SandRidge Energy Inc (SD) 2011 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Third Quarter 2011 SandRidge Energy Inc. Earnings Call. My name is Modesta and I will be your operator for today. At this time, all participants are in 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 your host for today, Mr. James Bennett, Chief Financial Officer. Please proceed, sir.

Thank you, Modesta. Welcome, everyone, and thank you for joining us on our third quarter 2011 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 Business Development.

Please note that today's call will contain forward-looking statements and assumptions which are subject to risks and uncertainties and actual results may differ materially from those projected in these forward-looking statements. Additionally, we 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.

Also note that this call is intended to address SandRidge Energy, not our 2 royalty trusts -- SandRidge Mississippian Trust 1 or SandRidge Permian Trust. The trusts will have separate earnings calls at 8 AM and 9 AM Central Time, one week from today on Friday, November 11. So, please hold any trust-related questions until the calls next week. Now, let me turn the call over to Tom Ward.

Thank you, James, and welcome to our third quarter operation and financial update. We continue to make great progress in executing on our 3-year plan of tripling EBITDA, doubling oil production and lowering our debt-to-EBITDA ratio. The plan revolves around our growth engine in the Mississippian formation of Northern Oklahoma and Western Kansas. This area has received a tremendous amount of attention in the last year; not only from SandRidge, but from other large industry players.

A snapshot of where we were last year to where we are now reveals that we have nearly doubled our acreage position in the original Mississippian play from 400,000 acres to 800,000 acres, while generating more than $800 million of capital from our initial investment of less than $200 million in acreage costs. Our organic production growth has increased by sevenfold from about 150 horizontal Miss wells we've drilled since January 2009. This represents nearly half of all the horizontal wells to date in the play.

On the first 37 wells drilled at year-end 2010, we averaged a 30-day peak IP of 244 barrels of oil equivalent, while the last 119 wells drilled in 2011 have averaged 308 barrels of oil equivalent a day. We currently have 18 rigs drilling horizontal producers, 2 rigs drilling saltwater disposal wells, while planning to exit this year were 20 horizontal rigs running.

We've now adjusted our goal for 2012 to average 26 rigs. This is averaging 2 more rigs than we would have indicated in the past for our 2012 Mississippi drilling plan. However, this will not impact our 2012 capital spending plan, as we will offset the increase in the Mississippian activity by reducing our Permian drilling by 4 rigs to 12 rigs.

We're currently seeing better capital efficiency in the Miss program, as we're experiencing some facility constraints in the Central Basin Platform. Matt will go into detail on the production constraints in the Permian, but the quick answer is that we've out-drilled some of our infrastructure and will be working to eliminate these bottlenecks over the next couple of quarters. Therefore, production is increasing in the Permian, but not at the rate we projected in our August guidance update.

With that said, we continue to see the Permian wells performing on type curve. At the same time, our Mississippian production has performed above our expectations. The Mississippian oil production is in line with our type curve and our natural gas production is better than we anticipated. A Miss well is now projected to produce 56% natural gas.

We have also tested the idea of drilling 4 wells per section. In fact, we have drilled 36 wells, or 18 lease line offsets, and have not experienced any evidence of negative interference between the wells to date. We did not want to visit the idea of 4 wells per section until we had tested the theory, but so far, the indication is positive to increase the amount of wells to be drilled.

However, we will not officially change our position on spacing until more time is seen on the producing wells. We believe the Mississippian is the most capital-efficient play in the US, and we continue to evaluate our rig allocation and make the best decisions going forward to maximize production and return on invested capital.

One of the key reasons the Miss works so well is that it's shallow and it also produces from a permeable rock that completes easily and is the lowest cost play of scale in US. We raised or announced over $1 billion of capital during the third quarter, through the closing of our Permian Royalty Trust, our JV with Atinum Partners, and the pending closing of our East Texas natural gas properties.

The royalty trust structure remains a part of our funding plans and we anticipate launching another royalty trust in the near future. Therefore, we cannot discuss particular assets that will be in the trust or details regarding the trust from this point forward. This year, we've raised over $1.8 billion and will be undrawn on our $790 million revolver, plus have a cash surplus moving into 2012.

We've previously mentioned that we intend to raise approximately $800 million of non-debt capital and we plan to have that accomplished during the first half of 2012. After this capital raise, we'll be able to fund our 3-year plan through cash flow from operations and additional long-term debt, as needed in 2013 and 2014. By the end of 2014, we anticipate being a Company that is self-funded with double-digit production growth.

This plan takes into consideration that we will have fully funded the acquisition of 1 million acres in our new Mississippian play, but does not give us any credit for future EBITDA growth or cash from a partial sale of acreage. We will not deviate from our CapEx plan until we sell acreage to pre-fund the development of the new Mississippian.

We've now secured over 700,000 acres on our way to 1 million acres in the new Mississippian play. We'll be at or near completion of the leasing stage by the end of 2011 and are planning to disclose the location and play details to investors later this year.

In researching and developing our thesis on the play, our technical teams have studied over 7,000 vertical wells with the same criteria that we used to develop our original idea. The criteria include proven oil and gas in place, commercial development of thousands of vertical wells, control of reservoir thickness, and shallow depth. We're now preparing to talk to potential partners.

The level of interest we received suggests that we could have a partner selected by mid-year 2012. When we discuss the area, we believe you'll more fully understand the value implications to this great idea where we'll have nearly 2 million acres by combining with our original Mississippian acreage.

The key to the next million acres is that it has to fund itself for us to meet the 3-year plan that we've laid out to you. Therefore, that is why we will sell or partner on a portion of the play before we commence the drilling program.

We also believe in hedging attractive rates of return. Therefore, we have continued to add to our hedge oil book. We've added over 8 million barrels of oil to our hedges since our last quarterly call and now have over $3.5 billion of hedges in place through 2015. The reason we hedge is that we do not see service cost pressure in either of our plays and have very attractive drilling rates of return at the current strip. Therefore, do not be surprised to see us continue this trend.

Our Company has developed and dominates 2 of the most capital-efficient projects in the US today. In the Miss, each time we drill a well and spend $3 million, we create a net present value of an additional $4.9 million. In the Central Basin Platform, when we spend $760,000, we create $1 million of net present value. I'm very proud that we have taken the route of high-quality reservoirs at shallow depths with scalable plays where costs can be controlled. I'll now turn the call over to Matt for the operations update.

Thank you, Tom, and good morning to everybody. We produced 6.2 million barrels of oil equivalent in the third quarter, as compared to 5.6 million barrels of oil equivalent in the second quarter. This is a 10% sequential quarter-over-quarter production growth for the Company. Oil production grew by 15% to 3.2 million barrels of oil in the third quarter, as compared to 2.8 million barrels of oil in the second quarter and natural gas production grew 4% to 17.9 Bcf from 17.2 Bcf in the same period.

Even though we just completed a quarter of record production numbers, we are revising our 2011 full-year production guidance, down approximately 2% to 23.4 million barrels of oil equivalent from our previous production guidance of 23.9 million barrels of oil equivalent. The new 2011 guidance consists of 11.8 million barrels of oil and 69.4 Bcf of natural gas.

The slight downward revision in the 2011 guidance is primarily due to excessive pressure buildup in our Company-operated low-pressure gathering systems in the Central Basin Platform, as a result of tremendous production growth we have experienced since the beginning of this year.

However, before going into details about the gathering systems in the Permian Basin, I want to point out that since we have already produced 17.3 million barrels of oil equivalent through the first 3 quarters of this year, our new full-year guidance of 23.4 million barrels of oil equivalent would suggest that fourth quarter production will be slightly less than our third quarter production.

The reason for the apparent fourth quarter production decline is that we are scheduled to close the sale of our East Texas properties the middle of this month and when we do, about 4,000 barrels of oil equivalent will come out of our production base. Otherwise, excluding the impact of East Texas, we would still project to have quarter-over-quarter growth as we end the year.

In regard to the pressure issues in the Permian Basin, due to our own drilling success, we have outgrown our low-pressure gathering systems in and around the Fuhrman-Mascho field on the Central Basin Platform. As a result, we project to produce about 590 million barrels equivalent less than our full-year forecast for the Permian Region, due to the facility constraints. Just for clarification, we don't expect production to decline, but we expect growth to be moving at a slower rate than we had forecasted for the Permian.

As you may remember, when we acquired these assets in July 2010, we had 2 primary issues to resolve in order to successfully ramp-up our drilling program. They were 1, inadequate electrical infrastructure and 2, poor third-party compressor and plant run time. We were successful in getting both of those issues resolved and have since added 600 new wells and have grown gross production nearly 50% from about 12,500 barrels equivalent gross to a current rate of about 18,500 barrels of oil equivalent gross.

However, the rapid production growth has created bottlenecks in the Company-operated low-pressure systems. This, in turn, has created excessive back pressure in the field and causing the more mature production to go off-line as we bring new, higher pressure wells on line.

Fuhrman-Mascho productions has had steady growth every month, including an 11% production growth surge in August, but has remained essentially flat in September and October. Individual tests of new completions continue to show type curve IPs, indicating no degradation in new well performance. In a recent pilot program at one of the tank batteries, we observed a 15% increase in production when we lowered the casing pressure at the wells.

We have scheduled 26 pressure reduction projects, accounting for over 1,500 wells and will impact essentially all of the current production in the field, and have begun our pressure reduction work. We expect to finish this work in Q2 of 2012 and expect to gradually restore production along the way as each system is completed. Assuming the similar response to our pilot program, we expect to ultimately see an increase of 2,500 to 3,000 barrels of oil as a result of these projects.

Partially making up for the slower growth rate in the Permian over the last few months is the performance in the Mid-Continent region. Driven by the success of our Mississippian drilling program, we project to exceed our year-end production target for the Mid-Continent region by about 260,000 barrels of oil equivalent.

The Mississippian program has performed beyond our expectations, and 30-day IPs have come in better than the type curve that was generated at year-end 2010. This type curve had a 30-day IP of 244 barrels of oil equivalent per day and an EUR of 409,000 barrels of oil equivalent. The last 119 wells drilled, with at least 30 days production, have averaged over 300 barrels of oil equivalent per day.

Outside of the Permian Basin and the Mid-Continent operations, we project our non-core areas, which include East Texas, Gulf Coast, Gulf of Mexico, the West Texas Overthrust and Tertiary to be under forecast by about 145,000 barrels of oil equivalent, which is less than a 1% impact to our total production guidance. These are primarily gas producing areas. With the exception of one new well completion last January in the Pinon Field, we did not drill in any other wells in any of these areas in 2011, and have no plans to do so in the foreseeable future.

As for 2012, we are maintaining our guidance of 27.7 million barrels of oil equivalent, but given the current constraints on our low-pressure gathering systems in the Permian Basin, we have adjusted our oil and gas allocation to 16 million barrels of oil and 70 Bcf of natural gas, as compared to our previous 2012 guidance, which was 16.5 million barrels of oil and 67.4 Bcf of natural gas.

As we work on our gathering projects in the Permian, we will take out 4 rigs in the Permian and add 2 rigs in the Mississippian. That is, at this time, we plan to average 12 rigs in the Central Basin Platform in 2012. However, we will continue to evaluate progress on our infrastructure projects and make adjustments, as appropriate.

In the Miss play, where we had planned on averaging 24 rigs for 2012 previously, we will now increase that to 26 rigs. We see these changes in rig allocation as essentially CapEx and production neutral at the corporate level for 2012. I will now turn the call over to James for the financials.

Thank you, Matt. Turning now to our financial results, for the third quarter, adjusted net income was $2.8 million or $0.01 per diluted share. Adjusted EBITDA was $169 million and operating cash flow was $144 million or $0.29 per diluted share.

Adjusted EBITDA and operating cash flow are both up 8% over the second quarter, driven by a 15% growth in oil production, slightly higher realized prices, and an improvement in per unit expense measures. This brings our year-to-date adjusted EBITDA to $479 million and year-to-date operating cash flow to $378 million.

On per unit measures for the quarter, LOE of $14.01 per BOE and production taxes of $1.68 per BOE were both below guidance ranges, and all other expense items were within guidance. Capital expenditures, excluding acquisitions, were $468 million for the quarter and $1.3 billion for the year-to-date period.

For the quarter, drilling and production CapEx was up $62 million, due to the increase in the rig count and drilling activity in the Mississippian, as Matt discussed. Leasehold acquisition was down slightly to $75 million compared to last quarter. Recall that we closed our Mississippian Joint Venture on September 28. Therefore, the third quarter drilling and production CapEx does not include the impact of the 13.2% drilling carry on our Mississippian wells.

We remain very active with our capital raising efforts, having raised approximately $1.85 billion of non-debt capital so far this year. Three of these transactions occurred in the third quarter, which resulted in over $1 billion in closed or announced proceeds.

First, in August, we closed the IPO of SandRidge Permian Trust, our second royalty trust, where we raised $581 million through the sale of a 66% interest in the trust. Second, in September, we closed the $500 million Mississippian Joint Venture, consisting of $250 million of cash at closing and $250 million of a drilling carry. Third, we signed the PSA for the sale of our all of our remaining East Texas natural gas properties for $231 million. We expect this East Texas sale to close later this month.

This $1.85 billion of capital raised year-to-date, combined with operating cash flow, fully funds our $1.8 billion 2011 capital budget and leaves an expected surplus of approximately $500 million to fund 2012. Consistent with what we have discussed in the past, we anticipate funding our 2012 $1.8 billion capital budget with a combination of this surplus from 2011, 2012 cash flow from operations, and by utilizing various funding options similar to what we did in 2011, including an additional royalty trust, sales of SDT and PER units held by SandRidge, or additional asset sales.

Importantly, we expect to fund these 2011 and 2012 capital programs without adding debt to the capital structure. Regarding our liquidity and balance sheet, at September 30 we had a cash balance of $325 million, $2.8 billion in senior notes, and no amounts drawn on our credit facility, giving us a net debt balance of $2.5 billion.

At September 30, our LTM-adjusted EBITDA was $675 million, resulting in a net debt-to-EBITDA ratio of approximately 3.7 times. As a result of our capital raising efforts, we reduced our net debt by $400 million since the beginning of the year and expect to end 2011 with no borrowings under our $790 million credit facility and cash on our balance sheet.

Also, in October, we did reaffirm our credit facility, maintaining the borrowing base at $790 million. Our liquidity position remains excellent. As of October 31 we had a cash balance of $225 million, which does not include the proceeds from the pending East Texas sale, and no borrowings under our credit facility, giving us liquidity of $1 billion.

As Matt discussed, we have updated our 2011 and 2012 guidance and you'll find the details for both periods in our earnings release. Keeping consistent with our hedging strategy, we continue to use oils swaps to lock in returns on our oil projects and also provide protection from downward fluctuations in commodity prices.

We continue to add to our hedge position, and since our August earnings call, have added 8.8 million barrels of oil swaps through 2015. This puts us at 78% of our guidance oil production hedge for the remainder of the year, at approximately $88 per barrel, and for 2012, 74% of our guidance oil production hedged at $89.50 per barrel.

In total, we have 39 million barrels of oil swaps through 2015, which lock in $3.6 billion of revenue. Also, in September we used the proceeds from the monetization of some of our out-year oil contracts to eliminate all of our remaining 2011 and 2012 natural gas basis swaps, with only a few basis swap contracts remaining in the first quarter of '13. The details of our commodity hedge positions are outlined in our earnings release.

Let me conclude with recapping the accounting for our 2 public royalty trusts. SandRidge Mississippian Trust 1 and SandRidge Permian Trust are both treated as variable interest entities under GAAP and their production reserves and financial results are consolidated into the financial statements of SandRidge. On SandRidge's balance sheet, you'll see the public's interest in the trust recorded under noncontrolling interest.

On the income statement, the earnings attributable to the public's interest is shown as net income attributable to noncontrolling interest. The actual cash distribution to the public's interest will be in the cash flow statement under financing activities as distribution to royalty trust unit holders.

Keep in mind that we're looking at quarterly and year-to-date noncontrolling interest in our financial statements. That number will include any noncash mark-to-market gains or losses on the trusts.

In our guidance, we have started to include adjusted net income attributable to noncontrolling interest, which will exclude these mark-to-market gains and losses on the hedges. Finally, the actual quarterly impact, the quarterly and year-to-date EBITDA from the trust can also be found in the reconciliation of adjusted EBITDA tables in our earnings release.

That concludes Management's prepared remarks. I would now like to ask the operator to open the line for questions.

(Operator Instructions) Neal Dingmann, SunTrust.

2 questions quick -- I understand, Tom, between you and Matt you talked about the gathering facility and the issues that you are going to have coming there. Just trying to get an idea of how much total capacity needs to be added or pipe, et cetera versus what's already in place?

Sure. Matt can take that one.

A little bit more detail on what those projects are all about. These wells in and around the Fuhrman-Mascho area are very shallow, they're about 4,500 feet deep, so they're very sensitive to pressure. In the past, what we've done, and historically, is we'd either bull plug off the casing or tie the casing into the tubing. And as pressure and as production increases, you start getting a line pack behind your tank batteries back to the wellheads.

So what we're doing now, and we've done this on one tank battery and saw really good results, about 15% increase in production, but we're laying a separate line, and this is a 2 inch poly pipe that we can roll out pretty quickly and tie a separate line to the casing back to the battery. So what it does is it reduces the pressure at the wellhead down to the [purse] and if you get a 10, 20, 30, 40 pounds reduction in pressure, you get more fluid entry into the wells.

Where it's been impacting us the most is on the older wells that were drilled several years ago and as we put on new wells, we pack the line the new wells can certainly produce. But, again, 1 for 1 incremental increase each time you add a barrel on, because an oil well is getting knocked off line. So we really think we can probably finish -- we have 26 projects we're going to roll out and we probably can finish here possibly late Q1, but I think to be safe, we say Q2.

Got it. Great answer, Matt. Just lastly Tom, it definitely appears that in the original horizontal Miss, it looks to me like economics continue to improve. Just wondering, given the improving results, any thought about, with the type, would you increase the type curves here? Secondly, thoughts on how you see, if you're able to comment yet, what your thoughts would be on the new horizontal Miss, how the economics could potentially stack up versus the first?

Sure. In fact, we're in the process of doing reserves, so we'll look and see what our third party engineers are seeing. Internally, we think that we could possibly be seeing a raise because our IP peak rates are higher than they were last year and what really tells about a field is what happens over time. Are the EURs going up or down over time? And now have 3 years worth of projections of which we've gone, or 3 different end of years that we'll be looking to increase each year.

So the Mississippian play continues to be very good. What I don't want to lead you to conclude is that with continually being a better 30-day IPs, that they'll continue to rise up to some point that is unreasonable. We like the 300 to 310 barrel a day IP on the 30-day and that's a fairly efficient well for us.

So we don't anticipate that's going to go to 400 or 500 barrels a day, as some have concluded. But we just make a lot of money drilling these types of wells and we see it all across the play. We're not trying to, today, pick out a core area. So that leads you to the second question you had, is that there was nothing too unique about the idea of where we bought the original Mississippian. The play had a tremendous amount of vertical production, we knew there was oil in place, we knew it was shallow, we know we could dispose of water, and we knew that we were going to be perforating and fracking the same rock that's been produced vertically.

The new area, and obviously we'll talk more about this in the next few months, is the same. You have maybe a little more shallow production, maybe a little bit more oil, and so we like it, and there's just a lot of history. That's the way we see this, and the reason we haven't participated in other plays, it doesn't mean that we don't like other plays, it's just we think there's higher risk in areas that don't have a tremendous amount of production history.

Great answer, guys. Thanks, Tom.

William Butler, Stephens.

In terms of the Permian gathering curtailments, when did those begin, exactly? During the third quarter or as of now?

I'll just let Matt take that one.

It's hard to pinpoint exactly when they occur. They impact us most in the third quarter; however, I suspect that we start seeing degradation in production, as we're adding new barrels on, probably in early summer. And then what happens is, initially it's a wedge effect, as you add on a new barrel of oil, you might see 0.9 and that increase got worse and now it may be 0.1 or 0.2, but I think that's what's causing the production to remain flat.

So we've gone out, and to make sure that our wells are doing all right, we put individual wells on test as we bring on the new completions and there has not been any degradation in the IPs. It's difficult to pinpoint that down, but certainly as you get to a certain point in the pressure and the reservoir just won't give up any fluid entry into your casing, there's nothing to pump out. So I would say early summer, if I had to put a time on it.

Okay. I guess what I was trying to do is translate that curtailment number you gave on a per day basis. What would you say the best way to think about that is?

I think, on average, if you look in the last 180, 200 days, then you probably get 2,500, 2,600 barrels a day, 2,800 barrels a day, something like that.

Okay. Thank you. Are you all seeing saltwater disposal impacting LOE in any way, currently?

No, I think from that standpoint, it's been pretty flat, actually, down a little bit. I think last quarter we had about 10,000 barrels of saltwater that we had to truck around our Permian operations there and that's down to probably half of that now. We still plan on getting that down to basically nothing by the end of the year.

Okay, so in your 2012 cost guidance, there's not really much in the way on the LOE side in terms of saltwater disposal?

That's correct.

Okay. 1 last question is, if you guys were to sell additional royalty trust units, there would be production associated with that. Is that already reflected in the guidance you all have provided? Or would that be additional production like the East Texas asset sale thinking about pro forma that way?

Yes, William. That would be additional, like you're thinking about East Texas. If we did about another trust, we would have a different net income attributable to minority interest and would be selling some PDP and production.

I guess I was considering if you all were selling units of existing in the open market?

Same question there, too. If we did sell some existing units in SDT and PER, then the public's interest would be larger and the net income attributable to noncontrolling interest in the income statement would go up little bit, yes.

Okay. I appreciate that. That's all I've got. Thank you.

Craig Shere, Tuohy Brothers.

3 quick questions -- 1, I think William touched on some of it with the saltwater disposal. It seems to be getting taken care of. But looks like the LOE falling to $14.01 from $14.51 in the second quarter is making a lot of progress. Can you characterize the progress towards fully reversing costs from the electric and saltwater issues, as well as the inefficiencies from the ramp-up in the old Miss that was driving costs of -- what was it -- $3.5 million?

The inefficiencies in the old Miss had us move to $3 million per well. We're seeing some service costs move down in the Mississippian play, but at the same time, we're bringing on additional rigs, ramping up and moving out into -- continue to expand in the play. So, we don't anticipate moving down our cost on the Mississippian play on a cost per well. Then on the LOE, for the Permian, as Matt mentioned, we anticipate continuing to move towards disposal wells versus trucking any water.

Right. The $3 million doesn't include the saltwater disposal. Is that correct?

That's correct. You are correct.

Okay. 2 other quick ones -- I see you broke out the EBITDA for Midstream. That $50 million of EBITDA is obviously going to be growing over time. Do you see potential in monetizing that in any way in addition to the royalty trusts and other property sales?

No, we're not anticipating monetizing any of the service operations yet.

Okay. Can you comment on per acre average costs so far on the 700,000 of new Miss?

No. We'll just be in or under our budgeted $200 million.

Okay. Thanks a lot.

Pearce Hammond, Simmons and Company.

Tom, if you could talk about, you mentioned you want to secure a partner for the new Miss. Do you want to finish getting all your leaseholds in place getting to the million acres before you start that process or have you already started that process? How should we think about timing on that?

We've said I think we will find a partner before the first half of 2012. That doesn't mean that we wouldn't start to discuss this with potential partners today. What we believe now or we know that we're on the course of winding down our leasehold buying, so by the end of the year, we anticipate being at or near where we want to be. There's not much of a way for us to keep from getting to our goal as it stands today. That's how come we're prepared to start talking to potential partners now.

Thank you. What is the status right now of your CO2 contract with OXY? You'd mentioned in the release the Pinon Field. I'm just curious if there's any impact or any possible payments to OXY on that?

There is. It's included in our LOE guidance and then the contract with OXY is a 30-year contract to deliver CO2 to them.

Great. Then finally, how would you describe the service cost environment right now in both the Central Basin Platform, as well as in the Miss?

We continue to see service costs fairly flat across both plays. We think that there are some other ways in the Mississippian project, in particular, that over time we might be able to move down some costs. But today, we're not seeing a service cost inflation in either of the plays, and haven't since we started working there a couple of years ago.

And when you say over time move it down, do think we could start to see the well costs coming down next year in 2012?

No. No. I think that what we're looking at are different ways to complete wells. As we build up a scale in an area, you do become more efficient as you drill more wells in each of the areas. But as long as you're continuing to add new rigs, that offsets the efficiency gain you have on your old rigs.

Thank you very much.

Hsulin Peng, Robert W. Baird.

A quick follow-up question to your considerations for monetization of your trust units. I was wondering if there is a minimum threshold of units that you would like to keep internally? And also, what kind of tax implication can we see from such a sale?

Sure. We have 3.8 million units of SDT and 4.8 million of common units for PER. The SDT units are past their lockup period, those are fully salable. The PER units will be through their lockup in February. Now, that doesn't take into account the subordinated units that we have. We still have subordinated units in both trusts and that represents exactly 25% of the total units of each trust. So while we have a targeted amount we would like to continue to hold, the subordinated units don't convert to common for about 4 more years and the common units are fully marketable now. In terms of tax implications, no, there are no tax consequences for us selling those units.

So there wouldn't be any tax linkage?

Correct, there would not.

Okay. It sounds like you would consider keeping the subunits, so only the common units would be potentially for sale?

That's correct.

Okay. Second question is, I know you mentioned you'll likely get to the 1 million acreage for the new Miss play by the end of the year. Is that when you think you can give us more details about the play, like where is this location and also the economics the end of the year?

Yes. We're targeting the end of the year, yes.

Okay, great. That's my questions. Thank you.

Duane Grubert, Susquehanna Financial.

When you think about the Oklahoma Mississippian going into full development mode, and you're rapidly getting there, you're continuing to experiment at this stage, but if you would conjecture, let's say 5 years from now, what do you think is going to be the biggest difference? And I'll give you 2 things I'd like you to comment on -- 1, do you believe directionally that the downspacing is going to occur and, 2, do think you're ever going to be shooting for higher oil cuts? Do you care about how much water you're producing in your long view?

Last first -- no, we don't care about the amount of water. Actually, in some of the areas where we have the most water production is where we produce the most oil. As long as you're in a depletion drive, both the oil, water and gas deplete at the same amount. So, having more water doesn't bother us. In fact, some of the most permeable rock has the highest total fluid cut. We encourage water production to get the most oil. What I think happens over time, in 5 years, is that this play becomes 1 of the larger plays onshore US and the rig count moves up dramatically, maybe to a couple hundred rigs and we'll be a big part of that.

Yes, I do believe, over time, that we'll be drilling wells closer together. I'm not ready to say today that it's exactly 4 wells per section or not. The worst thing you can do is over-drill a play. I would much rather have 3 wells per section and know that we're spending the least amount of capital to get out the most oil production than to continually try to increase EURs and speculate that things are going to be higher in the future. We'll just take this pretty slowly, but as you see, we've already tested the idea 18 times, so 18 pairs, and it is something we think about, as far as drilling closer.

Then the type curve, you guys say you're comfortable with that 300 to 310 barrel per day number and I respect that, but I'm curious if you have any anecdotal evidence of how wide is the range on the upside? What is the biggest well that you or maybe a competitor has had out there with this type of completion?

I hesitate to say that, because that puts us in with every other person who claims very high wells and don't talk about the overall trend of a play. In fact, I won't. I'll just say we have as high of producing wells as other large plays, but then we also have a lot of wells that don't produce as much. So I would just encourage you to look at 300 barrels a day as a good well.

Okay. Great. Just back to the casing pressure thing 1 more time, was I correct in understanding, Matt, that the solution to the facility constraint is largely going to be casing pressure reduction rather than building new facilities? At least at first?

Yes, largely that's correct. What we're doing, is we'll lay separate lines to the casing, so that, in itself, will reduce the casing pressure. At the same time, we're anticipating a production increase, so we'll have to expand some of our headers that feed into the tank batteries. But yes, basically, you're right on.

All right. Thank you very much.

David Deckelbaum, KeyBanc Capital Markets.

Just a quick question for you, on the Mississippian, did I hear correctly that the gassy composition now is assumed to be 56%?

Yes, that's our anticipation. What we're seeing is that we were fairly correct on our oil type curve, but as we drill more wells, the composition of gas is increasing. We're beating the type curve mainly with gas over oil as we move up from the 244 barrel a day equivalent.

Okay, great. In the Permian, specifically in the Fuhrman-Mascho, just curious to know, can you elaborate at all on what sort of EURs you've booked your PUDs on? And given some of the underperformance there now with some of the back pressure, do you see any risk to any of the PUDs that you've booked at this point heading into year end?

Our type curves are still the same, so what we're seeing is, is it's just a production issue and there's no change in the projected EURs of the wells.

Okay. Preliminarily right now, Midstream and some of the other miscellaneous spend was up $75 million. Does that fully include all of the anticipated spend that's getting Fuhrman-Mascho back up to where you'd like it to be?

A lot of costs in Fuhrman-Mascho will probably roll into next year, but that's incorporated into our 2012 budget. But, in total, we're talking a pretty small amount here. We're probably talking something to the tune of about $15 million, $16 million to get all this stuff done.

Okay. Great. Thank you, guys.

Mark Hanson, Morningstar.

Aside from some of the issues in the Permian, it sounds like things are firing on all cylinders. You've got a good hedge book in place, minimal service cost inflation, several years of inventory. I'm wondering here as you think about the next couple of years, what are the biggest areas of concern for you or some of the biggest threats to achieving your 3-year plan that you've laid out?

We try to hedge in the concerns that we have on the 3-year plan by hedging our oil production, so obviously the biggest issue would be demand for oil in the world. That's why we hedge so aggressively. Then we've hedged the other side of this by not taking into account any gain on the sale of the new Mississippian or any EBITDA from drilling in the new Mississippian. I think we've laid out a plan that we can hit very easily. For me, we've hedged our risk on the 3-year plan.

Okay. Thank you. As I look at the horizontal Mississippian, I think I got my numbers right here. You guys exited the second quarter at about 12.7 thousand Boe per day, you hit about close to 16 at the end of July and you averaged 12.8 for the quarter. I'm just wondering some of the variability over time there. Did you see a reduction at quarter-end that would account for that lower average than I guess the trend would indicate?

No. We see continued growth quarter-over-quarter for the horizontal Miss. We've grown it tremendously this year. I think we had around 53% growth just Q3 over Q2 and we expect continued growth going forward.

Okay. Can you disclose what the current run rate is there?

As far as just production?

Yes, average daily net production.

Yes. I think we're at around 18,000.

Great. 1 more quick question, if you look at the 2012 guidance for per unit lifting costs, it seems to be a little bit higher than I would've expected, given that for the first 9 months, you're at about $14 per Boe. Maybe just some commentary there on potential cost increases?

Did you ask about the Mid-Con?

The aggregate lifting costs there for the Company for 2012 guidance.

Yes, actually, the lifting cost we expect it to be about the same finishing out '11, going into '12, that's going to be pretty flat for lifting costs. We did add some additional dollars per unit just to handle some of the fixed cost contracts that we have out in the Pinon Field. That increased, but from an operations standpoint, we see it being pretty flat.

Okay. Great, thank you guys.

(Operator Instructions) Adam Leight, RBC Capital Markets.

Just a couple follow-ups -- on the Mississippian well results, can you at least address how much variance up or down from that 300 barrel a day well that you're seeing? Is it locational or is it more randomly spread through the play?

Adam, I'm sorry I heard the Mississippian well variance, I couldn't hear your question. I'm sorry.

What's been the spread between the poorer wells and the better wells versus that 300 barrel a day and is it locational or is it spread evenly? Is the randomness even throughout the play?

Yes. I hear you now. The play is a very large stratigraphic play, stratigraphic trap, so it's not like a shale play, it's set up to where there's not really a core area. So within each of the areas we drill, there are good and bad wells. The statistic we can use and can prove, I guess, is that in our first 37 wells, there was 1 that we talked about that would not pay back its cost. On the downside, you have a low rate of return and on the upside you have some extraordinary wells. That's how you continue to have a very high rate of return on the overall play. But there is a wide variance in each of the areas, not in 1 particular area.

Okay. For the rig allocation for the Mississippian, is that all for the original Mississippian or do you -- accounting for some drilling in the new play?

The only thing we've done in the new play is we account for the acreage money we've spent, and we don't account for any sales or any drilling. So all the drilling is accounted for in the original Mississippian.

So on the acreage spend in the third quarter, for the Mid-Con, was that all or substantially all for the new Mississippian?

I don't know exactly where all the -- it includes our Mississippian new acreage bought in the Mississippian, yes.

And that was approximately 200,000 acres from the end of last quarter, am I right on that?

Our last call we were at 200,000 (multiple speakers)

The last announcement, I think, was 500,000. We're fast approaching where we need to be.

Okay, I was just trying to do a little arithmetic there. I will try to ask this question so you can answer it, James. The expectation on timing, given that we're in November already for this next trust, I'm presuming that's a 2012 event?

Yes, we can't comment on specific timing, Adam. But just if you take into account normal 30-day SEC review in that process, it would be really hard to launch something now and get it done in this calendar year.

Okay, great thank you. I'm good.

Dan Morrison, Global Hunter.

Real quick one following up on Adam's question. You had previously said that you hadn't seen a hotspot develop or a core emerge in the play yet? Does that still hold after all the drilling you've done so far?

Sorry Dan, try it again. You're cutting out.

Sorry about that.

There you go. That's better.

Following through on Adam's question, previously you had mentioned that you hadn't really seen a core area evolve or hotspot. Does that still hold after all the drilling you've done so far?

Yes, we see the same type of variability across the play so far.

So, it's consistently inconsistent or consistently variable?

Yes, it's consistently variable, yes.

Got you, thanks.

Richard Tullis, Capital One Southcoast.

Going back to the old Miss play, Tom, what's the actual oil number out of the existing type curve? Is it around 200,000 barrels, a little bit better than that?

Yes, it's right in that range. 200,000, 210,000 barrels on the oil type curve.

So, if you bump up your EURs to match what you're currently seeing, is it your expectation that that oil number stays the same and it's just the gas piece that goes up?

Yes, that's correct. That oil number, I think, will be real close. It may increase slightly, but you should see more of an impact on the gas side.

How will that work if the reserve engineers don't give you any or as much of an increase as you're expecting? Do think that the oil component there, whatever it might be, 200,000 barrels, could decline?

We don't anticipate a decline, based on what we've seen. But you're right, that's up to the third party engineers.

Okay. Are you planning to do any drilling in the new Miss play, say in the first half of '12?

If we find a partner and move forward in the play, but not until we sell some acreage.

Okay, that's all for me. Thank you.

Phillip Jungwirth, BMO Capital Markets.

On your 2012 production guidance, which horizontal Miss type curve are you assuming to derive that? The current one or the one that you think or the increased one that could potentially come by year-end?

Our current type curve.

Okay. So that suggests if you increase the type curve, we could probably see an increase in production guidance, which I guess would be more weighted towards gas than oil, based on what you're saying?

That was a tricky question. We like our guidance as we've stated.

Okay. If you're experiencing constraints in the Fuhrman-Mascho, why wouldn't you be able to move rigs to drill the Clear Fork or some of your other fields in the Central Basin Platform?

We are going to move some of that around. But right now, the Miss is doing very well and we have 800,000 acres in old Miss, not including anything in the new Miss. In the Permian, we have 200,000 acres. With this constraint, it makes more sense to go ahead and reallocate some rigs in the new Miss and continue to drill that program out and hold our acreage.

Keep in mind, we'll drill close to 800 wells. It's not like we're not doing our work in the Permian.

Right. In 2012, do you still think you can drill 800 wells? Or what's the number of gross wells we should assume for '12, based on the lower rig count?

Yes. I got that. In 2012, we're modeling about 760 wells in the Permian and about 380 wells in the Mid-Continent producers.

Great. Thanks, guys.

Mike Breard, Hodges Capital.

In your original Mississippian play, you ended up buying a lot more acreage than you had originally expected because the lease costs were still low. Are you satisfied to stop at 1 million in the new Miss or would you raise that considerably if lease costs remained cheap?

We are satisfied with 1 million, and that comes with anticipating in a 5-year plan how you can effectively drill out the play.

Okay. 1 other question, are you looking for predominantly an oil company to joint venture with or money manager type or does it make any difference?

Actually, doesn't make any difference, we anticipate it will be more of an oil company.

Okay, thank you.

Craig Shere, Tuohy Brothers.

Very quick, Matt, I thought I heard you say that the costs for alleviating the pressure issues in the Central Basin Platform are only maybe $15 million, $16 million. If I'm reading the delta between the third quarter and second quarter releases correctly, total Midstream and other CapEx is rising $35 million between the 2 years. Can you explain where the other $20 million is coming from?

Sure, as we expand our Mississippian drilling next year, this year we'll probably drill somewhere about 170 to 175 Mississippian wells. Next year, we're looking at 380 Mississippian wells. We have more costs going to facilities in the Miss as well, probably primarily in electrical infrastructure.

Okay. So the things like electrical infrastructure and such, if we think a couple years out, how much of this can really be monetized eventually? Is it just gathering lines or how do you think about Midstream as it grows from $50 million EBITDA and maybe doubles over time?

Like Tom mentioned earlier, at this point in time, at least, we have no plans to monetize our Midstream assets or any infrastructure facilities. It's just too integral to our development plan at this point.

Okay, thanks again.

Ladies and gentlemen, that does conclude today's Q&A portion of the call. I would now like to turn it back over to Tom Ward for closing remarks.

Thank you for joining us, and we look forward to talking to you in the interim and at the next call.

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