SandRidge Energy, Inc. (SD) Q4 2012 Earnings Report, Transcript and Summary

Good day ladies and gentlemen, and welcome to the quarter four 2012 SandRidge Energy earnings conference call. [Operator Instructions] 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, operator. Welcome everyone, and thank you for joining us on our fourth quarter and fully 2012 earnings call. This is James Bennett, Chief Financial Officer, and with me today are Tom Ward, Chairman and Chief Executive Officer; Matt Grubb, President and Chief Operating Officer; and Kevin White, Senior Vice President of Business Development. Keep in mind that today's call will contain forward-looking statements and assumptions, which are subject to risks and uncertainties, and actual results may differ materially from those projected in these forward-looking statements. Additionally, we'll make reference to adjusted net income, adjusted EBITDA, and other non-GAAP financial measures. A reconciliation of any non-GAAP measures we discuss can be found in our earnings release and on our website. Please note that this call is intended to discuss SandRidge Energy and not our public royalty trusts. Finally, earlier this morning, we filed our Form 10-K, where you can find additional disclosures and information. Now let me turn the call over to Tom Ward.

Thank you, James. Welcome to our fourth quarter earnings and operational update. We have now surpassed consensus estimates for our earnings per share in each of our last four quarters, and EBITDA and production in three of the last four quarters, including the fourth quarter of 2012. The Mississippian Play continues to have strong production growth, coupled with lower cost, which is driving the better than anticipated results. We grew our Mississippian production to 35,900 BOE per day in the fourth quarter, which is a 19% quarter over quarter increase, and up from 15,500 BOE per day a year ago. We drilled 10 wells in the fourth quarter, with 30-day production average above 800 barrels of oil equivalent per day. These wells were located in Alfalfa, Grant, and Woods Counties, Oklahoma. Of these 10, five were above 1,000 barrels of oil equivalent per day, and our best well was above 1,500 barrels of oil equivalent per day for the 30-day average. These 10 wells produced an average of 68% oil. We did not break out the liquids stream until after the start of 2013. We’ve also announced the closing of our Permian sale, which has us in the strongest financial position in the company’s history, plus the Gulf of Mexico continues to perform above our projections. As we enter 2013, SandRidge has two key goals: spending at or below our capex guidance and meeting our production guidance. These goals are aligned with our core focus to drive rates of return higher in the Mississippian, which we will achieve through improving the average production of new wells, leveraging our infrastructure, and continuing to reduce both operating and capital costs. 2013 is a pivotal year for SandRidge. We have a strong cash position, and our net debt to EBITDA ratio is approximately 2x. This strong liquidity will let us sharply focus on delivering superior rates of return from the Mississippian Play. We have grown our production in the Miss to nearly 36,000 barrels of oil equivalent per day from a standing start in 2010, with an average of only 15 rigs. Our growth will continue as we ramp up to our ultimate rig count of 36 rigs by the end of 2013. Our drilling efficiencies have allowed us to reduce the ultimate rig count from the 45 rigs that we had previously projected. In 2012, we spent extensively on our infrastructure systems, which provide significant competitive and economic advantages to SandRidge in the Mississippian. Because of the infrastructure development, we are optimizing our system utilization and will drill 80% of our wells this year within our existing system. By doing so, we’ll be able to control infrastructure capex and grow our production with development wells. The salt water disposal system we have built can handle 1.6 million barrels per day of salt water, and we are currently injecting approximately 700,000 barrels of water per day, all of which is produced only from SandRidge operated wells. Effectively disposing produced water in the Mississippian is critical to controlling expenses. By developing our own disposal infrastructure, we’re able to save over $2 per barrel of water relative to trucking those water volumes. We’ve been focused on eliminating our dependence on trucked water, and now we’re able to exit the year trucking less than 1% of our produced water volumes, resulting in considerable LOE savings. We’ve invested over $450 million in the system. As James will discuss, we believe there is a strong market demand for water disposal assets, and we are currently evaluating the merits of monetizing our system. The savings we realize from our efforts to develop and optimize our infrastructure, coupled with the lowest per-well drilling and completion costs and lease offerings expenses in the industry is a primary reason that our Mississippian economics are so good, and why we’ve been able to secure excellent partner to share in those benefits for many years to come. Access to affordable electricity is also critical in the Mississippian, given the high power demand to run electrical submersible pumps. We have worked to reduce our dependence on diesel generators by tapping into the local power grid. We’re able to access power from the grid by constructing our own distribution lines to substations. We began 2012 with approximately 35% of our wells using power from generators. We successfully reduced that ratio to 13% by year end. Electricity from the grid results in up to $100,000 of savings per well per month, compared to running diesel generators. We choose to implement electrical submersible pumps because of the increased rates of return they achieve by producing approximately three times the fluid that a gasless system can. In the first 77 wells, with over 30 days of production, we’ve increased the rate of return up to 86% per well using a $3.1 million well cost. We anticipate drilling wells for $3 million or below in 2013, which would move these rates of return up to 95%. Our company’s clear strategy has always been focused on rates of return versus ultimate production numbers. That’s the reason we deliberately chose the Mississippian formation and projected our EURs of 500 MBOE in 2009. We knew we were in an active oil system that can be improved by finding more oil and by spending less money to enhance rates of return. These are the two ways to drive rates of return higher. Every day we focus on both. In November of 2012, we shifted our type curve to an average of 422 MBOE per well, which is down from 456 MBOE that we used earlier in 2012. The change in November that we made internally did have an effect on the oil in the curve where rates of return do matter. And we adjusted the rate of return down by about 20 points at that time. The discussion today around whether we find 369 MBOE or 422 MBOE has very little effect to the rate of return, because this changes at the end of the life of the well. It’s important to note that 90% of the rate of return of a Miss well is recovered in the first five years. In fact, we now have increased our projected rate of return per well since our November guidance by lowering well costs and improving our natural gas contract. As you see by our increased Mississippian guidance for 2013, we continue to anticipate finding as much or more oil and natural gas as we did in November. But we also acknowledge the different opinion on the end of life of the wells. We’ve said from the outset that we believe we’ll find wells in the Mississippian with a range of 300 to 500 MBOE per well. Even though we’ve taken down the back end of the curve, we remain very comfortable with any outcome in this range. We do take comfort in the historical production of the 17,000 vertical wells that have been drilled in this same formation since 1930 that show the very shallow end of life decline that we have been projecting. As I mentioned, our rate of return has been revised upward, by cutting the cost of our wells down to a fourth quarter estimate of $3.1 million per well from $3.6 million per well in the first quarter of 2012. We project that we will move our well cost down to below $3 million by the end of 2013. We have achieved similar cost trends in the LOE in the play, where optimization of our saltwater disposal and electrical infrastructure has resulted in a 43% decline in operating costs over the course of 2012. The rate of return will also be enhanced by our new contract with Atlas, beginning with new wells in 2013. This percentage of proceeds contract will move our liquids from the natural gas stream into the liquids stream. Our oil production has stayed between 43% to 50% since the first wells were brought online in 2010, but now our new production stream is divided into 60-70% liquids depending on which part of the field we drill in. The contract will not change our 2013 guidance, but will start to have an effect in 2014 and beyond. There have been several tests of new formations in Grant and Garfield Counties, Oklahoma. These tests look very promising, with wells producing between 350-1,000 BOE a day from the middle Mississippian and the Woodford Shale. These are two new zones that we’ve not extensively drilled before. We’ve watched these wells for over 200 days, and can now project that nearly 350,000 additional acres in Oklahoma can be targeted for multiple pay potential, where we control over 400 sections in areas where the upper Mississippian was not as prospective. Dave Lawler will address this new potential more at our analysts day. Our financial expectation for this year is to be able to clearly define a funding path through 2015 that will allow us to move our Mississippian well count up to 675 wells beginning in 2014, while maintaining a balance between growth and leverage levels. Clearly with the Miss performing as it is, we will experience strong production and EBITDA growth over the next two years. We have several avenues which will clearly allow us to continue this growth in the future, such as monetizing our salt water disposal system, selling additional units in our royalty trust, and finalizing our last JV on our Kansas acreage. A combination of any of these will give us clarity for funding capex all the way through 2015. We also continue to have a good hedge book. We’re now hedged approximately 85% on our projected 2013 oil at $98.29. This represents more than 80% of our projected revenue this year. We also have more than 15 million barrels of oil hedged in 2014 and more than 8 million barrels hedged in 2015, while our natural gas [borrowings] remain unhedged. We’re very pleased to close 2012 so strongly and our management team is even more optimistic about 2013. I’ll now turn the call over to Matt.

Okay, thanks, Tom. This morning I will talk about year-end and fourth quarter production performance, year-end reserves, 2013 capital spending and production guidance, Mississippian drilling and operating costs, and the year-end type curve and well head economics. I do want to remind everybody that we will be discussing all these items again, and in much more detail, at our analyst day presentation next Tuesday. Starting with production, we finished 2012 with 33.6 million barrels of oil equivalent. The production [unintelligible] was 18 million barrels of oil, including NGLs, and 93.5 Bcf of natural gas. That is 54% oil, including NGLs, and 46% natural gas. In the fourth quarter, we produced a record 107,000 barrels of oil equivalent per day for a total of 9.8 million barrels of oil equivalent, which is nearly 4% higher than the third quarter and the split was about 51% oil, including NGLs, and 49% natural gas. With respect to the Mississippian Play, we produced 10.1 million barrels of oil equivalent in 2012, or about 163% more than we did in 2011. The production split was about 45% oil and 55% natural gas. We wrapped up 2012 with an especially strong fourth quarter performance in the Mississippian, averaging about 36,000 barrels of oil equivalent per day. This is a 19% quarter over quarter production growth, with running only one more rig in the fourth quarter than we did in the third quarter. Natural gas liquids accounted for about 2% of the total liquids production in the Mississippian in 2012. However, with an enhanced percent of proceeds gathering and processing agreement that we recently executed with Atlas Pipeline, we will now be able to capture incremental NGL volumes on new wells that come online as of January 1, 2013. The new contract will certainly help us realize more total liquids, but more importantly, it’s an overall value enhancement to the play. This contract covers whole or parts of 11 counties in northern Oklahoma and southern Kansas, and will impact nearly 90% of the wells drilled in 2013. Our 2013 estimated capital spending is $1.75 billion. This is about 20% lower than our 2012 capital spending of $2.17 billion, and the guidance is consistent with what we had previously stated at our third quarter call last November. About 75% of the 2013 capital budget goes to developing the Mississippian Play. This includes our plan to drill and complete 581 horizontal producers, 74 disposal wells with all associated water gathering facilities, electrical infrastructure, and lease hold maintenance. Outside of the Miss Play, we are looking at a budget of $200 million in the Gulf of Mexico and $140 million in the Permian Royalty Trust. The plan in the Gulf of Mexico is to keep production essentially flat, drilling low-risk development projects and recompletions. It should be noted that our land spending has significantly reduced over the past couple of years. In 2011, we spent about $50 million in land, $190 million in 2012, and we expect to spend about $100 million in 2013. The 2013 production guidance is 34.3 million barrels of oil equivalent. This is about 16 million barrels of oil, including NGLs, and 110 Bcf of natural gas, or 47% total liquids, and 53% natural gas. The estimated liquids production in 2013, after the effect of the Permian sale, is 89% oil and 11% natural gas liquids, which is about the same as 2012. Adjusted for major acquisitions and divestitures, the 2013 production guidance represents a year over year total production growth of about 18%. The oil growth, including NGLs, is 22%, and 16% in natural gas production. We expect another year of strong production performance from our Mississippian Play in 2013. We produced 4.6 million barrels of oil and 33 Bcf of natural gas, for a total of 10.1 million barrels of oil equivalent from the Miss in 2012. For 2013, we are projecting 8.3 million barrels of oil with NGLs, and 55.5 Bcf of natural gas, for a total of 17.4 million barrels of oil equivalent. This is a year over year production growth projection of 78% for oil and NGLs, 68% for natural gas, and a 72% increase in total barrels equivalent. Moving to the year-end reserves, please turn to page three of our slide presentation for the conference call. We ended 2012 with proved reserves of 566 million barrels of oil equivalent, and associated total proved PV-10 is $7.5 billion. As compared to year-end ’11, this is a 20% increase in reserves volume, and a 9% increase in reserves value. When adjusted for asset sales and production, reserves growth is 37%, and value growth is 43%. Year over year oil reserves growth was 35% and 62% when adjusted for sales and production. The proved developed drilling finding cost was $21.68 per barrel equivalent, and the all-in proved developed finding cost, including lease hold and acquisitions, was $24.02 per barrel equivalent. The proved developed drilling finding cost for the Mississippian was $13.91 per barrel equivalent. The all-in reserves replacement, including revisions, was 454%, and finally, we had negative revisions of 112 million barrels equivalent, of which 88% of the revisions was due to low natural gas pricing. I will now talk about the Mississippian well costs, the year-end type curve, and our expectations for well head economics. We continue to be very excited about the Mississippian Play, along with the long term growth opportunity and value that it offers to our shareholders. We have said from the beginning that this is a low risk play, and one that could consistently deliver EURs in the range of 300,000 to 500,000 barrels equivalent per well. We have been executing on a strategy of creating value and steadily improving our cost structure in both capex and LOE through our up-front commitment to build and operate our own water gathering and disposal systems, as well as electrical infrastructure and our continuous efforts to reduce drilling and completion costs. The Mississippian is the lowest-cost horizontal play of scale, and we set a goal early on to drill and complete horizontal Mississippian wells of 4,500 foot laterals in the range of $3 million. Please turn your attention to page four of the slide presentation. In this slide you will see a very positive drilling and completion cost trend in 2012. We were able to reduce well costs by 14% from $3.6 million in Q1 to $3.1 million in Q4 of 2012. The $500,000 savings per well were primarily a result of faster drilling times. As you can see, the spud to spud time progression went from 27 days per well to 21 days per well during the year. And also, service costs have continued to come down, particularly in the area of hydraulic fracturing. We now believe that we can get drilling and completion costs to $3 million or below by the end of 2013, and we will discuss with you several new cost savings initiatives underway that we are very excited about at our analyst day next Tuesday. With respect to LOE, please turn to page five. Now that we have critical mass of water disposal wells in operation, and an expansive network of water gathering pipelines and electrical infrastructure in place, we were able to realize significant operating cost savings over the past year. Our LOE in the Mississippian was $13.38 per BOE in Q4 of 2011, and we ended the year about 43% lower, at $7.65 per barrel equivalent in Q4 of 2012. LOE savings were driven primarily by reduction in truck water volumes and the number of wells operating on diesel generators. Our truck water volumes peaked at around 8% in Q1 2012, and were reduced to less than 1% as we exited 2012. Also, our producing well to disposal well ratio has steadily increased over the last couple of years, showing continuous improvement in our operating efficiency. At the end of 2011, we were at 3.4 producers to 1 injector. We exited 2012 at 6.4:1, and we anticipate to exit 2013 at about 8:1. Our goal is 10:1, and we are rapidly progressing in that direction. Also contributing to LOE reduction, we had 35% of our wells on diesel generators in January of 2012. As a result of our early commitment to electrical infrastructure, we were able to exit 2012 with less than 10% of our wells on diesel generators. Our goal is to have substantially all wells off of diesel generators by the end of this year. Next, I will discuss the Mississippian type curve and drilling economics. Our year-end type curve, including NGLs, is 369,000 barrels equivalent. This is 167,000 barrels of total liquids, of which 107,000 barrels is crude oil and 60,000 barrels are NGLs. Natural gas recovery is expected to be about 1.4 Bcf at the well head, and about 1.2 Bcf at the tailgate of the plant after shrink. I should also note that NGL recovery in the year-end model assumes 2012 averages in which the plants were in ethane rejection mode parts of the year. Assuming full ethane recovery, our Mississippian curve would increase by another 27,000 barrels of NGLs to 194,000 barrels total liquids. The year-end type curve was developed from a production match of 644 PDP wells and the oldest wells now have about three years of production history. These wells span about 230 miles across 12 counties in Oklahoma and Kansas, and there is a tremendous amount of value due to scale and magnitude of the resource potential in this play. Now to elaborate a little more about the November type curve and the year-end type curve, please go to page six of the presentation. On our Q3 call last November, we projected an EUR of 155,000 barrels of oil and 1.7 Bcf of natural gas. And at that time, we had not executed our contract with Atlas, and so NGLs were not included. On page six, the red curve is the gas, and the green is oil. You can see that the November and year-end curve match and projections for both gas and oil are very similar and are both a good fit the actually oil and gas production data. First, looking at the type curve match for gas, we could easily argue that the actual gas production is trending higher than both November and the year-end projections, which gives us comfort that we could outperform the gas production forecast. So now let’s look at the oil curve. While the difference in the ultimate oil recovery between the two curves is 45,000 barrels, keep in mind that this is spread out over a period of about 50 years, or about 2.5 barrels of oil per day. The cumulative difference in oil production in the first five years between the two curves is 9,500 barrels, or about 5 barrels of oil per day. However, if you would look at the table at the top of page six, now that we are capturing NGLs, the year-end type curve is actually 4% higher in the total production in the first year than the November type curve, and cumulative production after five years is only a difference of about 5%. Moving to page seven, to talk about drilling economics, the most important thing to understand in all of this type curve discussion is the impact on rates of return. Looking at the table at the top of page seven, you can see the rate of return of sensitivity to well costs for the two curves. Assuming $3.1 million for drilling completion costs, the rate of return is 57% for the November type curve and 50% for the year-end type curve. You can also see in the slide that about 90% of the rate of return is generated in the first five years of production, and what happens beyond that has little impact on the economic outcome. This is due to low drilling and completion costs, relatively high IPs, and particularly high liquids production on the front end of the hyperbolic curve. Also, as we continue to have cost improvements, we may achieve even higher rates of return than we had with the previous type curve. For example, referring back to the table in the upper left of page seven, at $3.2 million, the November type curve delivers 53% rate of return. At $3 million, the year-end type curve delivers 55% rate of return. With that said, cost reduction continues to be our primary focus. Another opportunity to outperform the type curve and enhance value comes as a result of our water disposal and electrical infrastructure expansions over the past couple of years. We are now able to accelerate installation of electrical submersible pumps, or ESPs, in our Mississippian wells. Please turn your attention to page eight. This graph shows the performance of 77 wells on ESPs that had at least 90 days of production at year-end 2012. As you can see, while early, these wells have outperformed the year-end curve for oil and gas. Even if we assume no improvements in EURs, but only acceleration of production, you can see the tremendous increase in both rate of return and present value across all cost scenarios. And in 2013, we plan to install 300 to 350 ESPs. In summary, even though the type curve has changed in the last couple of years across this very large play, the range of the difference in EURs and economic outcome have not changed our view or our business plan for long term growth and value creation around the large Mississippian land position, and especially now that we have demonstrated our ability to drive down cost on both capex and LOE. Finally, let’s look at page nine of the presentation. As you can see, we have had remarkable quarter over quarter production growth in the Mississippian, dating back to the beginning of 2010. We averaged nearly 28,000 barrels of oil equivalent per day in 2012, and with an exit rate of about 36,000 barrels equivalent per day in the fourth quarter of 2012. And now we are expecting another great year in 2013, as indicated by our 72% year over year projection growth. With that, I will now turn the call over to James to discuss our Q4 and year-end financials.

Thanks, Matt. As Tom discussed, and as you can see from our press release earlier this week, we closed on the sale of our Permian Basin assets for $2.6 billion in cash. When we announced the Permian divestiture in November, we stated that our intent was to use the proceeds to fund the development of our Mississippian assets and for debt reduction. To meet that goal, this week we announced the redemption of $1.1 billion of long term debt. This will leave us with a December 31 pro forma debt balance of $3.2 billion and net debt of $1.5 billion. With the proceeds from this sale and associated debt reduction, our capitalization, liquidity, and leverage levels are in the best position in the company’s history, which puts us in a very favorable spot to execute our Mississippian drilling plans. Now turning to the fourth quarter results, this was a strong quarter with continued production growth from our Mississippian Play and improvements on the cost side, which led to beating consensus estimates in all categories. Production for the quarter averaged 106,800 barrels of oil equivalent per day, a 4% increase in sequential quarterly production and a 60% increase over the comparable 2011 period. The Mississippian continues to be the driver of this production growth, averaging just under 36,000 BOE per day for the quarter, a 19% sequential increase. In the quarter, we continued to benefit from our commodity hedge program, realizing $39 million of gains on our oil and natural gas hedges. These gains increased our realized oil price by almost $10 per barrel from $81.61 to $91 per barrel. The combination of Mississippian production growth, a strong hedge position, and improvement in lease operating expenses raised adjusted fourth quarter EBITDA by 7% to $318 million, up from $297 million in the third quarter. Full year adjusted EBITDA was approximately $1.1 billion, and cash flow from operations was $915 million. Recall that adjusted EBITDA and adjusted net income excludes certain one-time items such as unrealized gains and losses on commodity hedges, one-time costs, and asset impairments. All of these items are outlined in our non-GAAP reconciliation. Regarding asset impairments, in the fourth quarter we wrote off $315 million of intangible assets and gas processing facilities. This noncash writeoff consisted of $235 million of goodwill related to the Arena acquisition and $80 million related to our legacy CO2 processing plants in the Pinon field. Now that the Century plant is complete, use of these legacy plants to process gas will be minimal therefore, we wrote off most of the book value of these assets. Turning to expenses, LOE continues to trend down, as our operation team focuses on cost reduction and we achieved greater economies of scale in the Mississippian Play. In the Mississippian, we’ve lowered our LOE to under $8 per BOE, down from over $13 in the fourth quarter of 2011. We’ve also seen improvements in our Permian Basin and offshore LOE. In the fourth quarter, we began to accrue costs associated with the CO2 underdelivery at the Century plant. This expense totaled $8.5 million, and is reflected in Q4 lease operating expense. For the full year 2013, we estimate this same expense will be between $30 million and $36 million, all of which will be accrued in the fourth quarter LOE and is also included in our 2013 guidance. G&A expense for the quarter does include $28 million of one-time costs related to legal settlements and consent solicitation expenses. Excluding these one-time items, total G&A was $5.61 per BOE for the quarter and $5.92 for the full year, right in line with our guidance range. Capital expenditures for the quarter totaled $500 million, down from $560 million in the third quarter, due to a reduction in drilling on our Permian Basin assets, continued ramp down on our lease hold purchases, and further improvements in our Mississippian drilling costs. For 2013, we’re projecting capex of $1.75 billion, consistent with the 2013 guidance we put out in November. In terms of major changes from 2012 to 2013 capex, first, with the sale of the Permian, our 2013 drilling in West Texas is limited to our Permian Royalty Trust. Second, a decrease in our land purchases from just under $200 million in 2012 to $100 million in 2013, and third a decrease in infrastructure spending as we focus on the development of the plays where we have existing infrastructure in place. On the balance sheet and liquidity, at year-end cash was $300 million, our $775 million revolver was fully undrawn, and we had $4.3 billion in total long term debt. However, with the closing of the Permian sale, let me walk through the year and balance sheet items pro forma for the impact of the divestiture. Concurrent with the closing, we initiated a make whole redemption of our 2016 and 2018 bonds. This will reduce our debt by $1.1 billion, and we expect the redemption to close by the end of the first quarter, bringing our pro forma year-end debt balance down to $3.2 billion and our net debt balance to $1.5 billion. At year-end, our pro forma adjusted EBITDA, which is pro forma for the impact of the Permian and tertiary divestitures and offshore acquisitions, was $748 million, giving us a net debt to EBITDA ratio of 2x. In terms of liquidity, after applying $1.1 billion towards debt reduction, our pro forma year-end cash balance is approximately $1.7 billion and liquidity is $2.5 billion. For our 2013 and 2014 capex funding plans, with liquidity of $2.5 billion, we have more than funded the shortfall between our 2013 cash flow and $1.7 billion capex budget. In terms of funding through 2014 and 2015, we have several options at our disposal, and we will be working on these in the coming quarters. This would include a joint venture on our Kansas Mississippian acreage, where we have 1.3 net acres, sale or other monetizations such as creating an MLP of our salt water disposal midstream business, and the potential sale of $650 million of royalty trust units we hold. Finally, if for some reason these or other funding options are not available to us, we always have the ability to reduce our capex to be closer to spending within our cash flow. In terms of our salt water disposal business, at year-end ’12 we had approximately $400 million invested in the system, and that number will increase to $650 million at year-end 2013. The system currently has 116 disposal wells, 700 miles of gathering lines, and 1.6 million barrels a day of disposal capacity, we believe making it the largest water disposal system in the country. Our intent is to spend most of this year building out this system, to be in a position to monetize this asset late this year or early next. We believe that this is a valuable and strategically positioned midstream asset, and we’ll evaluate the right path forward to unlock the most value while also maintaining operational flexibility. That concludes our prepared remarks. Operator, please open up the line for questions.

[Operator instructions.] Your first question comes from the line of Neal Dingmann from SunTrust. Please proceed.

Tom, for either you or Matt, just wondering, you outlined in the press release, just looking first at the Gulf then we’ll go to the Miss. Just looking at the Gulf, you mentioned about the number of wells drilled, and then the numerous recompletes you had for the year. Just wondering, in the budget, if you’re going to do as many recompletes this year and just your thoughts - I know you don’t normally break out production in each area, but your thoughts about keeping production rather flat this year in the offshore.

In 2013, keep in mind that the $200 million budget for the Gulf of Mexico is fungible between drilling and recompletions and any kind of small bolt-on acquisitions we may have opportunities to look at. One acquisition we did last year, around $40 million, we bought some assets from Hunt that actually performed really well, and we doubled the production since we bought that and closed that back in June. So going forward, in 2013, we’re still maintaining a budget of $200 million, and the recompletions will probably be about in the low 20s. We have probably 20 to 21 recompletions and we’re looking at probably 7 or 8 wells that we could possibly drill next year. And that’s meant to maintain kind of flat production year over year.

And then just turning to the Miss, obviously there’s a lot of concern that - and you addressed on the type curve just the difference between the earlier and further out - again, remind us, how often will this be updated? I guess remind me number one, how many wells is this based on, and then number two, kind of incorporate that second slide that shows the ESPs. How long do you keep these ESPs on, and again, if it will play into the type curve?

In our slide presentation on page six, it gives you a pretty good visual of the type curve for both gas and oil. And so you can see in this type curve that it’s very similar in the two curves, but because these wells are such long life, they do produce a large delta, particularly in oil, where we’re talking about 45,000 barrels spread out over 50 years. It’s only a few barrels a day, and doesn’t really impact rate of return. But as far as the type curve, we typically don’t put out a new type curve until the end of the year. So we won’t expect to see another type curve here until the end of this year. But I think the good thing is that this type curve now has developed over a well base of 644 data points, and some of these wells are now going on three years old. So I think we feel pretty good about the type curve being in the range that we’re showing here.

And lastly, Tom, just strategically, you do obviously have a solid financial position, don’t necessarily need to sell acreage, but just your thoughts on strategy for the remainder of this year. Do you see yourself shedding any of the horizontal Miss?

Sure, and I’d also say that remember the type curve is those 600 wells are scattered over 200 miles, and where our goal is always to have a bell curve of production and we want to move the mean of the production to the right. So as we drill more wells, you drill better wells, around the wells that have been drilled. So even though a type curve is out here, we tend to be able to beat the front end of the type curve, because we’re drilling better wells as we drill more. Then our funding plans, now that we have ourselves basically funded through ’14, we’re looking for ways to fund out through ’15, and we like to keep ourselves about two years in advance if we’re going to be out spending cash flow. So James has mentioned that we have several ways of funding. One of those is additional sale of acreage around a JV. Now, keep in mind that acreage in the Mississippian, there’s so much acreage, there are around 20 million acres just in what we have mapped, that acreage itself is not worth very much. So remember we spent about $200 per acre to put together our acreage position. So why is it that we can get some multiple of that with a JV partner? Well, it requires you to have infrastructure, so if other parties don’t have the infrastructure that we have, obviously that’s worth something. We’ve spent $450 million so far. We’ll be overview $650 million in infrastructure by the end of the year. Drilling costs also matter, and if you’re going to do a JV. We average about $1.1 million per well less than the average of our peers. Well, we will save over $300 million this year net to SandRidge, just from the average of our peers in drilling wells. So whenever you’re selling acreage, you’re really not selling acreage, you’re selling an enterprise. You’re selling the ability for a joint venture partner to come and work with us for decades, and that’s what gets priced into price per acre. But that’s how come you can have different amounts from different players in this particular play. And remember, it is a niche play, where infrastructure and costs are very, very important.

The next question comes from the line of Charles Meade from Johnson Rice. Please proceed.

I want to try to drill down a little bit more on the type curve. And thanks for giving us the data on what went into it. I believe it was 644 wells, 12 counties, 200 miles. But if I look at your map, it looks to me that you’re oversampled, you know, versus the way the whole play is going to work out. You’re oversampled really in Woods, Alfalfa and Grant Counties. So is there an argument to be made that really the type curve you have is a type curve for those counties more than a type curve for the play as a whole?

Yeah, look, Charles, when we do a type curve, we put every well we drill in there. And so we’re not trying to focus on any kind of sweet spots or [unintelligible] areas. Every well that we drill that came on production is in the type curve. And so certainly the wells in Alfalfa, Woods, and Grant would dominate the type curve, just because we have more wells drilled in those counties, and that’s where we started the play. But overall, statistically, you can find these types of wells all over the counties we’re drilling.

I was going to mention one thing on that. Rodney will be addressing this also on the analyst day, going through the wells we’ve drilled. And in each county, we have good wells. So there’s a lot of speculation that one area is not good, other areas are good. But in each of the counties, including Alfalfa County, where we have by far the most rigs working today, we drill some wells that aren’t as good as in other counties. Now, we continue to keep a lot of rigs working there, and it’s a very good place to drill, but we think we can duplicate that across the play, and Rodney will spend a lot of time going over that at the analysts day. Sorry, I interrupted Matt.

No, I think Tom covers it. I was just going to say, you take an area of a township, and kind of move this thing around in all these 12 counties that we drill, statistically you’d probably see a similar type of curve. All I’m saying is that this curve, I think, is representative of the areas we’re drilling.

Right. So it’s exactly representative of what you drilled, and I guess it’s not representative of where you haven’t drilled.

What I’m saying is it’s representative in a large area of 12 counties. If you drill enough wells in any of those counties, you would expect this kind of outcome.

Got it. And then onto the same thing for the ESP type curves, the wells you put on ESPs. Are those in any one particular geography? Did you guys pick, for example, just Alfalfa to do those? Or is that really a fair sampling across all the wells you’ve drilled so far?

They’re across the play, where we can put in electrical systems. So it’s more defined about how quickly you can put in electrical system to get in the ESP, rather than one particular spot.

And the difference on the gas, is that because ESP, you don’t have to use fuel gas for the compressor? Is that why the gas curve goes higher?

Well, the gas production curve is higher because you’re instantaneously lowering the bottom hole flowing pressure of the wells. But typically these ESPs are running on either generators or electricity that we generate.

And then the last question, and this may be something you want to push off to analysts day, but what do you think the prospects are for truncating the lowest part of your bell curve, or translating that? What are the prospects for not drilling the low wells?

Well, what you see over time, with us drilling 600 wells, is that the initial production over time has gotten better. Even as we step out. Last year was really the year that we did more of a step out in 2012, and built out our infrastructure system, and now we’re drilling 80% of our wells as development wells within the infrastructure system where we do have a lot of data. So you have your development of wells, you’re only using 20% as extensional wells, and spending less, because logistics are better, where you’re closer to your other wells that you’re drilling, and you have more data. And what we’re seeing is we’re drilling better wells because of that, and that’s why we beat our production in the fourth quarter. And I think that’s why we’ll continue to do that.

The next question comes from the line of James Spicer from Wells Fargo. Please proceed.

Just a couple of questions for clarification first. Can you tell us what the premium is that you’re paying to take out the 9 7/8 and 8% bonds?

Yes, we’re doing a make whole so it comes to about 104 and 105 roughly for those bonds, respectively. It’s a [P plus 50] make whole.

And what’s your borrowing base pro forma for the Permian sale?

Our borrowing base right now is $775 million. We don’t anticipate any change in the borrowing base, pro forma, for the sale. We have our regularly scheduled spring bank meeting late in March, and we believe our revolver will stay the same, at $775 million.

And then finally, you made the comment that you believe you’re fully funded through 2014 currently. I guess first of all, can you just clarify that you’re assuming both a combination of cash on hand as well as revolver availability there? And I assume you’re thinking about a similar capex in 2014 to 2013? Would you say that?

Yes, it does include about a similar level of capex, and we’re assuming in there the cash on hand, $1.7 billion, and then the $775 million revolver, so about 2.5 of liquidity right now.

The next question comes from the line of Duane Grubert from Susquehanna Financial. Please proceed.

I guess the shock to a lot of people today is when they look at your type curve on page six, and it goes from 152,000 barrels in November to the 107,000 in year-end ’12. I just want to make sure I understand your communication on this. It seems that you’re saying the change in the type curve is the driver here, and the majority of those barrels are in the out years. So I wish you guys would just comment a little bit on how do you get confidence in changing your out year curve to that degree, when no well is older than, say, three years so far?

I’ll start, and Matt can always add to this. Personally, I believe that we’re being very conservative, because we have 17,000 vertical wells that have produced very flat rates for decades. And it’s the same rock that we’re producing in. So I think that we’ve adjusted down at the end of the life of the well accordingly to being a conservative estimate, but it really doesn’t have much of an effect on the front life of the well. In November, that did have an effect on the front life of the well, and it changed the rate of return. But it’s hard for me to argue what happens out 20 years plus. All I can look to is the producing wells that have produced vertically, and I believe that these wells will follow suit. But it really doesn’t have much of a difference as to whether you would choose to drill or not, based on this outcome.

And in passing, you guys mentioned the potential for Woodford drilling and some middle Mississippian. That went kind of fast for me. Can you say again how many wells have been drilled? And what kind of results are other people getting? Are they comparable in economics to Mississippian? Or is this a totally different ballgame?

Well, we’ve only had three, and those wells are in Garfield and Grant County, Oklahoma. And they have now enough production history, so we didn’t come out after day one. We came out after 200 days of production, and so it looks like these wells are comparable to our upper Mississippian wells and that opens up a new area that we have a lot of acreage. And we’ll talk more about that. Dave Lawler will spend a lot of time on this in the analyst day.

And then finally, in terms of how much acreage you have developed, how much of it is held by production now, of the total inventory? And I know the original intent was to hold it all, like in a five-year plan. Where will we be in a year and maybe in three years?

We’re about 15% now. Keep in mind there is still tremendous acreage available in the Mississippian. Acreage is not really the driver for being able to make a decision to drill a well. So what is important is having an infrastructure system, and if you notice, in the third quarter of last year, we actually added 50,000 acres within our infrastructure system. So will we drill maybe every acre that we have up through western Kansas and through Oklahoma? Probably not. But can we drill within our infrastructure system and have 11,000 locations? Yes.

Okay. I think what I heard you say is there is a subset of the total that would be material enough to support a very large program, so we shouldn’t get too hung up on if over time it doesn’t get developed.

That’s correct.

And the next question comes from Joe Allman from JPMorgan. Please proceed.

Good morning. This is Jessica Lee for Joe Allman. We’re trying to get an understanding of the Permian sale. I think you booked your year-end ’12 PV-10, proved reserves, of $3.2 billion, and from our understanding, that excludes any value for the unbooked reserves. So could you help us think through the decision to sell the Permian at a price below the proved reserves PV-10?

You know, typically when you have a reserves value that includes a lot of [puds]. You typically won’t get full value for the puds. In this particular case, I think we got really good value for the Permian, based both on a dollars per barrel production per day and a multiple on cash flow. I think it’s one of the strongest sales here in recent time. And so when you look at the PV-10 for the Permian, it’s a PV-10 of PDP, and a PV-10 of puds, and clearly there should be a little bit more risk on the puds than the proved, developing wells. And so any way you want to slice it, I think it’s a very good sale for the company.

And for your Mississippian, in terms of your IRRs of 50% or so, could you kind of walk us through the assumptions you used for that, including the price differential assumed for oil, gas, NGLs? And LOE and production taxes?

You know, I could probably spend the next 30 minutes on that. Why don’t we take that offline and I’ll walk you through the model after the call, and how we get to those rates of return, and go through the calculations in detail?

Okay. That works. And kind of moving to the Mississippian drilling and completion cost of $3.1 million you guys assumed for the fourth quarter, can you actually break that cost down into drilling cost only for the production well, completion cost for the production well, and the assumed salt water disposal cost for the well? And just kind of explain the allocation among the three?

Yeah, the $3.1 million does not include any infrastructure cost. It’s the result of the cost of all the wells we drilled in the fourth quarter, which probably 20-25% of those wells had the submersible pumps on them. A well that didn’t have submersible pumps came in less, probably around $3 million per well. And so that’s how we model, and that’s how we get to the 50% rate of return. It’s based on well head economics of drilling completion costs.

So that does not include the salt water disposal cost?

No, that does not. And what we typically do is, in terms of salt water disposal, we think about it in terms of about $200,000 additional per well.

Okay, so including salt water, it would be around $3.3 million?

Yeah, that’s right, and I think the point on the slide in the presentation on cost is that we’re working pretty hard to move that number down. You know, we’ve already moved it down from $3.6 million to $3.1 million just in 2012. So I think in 2013, if we can get that down to $3 million or $2.9 million, then your all-in cost rate is going to be kind of where it is now, about $3.1 million.

And just quickly, on your 2013 production guidance, could you break down the NGL production and oil production of the guidance?

In 2013, we had 34.3 million barrels of oil equivalent in our guidance, and the gas is 110 Bcf of natural gas. The oil is 14.1 million barrels, and the natural gas liquids is 1.8 million barrels.

And then just one last quick question for us. Do you have an update on the consent solicitation process? We understand the deadline is coming up March 15. Just any comments around that?

No, we don’t have anything other than the initial consent that was delivered to the company, so we’re not in a position to speculate on that.

Your next question comes from Brian Singer from Goldman Sachs. Please proceed.

As you think about your financing options that you talked about earlier, just a couple of questions on that. The first is what impact, if any, would selling your salt water disposal business have on operating costs or price realizations? Or I guess to incentivize a separate salt water disposal business, what would be the incremental agreement that SandRidge would have to reach that would impact costs? And then second, what level of interest are you seeing in Kansas properties from the broader market?

I’ll take the infrastructure question. If we were to sell or monetize that salt water disposal system, it would result likely in an increase in LOE, because we’d have to pay for third party, for water disposal into that system. That being said, if you run the math on it, and assume a water disposal cost per barrel of water of anywhere from $1.50 to $2.50 a barrel, depending on where you are, it’s very accretive and NPV positive and enterprise value positive based on where the valuations for these assets trade. So any increase in LOE would be more than offset by an increase in value and valuation, and even proceeds.

And with regard to Kansas acreage, we’re not doing any process currently. We think that there seems to be a tremendous amount of interest in wanting to partner with us for all the reasons I said earlier, mainly to do with lower well costs. And there’s a tremendous amount of acreage left to be drilled in even just the southern counties of Kansas, even if you didn’t look at anything to the north and west. So we are not currently in negotiations with anyone. We have tremendous liquidity and would look to do any two of the three things we talked about to fund ourselves through 2015. So this is one option that we’d look at, more towards the end of the year.

And then in the past you’ve indicated you get some decent pricing benefits from Mississippi Lime gas, but looking at your guidance, post the Permian sale, your gas differential to [Henry Hub] widens to $0.45 below from $0.40. Is it right to assume that that is just spreading contracts like the Century plant contract payments or other agreements over a smaller base of gas production, and if so, can you just refresh us on those contracts and Century in particular?

The basis on gas widening is really a result of the new Atlas contract, so the pricing that we’ll get for the dry gas there is not going to be premium priced gas like it was in the past. So that’s the primary mover for that basis differential.

And can you just give us a refresher on the Century contract? I think in the 10-K it was saying $30-36 million? Is that something that just goes on in perpetuity? Is there any option or move to try to come to any kind of resolution to get that off the books?

Yeah, we’ve got that number baked into our LOE guidance for 2013 as we’re not drilling in the Pinon field any longer. As that production declines, we would expect a gradual increase in that underdelivery payment.

And then the resolution would be, at some point, to find a logical buyer for those properties.

Your next question comes from Leon Cooperman from Omega Advisors. Please proceed.

Let me first declare myself. I’m not an energy specialist, but I have two that work with me. And I’m listening carefully to the call, and I find it kind of a little confusing. The gentleman a few comments ago said great quarter. Most everything you say is positive, yet your stock is down about 8% this morning, and we’re hovering near historic lows. And TPG alleges the value of the business is somewhere between $11 and $12 a share, yet we’re selling at slightly half that value. So I pose three questions. In your view, why? What is the Street missing? Do you have your own value of the business? And fourth, what are you going to do to get there? Any help would be very much appreciated.

We believe that we do have value. We believe the Mississippian Play is an extraordinary asset as our TPG [unintelligible] does also. And why are we here? It could be that - and I’m not positive why we’re here, but one theory might be that we, in 2009, had to make a fairly dramatic move with the company, and that did require us to work in an unorthodox way to get to the point that we have with the liquidity we have today, and people sometimes like more orthodoxy. But I think we can all agree, at least the people that are visiting about this, that we have a much higher NAV and a better company than we’re being valued today. So we’re in agreement with that. And how we’re going to get there is that the last four quarters we’ve beat consensus. We think the next four quarters we’ll do the same thing. And if we continue to have excellent rates of return out of an incredibly good play, that our value in the company will be recognized. And that’s the only things I know to say to that.

The next question comes from Craig Shere. Please proceed.

Were any of the 40 Kansas Miss wells drilled in the extension area beyond just north of the Oklahoma border? And if so, can you discuss some of those results?

Sure. We’ve had some encouraging results in all areas, including what we used to call the extension, now we just refer to it as Kansas. But I would ask you just to wait a couple of days and we’ll go through all the counties, including those that you’re referring to, and what we’re finding in each one. There are good results all the way across the play so far.

How repeatable is the reduced well costs, since you’re drilling more within existing infrastructure, but your total acreage vastly exceeds infrastructure? This is picking up off Duane’s question about [HBP] issues. But can you roughly quantify, if you’re going to have some core drilling, even if it’s many thousands of drill sites, what portion of your acreage that might encompass?

Sure. Today, we’ve only drilled to [unintelligible] county, Kansas. We do have infrastructure across the southern tier of Kansas up into Ford County, and across Oklahoma, that would give us, inside of that infrastructure, it would be enough wells to have us for many, many years of drilling ahead of us. And so I don’t know what happens in other parts of Kansas or in Oklahoma where we don’t have infrastructure, but we do believe that we have the capability to add inexpensive acreage inside of our infrastructure, if we didn’t drill everything outside of the infrastructure. So to answer you, yes, we do high grade in areas that are doing very well, and I think on Tuesday you’ll notice where our rig count is is around the better wells that we’re drilling.

And on Tuesday, would you be updating any expectations for absolute free cash flow breakeven after all of growth capex?

Yes, we’ll provide a reconciliation from EBITDA all the way to cash flow, and then the sources to fund between that and the $1.75 billion of capex for ’13.

I’m sorry, I meant from operating cash flows in terms of getting your arms around this vast opportunity over the years.

I don’t think we’ll be going through guidance past ’13. I think we’ve said publicly that we’ll try to keep capex around this level, and we have $2.5 billion of liquidity right now, and we have several options that we’re looking at to fund through ’15. So, sitting here, March of ’13, we think we’ve got a lot of the next few years mapped out.

And last question, I think this picks up off Neil’s question. We had some nice Mississippian megawell performance [unintelligible] second quarter 2012, and now fourth quarter 2012. We saw higher mid-continent liquids growth in fourth quarter ’13 than gas volumes, a nice change in trend from third quarter. But we seem to keep lowering the overall oil content in the play. And at the same time, Tom, you seem to be suggesting that you’re somewhat skeptical of your updated type curves. Why even put them out, if it’s mostly in the outer years, again, and you’re skeptical of it.

Well, we started in 2010, with a type curve, and we drilled by far the most wells of anyone in the play, so we thought that we should give an indication of what the 600 wells we’ve drilled to date, what they would look like. And at the first part of the curve, I can tell you that the November change was much more dramatic than this change here, even though it’s less oil. This change in the outer years is more art than science. Once you get out past 10 or 15 years, you do have to depend on other wells that have been drilled, and the wells that have been drilled aren’t horizontal. They’re vertical. So my opinion is that it will be more like what we had in November, but that is just my opinion.

And on Tuesday, you’re going to help detail for us some of the breadth of well performance in multiple specific locations, not just in aggregate?

You will be able to see a lot of information on Tuesday. We’re going to have four hours just on the Mississippian, basically.

Your next question comes from Adam Leight from RBC Capital Markets. Please proceed.

Your monetization plans, for the salt water disposal system, were you expecting to have meaningful third-party volumes in the system by the time you look to monetize? And if not, would you be looking at a sale lease back as a possible alternative?

I don’t think we’ll have third-party volumes, just [unintelligible] monetization. That’s always a potential for the system, and one of the things I think that could create a lot of value there, the ability to tie in third-party volumes. But it’s not part of our business plan right now. And remind me of your second question?

Well, if you’re the only customer - I could be misunderstanding this, but from other examples, this is my impression - you would have to be treated as a sale leaseback, as opposed to an asset sale?

Now I understand your question. No, that wouldn’t be the case. We’ve been approached by several parties, and they’re looking at a lot of different alternatives, anywhere from selling a portion of it maybe to a financial investor, to MLP-ing it ourselves, and dropping down assets over time, to selling it to an MLP. There’s a lot of different options, but actually a sale leaseback, transacting that way, is not one that we’re considering at all.

Okay, I thought that was a legal view, but I could be wrong. Secondly, on the unit monetization, or potential unit monetization, again, if I’m recollecting, these are still subordinated and would be in the timeframe that you’re talking about? Would you be selling them, if you went that way, as subordinated units?

Good question. The units do start to convert from subordinated to common units. For example, the Mississippian Trust 1, we’ll complete our drilling obligation here early second quarter. Those subunits will convert a year from now. We have 7 million subunits in the first trust, and a little over half a million common units. So we’d be in a position to sell those as common units, as early as a year from now. And then similar with the other two trusts, we have 13 million and 12.5 million common units that, over time, will convert to common.

Your next question comes from Mark McCarthy from Wexford Capital. Please proceed.

I was hoping that, given the transaction you did earlier in 2012, you might shed some light in terms of breaking out the Gulf of Mexico from the underlying business. First question would be, can you provide us the breakout between your current PV-10 for the Gulf of Mexico? It seems to me it’s making up about 40-50% of the remaining PV-10 for the asset base if we take out the noncontrolled interests. And then I think James, you mentioned some reference toward EBITDA or pro forma EBITDA now going forward. Can you provide what that looks like net of the Gulf of Mexico? Again, I think you were hoping that that asset would be generating between $300 million and $400 million of EBITDA and generating I think it was around $200 million of free cash flow. Is that still the expectation?

Let me take the last part of that. On the pro forma EBITDA that I mentioned in my prepared remarks, $748 million, that was a full year ’12 pro forma for the impact of the Permian sale, the tertiary sale, and the period we didn’t own the Gulf of Mexico asset. So that’s a full year pro forma, $748 million. We don’t break out EBITDA separately by Gulf of Mexico or by the Mississippian. So I don’t have a separate EBITDA for you, just for the Gulf of Mexico. I think we can give you some production, and even some margins per barrel that will get you close.

On the PV-10 value, of our $7.5 billion of PV-10 a year in reserves, the Gulf of Mexico represents about $1.4 billion. So about 18%.

I was comparing it to the $4.3 billion and the net of the $950, so really the net pro forma is I think around $3.4 billion pretax, and you’re saying the PV-10 of Gulf of Mexico pretax is $1.4 billion.

Yeah, so post-Permian, it would be like 32%. It would be $1.4 billion to the $4.3 billion.

Why did the PV-10 go down so much versus the time you acquired it?

I don’t think it went down.

I thought it was $1.9 billion when you bought it.

No, the [DOR] was $1.275.

That’s what we paid.

That’s what you paid. Yeah, you paid a discount to PV-10.

PV-10, on their reserves, were $1.8 billion…

A lot of that is just the gas prices. I think $2.75 in the [SEC] pricing.

The next question comes from the line of Adam Duarte from Omega. Please proceed.

On the one hand, we’ve had a couple of type curve downward revisions that are being viewed negatively, I think. And on the other hand, we have EBITDA and production guidance that’s better than what we were initially thinking about, or what the market was thinking about. So I guess my question is, how do you reconcile the two? And admittedly, the type curve discussion is really around years five through 30, but next year, we just raised our Mississippian production guidance from 50% to 60%, up to 72%. So I guess my question is, for 2013, and to the extent you can talk about even ’14 and ’15, how confident are you in your production and capex guidance? How do you get that comfort? And just talk about the difference between what we’re seeing in years five through 30 on the type curve, and what you guys are actually going to book from a production EBITDA capex and cash flow perspective.

Sure. The type curve, as you mentioned, is a discussion around that versus production. The type curve is out in the future, and the production guidance is in the present, so we feel very good about our production guidance, and being able to meet or beat that, that’s one of our two goals, that we’ll meet or beat our capex requirements, and we’ll meet or beat production guidance. And so we have five years’ worth of history around horizontal wells. There have been now 1,500 of those drilled, which are more than most of the plays that analysts would like to look at and say are now proven, and we know what the front of that type curve looks like. If you will look at ITG or [unintelligible] or us, and look at the November guidance that we had, or today’s guidance, the front end of the curve doesn’t change. So what everybody is arguing about is something that’s out in 15 or 20 years from now, that has really no effect on rate of return. So we should be able to hit our guidance, and we should be able to meet our capex requirements, or beat both of those, and then it’s just if you want to sit around here in 20 years and talk about how these wells performed, we can do that then.

And on the production side, where are you getting your comfort? Is it that you’re drilling in and around wells that are currently producing? Or is it that your capex is trending down? What are you guys seeing in terms of…

No, the reason we beat production is we’re improving off of what we expect. So we have a typical well that we project that we’re going to drill, and then as we drill enough wells, it only makes sense that you drill your wells around areas that have permeability and produce more. And so what we do is then drill more wells in that area, which increases our production more than what we guide to.

And then quickly, just to pick up on what Duane asked about, in Grant and Garfield county, with the wells that are targeting multiple objectives, how many of those wells are you going to drill in 2013, and do you have a sense for well costs, economics, EURs, or anything like that?

It should be the same type of economics for us, and we will start drilling in 2013. We have not, other than the three wells that have been drilled that we have an interest in, put a program together. But that’s coming together now, and we will talk more about that on Tuesday.

And you talked about some of the wells you drilled in Oklahoma, with I would all them abnormally high IP rates. Can you draw conclusions from those IP rates relative to what your EURs in those wells would be? You talked about sort of a range of EURs of 300-500 BOE. Are those the 500 BOE wells, or is it too early to tell?

Well, they’d be above the 500 MBOE wells, because our average is going to be 300-500. We have wells that are much better than that, and I picked the 10 best wells we drilled.

The next question comes from Richard M. Tullis with Capital One Southcoast. Please proceed.

I apologize if you’ve covered some of this already, but any tax gain related to the Permian sale?

No tax gain. We have enough NOLs, we have a little over $2 billion of NOLs to shelter any gain there. And we will have one very small amount, $15 million around, of AMT tax associated with the sale. So the only tax leakage is that $15 million of AMT tax.

And then how many net Miss Lime wells were drilled in ’12 and planned for ’13?

In 2012, we drilled about 396 gross and 280 net Miss Lime wells. And in 2013, we’re looking at 581 gross, and 379 net.

Your next question comes from Jeff Robertson from Barclays. Please proceed.

Just a question on the guidance. I think you said it’s for 2013 89% oil? Can you just help me understand with I assume all the growth coming from the Mississippian, where the mix of oil to the liquids volumes with the Atlas contract is about 64%, that NGL wouldn’t be a little bit bigger part of the 2013 outlook?

Normally it would, but because we’re selling the Permian, that had some NGLs with it too. So the NGLs kind of offset each other.

The next question comes from [Lin Shen from Height]. Please proceed. [Lin Shen from Height]: I just wanted to follow after Royalty Trust sales. Do you still owe common units under a couple of the trusts, like Mississippi 2 and also Permian Trust? Should I expect you guys to sell them this year?

We do own units in all three trusts, common units and subordinated units. We’ve said many times that we will use those as a source of capital over the years. We said that even right after we IPOed them. So I would expect that at some point we’ll monetize those. I can’t say if it will be this year or next or the next, but it will be a source of capital for us.

Your next question comes from Brian Singer from Goldman Sachs. Please proceed.

Just one follow up, listening to some of the comments in regard to the type curve and what caused that to change. Tom, I think you mentioned historical vertical well data that in your mind seems to justify that the type curve is essentially conservative. Whose decision was it to change the type curve? The vertical well data I assume has been around for a while. So is this something that was driven by outsider internal reserve engineers, or could you just add a little bit more color?

Sure. [unintelligible] is our third-party engineering firm.

Is it fair to say that you put the type curve out because [unintelligible], it’s their type curve and you think there’s maybe a little bit of disagreement here?

It’s our type curve also. I just gave you a personal opinion.

Sir, you have no questions at this time.

Okay. Thank you very much for joining us, and we look forward to having conversations with anyone who wants to call in. Thank you very much.