James D. Bennett - Chief Financial Officer and Executive Vice President Tom L. Ward - Chairman and Chief Executive Officer Matthew K. Grubb - President and Chief Operating Officer Kevin R. White - Senior Vice President of Business Development

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division Scott Hanold - RBC Capital Markets, LLC, Research Division Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division Joseph D. Allman - JP Morgan Chase & Co, Research Division David W. Kistler - Simmons & Company International, Research Division Craig Shere - Tuohy Brothers Investment Research, Inc. Unknown Analyst Charles A. Meade - Johnson Rice & Company, L.L.C. Brian Singer - Goldman Sachs Group Inc., Research Division Duane Grubert - Susquehanna Financial Group, LLLP, Research Division Daniel J. Morrison - Global Hunter Securities, LLC, Research Division Richard M. Tullis - Capital One Southcoast, Inc., Research Division Patrick Lee Graham Yoshio Tanaka - Tanaka Capital Management, Inc. Alex Heidbreder Joseph Stewart - Citigroup Inc, Research Division Anne Cameron - BNP Paribas, Research Division Robert Carlson

Good day, ladies and gentlemen, and welcome to the First Quarter 2012 SandRidge Energy Earnings Conference Call. My name is Dominique, and I'll 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. James Bennett, Chief Financial Officer. Please proceed, sir.

Thank you, Dominique. Welcome, everyone, and thank you for joining us on our first quarter 2012 earnings call. This is James Bennett, Chief Financial Officer. And with us today, we have Tom Ward, Chairman and Chief Executive Officer; Matt Grubb, President and Chief Operating Officer; and Kevin White, Senior Vice President of Business Development. Keep in mind that today's call will contain forward-looking statements and assumptions, which are subject to risks and uncertainties, and actual results may differ materially from those projected in these forward-looking statements. Additionally, we'll make reference to adjusted net income, adjusted EBITDA and other non-GAAP financial measures. A reconciliation of any non-GAAP measures we discuss can be found in our earnings release and on our website. Please note that this call is intended to discuss SandRidge Energy and not our public royalty trust, SandRidge Mississippian Trust I, Mississippian Trust II or SandRidge Permian Trust. SDT and PR will be addressed on separate calls on May 11. Also, SandRidge will file its 10-Q on Monday, May 7. Now let me turn the call over to Tom Ward.

Thank you, James. Welcome to our first quarter operational update. We had another great quarter where, once again, we achieved record oil production, which drove our earnings. SandRidge is fully financed for 2012, as we have now closed on our Dynamic acquisition and completed the IPO of our second Mississippian Royalty Trust. We averaged 36 rigs operating during the first quarter and drilled 250 wells. Currently, we have 42 rigs operating, including 5 rigs drilling disposal wells. It is quite remarkable the change that has happened at our company over the last 4 years. In the spring of 2008, there were few industry people worried about being a natural gas company. However, as large integrated companies begin to surface in North America after a 30-year hiatus, our management team did take notice. And by the end of 2008, decided that change needed to take place at our company, and change we did. We first hedged our natural gas through 2010 at above $8 an Mcf, then embarked on finding the very best conventional oil assets in the U.S. We went to our Board of Directors in early 2009 when natural gas was $4.13 and oil was $39.96 per barrel, with a bold plan to start acquiring the least expensive oil in the most prolific place, the Permian Basin. We not only chose the Permian, but the Central Basin Platform where the shallowest, most inexpensive oil was produced. Today, we produce over 30,000 barrels of oil equivalent from this asset, and we've drilled more than 750 wells here this year. In 2009, we also identified one of the largest stratigraphic traps in the U.S., with tremendous oil reserves and untapped horizontal drilling potential that was not being exploited because of high water production. At that time, there was much industry excitement…

Thank you, Tom. You'll find the full set of numbers in our earnings release, so I won't walk through all of them, but will instead hand out to you the major points. For the first quarter, adjusted net income was $21.2 million or $0.04 per diluted share. Adjusted EBITDA was $185 million and operating cash flow was $153 million or $0.31 per diluted share. Primarily driven by continued growth in oil production, adjusted EBITDA is up 27% over the comparable 2011 period and 6% over the fourth quarter 2011. Production for the quarter averaged 66.3 MBoe per day. Recall that we divested our East Texas gas properties in November of last year, and those assets were producing about 25 million a day of gas or 4,200 Boe per day. So adjusting for this divestiture, our quarter-over-quarter production grew from 64.3 MBoe per day in Q4 to 66.3 MBoe per day in Q1 or 3.4% quarter-over-quarter growth. In terms of per unit expansion measures for the quarter, both LOE and DD&A per Boe were below our 2012 guidance ranges. G&A of $8.31 per Boe was above our guidance range, but includes expense transaction costs associated with the Dynamic acquisition and other legal and advertising costs, and are front-end weighted in the first quarter of the year. For the full year, and taking into account the Dynamic acquisition, we still expect these per unit measures to fall within our published guidance ranges. Regarding Dynamic, we will start to see the contribution from the acquisition in the second quarter period. And for the first quarter, Dynamic average production of 26,000 barrels of oil equivalent per day and generate EBITDA of $89 million. This brings the Dynamic pro forma LTM EBITDA in Q1 to $393 million, and combined with SandRidge’s EBITDA of $691 million.…

[Operator Instructions] And your first question comes from the line of Neal Dingmann of SunTrust.

Say, Tom, could you just address a little bit maybe more in detail your comment about many monetizing the new acreage? To me, it looks pretty accretive. I just want to know your thoughts about that and if you would think about or have opportunity to continue to increase a little bit more than the 200,000 you recently added?

No. We're essentially through with acquiring acreage. Just -- as you might imagine, if you have hundreds of brokers in the field and you want to get to 1 million acres and make sure that you get to 1 million acres, what happens is you can move over that target just a bit, and we did in the first quarter. So we ended up with 1.2 million acres. However, the good surprise is, it came at $350 an acre. So even though it was at the tail end of our acquisitions, the price wasn't very high. And we think that, obviously, we've done much better than that with selling acreage in the past. So we don't have to sell acreage, but I think the 1.5 million acres was where we were comfortable and that kind of leaves us with a couple hundred thousand acres that we could sell, if we chose to. So the reason we brought it up is, it's just an unexpected surprise that we have a little bit more acreage than we anticipated. We spent the money in the first quarter and now we can look to monetize that if we choose to.

Okay, and then just 2 others. Tom, just you addressed some of the infrastructure and other things in the horizontal Miss. Does that mean -- did you look that more of those costs would be sort of an upfront in your CapEx? You see those going down for the remainder of the year? Or you continue to have sort of the water and other build-out costs throughout the year?

Matt can address that one.

Yes, Neal, now we do see it going down as we move forward. We did want to ramp up our logical infrastructure. We do have a pretty aggressive programs and install sub pumps. We want to get that kicked off. So you put in a logical facility. You can run quite those sub pumps and get that going. On the saltwater disposal side, these wells actually make a lot of water, so we do want to minimize LOE and be upfront with our pump with our saltwater disposal wells, seeing our original plan is to drill 57 wells this year and we've already knocked out, I think, 17 in the first quarter. So we are a little bit ahead on both of those areas. And then we also purchased -- prepurchased pipe further on program, so all those things are kind of onetime items.

Matt, and then just one last follow-up. Just over on the Perm, Matt, the issues you had previously on sort of the infrastructure, et cetera, had most those been addressed or where do you sit now on that? On the…

Yes. I think back in November we say we would finish that project in -- before the end of second quarter this year, and we are right there on schedule and on budget to complete that here this month.

Your next question comes from the line of Scott Hanold of RBC Capital Markets.

Just to clarify a point on the CapEx. So I mean, you obviously held your budget consistent with where it was before, and it sounded like you did have a little bit more acreage spend, maybe by $50 million, $60 million, $70 million, in the first quarter. So I mean, as we progress through the year, how do we get back to that $1.85 billion number that you're targeting?

Yes. Scott, I'm going to walk you through the CapEx. I think that is an important point. What we want to do is give you some sideboards on this thing and make sure that we don't take the $570 million and do a linear extrapolation and come to $2.3 billion for the year. That's not the case. We had about $140 million of CapEx in the quarter that were related to onetime items that include carryovers from last year's expenditure, some -- a little bit more land than we anticipated and also some acceleration of infrastructure. And so you take that $140 million off of $570 million, you have $430 million and you extrapolate that up by 4, you get to $1.72 billion. And then in Dynamic, where you're assuming $200 million CapEx, of which about $20 million has been spent in Q1, so that leaves you $180 million. $180 million plus the $1.72 billion gives you $1.9 billion and then you add back in this the $140 billion of onetime expenditures we talked about, you had $2.04 billion, okay? So that's kind of the high side of the CapEx. That's right at about 10% over expenditure. But how the CapEx rolls back down is through the acceleration of the carry interest in our JVs. So when you think about this, if you just look at an example on the Extension Miss where we're going to drill 50 wells, but none were drilled in Q1, and all of those are going to start -- we're starting right now in Q2 with Extension Miss, where if you look at a well and you think about it has a gross cost of $3 million, we end up only paying $750,000 for that well and have a 75% working interest because our JV partner has a 25% working interest. They carry us 2x of the working interest. So those kind of cost savings to the carries are not built in your Q1. And so in reality, if the Extension Miss works really well, and we decide to ramp up above the 5 rigs and drill more than 50 wells -- for example, we drill 100 wells, your CapEx spending for SandRidge will actually go beyond even further because the acceleration that carry. So that's how we get back down to our $1.85 billion.

Also as we're moving into Kansas, we are seeing that days on location for drilling had come down, as it should. Shallower wells, a little easier rock to drill through compaction, and the first 2 wells that were drilled in the Extension play will be under our average for the average well drilled in the original, which are still very quick, but it is unusual to go into a new area and beat the average that we had in the original. So I think Matt did a great job of explaining it. That’s just -- a couple of added commentary, there.

And so just to clarify a couple of points. On those carries, remind me how that works. Do you all like front the capital for the well and get reimbursed or does your JV partner pay that right away? And so will there be a timing delay in there, I guess is what I'm asking? And the second thing is just with respect to, I guess, picking up more acreage in the Miss, I mean, that itself -- and if I'm doing my math right, was about $70 million, so I mean how is that accounted for in the budget?

Well, what we do is we billing them for the carry upfront. We get paid basically in 30 days or so. There was -- because we did just start the JV, one of the JVs, which is effective January 1, there was a little slow in the payment this first quarter that we’ll get in the second quarter, plus we’ll get caught up in the second quarter, so we're going to get some extra carry payments there. But essentially, yes, it's not going to be real time, but it's very, very near-term payment on both the JVs. And the reason for this, the JV with Repsol also has a two-time working interest carry also. And I didn't get to that, but if you think about what we drill, we drilled 68 wells in Mid-Continent in the first quarter, only 21 of those wells were Repsol's in those wells, and we already drilled 13 ables [ph]. So you can see the acceleration in the JV structure and the JV impact that we're going to be seeing going forward.

Okay. And then on the -- and Tom, you mentioned those 2 wells that had some pretty robust production rates over the first 30 days. I know you don't necessarily like pointing out specifically your best wells in the play, but is there anything that can be said about that particular area of those wells that were different than others or the variability you tend to see across the play?

Well, if we have the best oil drill in the U.S. in the last 3 years that would be something totally different. But other than that, they're just very good wells. So we're in the middle of an oil system that you're going to have good wells. We have a couple of wells in Grant County that produce over 1,000 barrels a day. It's not so unusual to have really good wells. But what I really would love for people to focus on is that over thousands of wells, we have the ability to make very high rates of return. And these, if you look on that slide where we show our Mississippian production growth, you see a dramatic move-up. But even if you normalize that and go back over the last -couple of years, where you're just averaging 300 barrels a day, you have a tremendous growth in a very, very large asset base. So I mean it does, I guess, maybe frustrate me to see one well here and one well there across every play in the United States talked about with just the assumption that every well is going to be like that. We really don't believe that every well is going to be 1,000 barrels a day here, but we really do believe it's going to be somewhere between 244 barrels a day and 315 barrels a day. And if that happens, we will have a company that changes dramatically.

Okay. So then in particular, with those couple of wells, and not to belabor the point, but there wasn't any difference in the way you completed that well, which could be applicable elsewhere and/or it's not just a really good sweet spot where you've got some more development opportunity that could actually be pretty interesting.

Well, I think, no. It is completely the same way to say it's not a really good sweet spot would be wrong, but I think that there are opportunities to drill wells around high permeability streaks that you do have 2 or 3 wells that will be above average, and then we drill other areas where wells can be a little bit below average. But overall, I think that we've shown that we can continue to increase our rates over the course of time. I don't know if that happens from this point forward, but it doesn't have to.

Your next question comes from the line of Amir Arif of Stifel, Nicolaus. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Just wondering if you can give us a little more color about the wells that you are drilling in Kansas? You mentioned a little shallower or less drilling time. In terms of production or EURs, how are those stacking up relative to the quarter?

Well, we haven't -- we've only drilled 2. Well, we haven't completed any wells in the extension area. And I guess people might want to draw a line across Oklahoma to Kansas even though the geological time didn't really matter where the state boundaries are. The Kansas wells have averaged just a bit more. Our 30-day IPs in Kansas have been 346 barrels for 30 days and the Oklahoma IPs, their initial production rates have been 307. However, we've drilled many more wells in Oklahoma than in Kansas. So I think that, more than likely, the Kansas wells will gravitate to where Oklahoma and Kansas are exactly the same or very close to it. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: And Tom, so are these -- are the 5 rigs in Kansas focused on just north of the border like Comanche-Harper County or is this further up?

We also have a slide update in where all the wells have been drilled. There are 2 wells in the, what we call, the extension, one in Sandy and one in Hodgeman, that we haven't completed yet. And then the rest are along the borders that you're talking about across Harper, Barber and Comanche. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: And then just a final question on -- your production growth is so strong out of the area. Can you just give us some color on the oil takeaway and what kind of price realizations you're seeing?

Yes, I'm sorry, I didn't get the first part of the question. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Just the oil -- the takeaway for the oil production out of the area and price realizations.

Yeah, in the Mississippian play, we just recently signed a deal with Plains that really did enhance our oil takeaway and pricing, and how that helps us as it lowers the transportation cost and minimize the trucking business. All the oil in Mississippian goes to Cushing. And instead of having to truck every bulk to Cushing, we're trucking it into nearby injection points, and Plains gather and take it to Cushing, so we expect kind of a little bit of an upgrade there. But Cushing right now -- total storage is probably around 60 million barrels and there's probably around 43 million barrels of inventory. And what's happening here soon is Seaway is going to reverse their pipeline, which is probably here another 10 days to 2 weeks, and that's going to give you 150,000 barrels a day capacity, both from Cushing to the Gulf Coast. So that will further enhance the value of the oil that we'll get, plus certainly eliminating inventory issues at Cushing. So in the Mississippian play, we really don' see any capacity constraints for oil sales going forward. Seaway also going towards the end of the year, they're going to start some more pump stations, and that 150,000 barrels a day should increase to 400,000 barrels a day. And of course, you’ve heard about the Keystone project and the enterprise projects. I think there's going to be more capacity from Cushing going to go off coast going into '13 and '14. So I don't see any issues there. In the Permian Basin, about 65% of our oil production in the Permian Basin is being piped via an enterprise pipeline to Cushing. And the remaining 35% is also being piped, but it is also trucked short distance to the injection points. But right now, we don't see any issues with oil transportation coming out of the Permian. I think differentials had widened a little bit here in the Permian lately, and that had to do with a couple of refineries that went down for some unscheduled maintenance in March. But overall, I just don't see any issues with crude transportation and sales. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. Can you just give me a rough number of what the realized wellhead prices in the Miss relative to WTI? I'm just looking for the deferred.

Well, I think with the Plains there, we'll see something around $0.75 upgrade. And then once Seaway reverse, I mean, certainly, your WTI and LLS spreads should narrow. So you could see kind of $5 to $7 upgrade there potentially. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Yes. But relative to WTI, you’re getting...

Right now, we're probably $5 or so below WTI. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: $5. Okay, terrific.

I think we model $4 to $5. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: $4 to $5. Okay, terrific.

Your next question comes from the line of Joe Allman of JPMorgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Could you give us the production by area currently and then the average for the first quarter, if you could?

Yes. I don't think in the past, we've been giving out production by area, Kevin...

Yes. It's not per current [ph].

I can give you...

Joe, I can e-mail you that, if that's okay? Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. That'd be great, Kevin. Okay. And then a second question would be: the shares that you gave to Dynamic in the acquisition, is there a lockup period? Could you just talk about that a little bit?

Yes, there is a lockup. They took about, I believe, about 70% of the shares, but there's a 90-day lockup on those. So the closing date was April 17, lockup’s 90 days.

Your next question comes from the line of David Kistler of Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: Real quickly on the 200,000 acres that you bought, what portion of that is in the extension area, what portion of that is bolt-on? And then maybe to follow up on that, how does that fall within the AMI of these JV partnerships?

Yes, the first part of the question, the 200,000 acres roughly splits up about 90% of it’s in the Extension Miss, up in Northwest Kansas and about 10% of it are kind of bolt-on into our Fairway area, which was called Fairway, which is kind of the original Miss area, across Woods, Grant, Alfalfa Counties. What was the part of the question? David W. Kistler - Simmons & Company International, Research Division: Just thinking about the AMIs of the JV partnerships. Is all of this covered within the AMIs? Or is it -- some of it is going to be independent of that and...

No. It's all -- yes, this is nothing that's new. It’s all cover either the one AMI or the other -- the acreage in the original Miss could go to both JV partners acreage and the Extension Miss will certainly just go to Repsol. David W. Kistler - Simmons & Company International, Research Division: Okay. And then just trying to understand a little bit of the disconnect that's taking place in terms of you're seeing great well results, yet not just yourselves but others have been able to acquire acreage for less than $500 an acre. Is it just the pure size of the play that's facilitating that disconnect versus than what you're able to monetize that for? It just -- it seems like...

It is a very large play, but also somewhat of the infrastructure is a big part of this. So you have to be able to drill a tremendous amount of wells that have high upfront cost with the infrastructure, both with electricity and saltwater. And we are set up to do that. And in fact, that's what really made the play and allowed us to move in earlier than others. And we chose to move into the Western Kansas [indiscernible] we're still working in the original area in Oklahoma and Southern Kansas. I can assure you, you can't buy acreage in Southern Kansas and in Oklahoma for the same amount that we paid in the first quarter. And I don't know this because we're not that active, but I assume it will be difficult to duplicate what we did in the extension. David W. Kistler - Simmons & Company International, Research Division: Okay. So maybe just to try to summarize that it's essentially barriers to entry or need for scale and significant capital. Is that kind of...

Well, the original barrier to entry is to be first. So if you're the first one to buy the acreage, you're the first one to get it the least expensive. David W. Kistler - Simmons & Company International, Research Division: All right, great. And then one last follow-up. If I look at the rates of return, you guys have been talking about in the Miss line right now versus where you are in the Permian, does it make sense to maybe divest the Permian, leave that capital to accelerate in the Miss line and push the NAV associated with that much of an acreage position forward?

No. Because the Permian still has very high rates of return. But the main reason is, is that you can only go so fast in the Mississippian. And what we've chosen to do is efficiently move forward with one rig per month, increasing until we get to the size of 45 rigs. Now that has a lot of other work. It sounds easy, but you have to move forward before you ever put the rig to work and put in saltwater disposal, electricity. And if you try to ramp faster than that, we think you're going to be inefficient. So everything driving our decisions here are around costs, as well as how much we're finding on -- along gas side. So the way we look at this is about the fastest that we can move forward in the play is one rig adding per month to do it efficiently.

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

Following up on the additional Miss leasing, Tom, at IPAA, you said that you want to keep the drilling inventory to under 15 years and that you'd actively consider signing down maybe another $500 million to $1 billion of additional acreage at some point. So I had kind of 3 follow-up questions in light of the fact that now you have 200,000 extra acres. First, I'd like to confirm that any sell-down in the next year plus is likely to come almost entirely out of the expansion Miss. Secondly, I wanted to confirm that to maintain the appropriate R/P ratio in your mind that you probably want to sell an additional 100,000 to 200,000 acres beyond what went over. And lastly, focus on the timing, and that you said into the coming year and you also said that by the end of this year, you'll have proved out a lot of the value of Kansas and the extension area. I just want to focus on -- you're not going to rush to do something before it's de-risked and you can get a reasonable price. Is that a fair statement?

Craig, I'll try to address all 3. The last was, are we going to rush out to do something we don't -- we don't have to rush out to do anything. We are in the acreage at a price per acre to us that's obviously very accretive to us. I think reasonable price can be construed differently among different people. So I don't know if -- what if we would sell out, if it's ever construed to be reasonable or not. But I think that you are correct. As we drill out Western Kansas, we'll have about more information, and I personally think it's fairly low risk, but we do have a lot of acreage and we do want to move down to the 15-year inventory or so. And you're correct in that, that could be a little bit more than the 200,000 acres that we purchased, but then on a flip side of that is we don't have to. We can do -- we can hold all of our acreage from this point forward and still meet our 3-year goals of funding. So that leaves us with just a lot of flexibility as we go forward into play. And then I forgot your first...

The initial one was whatever the sell-down was, that would almost all be out of the Extension Miss.

That is correct.

Okay. And one last question. I don't know if Matt wants to take it, but there is some talk of potential, eventual decline in the b factor given more results over time, and I was just wondering given some of the well results you've announced and more time under your belt if there's any thought about adjusting the type curves?

Really, we're not looking at adjusting type curve now. We'll probably do it here at the end of the year. But right now, everything looks to be on track with the way we have modeled to the 456,000 barrels EUR. So we'll look at it again at the end of the year and see how things are declining and then we'll make a decision at that time.

And Craig, just to be clear, is we don't make the type curve. That’s done by outside engineers. So it's really them reviewing the data and determining if a b factor should change or not on the type curve.

Your next question comes from the line of John Samuels [ph] of First Foundation.

Looks like your team has done a good job, you and your team of developing these oil assets. We were researching your company. It looked like it was fairly inexpensive. But as we read the Primer [ph], surprised that the $25 million comp that you personally took and the $3 million you paid to your basketball team, could you describe -- you look like you're following McClendon [ph] over at Chesapeake, which seems to be personally very greedy. Why are you doing that to the company and wouldn't the company be much better off if you were more modest in your take personally?

Sure. That's a question on whether the company would be better off with or without me basically. Do I have other options that, that I could get paid as much or more, I would think so. So I'm here at the discretion of the board and the shareholders. And if I believe that I pull my weight and the play that we're working now in the Mississippian was largely from me being able to work the area over the course of my career and had the idea to go forward with it and put together the acreage that made several billion dollars to the company. So I'm, as, as you say -- there'll be many people that say I make too much money and some that might say I don't make enough.

Your next question comes from the line of Charles Meade of Johnson Rice. Charles A. Meade - Johnson Rice & Company, L.L.C.: So I'm going back to those 2 wells. I want to understand what's your -- I think you said it was the first and the third best wells drilled. But I wanted to get a little better idea around the definition there. Is that on the 30-day oil rate? And is that just U.S. onshore wells? And is that, I think you mentioned this, but is that in the last 3 years or [indiscernible] ?

Yes, all that is correct. U.S. onshore 30-day oil rig. Charles A. Meade - Johnson Rice & Company, L.L.C.: And that's in the last 3 years?

Last 3 years. Charles A. Meade - Johnson Rice & Company, L.L.C.: Got it, got it. And then, so, I mean, maybe this kind of plays into my second question. If you look at the charts you guys have on Page 10 of your presentation, it looks like in the period of maybe 2 weeks or so, it looks like you lost 8,000 barrels a day from 23,000 down to 15,000. And then maybe part of it was bringing these 2 wells on. You jumped in very short order up 12,000 Boe a day to 27,000. And I'm wondering, could you just kind of give the narrative of both the drop and then the big rebound?

Sure, and maybe it even helps is if you look at that page or Slide 10. The different peaks that you see along the way are larger wells that are coming on, some of the valleys -- or that you're noticing, especially the one where we lose 8,000 barrels, are as large wells fall off. You do have -- some of those wells will fall off faster than a normal decline. But you'll also have weather events across Northwestern Oklahoma and Kansas that we do rely on, electricity, as we talked about. And whenever there are storms rolling across especially in the spring, we tend to have downtime of, say, if you watch the weather across Western Kansas and Northern Oklahoma and see a lot of electrical storms, you'll notice for 2 or 3 days after that, we have to bring wells back on. Now we have an exceptional team that can do that. Whenever the tornadoes went across Woodward County and Woods County into Alfalfa a few weeks ago, we had, I believe it was 70-some-odd wells down that we were able to put back online within 24 hours. So it's just an exceptional job that's just done by our field crew. And that’s part of the efficiency we talked about, whenever we feel like we're the best in the Mississippian, because that's the area we focus. Charles A. Meade - Johnson Rice & Company, L.L.C.: Got it. That makes a lot of sense.

And Charles, I would say that the spike up, I didn't mention that, that does have to do with one of the 2 wells I talked about. But we also have some other very high rate wells that are coming on that move the production graph up. But even more than that, with 26 rigs working and there are 24 rigs drilling horizontally, you do have just an increase, a dramatic increase, even if you're bringing on 300 barrels a day per well, it averages -- you can -- with each rig we bring on, that curve is going to be higher. And imagine what it's going to look like when we get to 45 rigs. Charles A. Meade - Johnson Rice & Company, L.L.C.: Right. And just to -- this was kind of a conspicuous omission, you mentioned that, that third well was in Alfalfa, but you didn't say where the first one was, and I'm guessing that was by design.

No, no. It was also Alfalfa. Charles A. Meade - Johnson Rice & Company, L.L.C.: Okay, it was also Alfalfa.

Yes, but we have a couple of wells in Grant that are not that good, but just in the same ballpark of over 1,00 barrels of oil. And so it’s just -- we have some -- we've had good wells. We've had wells like that in Barber and Harper. So if you notice some of the fluctuations on 30-day IPs, that comes from great wells coming on and then falling off. But what I really, really tried to do is to focus you on 200 to 300 barrels a day or 250 to 300 barrels a day. And if you do that a few thousand times, we won't even have to -- these other wells will be just gravy. Charles A. Meade - Johnson Rice & Company, L.L.C.: Got it. And kind of picking up on that point, looking at Page 9, when you have your -- I guess the rightmost data point on that chart where you have the drilling program to date and have an IP of -- 30-day IP of 310. Am I reading this correctly? And does that imply that your 2012 wells are better than the kind of pre-2012 average and that's what's pulling that IP up from 302 to 310?

Well, I think you're correct. But also, the 245 wells were all wells to date from 2010 -- or 2009 through 2012. Charles A. Meade - Johnson Rice & Company, L.L.C.: Okay. And so in that 310 average is for all 245 wells?

That had 30-day rates. Charles A. Meade - Johnson Rice & Company, L.L.C.: Got it. And so, I guess, comparing that to the column just to the left, if 302 was the average kind of through December 2011, then that would imply that your year-day [ph] wells in 2012 have averaged something significantly over 302 and even over 310 in order to bring the average up to that.

I think you're correct. Once again, the 2011 is just for 2011. It does not count. But if you take that to the next step and say that -- or the type curve wells in 2010 were less, but keep in mind that the type curve well at the end of 2011 is less than what we actually did also, so I think there is some conservatism in the type curve.

Your next question comes from the line of Brian Singer of Goldman Sachs.

Just following up on those couple of strong wells again, and it might be illustrative of your point to just look at the averages. But I guess comparing your presentation here, looking at the Alfalfa County average 30-day IP relative to your IPAA presentation, it looks like it actually fell slightly. So I guess the question is, are those strong rates that you discussed from those wells averaged in? Or is it illustrative of your point that these IPs do average out?

Yes, the last well is not, Brian. It's less than 30 days old. That's how come we made a estimate that if it kept up at the rates it is, it would be the best one in the United States. But it was really just in the last 10 days or so that it came online. We did know that it made enough in the 10 days to pay out the well. But to answer your question directly, it's not in the Alfalfa 357 barrel a day equivalent.

Okay. Got you. And then, can you talk to some of the similarities or differences that you're seeing in gas versus oil content in the production mix from the wells that you've drilled in the northwest versus wells drilled in the southeast to the central portion of your acreage?

Yes. I mean, the gas and oil content varies a little bit. I will say that, probably if you look at the last 4 quarters of drilling, and we drilled all over this area, your gas content -- or actually let's talk about oil production. I look at the oil, there's a percent of total production. It probably ranges kind of 45%, 46%. It's a fairly tight range. The 2, you look at just current production, where the Miss is producing nearly 27,000 barrels equivalent. Not particular days, actually probably a little bit over 50% oil. And a lot of that has to do with just the recent wells we brought on in Alfalfa that just had higher oil content. For example, the wells that Tom’s been talking about is probably 90-plus percent oil. And so that did -- it's a big enough well that drilled the overall average. But overall, everywhere we drilled, we drilled enough wells in any one area. That range is fairly tight.

And lastly, for the wells that have been online for a while, are you seeing any changes in the production mix or is what you're seeing in the first 30-day rate what you're seeing now?

No, it's been pretty constant.

And just to clarify, we don't see the changeover to more of a gas profile until later in the life of the well. So that's why we estimate 55% natural gas over the course of the well with more than 50% oil in the first part of the well.

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

Guys, you're still at a really early stage, clearly a successful stage. I'm wondering if you can talk about what extra science you're doing now that you might not be doing in the future. For example, I'll be an offender and focus on these big wells too. I got to think you're thinking, wow, wish I had a core on those. Just to see, is it a permeability streak? Or is it, I have the most awesome completion ever, or what is it? So if you guys could just talk about what kind of science might we see you do versus what you're doing now and it might taper off in the future.

Well, the 2 big wells Tom talked about, we really didn't do anything different than what we've done overall on the play. Obviously, we've got into some really good, an area with really good rock there. And you get permeability, you get oil cut, et cetera. Most of our focus is in the Miss right now because, I mean, in general, the focus is playing at the very top of the Miss. They try to stay away from [indiscernible], where you get your best porosity and permeability. But most of our focus in this play, on the science is really to reduce cost. We are experimenting a little bit with open hole packer systems. We're trying with different types of fracture in there, different types of beats and that kind of stuff. But most of our focus really is on cost savings. From a science standpoint -- I mean, from a performance standpoint, I think, Tom alluded to it earlier, but we're very happy with the type curve. We're really very happy with what we said all along, was the 300,000 to 500,000 barrels of oil equivalent per well. But these last 2 wells that are very good does give you an idea and an indication what this play is capable of doing.

And Duane, we're hopeful. We don't know this, but we're hopeful as we move into Western Kansas, there is actually a step change up in porosity and permeability. We don't have any idea if it's any better or worse than the original play, but scientifically, from core data and logs, you would think that there is a chance for that to be better. We're not claiming that it will be, but we really -- in dealing with nanodarcy reservoirs, we really should be able to capture most of the oil in plays with traditional fracs that we're using. So I don't think there's -- maybe in some areas that look a little bit tighter than others, we can go in and try some different work on the fracture treatments. It's probably more enhancing the bottom portion of your reservoir-type wells than it is the topside because you should be able to -- a well that can flow 4,000 barrels a day, you should be able to treat it fairly with a minimum treatment and bringing that type of oil on in a good, with a decent frac. So we don't know yet in Western Kansas, but from -- let me say this also. The well offsetting, this last well we're talking about, it made -- a vertical well made 9,000 barrels of oil and 18 million cubic feet of gas. So obviously, it was in a tighter reservoir than what we encountered by drilling horizontally. That's how come we think that we're in an oil system that as long as you drill horizontal laterals over 4,000 or 5,000 feet, you're going to encounter some permeability streaks that will allow you to produce the well with large quantities of oil. And we think we can do that and scale over a very large area that you don't have a core area like when you're drilling in a nanodarcy reservoir that you have to have some kind of enhancement in order to find the core area of a shale play. So it's just -- even though most people want to call this a shale play, it's really not. It's a carbonate.

And so it sounds like you're not really taking any new cores? And it sounds like you have access to a bunch of old cores. Is that true?

Well, there's tremendous amount of information. There's 15,000 wells have been drilled, so you can use sub surface on a lot of this. But there is a lot of core data also, especially across Kansas, and then we are doing some new cores in as we draw an extension.

Your next question comes from the line of Dan Morrison of Global Hunter.

Quick question, speaking of shales. There's increasing industry attention being paid to the Woodford underneath the Mississippian. One, do you all have any plans to test that yourselves? And two, do those rights – are those rights conveyed under the JV arrangements with your partners?

Yes. So the rights are conveyed to our JV partners. And no, we don't have any plans to tip the Woodford. We still like the Woodford being our source rock and the Mississippian being the trap. That doesn't mean that at some time later in the play that you couldn't drill Woodford, actually drill the source rock. We think that would be more expensive and I don't know if we would have higher recoveries or not.

Your next question comes from the line of Richard Tullis of Capital One South Coast.

Tom, I know you had mentioned that your initial 2 wells in the Miss or in the extension area are focused on Hodgeman and Finney. Is that the general area where you plan to drill the initial 50 wells this year or will you extend that a bit from those counties?

We'll drill across the play, across the area.

Okay. And going to the Dynamic assets, what are your quarterly production expectations from those assets built into your guidance for this year?

We haven't changed our guidance for Dynamic since we announced our acquisition. Other than -- that's just been [indiscernible] this year and keep production flat at 25,000 barrels equivalent per day. We do have a bit of risk, a little bit for storm season, hurricane season and things you see in August, September and October or September, October, November, I can't remember for sure, but we had 10% risk in that built into our model. But essentially, it's 25,000 barrels per day with 10% risk for 3 months.

Okay. And Matt, the 26,000 barrels average for the first quarter for Dynamic, what was the rough oil-gas split there? And what were the realizations?

Yes. You can think of the oil-gas split probably around 12,000, 12,500 barrels a day of oil and about 85 million a day gas.

Okay. And I know at the investor meeting back in February you guys had discussed potential well cost savings going forward for the Miss wells. I guess that included decreased drilling days that you were seeing, some potential savings from doing the open hole packer completions. How are things looking there? Any potential savings going forward? Or is it being offset with some increases elsewhere?

Well, we're in the very early stages of doing some of those things that we talked about at our Analyst Day, so I don't want to go out and start announcing savings yet. But I do think we're moving in the right direction on cost. One of the big cost savings we announced earlier is our new hydraulic fracturing agreements, which is probably about -- on a per stage basis for hydraulic fracturing, we're probably down about 12%, 15% from where we were in '11. We are drilling more wells in Kansas. And when you go to Kansas, you're probably 500 feet to 700 feet shallower than what we've been drilling in Oklahoma. So certainly, that could save you a couple of days of drilling. The Packers Plus system, we've done a few of those. We haven't done enough to be conclusive or to make an impact, but they are working well. The pairs we have done and we are saving a couple days on completions there because we can pump the fracs faster and not have the delays in wireline and plug work. So yes, I mean, we're moving in the right direction in cost right now. I still want to think about these wells as $3 million of well. But as we drill more in Kansas and start doing more of these other ideas, then I do think we could see some savings.

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

This is Patrick Lee calling for James Spicer. I've got a question regarding, I guess, the funding. It sounds like you're fully funded with the availability under the revolver and the cash from the balance. Just trying to see whether or not, are you expecting -- I know your model for this year to be strong at that revolver? Or do you think that cash balance is sufficient with the cash flow from operations.

Sure. If you look at our -- let's just take the consensus numbers of kind of $1 billion of EBITDA, at cost interest of $275 million, preferred dividends of $55 million, P&A of roughly $40 million, gets you about $625 million of kind of adjusted cash flow from ops. We started the year with the $200 million cash balance. We've raised $950 million year-to-date. So the combination of those 3 numbers gets you about $1.8 billion, so we don't expect to be into the revolver much. I think we'll probably touch on it towards the latter part of the year, but we don't expect to be into it in a big way this year.

Okay. So I guess then, you don't expect any further monetizations or anything like that other than -- I know you spoke about the potential to monetize the 200,000 in the Mississippian extension at some point. Did you know the timing for that? Or do you have a specific idea?

I think we said -- we don't have to do it. We don't really have to do anything else. We can meet everything with the liquidity we have. We could look to monetize that over the next year or sell some noncore assets or sell some trust units if we needed to, but we really don't have to do one of those.

Okay. And I guess another question is, with respect to the distributions to the trust, I know you previously mentioned around $94 million for the SDR. That's for, I'm assuming, for this year. What about the other trust? Just wondering what cash effect that would be with respect to your trust for the remainder of the year.

Yes. We give -- on the NCI, the noncontrolling issuers of the net income piece, we give you that in our guidance. For the cash piece, I guess I would point you to 2 spots, would be the S-1 for both of those trusts. You can look in there and get the distributions or kind of public consensus estimates for the distributions for those for the next 4 quarters. We really don't give out quarterly guidance or any guidance on the trust, but point you those 2 spots to get a good beat on it.

Okay. All right. And just finally, it doesn't sound like you're -- since you've already got so much acreage, you're not necessarily looking for any other additional acquisitions, but I'm just trying to see if -- I mean, what is your appetite for that at this stage?

It's full. I'm going to say it's hard to quit when you know acreage values were as cheap as they were when we started. But we went in with the idea of 1 million acres and ended up with 1.2 million acres. And we'll just be satisfied because at the end of the day, the goal for the company is to meet a 3-year objective that we think can add tremendous equity value to our business by 2014. So that's what allows us to put on the breaks. And we just don't think that there's really incentive to have more than 20 or 30 years -- more than 15 years, but to have 30 to 50 years of inventory doesn't really help us any. So what we're focused on is looking out now into '13 and '14. And as our EBITDA is dramatically growing, is meeting that, making sure that we have the ability to bridge that by 2014 to where we can have what we call a mature company that can spend a couple of billion dollars and be within cash flow and grow at double digits and then still look to make acquisitions using debt and equity. And we think now, with all the work we did in 2011 and now with the first quarter work on funding that we're really to the point that we don't have to do any of those to meet that criteria of getting to that mature company status in 2014, so that's why we say we're in years of harvest.

Your next question comes from the line of Graham Tanaka of Tanaka Capital.

Just wondering -- sort of doing a downside analysis on price, you did mention price is the biggest risk. And just wondering kind of what a longer-term breakeven, say, 3, 4 years out beyond the hedge period? What would be a breakeven price realization? And how far out might you hedge in the future?

We look at $60 oil and $2.50 gas still having basically a 30% rate of return for the company. So what our goal is, is to be able anytime we can have $100 oil or somewhere in that range to where you have this close to a 100% rates of return to lock that in. And so we've already started hedging -- we're focusing on '14 now, but would even hedge further out if we get the opportunity.

And to go out to 2015, for example, just pretty far out, how much do you have to take that and give up?

Well, right now the curve is pretty backward-dated. You've seen when it was contango or flat earlier this year. We've put on a few hedges out in '14 and '15. We keep an eye on it and if it flattens out again, you'll see us have more hedges in '14 and '15, maybe even beyond.

The Q1 acreage purchases, or the purchases this year, how much of that was in the old Miss or the original Miss area versus the new?

We've said about 10% in the original.

The other is we're talking about potential production rates rising. Just wondering in terms of reservoir economics and dynamics, how conservative have you been? And what kind of assumptions have you made about what you can capture over the life of the wells and is that number changing?

You're talking about on the PDP production for Dynamic?

No, no. This is on your -- well Dynamic is even later, but on the Miss, in terms of what kind -- how much of the oil can you get out? What would be the potential capture over the life of the well and does that potential have upside?

Well, yes. I mean the EUR on our current type curve that we did year end was 456,000 barrels of oil equivalent. And I think the upside in that is that your b factor potentially could continue to go higher and break it over quicker. And your turnover decline is flatter than what it is. The other thing is we're early in this play and this reservoir is very thick. It's probably 300, 400, 500 feet thick. And it's really difficult to model the entire contribution at the rock section, the reservoir section, which could help us with our ultimate recovery. But right now, we're at 456,000, and I think that the way that, that could go up is probably the curve breaking over the center and staying flatter. That will certainly help EUR. But I think that if you do have that, it will be later in the life of the well or it doesn't really have a lot of PV impact on the present day of the well.

Okay. And then on the consistency of the well, production rates over the course of the play, you're finding some pretty large wells. And I'm just wondering if the production rates rise or EURs rise over time -- over the next, say, 1 year or 2 as you did more wells. Is the average going to rise because you're going to find more sort of mega or big wells? Or is it going to rise because maybe you've been conservative or you're getting more efficient?

Well, in most plays -- and not just the Miss, but in most plays, it's hard to predict whether you're going to make greater wells, but what you do is you learn how to factor wells better. You learn where to perforate. You learn where to place the lateral. You start drilling wells. We had the best success. So over time, those kind of things will help you to improve the overall recovery in each well. And that's why our view, we talked a little bit on Analyst Day, and that's why most people only look at going to development of the play, they use a Swanson's mean [ph] instead of a P15 [ph] number because the Swanson's mean does give you the advantage of learning about the play and improving the EURs. But yes, I think as we continue to run more rigs, continue to develop in a wider area, we continue to learn more about it than that in itself’s going to help us continue doing well.

Your next question comes from the line of Alex Heidbreder of Millennium.

Question on frac design. So have you guys tried any very high asset, very low profit wells the way Eagle’s doing it?

There has been few wells -- all we did was ask and it came in. As I was saying, very good rock area. Basically, what we're doing right now is I wouldn't say very high sand concentration, but we're probably pumping 50,000 to 75,000 pounds of sand per stage. And probably, I don't know, 3,000 to 5,000 barrels of fluid per stage. It's all basically a water-based fluid. The idea, I think, with this carbonate is it's such a tight rock that you don't need a lot of sand, you don't need a really big propping to keep this thing propped. Any kind of fracture that you can get with water is going to help. There's such a big, big permeability contrast between the hydraulic pressure that you pump versus the matrix of permeability that you're going to get, you benefit for the well. So I don't -- yes, the frac side is very simple, I guess what I'm trying to say. I don't want you to get the real, real complex with it.

Well I just want to -- from some of the initial data, Eagle, so far, seems to have the highest averages and they're doing a frac-ing of 20% maybe of the sand volume that other people are doing and much higher asset volume. And I don't know if that’s because they're on that sweet spot right between Alfalfa and Grant. Or if they're just taking a different method and it's working better.

Well, I think they are -- I do think Eagle is in a good spot. And with our play of 1.7 million acres, we can probably pick any one spot as big as Eagle and make very good wells. But I think it's less frac design and probably more rock quality from area to area in this play.

Okay. And then, thinking about [indiscernible] what Tom said is that, it's not necessarily trying to find out where the next mega well is. But if you could -- if you guys could back up the bomb [ph], 10% or 20% of your wells that don't really produce much at all. When you guys are putting down a new well, do the engineers that are doing it, do they have any clue ahead of time whether it's going to be one of the good ones or one of the bad ones?

Yes, I hope so. We have 100 people working on this play and that's all they look at 10, 12 hours a day. So certainly, we continue to learn more every day. And I think when you look at Page 9 or whatever that was in our presentation, one of the reasons IPs are going up, as you see over time, is that the shellers [ph] and engineers are doing their job and that we're continuing to improve on the IPs.

So just, I mean, when you're going kind of to more field level development in a given section, are you guys just dropping out from locations that you just don't think will be good enough?

Yes. We constantly review where we drill and we place rigs and we want to have the best use of capital, whether it's in the Miss, the Permian where we drill. But yes, certainly, if we are developing good wells, we continue to run rich in those areas. So it's an ongoing process of high grading our acreage, our play and where we drill.

Your next question comes from the line of Joe Stewart of Citi.

Tom, I was actually just going to follow up on a previous question, but Matt kind of clarified it. I think a previous caller asked about the b factor decreasing. Or is the 456,000 Boe type curve was based on a 1.5 b factor, while the vertical wells that you've seen in the play have exhibited a 2.5 b factor. Isn't that correct?

Yes.

Yes, that's correct.

So the b factor, there's not really much risk of the b factor decreasing, rather, there's more of a chance of that increasing over time which should bump the EUR significantly.

I would certainly agree with that, yes.

That doesn't change the PV very much.

Your next question comes from the line of Anne Cameron of BNP Paribas.

I think, James, might have addressed this at the beginning, but I just had a question about your LOE. The quarter run rate is a bit lower than your annual guidance, and it's about $14 a barrel consistent with last year. So could you help us get from last year's LOE guidance of -- or LOE of about $14 a barrel to this year, which is closer to $17? And I understand a good chunk of your production is going to be coming from Dynamic, which is more like a $16 a barrel LOE. But could you just walk us forward how we get to 6 -- to about $17?

Yes, LOE in Q1 is $13.77 per barrel of oil equivalent, and it's a little bit in between quarter because it's right before -- it's right after we finished '11 and right before we close on Dynamic. So what we expect with Dynamic going forward is, it is higher LOE. And so with Dynamic, we're probably looking at kind of $15.50 to $16 per Boe total for the company once we roll Dynamic in. And then also, we do have the Oxy penalty on the CO2 built into our guidance, which adds another kind of, probably $0.75 range, so that could get you up in the $16. 75 range, somewhere in there, which will be kind of the midpoint of our guidance.

And so the penalty on CO2 is increasing as you go through the year and that's what moves it up?

We don't have any penalty for CO2 at this point. It's just when we start paying forward it’ll hit our LOE.

Okay. And that's next quarter or...

Well, we're working with Oxy right now and as soon as we turn the plant over to them, then we'll have to start accruing the penalty. But that's -- I can't tell you exactly what -- when that's going to hit us. But I think it will be this year some time.

Okay. great. And then about your well cost because I know there have been a bunch of questions about them going down. And when I do the math on your Analyst Day presentation on what your drilling and completion costs are including the salt water disposal, although it looks like you're going to average around $3.7 million this year per net well? And we've talked about that is because you're essentially have to front load your saltwater, dispose the well cost [indiscernible] step out into Kansas. So at what point will we actually get to $3.2 million per well, because I expect you're going to be stepping out for quite some time given what a sizeable position you have?

Well, I think, right now, our wells are producing well to dispose [indiscernible] continue to increase. We were about 2.5 last year. Right now, we're probably around 4:1 and we're probably going to increase that 5:1, 6:1 here pretty quickly as we drill, as we ramp up rigs to drill the horizontal producers. So that cost is going to roughly compress down to $3.2 million. However, if you look at just Q1 alone, we drilled 68 gross wells. And our CapEx says here the horizontal well is only $91 million. And so that does have some impact of cost reduction plus carries and things like that. And we drilled 17 disposal wells and spent roughly $18 million less all the facilities associated with the main gathering, saltwater disposal lines and things like that. So costs are coming down. But you're right, when we do think about a well being $3 million and then $200,000 for disposal allocation, we are thinking in terms of 10:1 ratio. And right now, we're at about 4:1. But there are certain areas in Alfalfa County that we do -- are doing some heavy development that we are at 9, 10, 11, 12:1. So it's going -- that part of it is going to accelerate going forward because of the number of rigs that we're increasing.

Okay, great. And So when you talk about cost reductions, are you talking about getting to the 3.2 or you think you could get lower than the 3.2 a couple years out?

I think we can get lower.

Your next question comes from the line of Robert Carlson.

Am I right in saying, currently, we have 19 horizontal in the Mississippian and ended the year with 26 and ending 2013 with 45?

As far as rig count?

Rig count.

No, we have 24 rigs drilling horizontal producers right now in the Miss. And we're going to end the year at 33.

So 45 and 13?

End of year is 13.

End of year is 13. So think about it as adding a rig a month to get the 13.

And we have 5 wells -- there are 5 rigs drilling disposal wells.

Am I right in saying you have no dealing with Chesapeake at the present time?

Having no dealings?

No dealings.

Well, we operate together in a very large field in the Mississippian. So that -- we deal with Chesapeake every day in the field.

But I mean -- yes, I'm going to start with hedge funds [indiscernible]. I want to know what you got.

No, I left Chesapeake in 2006.

Your next question comes from the line of James Mullins of BL Cost Investment Group [ph].

When the company looks at the natural gas storage situation, and I know you're drilling 100% oil but you have the gas produce. What's your model's doing with worst case scenario? Let’s say we get full storage in an October timeframe. Have you run that model and what kind of the worst case implication cash flow, EBITDA or earnings in that third, fourth quarter period.

Yes, I would say if you look at our revenue, we're 80% oil. So even drastic changes in gas don't have that much of an impact on the cash flow or earnings or EBITDA of the business. So you can take one of the models and run it out. We show you on the presentation where our returns are, $250 gas with various oil prices. But even change in the gas price doesn't change our earnings much, but we don't really -- we don't give guidance at various prices.

That's fine -- that's financial. How about practically speaking, what would be the company's plans worst case? I mean, because it could be just a very unique environment that you have to plan for. Do you burn it? Do you just pay someone to take it away? What do you do with that?

There's always a self-inflicting pipeline. Basically, they cut off lower pressure wells to keep from having twofold injections. So we'll get to -- if we get to the scenario you're talking about, our newer wells would probably flow, while the older wells producing in different areas.

This ends our Q&A session today. I'd like to hand the call back over to Mr. Tom Ward, Chairman and CEO, for closing remarks.

Well, thank you. We don't have very many closing remarks other than to say thank you for the time that you've spent with us this morning. And we're happy to take further questions at any time you like to call. Have a great day.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect and have a wonderful day.