SandRidge Energy Inc (SD) 2011 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the second quarter 2011 SandRidge Energy earnings conference call. My name is Keisha, 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 purposes. I would now like to turn the conference over for your host for today, James D. Bennett, CFO. Please proceed.

Thank you, Keisha. Welcome, everyone, and thank you for joining us on our second-quarter 2011 earnings call. This is James Bennett, Chief Financial Officer. Joining me today are Tom Ward, Chairman and Chief Executive Officer; Matt Grubb, President and Chief Operating Officer; and Kevin White, Senior vice President of Business Development.

Please note that today's call will contain Forward-looking Statements and assumptions, which are subject to risks and uncertainties, and actual results may differ materially from those projected in these forward-looking statements. Additionally, we may make reference to adjusted net income, adjusted EBITDA, and other non-GAAP financial measures. A reconciliation of any non-GAAP measures we discuss can be found in our earnings release and on our website.

Also note that today's call is intended to address SandRidge Energy, and not the royalty trust, SandRidge Mississippian Trust One, ticker SDT. SDT will have a separate earnings call at 8 am central time on Friday, August 12. Now let me turn the call over to Tom Ward.

Thank you, James. Welcome to our second quarter operational and financial update. As you've read, we have had a busy few weeks. I will use this small amount of time to update you on our progress from the last quarter, and give you a glimpse of our new acreage play in the Miss, plus develop -- the development of our three-year growth plan.

Yesterday, we announced the signing of a joint venture with Atinum Partners, a highly respected financial partner and energy investor based in Seoul. The joint venture encompasses the original Mississippian idea that we have been developing over the last few years. SandRidge will receive $500 million in consideration, composed of $250 million in cash at closing and $250 million in a carry structure over a three-year drilling term.

We will deliver 113,000 net acres of our greater than 900,000 acre Mississippian position. With this sale, we will have monetized $580 million of cash and $250 million of additional carried interest on an initial investment of approximately $200 million, and continue to own our nearly 90% of our acreage. The transaction further substantiates that the Mississippian Carbonate play is considered one of the best areas to drill in the US today.

There have now been 92 wells, operated by SandRidge, with at least 30 days of production history. These wells have a 30-day rate of 297 barrels of oil equivalent per day, compared to the 244 barrel of oil equivalent per day rate used in the Netherland Sewell type curve that has an EUR of 409,000 in boe per well. We have information on a total of 136 total wells with at least 30 days of production, and these wells have a 30-day rate of 284 barrels of oil equivalent per day. We calculate our type curve well to have in excess of 100% rates of return using a $3 million well cost. The play in total now has over 250 horizontal wells that have been drilled.

Given the positive performance of our wells, we are now increasing guidance to 24.1 million barrels of oil equivalent in 2011, which is a 20% production increase over 2010. And we are projecting a corresponding 20% production increase in 2012 to 29 million barrels equivalent. We have also announced our second horizontal Mississippian play, in which we have purchased over 200,000 net acres, with a plan to be at 1 million acres by the end of this year. We do not anticipate spending anymore per acre than we did for the original Mississippian acreage plot in Oklahoma and Southern Kansas.

This new play has all the same characteristics of our original Mississippian play. We're focusing on shallow carbonate, low-cost oil that can be acquired and drilled for approximately the same amount as we have invested in the current Mississippian play. We also have and focus on thickness of reservoir, and have chosen to stay in areas that have at least 250 feet of Mississippian thickness. We like carbonates because of the matrix porosity and permeability.

However, maybe the most important factor in describing what we look for in a play is history. We want to understand what the production decline will look like several years into the play. The original Miss play had 7,800 vertical wells drilled within our [buy] area. The new Miss play has over 8,500 vertical wells drilled with very similar EURs to the current Miss, but even at shallower depths.

We also continue to believe the three wells per section is the appropriate estimate for wells in the Mississippian formation. The storage capacity to find 400 MBOE to 500 MBOE per well is found through matrix veracity, fracture veracity and pressure veracity and higher perm rock. Therefore, we are hesitant to drill too close, as we want to spend the least amount of capital to get the most oil and gas from the reservoir. It is also impossible to predict, with any accuracy, how our reservoir would decline over a long period of time without some history of production.

Within our areas of focus, carbonate wells have been drilled for decades, giving us confidence in that future well performance. We want to manage and minimize risk by investing in plays that will allow us to drill and complete wells with equipment that is plentiful and developing reservoirs that have a proven production history. The abundance of low horsepower drilling and completion equipment has allowed us to keep our drilling costs relatively flat during the last two years at a time when the industry's drilling costs have risen quite dramatically.

In summary, our strategy is quite simple. Drill in areas with historically proven production, and keep our costs down, while taking advantage of high oil prices to create strong rates of return. We then lock in these rates of return by hedging future oil production. We have already hedged over 30 million barrels of oil for the next three years and continue to be willing to hedge more.

Lastly, we are announcing a three-year plan, which by the end of 2014 we would have a self-funding program, debt to EBITDA ratio of less than two times, and maintain double-digit production growth. This plan incorporates bringing NAV forward by narrowing our drilling inventory in the Mississippian to approximately 10 years from the 25-year inventory we had in the first of this year and keeping our central basin platform inventory and drilling schedule as it is today. This goal is achievable with a capital budget of about $1.8 billion to $2 billion per year, and would generate EBITDA over $2 billion in 2014. The outcome will be a Company that doubles our 2012 production, a continued large inventory of drilling opportunities, and a very strong balance sheet with best in-class results. Lastly, our 2014 plan does not assume any success we may have with our new Mississippian play.

I'll now turn the call over to Matt to further describe our plans in the quarter.

Thank you, Tom, and good morning to everybody. I will start with Q2 production, then go into drilling performance, 2011 CapEx increase, and LOE. We produced 30,400 barrels of oil per day and 189 million cubic feet of gas per day, for an average of 63,000 barrels of oil equivalent per day in Q2, as compared to 28,700 barrels of oil per day and 192 million cubic feet of gas per day, or 60,700 barrels equivalent per day in Q1. This is a 2% quarter-over-quarter production growth, considering the impact of 1,500 barrels of oil equivalent per day for the New Mexico asset sales in April, our quarter-over-quarter pro forma total production growth is nearly 6% and approximately 10% in oil production growth.

With the announced 2011 CapEx increase, we have also increased our 2011 production guidance from 23.3 million barrels of oil equivalent to 24.1 million barrels of oil equivalent. This is a 3.4% increase to our previous 2011 guidance, and a 20% increase to 2010 production. Again, if we look at it on a pro forma basis for the New Mexico asset sales, this is approximately a 5.3% increase to the previous 2011 guidance. And if we add in the impact of the Wolfberry sales earlier this year, our new guidance represents 25% increase to 2010.

With our rig ramp-up plan in the Horizontal Miss, which I will discuss further, we seek to grow total production another 20% in 2012 over 2011. And that represents a 35% increase in oil production over that same period. We anticipate producing about 16.7 million barrels of oil and 75 million cubic feet of gas for a total of 29.1 million barrels of oil equivalent in 2012.

As mentioned earlier, we averaged 62,000 barrels of oil equivalent per day in the second quarter with a continued success we are seeing in the Horizontal Miss program, steady result of low-risk drilling, and an aggressive work-over program on the central basin platform. We have had a great start into the third quarter. Our total production in July increased to 66,000 barrels of oil equivalent per day, where we averaged nearly 34,000 barrels of oil and 192,000 cubic feet of gas per day. During this period, we also saw a one-day high of 68,000 barrels of oil equivalent.

From a drilling standpoint, we are running 16 rigs in the Permian Basin and plan to maintain that level for the remainder of 2011. We drilled 197 wells in the Permian Basin in the second quarter, bringing the total to 399 vertical wells drilled in the Permian Basin in the first half of this year. With some movement in the drilling mix, we anticipate to drill a few more wells in the second half of the year.

Our new projection is 834 wells drilled in the Permian Basin for 2011. This is 23 more wells than we had previously estimated for the year. Our Permian Basin activity is focused on the central basin platform, where we primarily drill low-risk, vertical, San Andreas and Clear Fork wells at depths from 4,500 feet to 7,000 feet.

In the Horizontal Miss play, we currently operate 14 rigs and continuing to ramp up with the goal of exiting 2011 at 18 rates. We drilled 30 Horizontal Miss wells in the quarter, bringing that total to 61 new wells drilled in the first half of this year. With our current rig plan, we now project to drill 171 Horizontal Miss wells in the year. That's 33 more than we had initially estimated.

As you have seen, we've increased our 2011 budget by $500 million to $1.8 billion total. The allocation for the increase is as follows. $150 million for drilling more wells in the Permian and the Miss wells, including saltwater disposal wells. And also that includes the adjustment of the well cost in the Miss from $2.5 million to $3 million. There are also $50 million of non-op drilling in the Mississippian, and increased work-overs and re-completions in the Company.

The biggest part of the increase is in land, $275 million in additional land spending for acquisition of new acreage in the Central Basin platform and the new Mississippian play, and $25 million for oil field services in Midstream. We also have guided to $1.8 billion -- $1.8 billion budget in 2012, where we anticipate drilling about 850 wells in the Permian Basin and about 350 Horizontal Miss wells in the Mid-Con next year.

We ended the quarter at $14.51 per BOE on LOE. This is a $1.41 per BOE higher than the high end of our guidance of $13.10 per BOE. The higher LOE is due primarily to higher costs associated with the rapid growth of the Horizontal Miss play in the Central Basin platform. Securing right of way and equipment have been slower than we anticipated for electrical infrastructure build-out in the Miss play, and as a result, we have had to rely on excessive use of rental generators and diesel fuel. This increased our LOE in Q2 by about $3 million, or $0.53 per BOE.

In the Central Basin platform, where we have added nearly 400 new wells in the first half of this year, we've outpaced our saltwater gathering and disposal capacity, and have had to rely more on trucking. This resulted in an LOE increase of about $0.32 per BOE. During Q2, we also had some unscheduled operated and non-operated maintenance expenses in the Gulf of Mexico in the amount of $2 million, or $0.35 per BOE. But we don't expect this to be a recurring event.

Lastly, we have embarked on an aggressive work over and maintenance initiative in the Central Basin platform to restore inactive wells, reduce well head pressures, and refract old wells. These are typically quick-payout, high ROR projects that will create long-term value. We increased spending in Q2 by $2.6 million in that area, and that represents a $0.46 per BOE cost increase.

In total, this adds up $1.66 per BOE. We are working aggressively to get ahead of our saltwater disposal and electrical issues in the Central Basin platform in the Miss play, but we anticipate it will take several more quarters to resolve. As a result, we have increased our LOE guidance to a range of $14.10 per BOE on the low side to a high of $15.50 per BOE, with a midpoint of $14.80 per BOE.

At this time, I will turn the call over to James for financials.

Thank you, Matt. Our second quarter was very positive and eventful for SandRidge. Our production was on target. Results in our two oil plays continued to meet or exceed expectations, and our confidence in our asset base continues to grow. We continue to have success in raising capital this year and announced two very significant transactions this week, the launching of a second royalty trust, and a joint venture in our Mississippian play. The combination of our large high-quality asset base and the ability to raise funds around these assets allow us to increase our capital program and bring forward the NPV of our drilling inventory, while at the same time adding another potential oil play. Regarding our balance sheet liquidity, we will continue the monetization of assets, and adhere to our goal of funding CapEx with non debt sources of capital.

Touching on a few of our financial results, for the second quarter, adjusted net loss was $2 million, or $0.00 per diluted share. Adjusted EBITDA was $156 million, or $182 million including realized gains on out-of-period hedges, and operating cash flow was $134 million. Recall that in April, we completed the IPO of SandRidge Mississippian Trust One, which is being consolidated into the financials of SandRidge, so in the second quarter, you'll see net income attributable to non-controlling interest on the income statement, which reflects the impact of the 62% of the trust owned by the public. Also the actual quarterly EBITDA impact from the trust can be found in our reconciliation of adjusted EBITDA tables in our earnings release.

SandRidge's second quarter adjusted EBITDA is up 7% over the first-quarter 2011 and 18% versus comparable period in 2010 as a result of higher oil production and higher realized oil prices, somewhat offset by a decline in gas production, and as Matt discussed, an increase in lease operating expenses. Capital expenditures for the quarter were $454 million and $874 million for the year-to-date period. In terms of lease hold, as Tom mentioned, we launched a new Mississippian play and began acquiring acreage in the play. In the second quarter, we also added to our acreage positions in the original Miss and the Central Basin platform in the Permian Basin.

In our earnings release we have updated full-year guidance, and included initial production and CapEx guidance for 2012. In terms of 2011, we are increasing our production guidance by 3%, or 800,000 BOE to $24.1 million BOE. We are also increasing 2011 CapEx by $500 million, to $1.8 billion, reflecting the increase in the rate count in Mississippian play and leasing efforts in our second Mississippian play.

Recall that 100% of our drilling expenditures this year are directed towards oil, as returns on our oil projects are superior to those on our gas assets. Other per-unit measures, including LOE, DD&A and G&A have also been updated. As Matt discussed, we are seeing higher lease operating expenses and have guided that range up to $14.10 to $15.50 per BOE. While we think over time, we can bring these per unit costs down as we achieve scale in the Mississippian play, for now, we feel it is prudent guiding at this higher level of LOE.

In terms of our capital raising efforts, this week we issued Press Releases for two pending and important components of our capital raising program. First on August 1, we launched the IPO of our second royalty trust, which we expect to close in mid-August, and net proceeds to SandRidge of approximately $600 million.

Second, this week we signed definitive agreements to enter into a joint venture and development agreement in our original Mississippian play. As discussed in more detail in the press release issued yesterday morning, this $500 million joint venture consists of $250 million of cash at closing, and $250 million in the form of a drilling carry, which is expected to be utilized over a three-year period. SandRidge will transfer of 13.2% working interest in approximately 860,000 acres, or approximately 113,000 net acres.

Also note that in the JV, we are not selling production or conveying an interest in any proved assets or HBP acreage. All of this is excluded from the AMI. The JV is expected to close in the fourth quarter.

The pending closing of these two transactions, combined with the $800 million in year-to-date closed asset sales will fully fund our revised $1.8 billion 2011 capital budget, and also begins to fund our 2012 capital needs. With the continued success of our capital raising efforts, we feel very comfortable raising our 2011 and 2012 CapEx guidance to $1.8 billion.

Turning to our liquidity and balance sheet, at June 30, we had total debt outstanding at $2.9 billion, consisting of $80 million outstanding under our credit facility, and $2.8 billion senior notes. This represents a $280 million reduction in total debt for March 31. As of August 1, we had $195 million outstanding under our $790 million credit facility and available liquidity of $573 million. Pro forma for the over $800 million in proceeds from our two pending capital raise transactions, we will have approximately $600 million of cash on the balance sheet, no debt outstanding under our credit facility, and will have reduced our leverage by over a turn of EBITDA.

In terms of our hedging position, we continue to hedge our oil production. To summarize our updated derivative position, which is outlined in our earnings release, since our second-quarter earnings, we have added oil hedges in the form of swaps for 6.4 million barrels at an average price of approximately $102 per barrel. For the remaining half of the year, we have approximately 71% of our guidance liquid production hedged at $88 per barrel, and through 2015 we have 32.5 million barrels of oil hedged at approximately $93.

This concludes management's remarks. Keisha, I'd like to open it up the call for questions.

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

Good morning guys. Tom, could you address a little more on the new Horizontal Miss play? Obviously, with the amount of money it seems like you've set aside with this new CapEx, is it safe to say that you've already earmarked some acres that are likely to be picked up for the remainder of the year? If so, any color you could give in relation to -- I understand it has the Horizontal Miss perspective location versus some of these existing play.

Sure. We won't get into location because we are still actively leasing. We've said we are at 200,000 acres. We think we can be at 1 million acres by the end of the year. That is all in our budget of the increasing our budget to $1.8 billion.

The key is that it has tremendous history. So, in any play, whether it is sandstone, carbonates or shale, the key to the play for SandRidge is that you have some kind of a history in place that you can estimate what future production will look like. And then keeping your costs down is the second thing that we look at. Being shallow and being able to drill in areas that don't have tremendous service cost, pressure is the second criteria.

Then you look at shallow -- as we talked about, carbonates we like. We know these types of reservoirs, so we are very comfortable with that. And then the other very important part of this is that it's oil.

So, for all of those criteria, plus having more vertical wells in our original play at the same type of EURs make us very comfortable, just as we were comfortable in doing the step-out program that we did inside our original Mississippian play.

And then, Tom, either for you or Matt, just wondering, you mentioned, I think the CapEx went up a little bit for the new drilling cost. A little bit more if Matt could suggest around what you're assuming for well cost. I think he addressed that a little bit, but obviously, with the slightly higher CapEx, is that safe to say costs will continue to creep up through the remainder of the year? What are you seeing around the Horizontal Miss and the Permian cost?

Keep in mind that our cost inflation has stayed relatively flat in service costs. What we did as we went into drilling in 1 specific area, in Alfalfa County, where we are to had a saltwater disposal system in place, and we drilled those wells fairly close together, and became very efficient at drilling.

So, we had service costs or well costs, if you might remember over the last year, started at $3 million and went down to the $2.5 million range. And so we made an estimate that we would be able to drill wells as we became more efficient at $2.5 million per well.

What happened, as we moved into different areas with different types of rock, even though it's in the Mississippian, and brought in new rigs, our efficiencies actually went the other way. And so, we moved back our cost to $3 million, and we feel like we will be able to hit that number.

Also in the Permian, we aren't really seeing any service costs increasing either. It's been relatively flat. So, the way to justify that is to say, look back at our June of 2009, we were locking in rates at what we thought were recession lows on service costs. And we estimated the cost of the San Andreas well to be $500,000 per well. And this year, just now, when we launched our Permian trust, the S1 has in that $513,000 per well.

The fracs are staying pretty stable in that, Tom? Frac cost?

Yes, basically all our service costs are relatively stable compared to the rest of the industry.

Okay, and then last quick question. Just on that assumption you have for the 2014 cash flow, what type of oil and gas prices are you assuming in there?

That was as of the strip.

Okay, perfect. Thank you.

And our next question comes from the line of William Butler, representing Stephens. Please proceed.

Good morning. Can you all talk a little bit about the current production rates on the Mississippian line right now?

Yes, as a whole or on a per well basis?

As a whole, versus the 8,400 average for the quarter.

Yes. Give me just a second here. Right now, the Miss play is producing 15,720 barrels of oil equivalent per day.

Okay. And where was it at the end of the quarter?

At the end of Q2 in June, we were probably right at just around 13,000.

Okay. Thank you. And then your CapEx that you've got outlined for 2012, that is already net of the $250 million or part of that carry, correct?

That's correct.

Okay. And what about, just help me, on the current production coming out of the Permian Basin, if you would also.

Yes, let me pull that up. The Permian Basin is currently producing, on a BOE basis for July, it averaged 29,300.

Okay, great thank you.

Thank you.

Our next question comes from the line of Joe Allman, representing JPMorgan. Please proceed.

Thank you. Good morning, everybody.

Good morning.

Tom, on the new Mississippian play, why announce it now and why give the details that you have given, including the formation that you're targeting?

Because we were including it in our CapEx, the spending for acreage.

Got you, okay. All right. I guess the reason for not giving more details is just you would think it would invite competition and raise the cost up, is that right?

That's right. We wouldn't have announced it at all if we didn't need to disclose we are going to spend be spending more acreage on land.

Got you okay. And then in terms of your screening process for looking at new plays, could you just describe that somewhat? And are you looking at additional plays in addition to this new Mississippian?

No, we are not looking to add to additional plays. But the screening process is just what I mentioned. First of all, you need vertical well production. You need it to be shallow; it needs to be oil.

And in our case, we like permeability and porosity, but if other plays didn't even have perm and porosity had good well control, and you could make high rates of return, we would look at those types of rock too. But in our case, we tend to like carbonates because of their permeability and porosity.

That's helpful, thanks. And then with the Permian trust that you launched, when do expect to close that?

This is James. We can't really comment specifically on the Permian trust. We launched the road show, and we would hope that in mid-August that is closed.

Okay, that's helpful. And then in terms of your guidance that you gave, just to clarify, that already includes the production and CapEx related to the JV?

Yes, that's correct.

Okay. And then lastly, in terms of financing needs, this $500 million is helpful. What do you view as additional financing needs? Do you feel like you need to go out and potentially do another royalty trust, or you need to do something else to help cover any cash flow shortfall?

Joe, what we've said, we've raised $800 million in proceeds this year. The royalty trust is pending, and the joint venture will fully fund all of this revised 2011 $1.8 billion plan, and also carry over into 2012. So, we have a deficit in 2012 that we will start to fill, and we've always said we have several ways of doing that.

Joe, keep in mind, we still have 90% of our basically 90% of our Mississippian -- the original Mississippian that we own. And we like the ways that we've chosen to finance so far.

Okay, that's very helpful. Thank you, everybody.

Thank you.

And our next question comes from the line of Dave Kistler, representing Simmons & Co. Please proceed.

Morning, guys.

Good morning.

Following up on Joe's question there. Looking at the JV, you guys announced yesterday no production was sold into that. How many PDP wells have you guys built up year-to-date, and what does the balance look like for the rest of this year in the Miss line up? The rationale for the question being that certainly would set up to support another royalty trust and could give us an idea of the magnitude of that royalty trust.

Sure. I think what I had was only numbers with a 30 day --

We drilled a total of 111 wells, horizontal Miss wells, that's Company-operated wells. And so, the first Miss trust, Mississippian trust, I believe had 37 PDP wells in it. And so, if you can do the math there and you can see what's available for another trust, if we decide to do so.

Wouldn't a portion of that though been captured in PUD drilling for the trust as well?

A portion of it is, yes, you're right. And I don't have that number right at the top of my head, how many wells that is.

And Dave, you would also have to decide how large of a trust that you want to do if you chose to do one.

Exactly, and that's what I'm getting at. It looks like, certainly, there will be enough PDPs not associated with the royalty trust to maybe have the royalty trust 2X the size of the first 1? Is that a reasonable --

Well, we would have more than enough available today to do 1 at least as large as the first.

Okay.

I do want to comment, we do have a Royalty Trust call next Friday that will go into details on exactly how many wells we're drilling in the trust and so forth.

Okay that is helpful. And then just on the financing line as well, looking at the revolver right now, I know in the past, you've had the opportunity to take it higher. But now, with these trust vehicles falling into place, can you guys comment a little bit on how reserves associated with the trust work as far as a credit facility, and whether or not those fall into reserve base lending.

Yes, Dave. This is James. That is a good question. The reserves associated with both trusts have always been excluded from our credit facility in terms of the borrowing base. The borrowing base has an interest in really collateral on all the assets of the Company.

But, the reserves associated with those, we pulled those out before we did any of our redeterminations. So, even the spring redetermination didn't include any of the reserves for the pending royalty trust. So,

that will have no impact on our borrowing base.

And if you recall in the spring, we were almost 3 times over-collateralized on a PDP, PV-9 basis in our revolving credit facility. So, if we wanted to, we feel we could have increased it, but really didn't plan to be in our revolver much this year.

Okay. And then the last question on financing would be clearly looks like a royalty trust is still on the table. JV market, as of yesterday, still seems robust. Where do we stand as far as thinking about equity as well?

Well as you know, what I have always said is that we -- there are basically 6 types of financing that we could do. We have -- we feel like that we have enough debt, so we want to grow into our debt. That's why we have a debt to EBITDA goal of less than two.

We feel like we have enough preferred out. We would rather not sell gas assets in a depressed gas market. So, that left us with the three options being joint ventures, and the royalty trust, and equity. I've never said we are going to issue equity. I've just said that they were the last three options that we have.

Okay, that is helpful. I've monopolized a little time. I'll let someone else hop on.

Thank you.

And our next question comes from the line of Mark Henson, representing MorningStar. Please proceed.

Good morning, guys. Would you mind talking a little bit about what backlogs look like right now in Central Basin, Permian, and Horizontal Miss? Just wondering -- wells waiting on completion and then waiting on tie-in, and what normalized run rates might look like?

Backlogs for SandRidge, I assume that's what you're asking about?

Yes.

I mean, the Permian Basin, we're always running about 30 wells that are rig release waiting on frac. And that number really hasn't moved much in the last 6 months. In the Mississippian, --we usually frac these wells within 7 to 10 days after we rig release, and there may be 5 or 6 head wells out there that is waiting on fracs right now.

Maybe your question is, are we being backlogged by infrastructure or services? And no, we are not.

Okay. And beyond 2012, do you anticipate holding the rig count in the Horizontal Miss at 24?

No, we anticipate in this growth environment or growth strategy that we have, we would end 2012 at 30 rigs. Now, keep in mind, if the world were to change, we have an excellent hedge book, and we can always move that back. So, the plan today is to add a rig a month in the Mississippian to be at 30 rigs at the end of 2012.

Okay great. And then what is your current working interest --

That gets us to what we've mentioned is an average 24 rigs during the year of 2012. That is what is in our budget.

Okay. And then accounting for the JV here, can you give us what you're working interest right now is across all your Horizontal Miss position?

Yes. Counting the JV, we will probably be around 70%.

Okay great, thank you, guys.

Thank you.

Our next question comes from the line of Gil Yang, representing Banc of America Merrill Lynch. Please proceed.

Good morning. The work over activity that you talked about is in the Permian, I presume?

Yes, that is correct.

Okay. The saltwater disposal issues, should we think of that as an ongoing, somewhat professional issue, or do you ever catch up in terms of the infrastructure that you can build out? And does it peak -- does that infrastructure peak long before you peak on the well activity?

I really think we will catch up. I think part of it was the part that's actually longest is we're waiting on a disposal permit from the Railroad Commission in Texas. That's taking some extra time. But from a planning process, we have gone out there and planned ahead, gone through the end of this year and the end of 2012.

So, to the extent we get those permits in the next few months, we should be able to catch up at least on the 10,000 barrels a day right now that we are having to truck. I think we will probably -- knowing that it's taking longer now for permits, we should be able to plan ahead and do a better job going forward.

I'm sorry, disposables you said are in Texas?

In the Permian Basin, the Permian Basin is in West Texas.

No, I thought the saltwater disposal issues were in the Mississippian area.

No, we don't have any disposal issues in the Mississippian. We are just waiting on some electrical infrastructure to be built there.

So, what is the misnomer is that the Mississippian is the only place in the country that produces water. Today, we produce about 150,000 barrels a day of water in the Central Basin platform on wells we operate.

So, we take care of the vast majority. We just have been drilling at a very fast pace and have out run that for the near-term. We will be able to drill disposal wells over time and catch that up.

Okay, and in terms of the well cost, you went from $3 million to $2.5 million to $3 million, with the new rigs that are maybe less efficient and new areas that you are less experienced in. Do you think you'll go back down to $2.5 million at some point?

I think that is our goal. Right now, we are just saying the play is so new that you're going to keep on bringing in new rigs, and you're going to keep on drilling new areas. And when I say a new area, that's really township by township.

Across 6.5 million acre play, there are a lot of townships to drill in. So, for the near future, as we go out through our plan, we don't anticipate cutting that well cost.

Thank you.

Thank you.

And our next question comes from the line of Craig Shere representing Tuohy Brothers. Please proceed.

Hi, good quarter.

Thank you.

Tom, you rightly mentioned again that you all have no interest in selling the gas properties. And you have recently been commenting about an expectation with the Haynesville and Barnett rolling over that 2012, we might see a nice recovery there. And you might get some good value in a year or two out of that ace up your sleeve, so to speak. More recently, unfortunately we're seeing an impact on demand with economic conditions. I just wonder if you could comment about your perspective on the gas market, and the value that's hidden in your portfolio today.

Sure, I can give a perspective. Keep in mind it's just my perspective, but I believe that we are -- we do have a lot of supply of natural gas. And that at these prices and bringing on new capacity in the Haynesville, that you will still see higher supply here in the near term.

But we believe 2012 will be a better natural gas market than it is today. I don't believe it will compete with oil in the future, so we will continue to concentrate on oil and look for a time to be able to do something with our gas assets. We don't know when that is, but I don't think it is necessarily out of the question that we couldn't start looking at that in the next year or so.

And I think you mentioned before, you wouldn't initially jump right into a sale on properties you haven't worked on for a while. It would be a little CapEx ahead of a final sale, is that correct?

We haven't even anticipated it, so speculation would be is you would want to -- any field that hadn't had any work on it in some time, you'd want to spend some capital with the idea of selling it. So, that could be.

Sounds great, thank you.

Thank you.

And our next question comes from the line of Duane Grubert, representing Susquehanna. Please proceed.

I'm impressed you get remarkable consistency of production across the Oklahoma and Mississippian wells. What do you guys envision is going to be the driver of efficiency improvements, in terms of the well bore. We always want you to have lower well cost through drilling times and all that, but is there anything about the physical design of the well or the frac that you see as a particular focus area going forward?

Yes, I think as we are drilling so far from end to end, it is probably something in order of 130 miles, 140 miles, 150 miles apart. As we know --as we learn more about the geology in each of the different areas a little bit better on a granular basis of exactly what rock we are cutting, we will do a better job of bit selection in those areas. I think that could add a day or 2 there. Save you a trip or 2 during the process.

As we move and do more drilling in Kansas in 2012, that is probably -- have an opportunity to drill 500 feet to 1,000 feet lower. So that's going to add -- take off a couple days also. We continue to try different types of completions. We've gone from 14, 15 stages at the beginning of this play in early 2010.

Then we went to 11 or 12 stages, and we went to 8 stages, and we'll continue to break that down. We've pumped probably half a dozen wells with 6 stages of fracs and have not seen any difference in the IP, so that will cut some costs also. Yes, there are things that we are continuing to learn, continuing to do, that I think over time we will continue to improve on the cost side.

Duane, even as we have -- again this is 150 miles of a part of wells. You are going to have some wells that have a higher GOR than others or have more oil. And we'll continue to work on our types of lifting, whether it's ESPs or gas lift. Other ways that we drill wells in different areas will improve for the production side out in the future. We still are very early in the play, but you're right, the consistency across the play has been very good.

Okay, and a related question, you are about to spend a lot more money and granted a lot of it is for land. What kind of staffing up do you need to do? And how is SandRidge fundamentally changing culturally and technically in terms of its mix with your go-forward plan?

Well we already had a great staff in place, and we've moved from drilling gas wells into drilling oil wells, and have moved the appropriate people into new areas. So, keep in mind, and 2008 we had 47 rigs running. So, the staffing here has been good. We do continue to hire new people, great people, so we don't see staffing as an issue.

Okay. And then sort of related again, in terms of vertical integration with your rig fleet, do you intend to pick up any more rigs or any other service investment with your increased activity.

We mentioned in the last call that there -- we anticipate, we haven't seen it yet, but we anticipate there would be an increase in drilling in the Mississippian play and Oklahoma and Southern Kansas. And with that, we thought there might be a tightening in the 1,000 horsepower rig fleet, but so far, we haven't seen that. And we have been able, over the last quarter, to go out and make contracts, and so far haven't had the necessity to be buying equipment.

So, it looks like -- if it looks like we can continue to fund -- to keep the rigs that we have and not have to increase, that is our goal.

Okay and then one final one. Just a real short answer too. Definitively on the joint venture you just did, so I heard you say you sold no wells, no production. Is it also true there's no PUDs on the books that got sold with that transaction?

No, that's not correct. The joint venture would be outside of units that are producing. So, there would be some PUDs in the joint venture and some PUDs that might not have been.

Very good, thank you.

And our next question comes from the line of Peter Kissel, representing Howard Weil. Please proceed.

Good morning guys. Most of my questions have been answered, but I had a quick question on the natural gas production. Guidance got a nice little bump, and the quarterly production looked a little bit better than what we were looking for. My question is, is that more due to a shallower decline than expected in the West Texas overthrust, or is it more just associated gas in the Permian and Mississippian?

Are you talking about for 2011?

Yes.

Really our gas decline outside the Permian and the Mid-Con and the non-active areas have been fairly consistent with what we predicted early in the year. But, what we are seeing is more gas in the Mississippi drilling. Not at the expensive oil, but certainly a higher gas rate than we have projected on the type curve.

Got you. That's helpful, thanks, Matt. That's all I have got. Thanks, guys.

As you think about that, and looking at the 30 day rate, it's above the type curve and that's mainly with gas.

Thank you.

Our next question comes from the line of Hsulin Peng, representing Robert W. Baird. Please proceed.

Good morning, this is Hsulin. My question is regarding your 3-year strategic plan. Can you talk about the growth rates that you are assuming for production in 2013 and 2014? Is it similar to the 20% for 2011 and 2012?

We just said that we will be comfortable with double-digit production growth.

Okay. In terms of your target debt to EBITDA, less 2 times, is that a goal for -- by the end of 2014, or would you like to see that earlier, say next year or 2013?

It's a goal by 2014.

By 2014, okay the end of 2014. Okay, got it. Great, thank you.

Thank you.

And our next question comes from the line of Derek Jumper representing DW Investment Management. Please proceed.

Hello, guys. It's actually Dan Shanra in on Derek's line. Good morning. I have a couple of questions. First, you went through, and I've been on and off the call, so I apologize if you've covered this in more detail. In the opening comments, you mentioned that your LOE costs went up $1.66, and you gave the different components of it. How many of those are really going to last, are going to be recurring for a long period of time? Or are they mostly just 1-time things for the next quarter or two?

What will be recurring for a long period of time is work over program. As we're drilling, now you're looking at drilling 1,000 wells a year. You'll have continued work overs, and just general well work.

What's not going to be recurring was the offshore maintenance work, at the heel of the BP tragedy there and the Gulf spill. Of course all of the regulatory bodies got everybody to look at our platforms pretty closely. And all of that came in Q1 where we did some corrosion mitigation on our platform, as well as our partners and in the non-op platform, but I think that's behind us now.

Then the other 2 LOE items, 2 items that increase LOE, had to do with saltwater disposal and electrical infrastructure then in the Mid-Continent and the saltwater spills issue in the Central Basin platform. Those we'll continue to mitigate over time. We, really just taken us longer on the electrical side to get right away and to get equipment ordered and so had to rent a bunch of generators to keep up with the wells we're drilling in the Mid-Continent. And then in the Permian Basin, we just added so many wells so fast this year we got behind on the disposal issue. But we will be working those off in the next 2 or 3 quarters.

So, of the $1.66, only really $0.46 per barrel is what we should expect as long-term increased cost?

Yes. I am hoping really by the end of this year to say that $1.66 down to $1.00, somewhere in that range. And then going forward from there, should whittle that down further.

Great, thanks. Can you give us a sense of what the absolute minimum CapEx you need to do is in the year? Aside from all these obviously very value-added projects. What you really need to do per quarter or per year?

For 2011?

2011, 2012.

Sure, 2011, we are basically on course to do the $1.8 billion because we are buying the acreage for the new play, and moving up our drilling as we mentioned. In 2012, you do have a lot of options ahead of you. If things were to deteriorate this fall and we had a reoccurrence of 2008, we went from 47 rigs to 4 rigs in 2008 to 2009. So we have the ability to change.

And as we did in 2008, we had a great hedge book in 2008 that allowed us to go through at time of cutting back rigs. And most of -- all of the Permian Basin's APP, and then in the Mississippian we can cut back to a very -- we can cut back rigs even to where we were at the first of the year was only at $1.3 billion, including land.

Great, that was what I was getting at. Thanks very much.

Our next question comes from the line of Dan Morris, representing Global Hunter. Please proceed.

Thanks, it is Morrison. Most of my questions have been answered. It's such a huge ramp coming in the Miss rig count, --

I'm sorry, Dan, I'm not catching it.

Can you hear me now?

Yes.

Sorry about that. You've got such a huge ramp coming in the rig count in Mississippian. Can you walk us through how that is going to scale up?

Sure, it's really a rig a month.

Rig a month, starting now?

Already started, yes.

Okay, great.

Thank you.

And our next question comes from the line of Scott Hanold, representing RBC. Please proceed.

Good morning guys.

Good morning.

Looking at your targets for 2014, how much external capital do think you need in total? And talk to the timing of when you'd like to see some of this in place to go forward?

Sure. We have 2 transactions pending, as we've said, that will fund all of 2011 and fund into 2012. I don't think we are going project an exact amount of capital that we need to get through 2014.

You can model it out. And we've said, and we continue to say, that we don't look to add to our debt load, rather to grow into it. I think you'll see us use some of the same monetization methods we have this year to fill that funding gap.

And you should also think that we have thought about how we are going to fund that, and have plans to move forward into 2011 and early part of 2012 before it's needed, obviously.

Okay, good color. And in terms of drilling in the old Miss, can you talk about any step out results that you have had recently? Obviously, you guys were active up in Comanche County. Is your recent activity still pretty much focused in, what I would call the center of the core of the play, or what do some of the step outs look like?

It's in between -- we did 3 step outs that we gave slides on that were the furthest extent of the play in basically each direction. There is nothing further out than that we have tested. So, everything, by definition, is inside of the step outs that we had that were all above our type curve wells.

It doesn't mean that -- I don't know how you define a core whenever you have all really these vertical wells across the whole play. And we're seeing very consistent results across 4 counties. Yes, it's all within the 3 step out wells.

Great, appreciate that. And have you guys, in the new Miss, when is the plan to spud your first well out there?

The new well, is that what you said?

The new Mississippian play, where it's undisclosed. When do you plan on spudding your first well?

We don't have plans yet.

Okay but you will be active there, I would assume, by early part of 2012? Is that a fair statement?

We will be acquiring acres this year.

Okay. Thank you.

Thank you.

And our next question comes from the line of Chris Pikul, representing Morgan Keegan. Please proceed.

Thanks. Can I just get a little more strategic color on the JV? Did you have an appetite for potentially bigger transaction. And then just are you looking to hold that 500,000 acres net to SandRidge, or are you think about that extra acreage for further monetization possibilities?

It's possible sure. We like smaller partners, financial partners. And so, the idea of one very large partner wasn't as appealing to us. The average JV that's been sold is, James did some work and said it was approximately 42% so far, and ours is 13%. So, what we are trying to do is keep as much of a great play as we can, and still bring in AV forward. That's the basic 2 reasons.

And then to just deal with a great partner, you're going to have a very long relationship with, and we felt like Atinum was perfect.

As far as the value of the deal, the implied acreage value, this is a loaded question, but do feel like this is a first step in establishing a potentially higher value as the play gets further proved up and developed?

We continue to feel like the play is meeting to beating our expectations as we produce more than our type curve. So, I can't answer that we will be able to have a higher price if we chose to do another one, but we don't think that there's anything deteriorating yet in the play at all.

Great, thanks, Tom.

Thank you.

We have a follow-up question coming from the line of William Butler, representing Stephens. Please proceed.

Hi there. I just wanted to get a little more color maybe on the Mississippian line, the ramp going from the first quarter through the second quarter. It looked like back in mid-May, you were producing over 12,000 BOE a day. Did something happen in June in terms of infrastructure or services to slow it down? It seems like it should have been a little bit north of the 8,400, I guess is what I'm getting at.

I'm not sure where those numbers are. Let me start with a rig count. In the first quarter, this year, we averaged about 8 rigs for that quarter. In the second quarter, we probably averaged 11 rigs, and now we have 14 rigs running.

And so in the first quarter, in the Miss play, in the first quarter, our Mid-Continent production, which is primarily Mississippian, was 8,200, call it a 8,300 barrels equivalent per day. In the second quarter, it was 11,100 barrels equivalent per day.

Okay. And of that 8,400 BOE a day, was Mississippian of the 11?

No. We're talking about 2 different time frames, 2 different quarters. The first quarter the Mid-Continent was 8,300, and then in the second quarter it increased 11,100. And that's all due to the Mississippian -- Horizontal Mississippian drilling.

Okay.

All right?

Okay. And I guess one other question is could you -- in terms of the JVs, you wouldn't JV any more or higher working interest to a separate party. That sort of funding method is behind us now, in terms of on that, the Mississippian line acreage in Oklahoma. Would that be accurate?

No, that's not accurate.

You could do more there?

We still have that option, yes.

Okay. You could do that with a different partner, and that would be -- there's nothing that prohibits you from doing that I assume?

No, nothing prohibits us.

Back to your first question about the Mississippian production, we just posted a new presentation in our slide book, and I think on page 16, it shows how that production has ramped up over time.

Okay. Wonderful, thank you, guys.

Our next question comes from the line of Richard Tullis, representing Capital One Southcoast. Please proceed.

Thank you, good morning. I think a lot of my questions have been touched on. Matt, I just wanted to go to the spacing issue -- spacing question in the old Mississippian play. I know you guys are using a little wider spacing than what say Chesapeake and Range talked about last week with pretty good success. Could you talk about the difference in your methods there?

Well, I think what it tells you is that we have a lot of upside there, if they are correct. Right now, we have approximately 900,000 acres in the old Mississippian play that we are working on, so there is really no reason for us to go and experiment with increased density drilling on the 640 acre section.

And as we know, the tighter the spacing, before you get a lot of reservoir knowledge and a lot of time on how horizontal wells are going to perform, the tighter the spacing, it certainly introduces more risk to the reserves. And so maybe we are conservative, maybe not. But right now, we feel the correct spacing is 3 wells per session.

Okay, and then the last question for me is have you thought about the low-end of your EUR range? Is it still in the 300,000 barrel neighborhood, given the performance you've had against your type curve with your first 100 plus wells?

Yes, we haven't changed the range. It is still 300,000 to 500,000 barrels of oil equivalent per day. We will revisit the type curve at the end of the year, and make a decision at that time whether we want to change the type curve in the range or not, but we are not there yet.

How many of your first wells would you put in the lower quadrant of that range?

I think the way to -- maybe you can explain that or look at it, is in the first trust that we did, there were 37 wells, and 1 of those we defined as would not pay back.

Okay. Thanks a bunch, I appreciate it.

Thank you.

(Operator Instructions) And our next question comes from the line of Noel Parks, representing Ladenburg and Thalmann. Please proceed.

Good morning.

Good morning.

Just a quick question. Back in the Permian, any update or thoughts on deeper targets in Central Basin Platform, or are your explorations focused much on the new plays Mississippian there, that it's on the back burner?

No, We drill deeper targets in the Center Basin platform. I don't know if you mean --Ellenberger is a deep target. We drilled some Ellenberger wells, we drill to Albany and Clear Fork and San Andreas and Grayburg. We do test deeper targets across the Permian.

Anything significant as far as representing a new project in your legacy areas there?

No we just have one type curve for the entire Central Basin Platform, and we continue to work on that.

Great, that's it for me.

We have a follow-up question coming from the line of Joe Allman, representing JPMorgan. Please proceed.

Thank you, everybody. I love your comments about calling the Mississippian play in Oklahoma and Kansas the Old Miss. It's not that old it seems to me. In terms of the $3 million cost for the old Miss, just to clarify, that does include the saltwater disposal?

That does not.

Okay, so if you were to allocate the cost to the well, would you make it $3.2 million per well?

That is correct.

Okay that is hopeful. And then to the Central Basin Platform, could you just describe the water disposal issues you have had out there, and what is the solution with the timetable?

Really, we just outdrilled our disposal capacity, with nearly 400 wells we put online in the first half of this year. And really the issue always waiting on permits, so we convert some more disposal wells.

Okay, so you've got permit applications, and you're waiting for the permits to get approved?

Yes.

And how many water disposal wells do you need to drill, and what is the cost associated with that?

I think we may drill 1 new 1, but we are looking at converting 4 or 5 oil well bores to disposal wells. So, very quick projects, as soon as the permits come in.

Okay, so not a big CapEx expense? And not a lot of time? And that will take care of you for what period of time?

I think it will care of us for the rest of this year, and then we will have to continue to stay on top of it going forward.

Okay, that is helpful. And back to the type curve question, the type curve you are using is 409,000 BOE. How much of that is oil; how much of that is gas? And you talked about wells doing better than type curve, and that incremental volume being primarily gas.

Could you describe that for us? Above the 409,000, how much -- what is the trend above the 409,000? Or what are those wells trending towards in terms of an EUR, and so how much incremental gas are you actually seeing?

Starting with the type curve, the type curve, that represents 400,000 barrels of oil equivalent is almost 50-50. I think it's 48 gas and 52 oil. I can't remember exactly the number, but on a first 30-day IP basis, you're looking at probably 650,000 to 750,000 MCF a day, and probably 120 barrels of oil a day, somewhere in the neighborhood.

As we drill out the wells, and Tom mentioned that the 30-day numbers are higher than the 244 barrels of oil equivalent, most of that is really on the gas side. Instead of seeing on average 650, 700 MCF a day, we're probably over 1 million a day on average on the gas side. And that's what driving the initial IPs, the 30-day IPs higher than the type curve.

Got you. I imagine you're seeing some wells below, some wells above, but on average you're seeing -- is that right, of the wells you've drilled so far, collectively you're seeing the wells actually doing better than that 409,000 type curve?

I would be comfortable saying that on average, we are seeing higher IP s than what represents the 409,000 type curve. But, I want to hold off on the EUR until the end of the year when we revisit everything.

And Joe on that same slide show, page16 shows the first 30 days for the 30-day rate.

Okay, got you. That is helpful. Thanks. And in terms of the new Mass, Tom, you mentioned no specific plans to drill. What's the reason for that? You just don't want to have other folks get data --

It's very simple. We know that oil is in place because there's been 8,500 vertical wells drilled, so why would you need to go out and pinpoint where you're trying to locate the play, or where the play is, whenever we already know that the oil is in place.

Got it. There is a competition aspect to this thing, as well?

Sure. I'd rather we not even talk about it today.

Okay. Agreed. And then in terms of -- in the past, you talked about selling off half of your old Miss position, and now you're saying you want to keep as much as possible. I thought that 1 reason for selling off half was that you didn't think that you could develop a huge position optimally within the Company.

So, now you're talking about developing a big position in the old Miss, and then a big position in the new Miss. Can you just talk about how SandRidge can efficiently and optimally develop these 2 big plays, in addition to the Central Basin Platform?

Sure. The original thought was we would have to sell half of our acreage, because we had -- we were anticipating up to 1 million acres, and we knew the play was working, but it was all around financing. Now we are much more comfortable with financing the play as we move forward. And then the new play only requires a couple $100 million of capital to maybe have something that is worth many billions of dollars ultimately to shareholders.

If you think about this, at the time that we moved into the Permian, no 1 thought it was a good time to be moving in. At the time we moved into the Miss, everybody questioned why in the world we would be trying to go into a new play. And the answer is, if we wouldn't have done it then, it would be gone.

Whenever you find a play that you really believe in, you have to act, and that's why we chose to move forward. And luckily, now that we've -- the play has moved in a direction that's very positive, so we have been able to finance it.

Okay. That is helpful.

The more we can finance and do deals like the joint venture or like the royalty trust that allows us to raise capital to a much higher price than we put into the play, so it allows us to keep more of our -- for ourselves a working interest.

So, for you it was never about the ability to optimally develop from an operations perspective, it was more about the financial part?

Yes, and we couldn't have gone to the 24 rig average if we wouldn't have been able -- put it this way, we always assumed we would move up the rig count, the question was how much of that we would own?

Okay. That's helpful. And if I could ask a question about the WTO. The more that you are focused on oil and not drilling gas the more there is a CO2 liability that grows. And so do have any an update on plans to take care of that liability?

Sure, I'll let Kevin hit that.

Joe, we have actually put a range around what we would think the 2012 liability would be at the current expected production coming out of -- or CO2 production coming out of the Pinion that it would in the $15 million to $20 million penalty range for next year's settlement with Oxy. Next year being 2012.

Kevin, is that just the nuisance payment or the late fee we talked about?

It is. And it would be due in early 2013.

Okay. As time goes on, you actually have a growing -- in addition to the late fee, the principle isn't changing right? I know you're producing some into the plant, but you're going to be having, as your gas production in the West Texas declines, you're going to have a growing liability of CO2 principal that you're going to owe Oxy. So, is there any update in somehow trying to take care of that liability?

As you know, Joe, it's a 30-year contract, so we are still pretty confident that over the 30 years, that field is going to be drilled, and there is going to be the CO2 delivered to Oxy that is asked for under the contract.

Okay, very helpful. Thanks guys.

Thank you.

We have a follow-up question from the line of Dave Kistler, representing Simmons & Company. Please proceed.

1 quick 1 on the new Miss play. Building on what Joe was asking as well. Aggregating or looking to aggregate 1 million acres there, at this point, based on your appetite, is that what SandRidge ultimately wants to hold? Or is it similar to the new Miss where you stepped in to grab 1 million acres with the anticipation of reducing it over time?

At this point, that is all we anticipate holding. Keep in mind, in the old Miss, we went in with the idea of getting up to 500,000, and then ultimately grew to 1 million. I think for any company 1 million acres is a substantial amount to try to take care of. As of today, we will -- we are safe to say we budgeted for 1 million acres.

Okay. And then also, clarification on at what price would you start reducing CapEx? I'm guessing you guys have run some sensitivities as part of this 3-year strategic plan. That if oil moves to X, we will start ratcheting down. What is that specific price?

I think it has more to do with the overall world economy, and if we saw oil go down for a short period of time, but felt like the world wasn't in some turmoil, that makes a lot of difference. Keep in mind that we are hedged for the next 3 years. I think we have been the most active hedger of oil in the business. So, that is the key.

But as we will look at this, we visit every day about what we think -- how many rigs in our budget. And we meet once a month formally to discuss budgets, so it can be -- we can be very fluid.

And I think maybe that is due to our size, but we can react pretty quickly if we foresee problems. But, I can go back easily and say $1.3 billion budget was something we were very comfortable with at the first of the year. That would not ultimately meet the 3-year plan that we have laid out, but it still would be a very attractive Company.

That is very helpful, I appreciate it guys.

Thank you.

And our next question comes from the line of Craig Shere, representing Tuohy Brothers. Please proceed.

Hi, on the old Miss, you all had originally said that you did need to double from first-quarter levels to 24 rigs to HBP, all that property. Can you talk about, or are you willing to discuss if the new lease terms in the new Miss are similar in terms of HBP obligations to the old?

Yes they would be. It's virtually the same type of lease terms. We get 5-year leases.

Great. Appreciate it.

Or 3-year with 2-year options.

Wonderful. So, basically, it's very similar strategy to the original one because you trued up that acreage before you really started seriously looking at the drilling campaign. And now with similar lease sold obligations, you're just doing the same thing?

That's correct. And again, the reason you can do that is history of the play. We didn't mind at all going out with 3 rigs, and drilling at the furthest extent of our original Mississippian play, because we were drilling offsetting vertical wells that had produced oil. So, we know the oil is in place. It's already produced next to us, alls we are doing is drilling it more efficiently by putting 10 well bores inside of 1.

Understood. Thank you.

Thank you.

With no further questions in the queue, I would now like to turn the call back over to Tom Ward for closing remarks. You may proceed.

As always, we are very thankful to have you on the call, and we look forward to talking to you next quarter. Thank you.

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