assets, and grow that asset base. You can grow the production and grow the reserves and PV base, I think that is best outcome for shareholders right now. That could change as market circumstances change, but right now we think that is the best path forward.

Great. Thank you.

Thank you.

Your next question comes from the line of Arun Jayaram with Credit Suisse. Please proceed.

Yes, James, good morning.

Good morning.

I was wondering if you could just quickly remind us the CapEx related to the Trust going forward, and does the impact on the carry in 2014 and 2015?

Yes, a couple things. We will wrap up the trust spending this year. I believe it is about $140 million this year that -- that we will be done with it after that point. Last year, it was over $300 million. So our Trust CapEx is going down considerably. That allows us to redirect that capital into wells that are 100% SandRidge working -- and net revenue interest wells as opposed to 20%. So a lot more financial gearing from every capital dollar we spend. So that is on the plus side, in terms of our CapEx.

The carry does go away this year. We have about $200 million left. It will be done in the August time frame. I think the combination of the trust, CapEx falling away, and these continued efficiencies we have seen are going to offset any loss in the trust. And some people say, how can you continue to spend $1.5 billion and grow? We think your CapEx needs to go a lot higher. That is not the case. We are very comfortably in this $1.5 billion zip code. One, is because the trust spending as I said is falling away, but we have gotten a lot more efficient. Kind of as I said in the call, these $100,000 and $200,000 savings in well costs, when you drill a $400,000 wells adds a lot of firepower to your capital plan, and plus our more efficient spending on the infrastructure.

Fair enough. And just my follow-up, Jim, one thing that wasn't intuitive to me was just the performance revision. Obviously, I appreciate the color around that. But can you just comment on that? Your inventory -- you are high-grading, right? So your EURs and your oil piece of that moved up. Your well costs are down. So I was just a little bit surprised on the performance revisions --

Yes, those are wells --

Any color around that? (Multiple Speakers).

Sure, sure. Those are wells that we are not going to get to in the five-year SEC time line. As we have drilled another 450 wells in the play, we have booked PUDs in better areas, better PUDs. There are some PUDs in some outlying areas and some other parts of the play that we are not going to get to in the five-year time frame. The new wells we have to drill are better economics and better returns. So we are just not going get those. So we did write off about 36, about 36 million barrels. But we added 117 million barrels. So on balance -- and there were [$16] million of positive price revision. So on balance, we are 100 million barrels up. But again, it is just from not meeting those in the five-year SEC timeframe.

Thanks a lot, Jim.

You're welcome.

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

Thank you. Good morning, everybody.

Good morning.

Just a quick question on the updated type curves. So if I read the release correctly, and if I am hearing correctly, so the EUR increase is not necessarily on the same wells. It's -- the EUR increase comes from just replacing some of the wells you are not going to drill over the next five years, with better wells that you are going to drill over the next five years? Is that correct?

No. It is both. We did, as we have said did eliminate some PUDs that we are not going to get to. But the performance, the base performance of the asset has improved. Our IP rates are up. Our first year cumn is up. If you noticed, as we reported last year, our 30 day IPs of 386 for the quarter, and 366 for the year are significantly ahead of where the type curve was. So, no, I think it is better performance in the asset.

Got you. So James, is it -- so if I looked at say, a handful of wells, like did you actually increase the EURs on those specific wells -- the specific wells that were booked 2012 as PUDs, did you actually increase the EUR assumption on those same wells?

Yes.

Okay. Got you. Okay. That's helpful. And then, in terms of the cost -- so in the fourth quarter, I think you averaged $2.9 million. Does that include the water disposal, and then if -- and what is the assumption for cost for 2014 per well?

That does not include the water disposal. We break out the water disposal separate. I think we spent about $95 million in total on the water disposal system last year, but that's just a D&C cost. It does not include the disposal. The assumptions for this year, I believe are $3 million in our model, and that does assume some amount of appraisal and testing. It also assumes drilling in some areas that are a little deeper, maybe tighter. So we got $3 million built into the plan for 2014.

Okay. But on the, without any extra costs, do you think on a per well --?

Joe, I think you cut out? Are you still there? I think we may have lost him.

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

Okay, thanks. Good morning.

Good morning.

I don't want to beat this to a dead horse, a dead horse here. But back to the revisions on the PUD EURs. So you increased it by 3% to 380,000 Boe. And it seemed like there was some PUDs that were worse that were taken off and some in better areas that were put on. So what was the actual increase on the apples-to-apples wells? Because 3% increase sounds a bit small, when you had a bit of high-grading going on there?

Well, a 3% increase may sound small, but a 10% increase in oil is not small. And I would take a 10% increase, and compound that over three or five years all day long. So I am very pleased with the results. And it is not just -- it is not just high-grading, I mean, it is improved performance. Remember, this 30 day IP point, our IP on the previous PUD type curve was 270 Boe a day roughly. Our average IP for 2013 was 366 per day. So we are getting better, drilling better results, better wells, better completion methods, better targeting. We are getting better at this.

I mean, specifically could you give an apples-to-apples kind of a view of a well last year versus this year? Just the same well, what did that same well have for a change in PUD that was booked?

Look, the type curve is a combination of hundreds of wells, so I don't think I can pick out any one specific well. But the wells got better, and our type curve is higher, and their performance of our wells is better. So I guess, I am not quite following you. We -- our type curve is up.

Yes. Well, what I think would be helpful is to take a look at the same wells that might have been on the PUD list last year versus this year. And sort of aggregate those, and say, all right, on our apple-to-apple wells, these are up x percent. So we can get a sense of how much of that 3% was a bit of a high-grade, and how much is true incremental performance improvement?

Yes.

And I appreciate the fact that you do have higher PUDs, because you have better wells you are drilling. But it would be good to see if there was an actual performance change year-over-year on those PUDs.

Okay. Yes, I understand. That is a great topic for Analyst Day. We will be going through a deep dive in the reserves on Analyst Day, and I think we will give you the information that you need there in New York next Tuesday.

Okay, appreciate that. And one quickly on the PDPs, is there a change -- was there a change -- what was booked for the PDPs, was there a revision on those year-over-year?

No. No, change year-over-year.

On the PDPs? Okay.

Correct, on the PDPs.

All right. Thanks.

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

Good morning, everyone. Just a couple of questions. James or Dave, could you talk about the costs related to the Sumner County wells, including the infrastructure incurred?

Sure. Richard, the Sumner County wells starting off, were a little bit more expensive than our base program, because we did a pretty intensive evaluation program, and we also drilled a little bit longer laterals which added to the cost. So they are a little bit more expensive at this point, than the kind of concentrated area and some of our other project or focus areas. So a little bit more expensive at this at least initially.

In terms of the infrastructure, that area does require some site generation because it is so remote. And so, we are looking to expand that as we go forward, because it's not as accessible as some other parts of the play. In Sumner, on the salt water disposal infrastructure, you will see from the teams on Tuesday this is where -- actually these specific example where they have implemented as a low-cost alternative salt water disposal system that you will hear us talking more about. It is very effective in some of these appraisal areas.

Okay. Did you receive any proved reserves for some of the new areas in the, say the Chester or Sumner County area? And if so, what were the reserves associated with the wells?

There is a small amount of Chester in the reserves. I don't have that exact number for you, but there are no Sumner County reserves in the year end reserve report.

Okay. And then just lastly, if you could walk through the change in the standardized measure of value year-over-year?

Yes. We will save the blood and guts of that for next week. But on a pro forma basis -- you have got to back out what we sold -- so back out Permian from last year and Gulf of Mexico from both years, it was $2.9 million, now it is $4.1 million. But we have got a lot of reconciliation next year on all the moves, and all the different change in the components there. We will go through that on Tuesday.

Okay. Thank you. Appreciate it.

Your next question comes from the line of Greg Slavin with TPG Axon. Please proceed.

Hello. Congratulations on the quarter.

Thank you.

I wanted to ask about the Repsol guidance that came out earlier in the week. On their Q4 call, they talked about the Miss Lime net to them being 20,000 to 25,000 barrels a day by year end 2016. Obviously, they are your JV partner across much of your acreage. And so, I was trying to do the math, the working interest math, and I got to about 115,000 to 140,000 a day net to SandRidge by year end 2016, which is a three year production [kicker] of over 30% to 40%. So I don't mean to upfront on your Investor Day. But I guess the first question is, did I do that math correctly, like translating Repsol guidance to SandRidge production? And second, what is the process for Repsol guidance? Are they taking your numbers here, or do they come up with this by themselves?

Yes. Great question. This just came out a couple of days ago, and Repsol had their year end. And they did -- they said that, they see 20,000 to 25,000 barrels of oil equivalent per day by the end of 2016. So if you do the math, they own about 14% roughly working interest. So if you gross that up, and then net it back down by SandRidge's working interest, we have about a 72.7% -- you want to round it to 73% working interest. So if you take that range of 20,000 to 25,000 gross it up their 14% working interest. Take it down to our 73% working interest, you do. You get this kind of 110,000 to 135,000 or 140,000 Boe per day in 2016.

So our guidance for 2014 for Boe per day is -- for the whole year is 63.5% for the Mid-Continent. So their numbers are good, and they are in line. And look, I would be very pleased with being at the top end of the range. And I think it is consistent with what we will talk about next week. These are not our numbers though. These are Repsol's numbers. They came up with them completely on their own. But I think it does correspond to what we are talking about. And I think it reaffirms our belief in the play and the growth of the play, and the development of the asset over the next several years. Does that answer your question, Greg?

Yes. That's great. Thanks a lot. You're welcome.

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

Yes. Thanks, everybody. Sorry about that. I got a phone problem. (Multiple Speakers). Sure. So just back to the updated type curve, so to what do you attribute the improved IP rates? Are you doing any enhanced completions? Or is it just, these wells are just performing better than you had modeled?

Joe, we will give you some more details at Analyst Day. I think it is a combination of that. The team has gotten it better at targeting, changing completion methods in some parts of the play, doing some open hole completions and some other things, trying some different packer systems and completion techniques. Better targeting, as I have said. So we will give you details at the Analyst Day. I think it is a combination of that, just because we have got over 1,200 wells drilled in the play now. So we get smarter every year, and every quarter and better at this.

Got you. And then, so back to the cost issue. So you are assuming a $3 million per well. So for the same type of well, do you think -- is the well going to cost you $100,000 more in 2014? Or is it going to cost you a little bit more than average because you are doing some extra stuff -- that you are doing some completions differently than before?

Yes, we will talk about that on Tuesday before, but it is doing a lot of extra stuff. Dave mentioned the wells in Sumner County. We spent a lot of money on science, ran tracers, ran image logs. So we are spending money upfront to make sure we understand the rock and the reservoir. We are drilling in some deeper -- just slightly deeper in a little bit tighter parts of the play, maybe in the lower Miss. So I think it is a mix of the wells of that is causing as not to project it at $2.8 million or $2.9 million. I think our base Miss program, and Dave Lawler and his team will go through it next week, we have seen a significant improvements in those well costs in just a base Miss well. In some cases, drilling those for $2.6 million or $2.7 million.

Got you. And then, in terms of the number of locations that you have to drill in the Miss play, what is the before and after?

Let's save that one for Analyst Day. I think we have a very robust discussion on our inventory count, and our locations for the next several years, if that's okay Joe?

That is not a problem. And then, there is something circulating about this subpoena. What is that about? Is that something we should be concerned about or?

We don't think so. It's early in the process. We don't have any more information at all about the facts of the investigation, other than what we put in the 10-K.

All right. So what is the topic there?

We don't even know.

Okay. Got it. I guess, well, all right, very helpful. Very helpful. Thank you.

Thank you.

(Operator Instructions)

Your next question comes for the line of [George Wen] with KUI Banc

Hello. It's George from KeyBanc.

Hello, George.

James, can you give more color on the total for the wells that you drilled in the fourth quarter? And are you seeing any difference, versus the first two batches of wells in your [third] quarter?

Yes, so the question is -- I will turn this over to Dave. He will be better suited to answer this. Have we seen the two Woodford wells that we talked about in this batch -- how is that different and what we have learned from the batch one?

Okay. Great. Yes, George. I may defer -- I know you have heard that several times, may defer that. But we will have a specific presentation on this next week. But I think just early, we can comment that there is a certain geologic model that we are targeting now, that we have learned about. Initially, we have the Woodford over a vast portion of our leasehold. So we started out testing different areas, and quickly learned from what we had seen, what the results showed us. And now we are starting to target a more specific area of the play, and that is the reason that you see the improved performance. And we have several wells coming up here in Q2 that will test that theory, and we will talk through that next week. But we are pretty excited. We think we have got a bead on it.

Okay. So in terms of those [six] zone, well drilling the Mississippian, is that Chester and Woodford? Can you give more color on the wells in Upper Miss, Middle Miss and Lower Miss? Because I don't see much color the press release?

Yes. Let's save that one for Analyst Day. I don't want to keep putting you off, but we have got a very thorough discussion about all those zones at Analyst Day, if that's okay?

Okay, thank you. Congrats on the quarter.

Thank you.

Your next question comes from the line of [Andy Parr] with [Surveyor].

Hello. A quick question on the Sumner program, I was curious, are those 45 wells substituted into this year's program? I think you have been talking about what 460 wells or something like that? Or have those been in there with that -- with the original 460 guidance?

Well, the Sumner wells displaced other projects.

Okay. Since the original. (Multiple Speakers).

In terms of the rate of return, it is significant. The question was asked earlier what the oil content was, and the oil content is around the 70% in Sumner.

And that's not unusual, as you go through the drilling program and learn more throughout the year, you adjust it accordingly.

Yes. No. I hear you. I was just trying to reconcile that with the guidance -- or there wasn't a guidance change -- and the 90% uplift in the EUR, I was trying to reconcile that in my head.

No guidance change. We just substituted it for other wells.

Okay. And then secondly, 300 -- I think it was a 386 rate for the quarter on the average well count. Does that include every well in the Mid-Con, Chester, Woodford, Mississippian or are those just Miss wells?

I believe that is every. Yes, that is every. We started giving that stat for all wells.

Yes. I just wanted to make sure. Okay. Thanks. See you next week.

Thank you.

This concludes the Q&A portion of today's call. I would now like to turn the call back over to Mr. James Bennett for any closing remarks.

Well, thanks everyone for listening. We hope to see some of you in New York next week or on the webcast. I think this wraps up a very successful year and quarter. The teams have done an amazing job, and couldn't be more proud of all the employees here, and the hard work that they do safely for all of us. We are going to be focused on what I said next year, growing our reserves and cash flow in a profitable manner, and driving shareholder returns. So we hope to tell you more about all of that next week. Thank you.

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