SandRidge Energy Inc (SD) 2012 Q4 法說會逐字稿

Welcome to the quarter four 2012 SandRidge Energy earnings conference call. My name is Lisa, and I will be your operator for today. At this time, all participants are in listen-only mode. We will conduct a question-and-answer session towards the end of this conference.

(Operator Instructions)

As a reminder, this call is being recorded for replay purposes. I would like to turn the call over to Mr. James Bennett, Chief Financial Officer. Please proceed, sir.

Thank you, Lisa. Welcome, everyone and thank you for joining us on our fourth-quarter and full-year 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 will make reference to adjusted net income, adjusted EBITDA and other non-GAAP financial measures. The reconciliation of any non-GAAP measures we discuss can be found in our earnings release and on our website. Please note that today's call is intended to discuss SandRidge Energy and not our public royalty trusts. Finally, earlier this morning, we filed our Form10-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 earnings per share in each of our last four quarters and EBITDA in 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 costs, 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 are located in Alfalfa, Grant and Woods counties, Oklahoma. Of these 10, five were above 1,000 BOE -- 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 liquid stream until after the start of 2013. We've also announced the closing of our Permian sale, which has seen 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 beating 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 was approximately 2 times. 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 45 rigs that we have previously projected.

In 2012, we spent extensively on our infrastructure system, which provides 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 will be able to control infrastructure CapEx and grow our production with development wells.

The saltwater disposal system we have built can handle 1.6 million barrels per day of saltwater. 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 are able to save over $2 per barrel of water relative to trucking those water volumes. We've been focused on eliminating our dependence on truck water and now are 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's a strong market demand for water disposal assets. We are currently evaluating the merits of monetizing our system. The savings we realized from our efforts to develop an optimize our infrastructure, coupled with the lowest per well drilling and completion costs, and lease operating expenses in the industry is a primary reason that our Mississippian economics are so good and while we've been able to secure excellent partners 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 were able to access power from the grid by constructing our own distribution lines and 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 that are achieved by producing approximately three times the fluid that a gas lift system can. In the first 77 wells, with over 30 days of production, we have 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 is the reason we deliberately chose the Mississippian formation and projected our EURs of 300 to 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 oil in the front of 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 change is at the end of the life of the well. It is 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 cost 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 for the wells.

We've said from the outset that we believe we'll find wells in the Mississippian with the range of 300 MBOE 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 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 costs 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 liquids stream. Our oil production is slated between 43% to 50% since the first wells were brought online in 2010. But now our new production stream is divided into 60% to 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 looks very promising with wells producing between 350 BOE to 1,000 BOE a day from the Middle Mississippian and Woodford Shelf. 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 Analyst 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 saltwater disposal system, selling additional units in our royalty trust, and finalizing our last JV on our Arkansas 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 are 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 volumes remain unhedged. We are 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 professional guidance, Mississippian drilling and operating costs and the year-end type curve and wellhead 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 split 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 that we did in the third quarter.

Natural gas liquids accounted for only about 2% of the total liquids production in the Mississippian in 2012. However, within 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 plans to drill and complete 581 horizontal producers, 74 disposal wells with all associated water gathering facilities, electrical infrastructure, and leasehold 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 $350 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 -- excuse me, 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% growth 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 8.2 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 72% increase in total barrels equivalent.

Moving to the year-end reserves, please turn to page 3 of our conference call -- 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 at $7.5 billion. As compared to year-end '11, this is a 20% increase in reserves volume and 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 and finding cost was $21.68 per barrel equivalent and the all-in proved developed finding costs, including leasehold and acquisitions, was $24.02 per barrel equivalent. The proved developed drilling and finding costs 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 cost, the year-end factor and our expectations for wellhead economics. We continue to be very excited about the Mississippian play, along with a 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 our strategy of creating value and steadily improving our cost structure in both CapEx and LOE through our upfront 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 lowest-cost horizontal play of scale. We set a goal early on to drill and complete horizontal Mississippian wells with 4,500-foot laterals in the range of $3 million.

Please turn your attention to page 4 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 cost 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. 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 cost to $3 million or below by the end of 2013. 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 5. 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 are 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 and 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 one injector. We exited 2012 at 6.4 to one and we anticipate to expect to exit 2013 at about eight to one. Our goal is 10 to one 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 wellhead and about 1.2 Bcf at the tailgate of the plant after shrink. I should also note that NGL recovery in a 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 300 -- I'm sorry, 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 6 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. At that time, we had not executed our contract with Atlas and so NGLs were not included. So on page 6, 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 both are a good fit to the actual 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 in 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 look at the table at the top of page 6, 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%.

So moving to page 7 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 7, you can see the rate of return sensitivity to well cost for the two curves. Assuming $3.1 million for drilling completion cost, 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 7, 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 last -- 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 8. 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. 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 change 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 costs on both CapEx and LOE.

Finally, let's look at page 9 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 of 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 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 divesture 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 the sale and associated debt reduction, our capitalization, liquidity and leverage levels are the best position in the Company's history, which puts us in a very favorable spot to execute our Mississippian drilling plan.

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 consecutive estimates in all categories. The production for the quarter averaged 106.8 thousand barrels of oil equivalent per day, a 4% increase in sequential quarterly production and a 60% increase over the comparable 2011 period. The Mississippian continue to be the driver of this production growth, averaging just under 36,000 BOE per day for the quarter and 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 the lease operating expenses, raised fourth-quarter adjusted 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 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 non-cash write-off 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 treat -- achieve greater economies of scale in the Mississippian play. In the Mississippian, we've lowered our LOE to under $208 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 in the Century Plant. This expense totaled $8.5 million and is reflected in Q4 lease operating expense. For the full year 2013, we estimate the same expense will 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 reduction in drilling on our Permian Basin assets, continued ramp down on our leasehold purchases and further improvements in our Mississippian drilling cost.

For 2013, we are 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, for 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 play where we have existing infrastructure in place.

On the balance sheet and liquidity, our 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-end 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 400 -- sorry, $748 million, giving us a net debt-to-EBITDA ratio of 2 times. 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.

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 the $1.75 billion CapEx budget. In terms of funding through 2014 and 2015, we have several options at our disposal and will be working on these in the coming quarters. This will include a joint venture on our Kansas-Mississippian acreage, where we have 1.3 million net acres, sale or other monetizations, such as creating an MLP of our saltwater 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 monetization of our saltwater 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 the system and be in a position to monetize this asset late this year or early next. We believe 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. Lisa, please open up the lines for questions.

Thank you.

(Operator Instructions)

Please stand by for your first question. Neal Dingmann, SunTrust.

Tom, for either you or Matt, just wondering, you outlined in the press release, just looking first at the Gulf and then I'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. I'm just wondering the budget, the number of -- if you're going to do as many recompletes this year? And just your thoughts for you all, as far 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?

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

Okay, and then obviously, just turning on the Miss. Obviously, there's a lot of concern that and you addressed on the type curve, just the difference between the early year and further out. Again, remind us how often will this be updated? Remind me, number one, how many wells is this based on? And then, number two, you -- with the -- incorporate that second slide that shows the ESPs, how long you keep these ESPs on and again, how will that play or if it will play into the type curve?

Yes, so, we -- in our slide presentation on page 6, it gives you a pretty good visual of the type curve for both gas and oil. So you can see in this type curve that is -- it's really similar in the two curves, but because these wells have 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 this -- we feel pretty good about the type curve being the range that we're showing here.

(multiple speakers) Lastly, Tom, just strategically, you do obviously have a solid financial position, don't necessarily need to sell acreage, but just your thoughts, Tom, 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. We want to move the mean of that production to the right, and so in order to -- 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 plan, now that we have ourselves basically funded through '14 so we're looking for ways to fund out through '15. We like to keep ourselves about two years in advance if we are 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 the JV. Now, keep in mind that acreage, in Mississippian, there is so much acreage. There's 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 over $650 million in infrastructure by the end of the year. Drilling costs also matter and if you're going to do a JV, if you're -- we average about $1.1 million per well less than the average of our peers.

Well, we will save over $300 million this year in 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 is worth -- it just gets priced into a price per acre. But that's how come you can have different amounts from different players in this particular play. Remember, it is a niche play, where infrastructure and costs are very, very important.

Thank you. Great quarter.

Charles Meade, Johnson Rice.

I want to try to drill down a little bit more on the type curve, and thanks for giving us that -- 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 like -- that you're over-sampled versus the way the whole play is going to work out. You're over-sampled really in, call it, Woods, Alfalfa, and Grant counties. So, is there an argument to be made that really the type curve you have is a type of curve for those counties more than a type curve for the play as a whole?

Yes, look Charles, we -- when we get a type curve, we put it out there what we drill in there and so we are not trying to focus on any sweet spots or local areas. Every well that we drill, that we -- that came on production is in the type curve. So, yes, certainly, the wells in Alfalfa, Woods, and Grant, we dominate the type curve just because we have more wells drilled in those counties and that is where we started the play. But overall, statistically, you can find these type of wells all over the counties we're drilling. That's done (multiple speakers) --

I was going to mention one thing on that, Charles. This is Tom. Rodney will be addressing this also on the Analyst Day with -- going through the wells we've drilled and in each County, we have good wells. So, there's a lot of speculation that some -- 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 drilled 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. Rodney will spend a lot of time going over that at the Analyst Day.

Got it. And it could --

(multiple speakers) I interrupted Matt, I'm sorry.

I think Tom covers it. I was just going to say if you take an area of a township and move this thing around in all these 12 counties that we drill, you -- statistically, you'd probably see a similar type of curve. So all I'm saying is that this curve, I think, is representative there as we're drilling.

Right, right, so it's just -- it's exactly representative of what you drilled and I guess it's not representative where you haven't drilled. But, and then following on, on this --

Charles, what I'm saying is, it's represented in a large area of 12 counties. If you drill enough wells in any of those -- pick an area in those 12 counties you drill, you would expect this outcome.

Got it. And then onto the same theme for the ESP type curves, or the ESP wells or 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 of the wells you've drilled so far?

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

Got it, and the difference on the gas? Is that because the ESP, you don't have to use fuel gas for the compressor for gas lift? 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.

Got it, and then the last question, and this may be something you want to push off to Analyst Day. But, what are the -- what do you think the prospects are for, Tom, I think you alluded to this to truncating the lowest part of your bell curve or translating that, what are the prospects for not drilling the low wells (multiple speakers)?

What you see over time with us drilling 600 wells is that the initial production, over time, has gone 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. 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 developmental 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. You have more data so you should be able to, and what we're saying is we're drilling better wells because of that. That's why we beat our production in the fourth quarter and I think that's why we'll continue to do that.

James Spicer, Wells Fargo.

Just a couple questions of clarification. First, can you tell us what the premium is that you're paying to take out the 9.875% and 8% bonds?

Yes, we're doing a make-whole, so it comes to about [$1.04 billion and $1.05 billion], roughly, for those bonds, respectively; it's a fee plus 50 make-whole.

Okay, great, and what is 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.

Okay, great. And then finally, you made the comment that you believe you're fully funded through 2014 currently. First of all, can you just clarify that, that you are assuming both a combination of cash on hand, as well as revolver availability there? I assume you're thinking about a similar CapEx in 2014 to 2013 when you say that?

Yes, James, it does exclude -- include about a similar level of CapEx. We are assuming in there the cash on hand of $1.7 billion, and then $775 million revolver, so about $2.5 billion of liquidity right now.

Duane Grubert, Susquehanna Financial.

I guess the shock to a lot of people today is when they look at your type curve on page 6 there 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 take confidence in changing your out year curve to that degree when no well is older than, say, three years so far?

You want -- well, I'll start and Matt can always add to this. So Duane, we have -- personally, I believe that we're being very conservative, because we have 17,000 vertical wells that have produced very flat rates for decades. It's the same rock that we're producing on. 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.

And then in November, that did have an effect on the front life of the well and it changed the rate of return, but it is hard for me to argue what happens out 20 years plus. All that I can look to is the producing wells that are 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 a well or not, based on this outcome.

Okay and then in passing, you guys mentioned the potential for Woodford drilling in some Middle Mississippian. Can -- I -- that went fast for me. Can you say again how many wells have been drilled and what results are other people getting? Are they comparable in economics to the Mississippian, or is this like a totally different ballgame?

Well, we 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 said, 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 will talk more about that, Dave Lawler will spend a lot of time on this in the Analyst Day.

Okay, 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? What might be -- 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?

In fact, we're about 15% now. Keep in mind, there is still a tremendous acreage available in the Mississippian. Acreage is not really the driver for being able to make a decision to drill a well. So, the -- what is important is having the infrastructure system, and if you noticed 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, if I -- 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 all get developed?

That is correct.

Joe Allman, JPMorgan.

This is this is Jessica Lee for Joe Allman. Just -- we're trying to get an understanding of the Permian sale. I think you booked your year-end '12 PV-10 proved reserves at $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 reserve PV-10?

Yes, this 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 a 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 times. And so, I think it's -- when you look at the PV-10 for the Permian, it's a PV-10 of PDP and a PV-10 of PUD and clearly, there should be a little bit more risk on the PUDs than the proved developing wells. So any way you want to slice this, I think it is very good sale for the Company.

Okay, great. And for your Mississippian, going back to Mississippian in terms of your IRR as a 50% or so, could you walk us through the assumptions you -- for that, including the price differential assumed for oil, gas, NGLs, and LOE and production taxes?

Yes, I can probably spend the next 30 minutes on that. Why don't we take that off-line and walk you through the model after the call and how we get to those rate of returns and go through the calculations in detail.

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

Yes, the $3.1 million does not include any infrastructure costs. It includes all -- it's the result of the cost of all wells we drilled in the fourth quarter, which probably 20% or 25% of those wells had submersible pumps on them. Wells that didn't have submersible pumps came in less, probably around $3 million per well. So when you model that, that's how we model and that's how we get to the 50% rate of return that's based on wellhead economics of drilling and completion cost.

Okay, so that does not include the saltwater disposal cost.

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

Okay, so including saltwater, it would be about $3.3 million?

Yes, 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. 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 there is going to be where it is now, about $3.1 million.

Okay, great, that is helpful. Just quickly on your 2013 production guidance, could you break down the NGL production and oil production of the guidance?

Yes, give me just a second, here. So in 2013, we have 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.

Okay, great. 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, so just any comments around that?

No, we don't have anything other than the initial consent that was delivered to the Company. So we are not in a position to speculate on that.

Brian Singer, Goldman Sachs.

As you think about your financing options that you talked about earlier, just a couple questions on that. But the first is, what impact, if any, would selling your Saltwater Disposal business have on operating cost or price realizations or to incentivize separate Saltwater Disposal business? What would be the incremental agreement that SandRidge would have to reach to -- that would impact cost? And then second, what level of interest are you seeing in Kansas properties from the broader market?

Sure, I'll take the infrastructure question, Brian. If we were to sell or monetize that saltwater disposal system, it would result likely in an increase in LOE, so we would 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 even proceeds.

Brian, on -- with regard to Kansas acreage, we are not doing any process currently. We would think that we're highly likely to -- 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. There is 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 in currently in negotiations with anyone. We have tremendous liquidity and would look to do something at any two of the three things that 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.

Great, thanks. In the past, you indicated you had 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, such as Century Plant contract payments over -- 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?

Yes, Brian, the basis on gas -- this is Kevin, 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 price gas like it was in the past. So that's the primary mover for that basis differential.

Got it. Can you just give us a refresher on the Century contract? I think in the 10-K, it was saying they're $30 million to $36 million? Is that something that just goes on in perpetuity, or is there any option or move to try to come to just any resolution to get that off the books?

Yes, we've got that number baked into our LOE guidance for 2013, as we are 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.

Leon Cooperman, Omega Advisors.

Let me first declare myself, I am not an energy specialist but I have two that work with me. I'm listening carefully to the call and I find it a little confusing. The gentleman, a few comments ago, said great quarter. Most everything you say is positive, your stock is down about 8% this morning and we are hovering near historic lows. So, and TPG alleges the value of the business is somewhere between $11 and $12 a share, yet we're selling it slightly on half that value.

So I pose three questions. In your view, why? What is the Street missing? Do you have your own view of value of the business? And fourth, what are you going to do to get there? Any help you could be would be very much appreciated. Thank you.

Sure. We believe that we do have value. We believe the Mississippian play is an extraordinary asset as our TPG-Axon also. Why are we here, it could be that and I can't -- I'm not positive of why we are here, but one theory might be that we, in 2009, had to make a fairly dramatic move with the Company. That did require us to work in an unorthodox way to get to the point that we have liquidity we have today. People sometimes like more orthodoxy, and so --.

But I think we can all agree, at least the people that are visiting about this, can agree 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 beat consensus. We think the next four quarters we'll do the same thing. If we continue to have excellent rates of return out of the -- an incredibly good play, that our value in the Company will be recognized. That is the only things I know to say to that.

Craig Shere.

Looking forward to the Analyst Day next week. Couple of questions. 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 have had some encouraging results in all areas, including what we used to call the extension, now we just refer as Kansas. But we -- I would ask you just to wait a couple of days and we'll go through all the counties, including those that you are 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 cost since you're drilling more within existing infrastructure but your total acreage is -- vastly exceeds infrastructure? This is picking up off, I believe, Duane's question about HBP issues. But can you roughly quantify if you're going to have some core drilling, even if it is many, many, many thousands of drill sites, what portion of your acreage that might encompass?

Sure, I mean, from today, we've only drilled to Finney 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 area, it would be enough wells to have us for many, many years of drilling ahead of us.

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 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.

On Tuesday, would you be updating any expectations for absolute free cash flow breakeven after all of growth CapEx?

Yes, we will provide a reconciliation from EBITDA all the way to cash flow and 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, Craig, guidance past '13. I think we said publicly that we'll try to keep CapEx around this level. We have $2.5 billion of liquidity right now and we have several options that we are looking at to fund through 2015. So sitting here, February -- March of '13, we think we've got a lot of the next few years mapped out.

Okay. Last question, I think this picks up off of Neal's question. We had some nice Mississippian mega-well performance juicing 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're -- 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 are skeptical of it?

Well, we started in 2010 with a type curve. So we chose to -- 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. 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. So once you get out to 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 are vertical. So my opinion is, that it will be more like what we had in November, but that is just my opinion.

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.

Okay, thank you very much.

We are going to have four hours just on the Mississippian, basically.

Look forward to it.

Adam Leight, RBC Capital Markets.

Just a couple of quick ones and probably for James, but your monetization plans, for the saltwater disposal system, were you expecting to have meaningful third-party volumes in the system by the time you looked to monetize? If not, would you be looking at a sale leaseback as a possible alternative?

Yes, Adam, I don't think we'll have third-party volumes at the tie-in monetization. That's always a potential for the system and one of the things I think will create -- could create a lot of value there, the ability to tie in third-party volumes but it is not part of our business plan right now. I'm sorry, remind me of your second question, Adam?

Right. If you are the only customer, I could be misunderstanding this, but from other examples, it was my impression that it would have to be treated as a sale leaseback as opposed to an asset sale?

I understand your question, thank you. No, that wouldn't be the case, Adam. We would look to -- we have been approached by several parties and are 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 a MLP. There's a lot of different options, but actually a sale leaseback in our accounting struc -- transacting that way is not one that we are 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?

Yes, good question. The units do start to convert from subordinated to common units. For example, the Mississippian Trust 1 will complete our drilling obligation here early second quarter. Those units, the subunits will convert a year from now. We have seven million subunits in the first trust and a little over 0.5 million common units, so we would 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, we'll convert to common.

Mark McCarthy, Wexford Capital.

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. I've done some very basic math in terms of the year-end reserves you've put up here. It seems as though, if that year-end -- well, 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 towards 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, just 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 that we didn't own the Gulf of Mexico assets. So that's a full-year pro forma, $748 million. We don't break out EBITDA by 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 would 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%.

Okay, I was comparing it to the $4.3 billion and then net of the $950 million, so really the net pro forma number is, I think around $3.4 billion pre-tax and you're saying the PV-10 of Gulf of Mexico pre-tax is $1.4 billion?

Yes, so post-Permian, it would be, call it, 32%, it would $1.4 billion of 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, no, the deal was $1.275 billion.

That is what we paid.

You paid discount to PV-10. (multiple speakers)

PV-10 on the reserves were $1 --

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

Adam Duarte, Omega.

So, on the one hand, we have -- 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 my question is, how do you reconcile the two? 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, 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? 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, is 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 is one of our, I mentioned, one of the two goals is 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 now been 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. We know what the front end of that type curve looks like. If you were to look at ITG or Netherland Sewell 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 if we -- 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.

On the production side, where you getting your comfort? Is it that you're drilling in and around wells that you've -- that are currently producing or is it that your CapEx is trending down or what are you guys seeing in terms of --

No, the reason we beat production is, is that 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 processing 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.

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

No, it should be the same type 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, we've not put a program together, but that's coming together now. We will talk more about that on Tuesday.

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

Well, they would be above the 500 MBOE wells because our average is going to be 300 to 500 BOE. We have wells that are much better than that and I picked the10 best wells that we drilled.

Richard Tullis, Capital One Southcoast.

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

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

Okay and then how many net misaligned wells were drilled in '12 and planned for '13?

Yes, in 2012, we drilled 308 -- well, it's about 396 gross and 280 net misaligned wells.

Okay.

In 2013, we're looking at 581 gross and 379 net.

Jeff Robertson, Barclays.

Thanks, Matt, just a question around the guidance. I think you said it's for 2013, 89% oil. Can you just help me understand with all -- what I assume all the gross coming from the Mississippian where the mix of oil to the liquids volumes with the Atlas contract is about 64% that the NGL wouldn't be a little bigger part of the 2013 outlook.

Yes, normally, it would but because we're still in the Permian, that had some NGLs with it, too, so the NGLs offset each other.

Lin Shen, HITE.

Just want to follow-up on your royalty trust sales. Do you still own common units under, like, a couple of the trust? Do you have 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 IPO'd them. So, I would expect at some point we will monetize those. I can't say if it will be this year or the next, or the next, but it will be a source of capital for us.

Brian Singer, Goldman Sachs.

Thanks. Just one follow-up, listening to some of the comments with regards 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 this type curve is potentially conservative. Whose decision was it to change the type curve as the vertical data I've seen 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, this is a -- Netherland Sewell is our third-party engineering firm.

And so is it fair to say that your view is that you put the type curve out because Netherland Sewell, it's their type curve and you think it's -- there's maybe a little bit of a disagreement here?

It's our type curve also. I just give you a personal opinion.

Sir, you have no questions at this time.

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

Thank you for joining today's conference. This concludes the presentation. You may now disconnect. Good day.