SandRidge Energy Inc (SD) 2011 Q4 法說會逐字稿

Good day ladies and gentlemen, and welcome to the fourth quarter 2011 SandRidge Energy earnings conference call. My name is Gina and I will be your coordinator for today. At this time, all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of today's conference.

(Operator Instructions)

As a reminder, this conference is being recorded for replay purposes. I would now like the turn the presentation over to your host for today's conference, Mr. James Bennett, Chief Financial Officer. Please go ahead.

Thank you, Gina. Welcome everyone and thank you for joining us on our fourth quarter and year end 2011 earnings conference 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 risks and uncertainties and actual results may differ materially from those projected forward-looking statements. Additionally, we will make reference adjusted net income, adjusted EBITDA, and other non-GAAP financial measures.

For reconciliation of any non-GAAP measures we discuss can be found in our earnings release and on our website. Please note that today's call is intended to address SandRidge Energy and not our two royalty trusts, SandRidge Mississippian Trust I or SandRidge Permian Trust and SandRidge Also, SandRidge will release its 10-K on Monday, February 27. Now, let me turn the call over to Tom Ward.

Thank you, James, and welcome to our fourth quarter operations call. As you have seen from our press release, we beat our projections for the quarter and capped off a tremendous year for SandRidge. Let's take a minute and go through what transpired during 2011.

We had a CapEx budget of $1.8 billion and cash flow from operations of $535 million. Where did the cash from come to fund our high rate of return drilling program? We raised over $2 billion in seven transactions through joint ventures, royalty trusts, and asset sales without increasing debt or issuing equity.

As a result, we were able to grow our oil production by 60% and increase our SEC PV-10 reserves to $6.9 billion which is an increase of 52%. We were also able to increase our net acreage position in the Mississippian to 2 million acres and retain 1.5 million acres even after the joint ventures with Repsol and Atinum resulting in $2.33 billion in value from cash and drilling carries.

Our results in 2011 come only after the ground work was laid starting back in 2008. Our move to oil was started by hedging all of our natural gas production in 2008 at over $8 in Mcf. At the time, we were considered too conservative, as natural gas prices were surely going to bounce back in 2009. However, then we made the next critical step and bought oil in some of the best fields in the Permian Basin before the runup in oil prices. This was met with resistance because we had to be buying oil in places where nobody else wanted it and it couldn't be a good deal.

We moved into 2010 by buying Arena, and met more resistance, as we were thought to have overpaid for warn out shallow drilling while everybody else moved to deeper, higher pressure horizontal shale reservoirs. These two acquisitions led the way for our Permian division to grow from $1.5 billion net investment to an SEC PV-10 proved reserves value of $3.3 billion today. The Permian oil acquisitions were the initial stage of a plan to move from a single natural gas asset Company to a premier oil Company built on shallow, conventional, low-risk, low-cost reservoirs.

I've already described what we did in 2011. However, it would be inappropriate to not give credit to our organization for a historic year. 2011 was the transitional year for SandRidge as we were able to monetize assets to build our position and our ultimate growth vehicle, the massive Mississippian oil play in the Mid Continent. During 2010, it became clear to us that we knew something that no one else had focused on, which is drilling for shallow conventional oil on shore US is very profitable and scalable. The key is to stay away from competition and be a first mover into acreage once you have determined your play.

The Mississippian is our play. We not only bought 1 million acres initially, we dismayed the analytical community as we announced a second million acre in the third quarter. It was assumed we could not sell down without drilling multiple wells first. However, the success in the original Miss and the thousands of vertical wells drilled today gave us the history needed to find a partner without spending the capital to drill new wells. Repsol is a company focused on carbonate reservoirs around the world who chose to join us in the Mississippian extension acreage.

We have stood firm in our resolve as others questioned our reason, timing, and size of our continued investment in the Mississippian. We are hopeful the results of now over 225 horizontal tests by SandRidge and nearly 500 horizontal tests in the play, with production blossoming to over 65,000 barrels of oil equivalent per day in the last year, will speak for themselves that the Mississippian oil play is the best rate of return drilling of any large play in the US today. We will be discussing the play in detail at our Investor Day meeting next Tuesday.

We've been consistent with communicating a three-year plan to investors of tripling EBITDA, doubling oil production, and continuously improving our debt metrics by drilling and acquiring conventional oil. We've reviewed what we've done to get here. Now let's chat about why we bought DOR and what is left to fund our three-year plan.

Our ongoing journey to identify and secure cheap oil has led us to the Gulf of Mexico. As we tried to sell our own Gulf of Mexico assets in 2007 and again in 2011, we were met with buyers who, in our opinion, were trying to capture too much upside. Not only did they want to purchase for 1.5 to 2.5 times cash flow, they wanted to get our uphole and infield drilling for free.

The crazy thing is that we were almost willing to accept the offers as we, just like others, did not see ourselves as long-term players in the Gulf of Mexico. However, as we reviewed the possible transaction, we could see this strategy could actually be the most accretive way to add high return, high cash-flowing producing assets that could help fund our three-year plan.

Let's review our alternatives to triple EBITDA, double production, and improve our credit metrics. We could have done one or a combination of six things and met one or two of the components, but not all three. First, we could have slowed down drilling. That's not a good idea as our growth in oil production is driving EBITDA and delivering robust rates of return in our drilling programs. We could have issued debt. We were already pretty levered at 4 point times, and did not want to take on more debt without first growing EBITDA and allowing for favorable debt metrics.

We could have issued equity. Yes, we could have, but this would have not added 25,000 barrels of oil equivalent per day of production and be immediately accretive to cash flow, EBITDA, and debt. We could have issued more royalty trusts. That was another option and while the valuations are attractive, in doing this you're selling EBITDA and selling your most proven reserves.

We could have sold more Miss acreage. That's what most of you wanted us to do. As an option, that's a good option, but it becomes more dilutive to NAV as our Miss acreage has an NAV of 16,000 per acre. Therefore, our goal is to keep as much acreage as possible. Or we could have bought Dynamic, which represents a highly accretive transaction on every relevant measure which generates significant EBITDA to help finalize our three-year plan and sets us up with a great team for our Gulf of Mexico business, where there continues to be a dislocation by the market in value for oil produced.

We've come a long way in the last three years and believe the next three years will be years of harvest as our earnings production and share price all climb together. We have projected one more royalty trust and then we can rely on a combination of cash flow from operations and debt financing while still improving our credit metrics to meet our three-year plan of tripling EBITDA and doubling production. It's been a long journey, but I believe you'll agree that it was a road worth traveling.

I'll now turn the call over to James to go through the quarter financialing.

Thank you, Tom. Before I run through a summary of our financial results let me comment on our Dynamic acquisition. In terms of the fit and the reasoning for the deal, as Tom discussed, we were able to acquire Dynamic at a very reasonable price of $50,000 per flowing barrel equivalent per day, 3.4 times EBITDA, and 67% of proved PV-10. While we continue to view the Mississippian and Permian as our core drilling assets, in the case of Dynamic, if we can buy offshore cash flow and production for the low multiples that we are seeing, this represents a compelling opportunity for us that inexpensive production and EBITDA, improve our leverage, and derisk our balance sheet, all of which remain consistent with our three-year plan.

Turning to the fourth quarter, as you can see in the earnings release, adjusted net income was $9.1 million or $0.02 per diluted share. Adjusted EBITDA was $175 million and operating cash flow was $153 million or $0.31 per diluted share. Fourth quarter adjusted EBITDA is up 34% over the comparable 2010 period driven by a 26% growth in oil production and higher realized oil prices, somewhat offset by decline in gas production.

For the full year 2011, adjusted EBITDA was $654 million, and operating cash flow was $535 million or $1.08 per diluted share. Note that operating cash flow does not deduct the distributions to the public unit holders of our two royalty trusts which totaled $57 million. On per unit measures, LOEs continued to improve the last two quarters, and for the full year LOE of $13.81 per BOE and production taxes of $1.97 per BOE were both below the low end of 2011 guidance ranges.

DD&A of $13.97 for BOE was right within guidance and G&A of $6.35 per BOE fell just outside of the high end of guidance range, primarily due to headcount increases to handle the continued growth in the Mississippian. Capital expenditures excluding acquisitions were $500 million for the quarter and $1.8 billion for the year, right in line with guidance.

We continue our capital raising efforts. And in January, we closed the $1 billion Mississippian joint venture with our partner Repsol, receiving $250 million cash on January 5, and the remaining $750 million in the form a drilling carry, which we expect to utilize over the next three years. Also, in January, we filed the registration statement for the IPO of our third royalty trust. The registration statement is under review by the SEC, and therefore we can't further comment on the offering on this call except to say that SandRidge expects to realize proceeds from the offering early in the second quarter.

As we disclosed in our Form 4 filing on Wednesday, earlier this week we sold 1.58 million of our common units of SandRidge Mississippian Trust I SDT for proceeds of approximately $52 million, which is not yet reflected in our current $200 million cash balance. We still hold under 2.2 million SDT common units and 4.9 million SandRidge Permian Trust common units, with a combined market value of approximately $200 million. Finally, in terms of potential sources of capital, we can also JV up to an additional 250,000 acres in the Mississippian if we choose.

Regarding our liquidity and balance sheet, at December 31, we had a cash balance of just over $200 million, $2.8 billion senior notes, and no amount drawn on our credit facility, giving us a net debt balance of $2.6 billion. This represents a reduction in net debt of $300 million from year-end 2010. It puts our year-end net debt to adjusted EBITDA at 4 times, and pro forma the impact of Dynamic, 3.3 times.

Our liquidity position remains excellent. As of February 21 we had a cash balance of $205 million and no borrowings under our credit facility, giving us liquidity of approximately $1 billion. Our $790 million credit facility matures in 2014. However, sometime in the second quarter of this year, we intend to enter into a new revolving credit facility to more likely increase the borrowing base from its current level. In terms of our borrow matures, we have only one $350 million note maturing in the next four years.

So tying together an improved balance sheet from continued successful capital raising, $1 billion of liquidity, a deep inventory of high return or drilling opportunities in the Mississippian and the Permian, plus the Dynamic acquisition, we believe the Company's in the best position it has been in since its inception in 2006. We have in place now with 2012 capital plan, inclusive of Dynamic, $1.85 billion which we can fully fund with cash flow from operations, proceeds from the Repsol joint venture, and our $1 billion of current liquidity. Also, with our credit measures continuing to improve, we will be in a position to utilize some amount of long-term debt beyond 2012 to fund our growth.

In yesterday's press release, we published updated 2012 guidance. This guidance represents expectations for SandRidge standalone for the January through April period, and assumes the closing of the Dynamic acquisition on April 30, giving effect to the Dynamic acquisition contribution for May 1 forward. While we don't give quarterly guidance, with the Dynamic acquisition not closing until early second quarter, for the first quarter 2012 I would point you to the SandRidge guidance ranges that we published in our last two investor presentations as a good representation of expected Q1 results.

In terms of production, we are maintaining SandRidge standalone guidance of 26.5 million barrels of oil equivalent, broken down as 15.4 million of barrels of oil and 66.6 Bcf of gas. We're guiding Dynamic to contribute production of 5.8 million barrels of oil equivalent for the May to December period. This represents 25,000 barrels of oil equivalent per day of production which we then risk down slightly during hurricane season to get an average production of 23,700 barrels of oil per day for the eight-month period in 2012. Combined oil differentials improved from $13 to $9 due to the higher realized LLS pricings for Dynamic's oil production, which typically trades at 10% to 20% to WTI.

In terms of costs, we have updated lifting costs to account for the higher operating costs and insurance expense of operating offshore in the fixed price nature of some of our gathering contracts in the WTO. Production taxes for BOE declined due to lower overall tax burden on the Dynamic assets. We have broken out plugging and abandonment cash costs of $35 million and will be reporting these separately from capital expenditures.

Regarding CapEx, we increased SandRidge standalone land CapEx by $50 million to reflect future additions of acreage in some of the proven areas of the Mississippian, bringing SandRidge standalone CapEx to $1.65 billion for the year. For the Dynamic assets, we are projecting CapEx budget of approximately $200 million for the May through December period. Beyond 2012, we do expect our annual offshore CapEx to stay flat at $200 million, but for 2012 Dynamic's budget heavily weighted towards the back two-thirds of the year. In total, this brings the 2012 capital expenditures budget to $1.85 billion.

We are entering 2012 with a very strong oil hedge position. For calendar year '12, we have approximately 14 million barrels of oil hedged at $99.82 per barrel, and dynamic has approximately 1 million barrel swap at just over $91 a barrel. Combined, this represents approximately 82% of estimated 2012 oil production hedged at approximately $99 per barrel. The details of SandRidge commodity hedge positions are outlined in our earnings release, and Dynamic's hedges, the majority of which we anticipate assuming at closing, are disclosed in its public filings. This concludes management's prepared remarks.

I would like to ask the operator to open the line for questions.

(Operator Instructions)

Neal Dingmann, SunTrust.

Morning, gentlemen, solid quarter. Say, Tom, first question, just on it looked like the last several results in the horizontal Miss have been a bit better than what it was towards the beginning. Just wondering if you could comment on the type curve? Do you see that potentially reflecting a change again upwards or are you going to be content with that for a bit?

We'll be content for this year at 275 barrels a day on the first 30 days. We're the only company that gives all of the data on our wells and the 30 day average of all of our wells that we drill. And so far, we're above the 275. In fact, in 2011 we were at 302 per day on the first 30 day average, and we're continuing to be above that in 2012. However, we won't change our type curve. If it changes at all, it won't change until the end of 2012 when we look back at the overall program as -- at the end of the year when we do our outside reserves. So remember, the type curve is established by the outside reservoir engineers.

Okay. Tom, it looks like on the upcoming or the second horizontal Miss Trust that some of those wells are going to be in what I consider now is the newer of the plays. And was wondering now when you see the operations or the wells that you have laid out to drill for the remainder of this year, both within that new trust and just overall, will it be pretty spread out up into Kansas as well as the entire area or will you still be focusing on -- I don't want to say core areas, but the older areas?

I can't refer to the royalty trust, but I can say that we are expanding the saltwater disposal system. So the key to the play is being able to dispose of water inexpensively. As we have talked about from the very start of this play, it's knowing that there was a very large stratigraphic trap with oil in place and then how do you handle the massive amounts of water that come with that oil and why it wasn't discovered over the last course of the last 50 years, this play is because of the amount of water we produce. So the efficiency of taking care of saltwater disposal is what makes the core area. So the reason we've drilled the most wells in one particular area is because we already have the saltwater disposal system in place. You can save about $2 a barrel on thousands of barrels of water a day by having a saltwater disposal system. We're the only company that has a very large saltwater disposal system in place, and that's the key to keeping the rates of return on the wells. And so, to further answer your question or specifically is yes, we plan and continue -- we'll be moving out and adding saltwater disposal systems, but if you -- when you see our Analyst Day, you'll notice when Dave Lawler gives his presentation, that it's all keyed around the efficiencies of putting in a disposal system first.

Okay. And then last one if I could, Tom, just on Dynamic. I know when you had the conference call around that, you mentioned just the plethora of all of the work overs, not to mention the new wells that will be drilled. Is that sort of the plan, to continue to look at rework opportunities in order to keep costs low? If you could comment on, as you see future rework opportunities mixed with new well results, how you see growing Dynamic for the new year or so?

Sure, Matt will take that.

Yes, Neal, this is Matt. Yes, a lot of projects going forward is going to be re-completions. They have 37 re-completions slated this year and most of all that work is low risk through tubing where you're already working in existing wells and known production blocks. We'll probably drill 14, 15 wells this year, which two-thirds of those development wells, and you have 5 or 6 that are expiration. But yes, the bulk of the work is going to be low risk, uphole re-completions.

Got it. Thanks, guys.

Dave Kistler, Simmons and Company.

Just following up on the Miss, with about 2 million acres across the play for you guys, do you think about maybe at the Analyst Day breaking it up into a couple of different sections with different type curves? Just trying to figure out the best way for us to optimize modeling it.

I think at the Analyst Day, we still don't know enough about the entirety of the play to be breaking out different type curves. What we've tried to do is have a type curve that we feel is representative of the whole play, and we'll talk more about the extension versus the original part that we bought into and how the geology is the same and how it might differ. And I think post Tuesday, you probably should have a better understanding of how come we bought acreage where we did. To say we're going to have a different type curve is just probably too new for that until we drill more extensively across the play that I'm sure there will be areas that are better than others. We just have not drilled enough across the whole play to understand that yet. What we're really seeing is good wells across the whole play and so you can drill within areas, instead of saying you have one core area. Within each of our townships there are good areas to drill and areas that aren't quite so good. We've drilled the most wells in the play and think that we understand where we like to drill so far and that's -- I do think that on Tuesday you'll get more of a flavor for what our ideas are.

Great, appreciate that. And then just a clarification, I thought I heard James say that you only had about 250,000 acres that you looked to JV in the Miss? Did I mishear that statement?

Keep in mind that it was -- we had publicly said it was 250,000 to 500,000 additional acres. Now it's 0 to 250,000.

And what's the driver of that change?

Just the Dynamic acquisition.

Is there just not the need to modify as much?

We want to own as much acreage as we can.

Great and then last question. With about 82% of oil hedged for '12, what's the targeting hedge profile for the Company now? When you think about Dynamic, it's going to have weather related risk, et cetera. Is there an optimal hedge level that you guys look at, or are you just looking to lock down pretty large levels so you can lock in at least the near-term economics?

We're trying to cut the risk as much as possible in all ways in our business models. If you think that our costs aren't rising, and in fact, our service costs haven't moved up since mid 2009 and we now have rates of return in the Permian of 72% on the projected wells we're drilling this year and the rates of return close to 100% in the Mississippian. And we just see this as if you can lock in that price, it's nothing more than greed to try to get more than that. So as what you see -- will continue to see is us, as prices move up, is to continually hedge into that and hope that prices continually move up so we can hedge more in out years. And I think it's as simple as that. We're just trying to lock in -- take out risk in our business model.

Okay. Appreciate the clarifications, guys, thank you.

Operator. Your next question comes from the line of Craig Shere with Tuohy Brothers. Please go ahead.

Good morning, guys. Couple of questions. So first, the 1.5 million Miss acreage, that is after the two JVs, but assuming a successful second Mississippian Trust, what would the net be after minority in trust?

I don't know, can we talk about the second Mississippian trust? We really can't.

You can talk about our whole acreage and what it would be after the Mississippian trust.

Yes, we're at 1.5 million net acres. And I can tell -- I'll just tell you the second Mississippian trust, what we're contemplating is only about 52,000 acres. So there's a very little impact to the entire play for SandRidge, if you will.

And how -- since you're retaining more ultimate acreage here, how should we think about any changes in the long-term drilling plan? Wouldn't you need to jack that up a tad to ultimately HPP everything?

No, we're in good shape there because if we run the rig count that we have planned, the ramp-up, which is adding a rig all the way through '14. We look at substantially holding all of that acreage in a five year time frame.

I'm sorry, a rig a month through '14?

Yes.

Okay. And I guess somewhere given the time line you just described, the second Miss JV with Repsol was a bit a step-down in value per acre versus the first Miss JV due to the inclusion of the extension play that obviously hadn't been as derisked. At what point do you say this is largely derisked and it's at least worth possibly what the original JV was.

We think Repsol made a great deal as that it was the same derisking that was in the original Mississippian before we drilled horizontally there is that you have thousands of vertical wells. And so in our opinion, it's very much a derisk play. So now we just have to go drill horizontally and convince everyone, including ourselves I guess, that it's the same as the original play. You'll be able to see a lot more on Tuesday and understand our reasoning as to how come we think that the extension Miss is virtually the same as the original.

Okay. And last question, Tom, with the guidance out there for doubling the EBITDA and recognizing you didn't want to just issue equity and dilute everything, but also recognizing equity was used to acquire at attractive valuations the free cash flow and the reserves from the Gulf of Mexico asset, how do you think about production and EBITDA per share? Do you have specific targets in mind for that?

Yes, this is James. The Dynamic acquisition was very accretive on cash flow per share and earnings, all those measures. One of the things we look at is cash flow per share accretion. At the same time, what's our leverage levels and how do we derisk it. So it's really balancing all of those. I don't think we have specific cash flow or earnings per share target in mind for that far out, really just for focusing on EBITDA, but again, not wanting to have an overlevered balance sheet, not wanting to dilute the shareholders to get there.

Okay, appreciate it.

Brian Singer, Goldman Sachs.

Thank you, good morning. As more companies come into the Mississippian, are you seeing any cost pressures as you add rigs or are these offset by the benefits of scale such as water disposal as you mentioned and reduced drilling [there]?

We're not seeing any cost pressure from the service side as we move in -- move more into -- or other companies move into the Mississippian. Keep in mind that we use equipment that is readily available and has been the backbone of our industry over the last several decades and very shallow low pressure equipment, and the only offset that we have from not lowering our cost substantially is the efficiencies of bringing on new rigs. So we continue to keep our cost essentially flat as we bring new rigs on.

Great, thanks. And then I think you mentioned in your opening comments that the $200 million or so of CapEx that you're planning for the Dynamic assets from May on is backend loaded. Can you add a little color on what's driving that, and whether going forward annualizing that rate to 12 months would over or understate your ongoing spending plans?

Answering the last question first, I think going forward into 2013 and on, we can think about $200 million. What's happening this year is as you know Dynamic was in the middle of an IPO process. They've grown through acquisitions since 2008 and this is their first year of really running a capital program. And the first thing people think about is when they hear about $200 million capital program, they take that divide by 12 and it's $16.67 million a year. Everybody wants to prorate that to the eight months we're going to own Dynamic and say $133 million. The fact of the matter is they have three rigs coming from Dynamic's and the way they're lined up they probably will hit all at the same time in April. And so there's very little capital spending in January and February and everything -- because of the process that we're going through with this transaction and everything -- everything is delayed probably four weeks to six weeks. So the bulk of the capital spending is going to be really May through December. In fact, the high water mark is probably $35 million, $40 million in June or July and then it starts rolling off. But yes, we've put a real hard pencil to it. We could probably could guide to $185 million to $190 million, but we chose to keep it at $200 million.

Thanks, that's helpful color. And lastly, with your focus almost entirely on the Mississippian, Gulf, and Permian, can you just give us an update of the Century Plant CO2 contract at Pinon mitigation there and whether we should expect any changes or restructuring to it?

No, there's no changes to the obligation to OXY and I think we have publicly said numbers in the range of maybe $20 million annually for the penalty. There's no change in that; we'll pay our penalty. There's no reason to drill gas wells at this same time with the high rate of return on oil wells that we have in our portfolio.

Great, thank you.

Charles Meade, Johnson Rice.

Good morning, gentlemen. Thanks for taking my question. First, Matt, thanks for the clarification on that Dynamic CapEx. I was wondering the same thing. But, Tom, I was hoping you could elaborate a bit more on your thinking with the Mississippian acreage. I think we're getting the message that you guys have a diminished need or appetite to sell more acres, but how does that fit with your incremental $50 million to buy acreage in the Mississippian?

As I mentioned earlier, within townships we have a different taste in different types of wells. If you noticed in the last 43 wells that we gave production on in the last slides that we had, there's some wells that are extremely good and some wells that are poorer, and I think there are geological reasons around that. So what we do is once we have good area that we're drilling in, we tend to try to buy more acreage and that's the infield drilling -- or infield acreage acquisition that we're able to do. It's in fairly small amounts, but it does add up. But it's very accretive to us to buy that acreage knowing that we're going to drill it very soon.

Great, that makes sense. And so how many total acres do you think that -- additional acres that's going to get you, that $50 million?

We don't know yet because we just added that assuming we're going to be able to buy that acreage in 2012.

Got it. Okay, that's it, thank you.

Richard Tullis, Capital One.

Thank you, good morning. Tom, looking at the guidance that includes Dynamic, I know you're only including May through December and building in some downtime. But I was thinking back to the Dynamic road show info. Weren't they looking at like 26,000, 27,000 barrels a day in 2012, and that probably already included downtime, I'm guessing?

I don't know about the road show at Dynamic. When we reviewed the company and based on our acquisition, we looked at the company as producing 25,000 barrels a day in 2012.

What are they currently producing?

They've been averaging just about 25,000 barrels a day. Is that right, Matt?

That's correct.

And then looking at the Permian EUR, I guess, change in current presentation versus, say, last year when you went from 83,000 barrels a day -- I mean 83,000 barrel EURs to 58,000. Can you talk about that, what's dropping that change?

We're going to talk a lot about that in our Analyst Day presentation next Tuesday, but just long story short, it's a change in the well mix. As with most programs, you go out and you drill your highest rate of return wells first. As we roll those wells out of the program, getting down to the smaller number of 100,000 barrel wells, we start drilling something that looks like a Fuhrman-Mascho well which is 38,000 barrels. Like in 2012, about 600 of the 760 wells or so we drill, it's going to be Fuhrman-Mascho at 38,000, 39,000, 40,000 barrels a day. So that drives the entire average of the program down a little bit.

So you're looking at it more as a yearly EUR number rather than long term?

It is more of an annual program number, but also this year we get to the point where that program pretty much represents the entire reserve space going forward. This is what I think you can expect going forward is this 72% rate of return, 58,000 barrels equivalent type of number.

Okay. And lastly for me, any indication yet from the BOEM on how they're going to handle the transfer of the Dynamic leases? I know Energy XXI ran into pretty significant delays following their acquisition of Shell assets a little over a year ago where the BOEM held up some of the leases for an extended period. So any early indication from BOEM on handling?

Yes, we are working on those issues as we speak right now, and at this time there's no indications there being any delays or any problems doing so. So I don't expect any issues at this point.

Thank you, appreciate it.

Dan Morrison, Global Hunter.

Good morning, thanks. Just a quick question on Permian, update on the re-plumbing project that Joe launched into, is that pretty much wrapped up?

Yes, I think in our November call we said we would be complete with that by the end of the second quarter this year and we're on track to do that. There were 28 tank battery projects. We finished 11 of them by the end of 2011 at year end. We're currently working on a dozen more here this quarter and we'll finish it out in the second quarter. So far, with decline in production and with new wells being added on, the net impact's probably 500, 600 barrels equivalent per day, and we were anticipating 1,500 barrels to 2,000 barrels of improvement when we finished. So I think we're on track to do that.

Great, thanks. And with the Dynamic, you talked a little bit about re-completions being the gist of the capital program in the near term. Are there any drilling projects in this year's CapEx or when do those start to come in?

Yes, there are. I mentioned earlier, I think the plan is to drill about 15 wells starting in April, kicking it off with three rigs. So yes, that is a pretty significant part of the capital project for 2012.

Okay. Sorry I missed that, Matt.

I'm sorry?

I said I'm sorry I missed you saying that. Thanks.

(Operator Instructions)

Joe Allman, JPMorgan.

Thank you, good morning everybody. Tom, just strategically at this point you now have three core assets when you include this Dynamic deal. So are you satisfied with these three core assets? And my impression was that you were satisfied with the two core assets and that you were going to actually stick with those two core assets until some point in the future? So just looking forward, is this it in terms of the portfolio?

Sure. I never know what the future brings. What I looked at was options as far as funding our Mississippian growth, and then the Dynamic or the idea of shallow Gulf of Mexico, but really having a team that can make a accretive transactions in the cheapest oil in the world basically was appealing to us. So yes, we did make a move from two core assets to three core assets. We're hopeful that we can continue to buy low cost oil if others are willing to sell out of an area that is selling out $125 oil today for 2 to 2.5 times cash flow. I think we'd be willing buyers, but I don't have any plans as we talked today to have a new area.

Okay, that's helpful, Tom. And then remind us how much free cash flow you think the Dynamic assets will throw off each year?

There's been a number, we've talked about around $100 million. That's a good estimate.

So, you're basically -- you're taking on several hundred million dollars of debt. So it will take you six or seven years to pay off that debt with the free cash flow?

But you still have an asset that's producing 25,000 barrels a day.

You mean after you paid off the debt you're incurring for this transaction?

Each year.

Okay. In terms of -- so are you going to be taking on all of the professionals from Dynamic to run the program?

We are, yes.

And on annual -- what kind of G&A add is that annually?

It's in the range of $30 million which is consistent with what Dynamic had in their best one.

Okay, all right. I know you guys went through how you're going to be paying off your funding gap, your CapEx versus cash flow over the next three years, but can you just kind of -- just list the items that you're going to monetize. Are you still going to sell the common SDT units? Is that still a plan? And then the common PER units?

You saw we sold almost 1.6 million units earlier this week. We said I think starting six or nine months ago that those -- all of those common units are available to monetize and as funding options. So I don't know -- I'm not going to comment on specifically when and if we'll sell them, but it's an option for us to use to monetize. We could also JV some more of the Mississippian acreage, and keep in mind that we've got $200 million of cash right now, $250 million if you include the units we just sold, a fully undrawn revolver which -- we expect to increase the size of that resolver later this -- early in the second quarter. And also cash flow from operations is going up quite a bit this next year, and so we think we're fully set this year and what that positions us to do is come next year, we're in a good position to utilize some long-term debt if we need to. Our credit measures have improved. So we think we're through this period where we were in 2011 of seven transactions monetizing assets. We're kind of winding down our asset monetization needs here.

That's why I called the next three years the years of harvest.

Got you, okay. So at this point, once you get this Dynamic deal done, you're basically satisfied with the balance sheet at this point, no need to reduce debt beyond now?

That's right. Our credit metrics are improving.

Got it. All right, thank you, very helpful.

Operator. David Heikkinen, Tudor, Pickering, and Holt.

Good morning, guys. Just a question and wanted to clarify, did you talk about adding one rig a month in the Mississippian between now and 2014? So would that take your rig count from roughly 21 rigs to 45 rigs in 2014?

Yes, we're looking at moving to 45 rigs.

And so as you think about 2014 capital budget, what will that be?

We haven't projected 2014 capital budgets yet, but we've talked about us staying within the range of between $1.8 billion to $2.2 billion.

Okay. And then just going to the Permian, Matt, I think you said the more of your locations are more like Fuhrman-Mascho heading forward less the shift in type curve. Is it that your remaining inventory is more like San Andreas like?

Yes, I think what I was trying to say is that our program is pretty much going to be dominated by San Andreas wells. For example in 2012, 600 of the 760 wells will be San Andreas wells and that's the way we should think about it going forward.

Okay, so more of the shallower, lower cost wells.

That's correct.

And then just final question, and this is comparing and contrasting, Range talked about the chat being important and being on a structural high important from their acreage for this in the Mississippian Lime. Do you have any thoughts about -- I don't know if you have read their commentary or thought about the importance of having chat or being on a structural high in the Mississippian, but if you have any thoughts it would be helpful just to compare and contrast for us?

Sure, we look at the play as a very large stratigraphic trap that has subtle structure involved in it, but more of being encouraging porosity -- the porosity and permeability out of water-bearing rock, and so it's not important for us to be structurally high in a given area. So yes, we do look at structure in very specific areas, but over the region that's not important, and we drilled some of our best wells in structurally low positions.

Okay, that's helpful. Thanks, guys. See you next Tuesday.

Craig Shere, Tuohy Brothers.

Hi, just a follow-up. Originally, before the steep ramp in the rig count in the Mississippian, I think you all were looking at efficiencies maybe driving cost to, if I remember, $2.7 million a well, but that a rig a month led to some inefficiencies and postponed that for a while. Given the fact you're going to be adding a rig a month for an extended period of time here, is there a point where the legacy rig count becomes so great and the efficiencies of those become so great relative to the additions that you think we start turning the corner on average cost per well a year out?

I'll say this, let's take -- watch us on Tuesday and we'll spend a lot of time talking about cost because the real driver in future rates of return to even be higher rate of return is in lowering costs. So there are a number of ways that we're looking to lower costs. However, as we bring on a rig per month, we're still anticipating keeping our costs flat because of the inefficiencies of new rigs that come in. So as of today, I'd like for you to keep your costs at the $3 million range, but watch us on Tuesday and see if you can be encouraged about how we might be able to drive down costs in the future.

Great, thank you.

Anne Cameron, BNP Paribas.

Hi, good morning guys. A question about your rig count. So you're adding rig a month, that gets you to a max rig count of I think it was 45 rigs?

Yes, through '13.

Okay. And so how many -- that's gross of the royalty trust rigs?

That is.

Okay, so if you do another royalty trust, what's the max amount of rigs you could have committed to drilling puds on the royalty trust takers and still hold your acreage?

We can't talk about the second royalty trust. What we can talk about in the first royalty trust is that we had basically three rigs running on the SDT.

Okay. And the max rig count of 45 rigs was the same max rig count before you added the extra million acres in the new Mississippian?

Yes.

So how is it that you can double your position and still run the same number of rigs without, say, impairing the present value of the acreage?

Without impairing -- without impairing the present value of the acreage?

It's going to take you longer to get (inaudible - multiple speakers)

Well it's how come we sold 500,000 acres, and I don't think it impaired our present value on it.

Okay, but these are gross rigs or net rigs?

They are gross rigs.

So isn't -- aren't the same number of rigs going to be running your acreage overall as before those transactions?

We're looking at drilling 7,000 wells out here over the next 12 years. That's how the NAV in this acreage is figured out. So if you're looking at 45 rigs, you're drilling 500 wells a year. So there's really no movement in the PV. And if you look at 500 wells a year, you look at potentially holding 300,000 acres, something like that a year times five. You have your 4.5 million acres held, and that's just Oklahoma. In Kansas, you can hold about 1,240 acres per well. So I think the way we have it designed is two ways. One is to maximize present value to realized NAV and at the same time holding all our acreage.

Okay, that's helpful. Thanks, guys.

Alex Heidebreder, Millennium.

How are you guys doing today? Congratulations on the quarter. So I understand that you guys don't want to sell acreage because that makes a lot of sense because it's very NPV destructive, but in terms of trying to bring forth some of the NPV from the Mississippian, why aren't you looking to bring forward some of the 7,000 net locations? I mean even as you're doing 500 locations a year, you still have 12 years of inventory today and years 7 through 12 don't create a lot of NPV.

So you like to drill more?

Yes, or find someone else to drill it for you and keep the economics.

There are five other guys right behind you that want us to drill less.

But they're wrong. (laughter)

No, it's really the efficiencies of the play and I think if you watch on Tuesday, you can see that trying to, let's say, double our rig count and do the disposal work and having all of these -- when we look at an area it's really 18 square miles and put in a disposal system, you have to really do everything, not just go out and drill wells and bring them on. You have mid-stream and really disposal system is also critical to this. And to keep our costs down you don't want to be moving in too many rigs at once. So we feel like the best thing for the Company and the most efficient is to maintain the highest rate of return is to add about a rig a month.

And so by the end of the year that means you're at a 500 per year rate?

By the end of '13.

By the end of '13. And how aggressive or conservative is the 7,000 net locations?

It's three wells per section and you can have a debate on whether you should be more or less on that. I don't think anyone is less than three wells per section that's currently drilling. I don't know if that's conservative or not. I think we're comfortable with three wells per section.

I mean 10 years from now, is that still going to be the number or is it going to be four or five? If you had to guess as to where it's going to go eventually?

If I had to guess, I'd guess at three wells per section because that's what we currently model. But we've tested four -- we've tested as close as having four wells per section and we're not seeing interference, but that doesn't mean that we want to change our idea yet of three. We don't want to spend capital and have drainage, so that's how come we're projecting three wells right now.

I'm patient. I can let you drill them out, but you guys are clearly not receiving hardly any of the NAV value today for the 7,000 locations.

You would be one of our few shareholders that are patient.

I don't think another JV or two would hurt NAV as much as it would bring forward NPV.

We hear you.

All right. Congratulations, guys. Keep up the good work.

Ladies and gentlemen, that concludes the Q&A session with all questions answered. I will now turn the conference over to Mr. Tom Ward for closing.

Thank you, and as always we appreciate your attendance and we look forward to seeing you next Tuesday at our Investor Day. Thank you.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation. You may now disconnect, and have a great day.