SandRidge Energy Inc (SD) 2012 Q1 法說會逐字稿

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. 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 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. 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 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 will make reference to adjusted net income, adjusted EBITDA, and other non-GAAP financial measures. A reconciliation of any non-GAAP measures we discuss can be found in our earnings release and on our website.

Please note that this call is intended to address SandRidge Energy and not our public royalty trusts, 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've 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 five rigs drilling disposal wells.

It is quite remarkable the change that has happened at our Company over the last four years. In the spring of 2008, there were a few industry people worried about being a natural gas company. However, as large, integrated companies began 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 US. 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 is produced. Today, we produce over 30,000 barrels of oil equivalent from this asset and we'll drill more than 750 Wells here this year.

In 2009, we also identified one of the largest stratigraphic traps in the US 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 about emerging shale gas plays leaving little attention to the Mississippian Play. However, where others saw water, we saw vast amounts of oil over an area of 17 million acres across Oklahoma and Kansas. The Mississippian Play had begun.

During the next two years, we leased 2.2 million acres for about $415 million and created one of the largest oil resource plays in the world. Now, it is widely known that the Mississippian is among the very best places to drill and in our opinion, it is the very best place to drill in the United States. It is important to note that SandRidge is focused on only two drilling plays and one resource play to lease land in the last three years.

Our Company standard is to be the most efficient operator of each area we choose to develop. We are efficient because of our relentless focus on the single plays. In the Mississippian, this allows us to prepare lead time to install electricity and disposal before we drill and to watch our drilling costs very closely. We see a lot of companies talk about how much a well might make in a particular play, on a particular day, but not many discuss what really matters, which is how much you spend, how you prepare, and how much you find after drilling several hundred wells on your way to several thousand.

SandRidge has now drilled nearly 300 of the 640 horizontal wells in the Miss and currently operates 29 rigs in the play, of which 19 are drilling horizontally in Oklahoma, five are drilling horizontally in Kansas, and five are drilling saltwater disposal wells. We drilled 68 wells in the first quarter, with 55 of those in Oklahoma and 13 in Kansas. We anticipate ending the year at 32 horizontal rigs and project ending 2013 at 45 horizontal rigs, drilling for shallow, conventional oil across northern Oklahoma and Kansas.

We believe our industry will create over 100,000 jobs across this area over the next five years and will have a play as large and as important as the Bakken is to North Dakota and Montana. We think it's a good use of capital to increase land in an area that you already sold for more than 10 times your investment and are drilling exceptional wells instead of trying to find a new area to buy and start all over again.

Our type curve, EUR, of 456,000 barrels equivalent has an average peak 30-day rate of 275 barrels of oil equivalent per day. However, we do have prolific success stories. One well we recently completed in Alfalfa County, Oklahoma averaged more than 2,200 barrels of oil equivalent per day at 92% oil and is calculated to be the third highest, 30-day rate oil well drilled in the United States in the last three years.

Another well is even better and it appears to be on track to be the highest 30-day rate oil well drilled in the US in the last three years. This well has averaged over 3,750 barrels of oil a day and 1.5 million cubic feet of gas a day, or 4,000 barrels of oil equivalent per day and paid the $3 million well back during the initial flow back period of 10 days.

However, we have chosen to not only discuss our best wells, but the nearly 300 wells we drilled across the more than 150 miles from Comanche County, Kansas to Noble County, Oklahoma. A well that averages only 244 barrels of oil equivalent per day, which is what our type curve was at the end of 2010, would have a rate of return of more than 80%. A well that averages 310 barrels of oil equivalent per day during a 30-day peak rate will have a rate of return of over 125%. We are very happy with both of these outcomes or really any in between, because even at the low end of the range, we can meet our three-year goal of tripling EBITDA, doubling oil production, and improving our credit metrics.

Therefore, at our cost structure, we're very content finding 400,000 to 500,000 MBoe and not having to rely on the monster wells, but be thankful when they come our way. You can see the dramatic effect on production these wells have, even on a large producing base, by reviewing our Mississippian production slide on page 10 of our corporate presentation we updated yesterday.

Our production in the Mississippian averaged 19,300 barrels of oil equivalent per day for the first quarter, but is currently over 26,000 barrels of oil equivalent per day. Our Miss production has grown from a standing start in 2010 to the 26,000 barrels of oil equivalent per day, level with only an average of 14 rigs. You can imagine the growth we plan to have with 45 rigs running by the end of 2013.

This steady growth of low risk production, with low cost from shallow oil wells that come with high rates of return fits our Company's long-term strategy perfectly. In fact, the only risk we see is lower oil prices. Therefore, we continue to hedge aggressively, through 2014, and will look even beyond as the market moves toward $100 per barrel.

We have started our first two wells in the extension portion of our Mississippian Play. Like the original Mississippian, we expect to have a statistical combination of good and not as good wells. However, this is still a play that, in the long-term, will provide excellent returns for the Company and our investors. Just a reminder that we had over 7,000 vertical wells to tell us where to buy acreage and it's the same formation with the same trapping mechanism that we're drilling in the original play. Therefore, we believe the risk is low, but we'll know much more by the end of the year as we drill our first 50 wells in western Kansas.

The Gulf of Mexico has also provided us with an opportunity to invest in, what we believe, is the least expensive oil to purchase in North America today. Post-Macondo, the Bureau of Ocean Energy Management Regulation and Enforcement has decided to be more aggressive in enforcing operators to plug and abandon any active platforms. This has created a dislocation the market as companies would prefer to sell producing assets at very low prices in order to eliminate the obligations to plug and abandon.

The Gulf of Mexico is the largest producing area in the US and has a tremendous pipeline of opportunities to review. Our SandRidge Gulf of Mexico team has created a niche in acquiring oil where there is very little competition. We believe that we are in a scenario much like the Permian Basin was in 2009 and will have the same dramatic results in creating value over the next couple of years. The goal for our Gulf of Mexico team has not changed; it is to maintain 25,000 barrels of oil equivalent per day of production by spending $200 million per year. We are very happy to have closed this acquisition and we welcome our 150 new employees to SandRidge.

As James will point out, our liquidity position is the strongest it's been in the six years the Company's been operating. We now have $1.6 billion of liquidity; of which, about $600 million is in cash and an additional $1 billion undrawn on our revolver. In fact, we could meet our three-year objectives by using all debt if we chose, but assume, when we use one of the many levers available to us in the next two years to bridge the smaller and smaller gap between cash flow and CapEx.

As for Q1 CapEx, we had about $140 million relating to one-time expenditures and front-loaded expenditures in infrastructure and land costs associated with the Mississippian Play. Last year, we set out to acquire 1 million acres in the extension Mississippian area and we'll end up with about 1.2 million acres, bringing our total Miss acreage about 1.7 million acres. This essentially completes our leasing effort in the Mississippian Play, but some of the costs spilled over from 2011 into Q1 of 2012. We have now approximately 200,000 acres more than expected and will plan to monetize this acreage sometime within the next year.

With the rig ramp schedule in the Mississippian, we have also front-loaded our spending in areas of pipe purchases, salt water disposal facilities, and electrical infrastructure. We're also wrapping up our low-pressure gathering projects in the Permian Basin that started at the end of 2011, in which the bulk of that cost also landed in the first quarter of 2012.

Lastly, I'd like to say a few words about some of the media commentary that you may have heard recently regarding a hedge fund. The fund that you've read about was formed to manage personal investments and focused on a wide range of commodities, not specifically on energy. The day-to-day activities of the fund were managed by a group of professionals that were hired by the fund and while I served as an oversight role, as I would for any other personal investment interest of mine, the time I spent dealing with this fund was relatively minor. The fund was wound up in 2008.

Now I'll turn the call back to James for the financial update.

Thank you, Tom.

You can find a full set of numbers in our earnings release so I won't run through all of them, but will, instead, offer 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.

Adjusting for this divestiture, our quarter-over-quarter production group 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 expense measures for the quarter, both LOE and DD&A per Boe were below our 2012 guidance ranges. G&A of 831 per Boe was above our guidance range, but includes expense transaction costs associated with the Dynamic acquisition and other legal and advertising costs that 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 the second quarter period and for the first quarter, Dynamic average production of 26,000 barrels of oil equivalent per day and generated EBITDA of $89 million. This brings to Dynamic pro forma LTM EBITDA at Q1 to $393 million and combined with SandRidge's EBITDA of $691 million, we have a combined LTM adjusted EBITDA of approximately $1.1 billion.

In terms of capital raising, we had a very busy year-to-date period. In January, we closed the $1 billion Mississippian joint venture and in April, we closed the IPO of our third royalty trust, SandRidge Mississippian Trust II, ticker SDR. SDR priced at $21 per unit, the high end of it's $19 to $21 range, raising net proceeds to SandRidge of $590 million and far exceeding our $500 million target.

Also, in the first quarter, we raised $100 million through the sale of common units in our two other trusts, SDT and PR, and we still hold approximately $300 million in royalty trust common units. In total, for the year-to-date period, we raised approximately $950 million in cash proceeds. We also closed the $1.24 billion Dynamic acquisition in April, which was funded with $750 million of 8.125% senior unsecured notes due 2022 and the issuance of approximately 74 million SandRidge common shares.

On our credit facility, in March, we increased the borrowing base from $790 million to $1 billion and extended the maturity from 2014 to 2017. With this extension of the credit facility maturity, we now have only $350 million of debt due in the next four years.

Consistent with the plan we laid out at the beginning of the year, the proceeds from the SDR royalty trust represent the final piece to our 2012 funding plan. We now have approximately $600 million in cash and a fully undrawn $1 billion revolving credit facility. This liquidity, combined with cash flow from operations, is more than sufficient to fund our 2012 capital program.

Moving beyond 2012, with our leverage now around 3 times EBITDA and $1.6 billion in liquidity, we can look to more traditional means to fund our growth, such as high-yield bonds and bank debt. However, still available to us, if needed, are royalty trust common unit sales, non-core asset sales, and possible JVs or sales of additional Mississippian acreage.

In our earnings release, we published updated 2012 guidance, which is largely unchanged from prior guidance. One item to note is the updated net income attributable to non-controlling interest, which increased by $29 million, due to the IPO of the Mississippian Trust II. Recall that this non-controlling interest represents the public's interest in the trust's net income. For the SDT, the public ownership is 67.3%, for PR 69.5%, and for SDR, 60.1%.

Regarding the 2012 EBITDA impact of the SandRidge Mississippian Trust II IPO, one method to forecast or estimate the SandRidge EBITDA reduction would be to take the aggregate amount of the trust's distributable cash in 2012, based on the target distributions in the S-1, which is $94 million, net this by the public's 60% ownership to arrive at a non-controlling interest EBITDA adjustment, or approximately $56 million.

This also speaks to why we chose to do another trust as a means to raise capital. For an approximate $56 million reduction in 2012 EBITDA, we raised $590 million of capital net of fees. This valuation of approximate 10.5 times forward EBITDA is a very compelling multiple versus where our C-Corp trades.

I'll just make one other editorial note on how the net income attributable to non-controlling interest, or NCI, is reported versus how we guided that figure. In our income statement, the reported NCI includes the impact of any trust unrealized hedging gains and losses in accordance with GAAP reporting. For any quarter, unrealized hedge losses will serve to reduce the GAAP reported NCI on the income statement. Conversely, unrealized hedge gains will increase the NCI. However, we guide to an adjusted NCI figure, which excludes any unrealized non-cash gains or losses. Just like SD, we don't guide to or project unrealized hedging gains or losses for the trust and when those occur, we back them out of our EPS and EBITDA.

For example, in the first quarter, the NCI on the income statement of $1.9 million includes $22 million of unrealized, non-cash hedge losses. This is highlighted in footnote 1 on page 11 of the earnings release. Backing these in realized hedge losses out, the adjusted NCI for the quarter was approximately $24 million.

In our earnings release, you also find updated hedge position, which reflects the combination of the SandRidge and Dynamic hedges through 2015. We have significant hedge protection in place for oil through the balance of the year with approximately 81% of our guidance of oil production hedged, with swaps at over $100 a barrel.

This concludes managements' remarks. I would now ask Dominique to open up the line for questions.

(Operator Instructions) Neal Dingmann, SunTrust.

Good quarter. Tom, could you address a little bit maybe more in detail, your comment about maybe monetizing the new acreage? To me, it looks pretty accretive. Just wondering 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 acres you recently added?

No. We're essentially through with acquiring acreage. 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. We ended up with 1.2 million acres; however, the good surprise is it came at $350 an acre.

Even though it was at the tail end of our acquisitions, the price wasn't very high and we think obviously we've done much better than that with selling acreage in the past. We don't have to sell acreage, but I think the 1.5 million acres was where we were comfortable and that leaves us with a couple hundred thousand acres that we could sell if we chose to. The reason we brought it up is that 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. Tom, you addressed some of the infrastructure and other things in the horizontal Miss. Does that mean that you look at more of those costs would be an up-front in your CapEx? Do you see those going down for the remainder of year or will you continue to have the water and other build out costs throughout the year?

Matt can address that one.

Yes, Neil, we do see it going down as we move forward. We did want it to ramp up our electrical infrastructure. We do have a pretty aggressive program to install sub-pumps, we want to get that kicked off. So, you put in a electrical facility, you can run quite a bit of sub-pumps and get that going.

On the saltwater disposal side, these wells obviously make a lot of water, so we do want to minimize LOE and be up front with our saltwater disposal wells. Our original plan was 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. Then we also pre-purchased pipe for our drilling program, so all those things are one-time items.

Over on the Perm, Matt, the issues you had previously on infrastructure, et cetera. Have most of those been addressed or where do you sit now on that?

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

All right. Thank you all.

Scott Hanold, RBC Capital Markets.

Just to clarify a point on the CapEx, you obviously held your budget consistent with where it was before. It sounds like you did have a little bit more acreage spend, maybe by $50 million, $60 million, $70 million in the first quarter. 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 CapEx, because 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 into 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 one-time items, that included carryovers from last year, expenditure, a little bit more land than we anticipated and also some acceleration of infrastructure. If you take that $140 million off of the $570 million, you're at $430 million. If you extrapolate that out by four, you get to $1.72 billion. Then, in Dynamic, we are 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. Then you add back in this $140 million of one-time expenditure we talked about, you're at $2.04 billion.

That's high side of CapEx. That's right at about 10% over expenditure. But, how the CapEx rolls back down is through the acceleration of the carried interest in our JVs. When you think about this, if you just look an example in the Extension Miss, where we're going to drill 50 wells, but none were drilled in Q1. We're starting right now in Q2 with Extension Miss, where, if you look at it well and we think about it as 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 two times with working interest.

Those cost savings to the carries are not built in your Q1. In reality, if the Extension Miss works really well and we decide to ramp up above the five rigs and drill more than 50 wells; for example, we drill 100 wells, your CapEx spending percentage will actually go down even further because the acceleration of the carry. That's how we get back down to our $1.85 billion.

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

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

What we do is we bill them for the carry up front. 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 the second quarter, plus we'll get caught up in the second quarter. We're going to get some extra carry payment there. But essentially, yes, it's not going to be real-time, but it is very, very near-term payment on both the JVs.

In the original Miss, the JV with Repsol also has a two time working interest carry also. I didn't get to that, but if you think about what we drill, we drilled 68 wells in the Mid-Continent in the first quarter. Only 21 of those wells where Repsol's in those wells and we already drilled 13 in April, so you can see the acceleration in the JV structure and the JV impact, that we're going to be seeing going forward.

Okay, thanks. Tom, you mentioned those two wells that had 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 anything that can be said about that particular area of those wells that were different than others? Or is it just the variability you tend to see across the play?

If we have the best well drilled in the US in the last three years, that would be something that's a little bit different. But other than that, there just very good wells. 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 will 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.

If you look on the slide where we show our Mississippian production growth, you'll 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 tremendous growth in a very, very large asset base. It does 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. If that happens, we will have a Company that changes dramatically.

Okay. Then in particular with those couple wells -- 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?

No, it was completed the same way. To say it's not a really good sweet would be wrong, but I think that there are opportunities to drill wells around high permeability streaks that you do have two or three wells that will be above average. Then we drill other areas to 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.

Okay. Appreciate that. Thanks.

Amir Arif, Stifel Nicolaus.

Just wondering if you could give us a little more color about the wells that you are drilling in Kansas? You mentioned a little shallower, less drilling time; in terms of production or EURs. How are those stacking up relative to the quarter?

We haven't completed any wells in the Extension area. 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. 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.

Tom, so are the five rigs in Kansas focused on just north of the border like Comanche, Barber, [Harper] or is it further up?

We also have a slide updating where all the wells have been drilled. There are two wells in what we call the Extension -- one in Finney 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.

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 price realizations you're seeing?

I'm sorry, I didn't get the first part of the question?

Just the takeaway for the oil production out of area?

Okay. Yes.

And price utilization.

In the Mississippian play, we just recently signed a deal with Plains, that really did enhance our oil takeaway and pricing. How that helps us is it lowers the transportation costs and minimized the trucking business. All the oil in the Mississippian goes to Cushing and instead of having to truck every barrel to Cushing, we're trucking it to nearby injection points, and Plains gather and take it to Cushing. So, we expect a little bit of an upgrade there. Cushing, right now, total storage is probably around 60 million barrels and that's probably around 43 million barrels in inventory.

What's happening here soon is Seaway is going to reverse their pipeline, which is probably here another 10 days to two weeks and that's going to give you 150,000 barrels a day of capacity of oil from Cushing to the Gulf Coast. That will further enhance the value of the oil that we'll get plus it will certainly eliminate any inventory issues at Cushing. In the Mississippian Play, we really don't see any capacity constraints for oil sales going forward. Seaway also is going, towards the end of year, they're going to install some more pump stations and that 150,000 barrels a day should increase to 400,000 barrels a day.

Of course, you've heard about the Keystone project and the Enterprise project. So, I think there's going to be more capacity from Cushing on the Gulf Coast going into '13 and '14. 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.

The remaining 35% is also being piped, but it is also trucked a short distance to its injection points. But, right now, we don't see any issues with oil transportation coming out of the Permian. I think differentials have widened a little bit here in the Permian lately and that had to do with a couple refineries that went down for some unscheduled maintenance in March. But, overall, I just don't see any issues with crude transportation and sales.

Okay, so can you just give me a rough number of what the realized well head price is in the Miss relative to WTI? For the different --?

I think with the Plains deal, we'll see something around $0.75 upgrade. Then once Seaway reverse -- certainly your WTI and LLS spreads should narrow. So, you could see $5 to $7 upgrade there potentially.

So, relative to WTI you're getting --?

Right now, we're probably $5 or so below WTI.

$5? Okay. Terrific.

I think we modeled $4 to $5.

$4 to $5, okay. Terrific, thanks, guys.

Joe Allman, JPMorgan.

Could you give us the production by area currently and then average for the first quarter, if you could?

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

Yes. For current. Joe, I can e-mail you that if that's okay.

That would that be great, Kevin, thanks. The shares that you gave to Dynamic in the acquisition, is there a lock up period? Could just talk about that a little bit?

Yes. There is a lock up period. They took about, I believe, it was about 70% of the shares. There's a 90-day lock up on those. The closing date was April 17, lock-up's 90 days.

Okay, all right. Very helpful. Thank you very much.

Dave Kistler, Simmons & Co.

Real quickly, on the 200,000 acres that you bought. What portion of that is an Extension area? What portion of that is bolt-on? To follow-up on that, how does that fall within the AMI of these JV partnerships?

The first part of the question, the 200,000 acres, roughly splits up about 90% of it's in the Extension Miss, up northwest Kansas. About 10% of it are bolt-on into our Fairway area, which was called Fairway, which is original Miss area across Woods, Grant, Alfalfa counties. What was the second part of the question?

Just thinking about the AMI for the JV partnerships, is all this covered within the AMI's or is some of it going to be independent of that?

No. This is nothing that's new, it's all covered either in one AMI or the other. The acreage in the original Miss could go to both JV partners, acreage in the Extension Miss will certainly just go to Repsol.

Okay. 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 then what you're able to monetize that for? It seems like --?

It is a very large play, but also, saltwater infrastructure is a big part of this. You have to be able to drill a tremendous amount of wells that have high upfront cost with the infrastructure both electricity and saltwater. We are set up to do that. In fact, that's what really made the play and allowed us to move in earlier than others. We chose to move into the Western Kansas (technical difficulty) we're still working in the original area in Oklahoma and Southern Kansas. I can assure you can't buy acreage in Southern Kansas and in Oklahoma for the same amount that we paid in the first quarter. I don't know this, because we're not that active, but I assume it would be difficult to duplicate what we did in the Extension.

Okay. Maybe just try to summarize that essentially barriers to entry are need for scale and significant capital. Is that --?

The original barrier to entry used to be first. So, if you're the first one to buy the acreage, you're the first one to get the least expensive.

All right, great. If I look at the rates of return you guys are talking about in the Miss line right now versus where you are in the Permian. Does that make sense to maybe divest the Permian and use that capital to accelerate in Miss line? Then push the NAV associated with that much of that acreage position forward?

No. Because the Permian still has very high rates of return. But, the main reason is that you can only go so fast in the Mississippian. 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. Everything driving our decisions here are around cost, as well as how much we're finding on the oil and gas side. 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.

Okay, I appreciate the additional color there, guys. Thanks.

Craig Shere, Tuohy Brothers.

Congratulations on some of these stellar results in the Miss. Following up on the additional Miss leasing, Tom, at IPAA, you said you wanted to keep the drilling inventory to under 15 years. That you'd actively consider selling down maybe another $500 million to $1 billion of additional acreage at some point. I have three 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 one year-plus is likely to come almost entirely out of the Extension Miss?

Secondly, I want 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. Lastly, focus on the timing, in that you said in 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 in the Extension area. I just want to focus on, you're not going to rush to do something before it's derisked and you can get a reasonable price -- is that a fair statement?

I'll try to address all three. The last was are we going to rush out to do something? We sure 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 and I think reasonable price can be construed differently among different people. I don't know, if what we would sell out if it's ever construed to be reasonable or not. But I think that you are correct that as we drill out Western Kansas, we'll have a lot 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. You're correct in that could be a little bit more than the 200,000 acres that we purchased. But then, on the flipside of that is that we don't have to. We can hold all of our acreage from this point forward and still meet our 3-year goals of funding. That leaves us with just a lot of flexibility as we go forward in the play. I forgot your first?

The initial one was whatever the sell down was that it 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? 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 what we have modeled to the 456,000 barrels EUR. We'll look at it again at the end of the year and see how everything's declining and then make a decision at that time.

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

Understood. Thank you.

John Samuels, First Foundation.

It 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 (technical difficulty) were surprised at 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 over 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 I could get paid as much or more? I would think so. I'm here at the discretion of the Board and the shareholders, and I believe that I pull my weight. That 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. I am, as you, you say there'll be many people that say I make too much money and some that might say I don't make enough.

Charles Meade, Johnson Rice.

I'm going back to those two 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 US onshore wells? I think you mentioned this, but is that in the last three years?

Yes, all that is correct. US, onshore, 30-day oil rate.

That's in the last three years?

Last three years.

Got it. Got it. Maybe this plays into my second question, if you look at the chart you guys have on page 10 of your presentation. It looks like, in the period of maybe two weeks or so, it looks like you lost 8,000 a day from 23,000 down to 15,000. Maybe part of it was bringing these two wells on. You jumped, in very short order, up 12,000 Boe a day to 27,000. I'm wondering, can you just give the narrative of both the drop and then the big rebound?

Sure. Maybe, it even helps if you look at that page, slide 10. The different peaks that you see along the way are larger wells that are coming on. Some of the valleys that you're noticing, especially the one where you 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 also have weather events across Northwestern Oklahoma and Kansas that we do rely on electricity as we talk about. Whenever there are storms rolling across, especially in the spring, we tend to have downtime. If you watch the weather across Western Kansas and Northern Oklahoma and see a lot of electrical storms, you'll notice for two or three 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. It's just an exceptional job that's done by our field crew. That's part of the efficiency we talk about whenever we feel like we're the best in the Mississippian because that's the area we focus.

Got it. That makes a lot of sense and thanks for that clarification.

Charles, I would say the spike up, I didn't mention that. That does have to do with one of the two 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 -- or 24 rigs drilling horizontally, you do have just a dramatic increase even if you're bringing on 300 barrels a day per well. It averages, with each rig we're bringing on, that curve is going to be higher and imagine what it's going to look like when we get to 45 rigs.

Right. This is a conspicuous in summation, you mentioned the 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.

Okay, it was also Alfalfa?

But we have a couple of wells in Grant that are not that good, but just in the same ballpark of over 1,000 barrels of oil. We've had good wells that 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've really, really tried to do is to focus you on 200 barrels a day to 300 barrels a day or 250 barrels a day 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.

Got it. Picking up on that point, looking at page 9. When you have the right most data point on that chart where you have the drilling program to date having a 30-day IP of 310. Am I reading this correctly, and does that imply that your 2012 wells are better than the pre-2012 average? And that's what pulling that IP up from 302 to 310?

I think you're correct, but also, the 245 wells were all wells to date from 2010 or 2009 through 2012.

Okay. That 310 average is for all 245 wells?

That had 30-day rates.

Got it. Comparing that to the column just to the left. If 302 is the average through December 2011, then that would imply that your year-to-date 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, but again, the 2011 is just for 2011. It doesn't count. But if you take that to the next step and say that 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. I think there is some conservatism in the type curve.

Okay, great. Thank you. That's it for me.

Brian Singer, Goldman Sachs.

Just following up on those couple of strong wells again. It might be illustrative of your point to just look at the averages, but comparing your presentation here looking at the Alfalfa County average 30-day IP relative to your IPAA presentation, it looked like it actually fell slightly. 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 an 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 do know that it made enough in the 10 days to pay off the well. But to answer your question directly, it's not in the Alfalfa 357 barrel a day equivalent.

Okay. Got you. 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 and central portions of your acreage?

The gas and oil content varies a little bit. I will say that, probably you look at the last four quarters of drilling and we drill all over this area, your gas content -- or actually let's talk about oil production. I look at the oil as a percent of total production, it probably ranges in the 45% to 46%, it's a fairly tight range. The two, you look at just current production where the Miss is producing nearly 27,000 barrels equivalent, on that particular day it's actually probably a little bit over 50% oil.

A lot of that has to do with just the recent wells we've brought on in Alfalfa that just had a higher oil content. For example, the well that Tom's been talking about is probably 90%-plus oil. So, that did, it's a big enough well that it drilled the overall average. Overall, every well we drilled, we drilled enough wells in any one area that range is fairly tight.

Thanks. 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.

Great, thank you.

Thank you. Just to clarify, we don't see the change over to more of a gas profile until later in the life of the well. 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.

Thank you.

Duane Grubert, Susquehanna Financial.

Yes, 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've got to think you're thinking -- wow, I wish I had a corer on those. Just to see, is it a permeability streak or is that I have the most awesome completion ever -- or what is it? If you guys could just talk about what science might we see you do versus what you're doing now and it might taper off in the future?

The two big wells Tom talked about, we really didn't do anything different than what we've done overall in the play. Obviously, we've gotten into an area really good rock there and good permeability, good oil cut, et cetera. Most of our focus in the Miss right now because, in general, we focus staying at the very top of the Miss to try to stay away from [water] and that's where you get your best porosity and permeability, but most of our focus in this play, on the science side, is really to reduce cost. We are experimenting a little bit with open hole Packer systems, we're experimenting with different types of fracks here and there, different types of bits and that 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. These last two wells that are very good does give you an idea, an indication of what this play is capable of doing.

Duane, we're hopeful, we don't know this, but we're hopeful as we move into Western Kansas, there's 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 that you would think that there is a chance for that to be better. We're not claiming that it will be, but in dealing with millidarcy reservoirs, we really should be able to capture most of the oil in place with traditional fracks that we're using. Maybe in some areas that look a little bit tighter than others, we can go in and try some different work on fracture treatment. 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 with a minimum treatment and bring that type of oil on with a decent frack.

We don't know yet in Western Kansas but, let me say this also. The well offsetting, this last well we're talking about, a vertical well made 9,000 barrels of oil and 18 million cubic feet of gas. Obviously, it was in a tighter reservoir than what we encountered by drilling horizontally. That's how come we think that we're going 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 a well with large quantities of oil.

We think we can do that in scale over a very large area that you don't have a core area like when you're drilling in nanodarcy reservoir that you have to have some enhancement in order to find the core area of a shale play. Even though most people want to call this a shale play, it's really not. It's a carbonate.

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?

There's a tremendous amount of information. There's 15,000 wells that have been drilled, so you can use the subsurface on a lot of this, but there is a lot of core data, also, especially across Kansas. Then we are doing some new cores in as we drill in the Extension.

Great, thank you.

Dan Morrison, 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, the rights are conveyed to our JV partners. No, we don't have any plans to test the Woodford. We still like the Woodford being our source rock and the Mississippian being the trap. That doesn't mean that, at sometime later in the play, that you couldn't drill Woodford, actually drill the source rock. But we think that would be more expensive and I don't know if it would have higher recoveries or not.

Great, thanks.

Richard Tullis, Capital One Southcoast.

Tom, I know you had mentioned that your initial two 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 out a bit from those counties?

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

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

Yes, we haven't changed our guidance for Dynamic since we announced our acquisition of it and that's the spin. $200 million this year in key production flat at 25,000 barrels equivalent per day. We do have it risked a little bit for storm season, hurricane season, I think it's in either August, September and October or September, October, and 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 of oil per day with 10% risk for three months.

Okay. 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. 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 it included decreased drilling days 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?

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% to 50% 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 where we've been drilling in Oklahoma. So, certainly that could shave 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 areas we have done them, we are saving a couple of days on completions there. Because we can pump the fracks faster and not have the delays in wireline and plug work. We're moving the right direction in cost right now. I still want to think about these wells as $3 million a 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.

Okay. That's all for me, thanks a bunch.

James Spicer, Wells Fargo.

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

Sure. Let's just take the consensus numbers of $1 billion of EBITDA, back off interest of $275 million, preferred dividends of $55 million, P&A of roughly $40 million, gets you about $625 million of adjusted cash flow from ops. We started the year with a $200 million cash balance. We've raised $950 million year-to-date. So, the combination of those three 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. 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 acres in the Mississippi Extension at some point. Do you know the timing for that or do 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 that we have. We could look to monetize that over the next year or sell some non-core assets or sell some trust units if we needed to, but we really don't have to do either one of those.

Okay. 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 trusts? I'm just wondering what cash effect that would be with respect your trusts for the remainder of the year?

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

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

It is full. I can 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. We'll just be satisfied because at the end of the day, the goal for the Company is to meet a three-year objective that we think can add tremendous equity value to our business by 2014. That's what allows us to put on the brakes. We just don't think that there's really an 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.

What we're focused on is looking out now into '13 and '14. As our EBITDA is dramatically growing, is 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. 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 the criteria of getting to that mature Company status in 2014. That's why we say we're in years of harvest.

All right, thank you.

Graham Tanaka, Tanaka Capital.

Congratulations. I'm doing a downside analysis on price, you did mention price is the biggest risk. Just wondering what a longer-term breakeven, say three or four years out, beyond the hedge period, what would be a breakeven price realization? How far out might you hedge in the future?

We look at $60 oil and $250 gas still having basically a 30% rate of return for the Company. But what our goal is, is to be able to, any time we can have $100 oil, or somewhere in that range to where you have these close to 100% rates of return, to lock that in. We've already started hedging, we're focusing on '14 now, but would even hedge further out if we get the opportunity.

To go out to 2015 for example, which is pretty far out, how much do you have to pay for that -- or give up?

Right now, the curve is pretty backward-dated, as you've seen, when it was Contango or flat earlier this year, we 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 add more hedges out in '14 and '15, maybe even beyond.

The Q1 acreage purchases, 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. In terms of reservoir economics and dynamics, how conservative have you been and what 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. Well, Dynamic sooner than later, but on the Miss. In terms of how much of the oil can you get out? What would be the potential capture over the life of the well and is that potential have an upside?

Yes, the EUR that we did on our current type curve that we did year-end was 456,000 barrels of oil equivalent. I think the upside in that is that your B factor potentially could continue to go higher and break it over quicker and your [turn over to clients] flatter than what it is.

The other thing is, we're early in this play and this reservoir's very thick. It's probably 300, 400, 500 feet thick and it's really very difficult to model the entire contribution of 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 could go up is probably the curve breaking over sooner and staying flatter. That would certainly help the EUR, but if you do have that, it would be later in the life of the well where doesn't really have a lot of PV impact on the present value of the well.

On the consistency of the well, the 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, the EURs rise, over time -- over the next, say, year or two as you do more wells, is the average going to rise because you're going to find more mega or big wells? Or is going to rise because maybe you've been conservative or you're getting more efficient?

In most plays and not just the Miss, but in most plays, it's hard to predict whether you make greater wells. But what you do is you learn how to frack the wells better, you learn where to perforate, you learn where to place the lateral, you start drilling wells where you have the best success. Over time, those kinds of things will help you to improve the overall recovery in each well.

That's why, we talked a little bit on Analyst Day and that's why most people when they look at going into development of a play, they use a Swanson's mean instead of a P50 number. Because the Swanson's mean does give you the advantage of learning about the play and improving EURs. Yes, I think as we continue to run more rigs, continue to develop in a [broader] area, we continue to learn more about it and that, in itself is going to help us continue to do well.

Congratulations, thanks.

Alex Hetwerder, Millenium.

A question on frack design, have you guys tried any very high acid, very low profit wells the way Eagle's doing it?

There has been a few wells out here where all we did was acid and it came in. It was obviously in a very good rock area. Basically what we're doing right now is, I wouldn't say a very high sand concentration, but we're probably pumping 50,000 to 75,000 pounds of sand per stage and probably 3,000 to 5,000 barrels of fluid per stage. It's all basically 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 really big proppant to keep this thing propped. Any fracture that you even get with water is going to help, there's such a big, big permeability contrast between the hydraulic fracturing that you pump versus the matrix permeability that you need to get, you'll benefit for the well. The fracks out here are very simple, I guess is what I'm trying to say. I don't think we need to get to the real, real complex with it.

From some of the industry data, Eagle so far seems to have the highest averages and they're doing a frack -- 20% maybe of the sand volume that other people are doing and much higher acid volume. I don't know if that's just because they're in that sweet spot right between Alfalfa and Grant or if they're just taking a different method and it's working better?

I think they are. I do think Eagle is in a good spot. 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 frack design and probably more rock quality from area to area in this play.

Okay. To pick up on some of what Tom said, it's not necessarily trying to find out where the next mega-well is, but if you guys could back out the bottom 10% or 20% of your wells that aren't -- 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 or 12 hours a day. Certainly, we continue to learn more every day. I think when you look at page 9 or wherever that was in our presentation. One of the reasons the IPs are going up, as you see over time, is that the geologists and the engineers are doing their job and we continue to improve on the IPs.

When you're going to more field-level development in a given section, are you guys just dropping out some locations that you just don't think will be good enough?

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

Okay. Thank you, guys.

Joe Stewart, Citi.

Tom, was actually just going to follow up on a previous question, but Matt clarified it. I think a previous caller asked about the B factor decreasing, whereas the 456,000 Boe type curve was based on, at one point, 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.

The B factor, there's not really much risk of the B factor decreasing. Rather, there's more chance of it increasing over time, which would bump the EUR significantly?

I would tend to agree with that, yes.

But it doesn't change the PV very much.

The PV, right. Yes, okay. That was all I had guys. Thanks a lot.

Anne Cameron, BNP Paribas.

I think James might have addressed this at the beginning, but I 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. Could you help us get from last year's LOE guidance -- or LOE of about $14 a barrel to this year, which is closer to $17? I understand a good chunk of your production's going to be coming from Dynamic, which is more like a $16 a barrel LOE. But could you just walk us forward to how we get to about $17?

Yes, LOE in Q1 was $13.77 per barrel equivalent and it's a little bit of an in between quarter because it's right after we finished '11 and right before we closed on Dynamic. What we expect with Dynamic going forward is it is higher LOE. So with Dynamic, we're probably looking at $15.50 to $16 per Boe total for the Company once we roll Dynamic in. Then we do have the oxy penalty on the CO2 built into our guidance, which adds another probably $0.75 range. So, that could get you up in the $16.75 range, somewhere in there, which would be in the midpoint of our guidance.

Great, 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 for it, it will hit our LOE.

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

We're working with oxy right now and as soon as we turn the plant over to them, then we'll have to start incurring the penalty. I can't tell you when that's going to hit us, but I think it will be this year some time.

Okay. Great. Thanks. About your well costs, because I know there have been a bunch of questions about them going down. When I do the math on your Analyst Day presentation on what your drilling and completion costs are, including the saltwater disposal wells, it looks like you're going to average around $3.7 million this year per net well. We've talked about that is because you essentially have to front-load your saltwater disposal well costs as you step out into Kansas. 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?

I think right now our producing well to disposal well, continue to increase. We were at about 2.5 last year. Right now, we're probably around 4 to 1. We're probably going to increase that 5 to 1, 6 to 1 here pretty quickly as we ramp up rigs to drill the horizontal producers. That cost is going to rapidly compress down to $3.2 million. However, if you look at just Q1 alone, we drilled 68 gross wells and our CapEx associated with those horizontal wells is only $91 million, so that does have some impact of cost reduction plus carries and things like that.

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. 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 to 1 ratio. Right now, we're at about 4 to 1, but there are certain areas in Alfalfa County that we are doing some heavy development that we are at 9 to 1, 10 to 1, 11 to 1, 12 to 1. That part of it's going to accelerate going forward because of the number of rigs that we're increasing.

Okay. Great. When you talk about cost reductions, are you talking about getting to the $3.2 million or do you think you could lower than the $3.2 million a couple years out?

I think we can get lower.

Okay. Great. That's it for me. Thank you.

Robert Carlson.

Congratulations on the quarter and the numbers. Tom, I want to say congratulations to you for bringing up the [hedge fund] situation. But am I right in saying, currently we have 19 horizontal in the Mississippian, ending the year at 26 and ending 2013 at 45? Is that right?

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.

Then 45 in '13?

End of year '13.

End of year '13. Think about it as adding a rig a month to the end of '13.

Okay. Great.

We have five wells -- or five rigs drilling disposal wells.

Am I right in saying we have no dealings with Chesapeake at the present time?

Having no dealings?

No dealings.

We operate together in a very large field in the Mississippian, so we deal with Chesapeake every day in the field.

I mean as far as hedge funds or anything along those lines?

I left Chesapeake in 2006.

Great. Thank you.

James Mullins, DL Carlson Investment Group.

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

Yes, I would say, 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 on the business. You can take one of the models and run it out, we show you on the presentation where our returns are, $2.50 gas with the various oil prices. But even change in the gas price doesn't change our earnings much. But we don't give guidance at various prices.

That's fine. That's a financial -- how about practically speaking? What would be the Company's plans, worst case, 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 if that --

There's always a self-[inflicting] by the pipelines, they cut off lower pressure wells to keep from having too full of injections. If we get to the scenario you're talking about, our newer wells would probably flow while the older wells producing in different areas would not.

Very helpful. Thank you.

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.

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