SandRidge Energy Inc (SD) 2013 Q2 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the second-quarter 2013 SandRidge Energy earnings conference call. My name is Tahisha and I'll be operator for today. At this time all participants are in listen-only mode. Later we will conduct a question-and-answer session.

(Operator Instructions)

As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to your host for today, Mr. Kevin White, Senior Vice President of Business Development. Please proceed

Thank you, Tahisha. Welcome, everyone. Thank you for joining us on our second-quarter call.

This is Kevin White and with me today are James Bennett, President and Chief Executive Officer; Eddie LeBlanc, Executive Vice President and Chief Financial Officer; and David Lawler, Executive Vice President and Chief Operating Officer. Keep in mind that today's call will contain forward-looking statements and assumptions which are subject to risks and uncertainties and actual results may differ materially from those projected in these forward-looking statements.

Additionally, we will make reference to adjusted net income, adjusted EBITDA and other non-GAAP financial measures. A reconciliation of any non-GAAP measures we discuss can be found in our earnings release and on our website. Please note that this call is intended to discuss SandRidge Energy and not our public Royalty Trust. Finally, you can expect to see our second-quarter 10-Q filed after the market close today.

Now, let me turn the call over to James Bennett.

Thank you, Kevin, and welcome, everyone. I also want to welcome the newest member of our senior management team, our Chief Financial Officer, Eddie LeBlanc. Eddie brings to us over 30 years of E&P finance and CFO experience and we are excited to have him here.

Now that we're more than halfway through 2013, I feel confident in saying the course we laid out earlier this year is delivering results. In the first quarter, we made changes to our business plan to high-grade our capital program, focus on returns, exercise capital expenditure and overhead cost discipline, and lower the risk profile in the business. Our second-quarter results are evidence that these changes are taking hold.

Highlighting the recent successes to come out this plan are the fact that our production continues to set new highs and our costs new lows. Since building our Mississippian position, starting in 2010 we've emerged as a dominant operator in the play. We continue to make improvement, exploit our knowledge base and create better returns. Quarter over quarter, we grew our Mississippian production by 20% and Mississippian oil production by 30%. We grew total Company production, adjusting for the Permian sale by 5%, even taking into account expected declines in our Gulf of Mexico business. Our well performance continues to improve with 111 second-quarter Mississippian wells producing an average peak 30 day IP of 377 barrels of oil equivalent per day. We had six wells with 30-day IPs over 1,000 barrels of oil equivalent per day.

Recall that we high-graded our drilling program to concentrate in our six-county focus area, where we're seeing more consistent results and can better utilize our infrastructure. This year we anticipate 90% of our drilling to be concentrated in these areas where we have 925,000 gross and 615,000 net acres and approximately 3,000 drilling locations. With the progress made during the first half of 2013, we were able to raise our full-year production guidance by 2%, or 600,000 barrels of oil equivalent, 100% of this increase being comprised of oil and liquids. Importantly, we're able to do this while maintaining the same $1.45 billion CapEx budget. This updated guidance delivers a very robust organic production growth taking into account all A&D activity of 25% of liquids and 15% in total production.

In terms of the quarterly production trends in our full-year guidance, recall that in reducing our CapEx budget earlier this year, this called for a gradual decrease in our rig count from a high of 32 to a low of 22 with an average of 25 rigs for the year in the Mississippian. In the first quarter in the Mississippian, we averaged 32 rigs, in the second quarter 26 rigs, and for the remainder of the year we will average approximately 22 rigs. This was our plan all along. This 33% rig count decline from the first quarter to third quarter will cause the Miss growth rate to temporarily slow, but this is completely a function of the one time decline in rig count. Looking forward to 2014, we plan to begin to increase our rig count again to the 25 range and spend a similar approximately $1.5 billion of capital.

With this level of spending, we are confident that we can maintain a double-digit total Company production growth rate, a higher oil growth rate and approximately 30% year-over-year Mississippian production growth. The stacked pay in deeper zones that we mentioned at our Analyst Day and then again our first quarter are showing positive results and have the potential to open up vast areas of the play with multiple zone development. Our Mississippian teams are doing excellent work developing new opportunities sets for us in the play. We are still early in this program and will continue to report our findings in the coming quarters, but initial results we are seeing are very encouraging.

Again, our strategy of focusing on a high-graded capital plan is paying off. Let me walk through a few examples to showcase our focus on capital efficiency and, importantly, value. In terms of CapEx, back in the second quarter of 2012, we spent $216 million in the Mississippian. This includes drilling completion costs, salt water disposal, facilities and work overs. With this capital we drilled 91 producing wells. In the second quarter of '13, we spent $224 million and drilled 127 producing wells. So year over year we spent 4% more CapEx and delivered 40% more or 36 additional horizontal Mississippian producing wells.

The same trend extends to our salt water disposal facilities, where we are gaining efficiencies. The 40% more horizontal wells in Q2 were brought online with 50% less salt water disposal spending. As a consequence, our ratio of producers to salt water disposal wells drilled during the quarter has increased to 12.5 to 1 from 4.5 to 1 in the same period last year. In total, we are drilling more wells with approximately the same amount of capital. These wells are requiring less infrastructure and production rates are coming in above our type curve expectations.

On infrastructure, these 2011 and 2012 early investments in both electrical and salt water disposal infrastructure are paying off. At year-end we will have approximately $650 million invested in this infrastructure, which is proving to be a material competitive advantage in the play in terms of lowering or cost, consolidating leasehold within our focus areas, and offsetting our best producing wells. We have said before that this infrastructure is a potential source of capital in the future. For now we intend to continue to building out the system and leverage the competitive advantages that it provides us through economies of scale and lowering our cost structure.

On our Gulf of Mexico business, our strategy of low-risk recompletions augmented by selective pud drilling opportunities, is delivering consistent returns in production. While we had some pipeline shut-in issues that impacted the second quarter, we still expect this asset to average around 28,000 barrels of oil equivalent per day for the full year, approximately a 10% decline from 2012 production of 31,000 barrels of oil equivalent per day for the year.

Eddie will walk through some of the G&A numbers in greater detail. But in the second quarter, our G&A, adjusted for one-time items is approximately $45 million. We are confident that we will achieve the $150 million run rate later this year through reducing non-critical and non-E&P spending.

As we outlined in our first-quarter call, the primary reason for our change in the capital program for 2013 was to lessen our cash-flow short-fall and provide clear funding visibility for two years. We believe this is the right position to be in, as we can fund or growth from current liquidity and predictable cash flows from operations with limited variability due to our strong hedge position. Reducing this gap further in the coming years is a major focus of ours. Beyond 1014, we have talked before about the funding options we have available, joint ventures, monetizing our infrastructure assets, or selling Royalty Trust units. We constantly evaluate all these options and in the coming year we will be more concrete on our plans there. Currently we have $1.8 billion of liquidity and a leverage ratio of 2.4 times, which is a very comfortable place for us.

Also highlighting the great work of our teams, are our improvements in well costs in LOE, where in the quarter, we achieved record lows for both. It's the combination of these efforts that's making us successful in the play, lower costs, improved capital efficiency, better well results, and testing new zones. It's these results, repeated over time, that will drive our performance and significantly improve our net asset value. Another thing about the Mississippian that I think is often overlooked and not given proper attention, is that to be effective in this play requires size and scale, contiguous acreage positions, infrastructure and low costs, all of which we have. We have seen many other players who have a couple of these pieces, but not all, fail to be successful in the play. As these companies move out or shift their focus that provides more opportunity for us.

Looking forward to the remainder of the year and through 2014, our vision for SandRidge is to continue to capitalize on our position in the Mississippian play, where we are undoubtedly the best operator, have the lowest costs and the most infrastructure and an attractive leasehold position. We will exploit these competitive advantages in the Miss, increase our critical mass of production, expand our focus areas, find new zones and opportunities and bring in additional capital to accelerate and grow our net asset value.

Finally, we intend to accomplish all of this by being predictable and consistent in terms of the capital we invest, the volumes we will produce, the expenses to produce these volumes and the overhead to run the business. It's critical that we meet or beat our goals consistently. We believe that over time the market will reward our shareholders for this.

Now let me turn the call over to Dave Lawler.

Thank you, James. Good morning to everyone joining us on the call today.

As outlined in our second-quarter earnings release, the Mississippian offshore and Permian business units continued to deliver strong results. While we are pleased with the numbers themselves, we are also pleased with our progress on three key initiatives which are serving as the catalysts of the improved performance. First, we have significantly increased our production in the Mississippian business unit. As James pointed out, we delivered 111 wells to first sales with an average 30-day IP of 377 Boe per day. This rate is 39% above expectation.

If you recall from our Q1 earnings release our average 30-day IP was 21% above expectation, so we are pleased with this sequential increase. We attribute this production improvement to our sub-surface characterization and modeling efforts. Our model is based on the data collected from over 850 horizontal wells, 126 disposal wells, 13 hole cores, horizontal formation image logs, and recently acquired 3D seismic covering 183 square miles. We have analyzed this data and formulated seven value-enhancing variables that help guide our well planning process. One of these variables, for example, centers on the natural fracture systems that enhance hydrocarbon recovery. When combined, these seven variables allow us to high-grade our projects during the well selection process and by identifying the specific area, depth, zone and artificial lift technology required to maximize value.

Second, we have significantly reduced our drilling and completion costs. As highlighted, we decreased our well costs from $3.1 million to $2.95 million during the quarter. This $150,000 improvement increases our rate of return from 44% to 50% and increases the number of wells in our development portfolio, since more projects now exceed our capital investment threshold. Approximately $100,000 of this savings was achieved through the redesign of our well site production facilities and is a permanent reduction in our structural costs. The additional $50,000 is linked primarily to pad drilling operations and the continual focus on safely improving drilling speed. As an example of this focus, we drilled eight wells in less than 12 days and five of the eight wells using rotary steerable technology.

Well cost reductions have become significant and impactful. Over the last two years, the Mississippian business unit has decreased the cost of our wells approximately $900,000 each. In some areas, we are drilling 50% less than our competitors. During this same period of time, we have established cost control measures and processes that have narrowed the variance between the field estimates and the actual invoices of our wells to less than 1.5%. The $2.95 million average well cost also includes the installation of 62 electric submersible pumps, or 49% of the total well count for the quarter. ESPs typically cost around $250,000, so without an ESP well costs are around $2.7 million.

We believe we can secure additional gains in the next 6 to 12 months. The only caveat we would add to our drilling and completion costs going forward is that it may fluctuate due to the number of ESPs employed, pad wells drilled, and the number of stages required to adequately stimulate the type of reservoir we are developing. In addition to improved production in capital efficiency, our operating costs is now at a record low and is our third key initiative. Due to significant front-end engineering and field management expertise, we have eliminated almost all trucked water in the field except for appraisal wells, and have materially reduced the number and switched the type of generators needed to support the operation. As such, lease operating expense decreased to $7.38 per Boe, or 22% below the second quarter of 2012. This translate into a savings of $8.8 million for the quarter.

Beyond production, CapEx and OpEx improvements, our stacked pay testing program achieved success during the quarter. We drilled five horizontal Mississippian wells in new zones in areas directly offsetting existing primary production. These five wells delivered an average 30-day IP of 255 Boe per day, which is in line with expectation. Three additional test wells were drilled and completed with mixed results. We continue to monitor the production of these wells and have modified several future projects based on the individual out comes observed.

As discussed in the past, we have developed the upper zone of the Mississippian as our primary target. With the expanded appraisal and stacked pay testing program, we have confirmed that the middle Mississippian is highly prolific in certain areas of our lease position. As such, we drilled and completed a number of middle Mississippian wells in the quarter as the first zone developed. Eight of these wells delivered an average 30-day IP of 708 Boe per day. As part of the drilling and evaluation process, we identified development potential in the upper Mississippian zone. We believe with the infrastructure already in place, the upper zones may be added for minimal cost.

In addition to the Mississippian test, we finished drilling a third horizontal Chester well, which is expected to achieve first sales later this month. In our Kansas focus areas, we aggressively applied our sub-surface model and targeted areas with natural fracture systems for development. Today we have installed 15 openhole packer systems that will allow enhanced production contribution form the natural fractures. In addition we installed ESPs at 90 degrees to decrease flowing bottomhole pressure as low as possible and maximize oil recovery. To compliment the openhole packer systems and horizontal ESP installations, we pumped alternating fracture simulation cycles to increase the fracture density around the horizontal well bores. We are encouraged with the early results of this program and look forward to sharing more information with you in the coming months

During the quarter, the development teams continued securing additional leases in our project areas. Through a combination of the pooling process, strategic acquisitions and acreage trades, we were able to gain control of 48 highly productive sections. As each operator in the Mississippian continues to delineate their own position, it allows us trade opportunities wherein we exchange acreage outside our focus areas for acreage inside to take full advantage of our existing infrastructure. This activity is leading to our dominance in multiple focus areas.

Beyond the Mississippian growth engine, our offshore business unit continued to generate strong production and cash flow. The asset delivered an average rate of 28,743 Boe per day with 53% liquids. We achieved this rate in spite of deferring 70,000 Boe related to pipeline curtailments. The team performed six low-risk recompletions delivering 630 barrels of oil per day and 6.2 million cubic feet of gas per day. In addition, we finished drilling Green Canyon block 108, well number A21. The well found pay in the upper Pliocene J sands with no apparent water contact observed. The final phase of the completion is underway and we expect to achieve first sales by the end of this month.

We were also at 25% non-operated working interest partner in a discovery well targeting Miocene-age reservoirs that were identified with 3D seismic and AVO technology. The well encountered commercial quantities of hydrocarbons and we anticipate first sales in early 2014. We plan to operate two rigs in the gulf during the third quarter. One rig will remain on the Bullwinkle platform and is scheduled to drill two wells by the end of the year, and the other rig will drill two wells, one at High Island and one at South Marsh Island. We also plan to operate or participate in another 10 recompletions. The Permian asset also continues to improve results. Since the beginning of the year, the team has decreased drilling and completion costs from $700,000 to $600,000 per well, by continuing to optimize each step of the well delivery process.

In summary, we are making steady improvements across the business and we are working to generate additional value from our Mississippian assets through the stacked pay testing program. Our business units have delivered strong results during the quarter, so I'd like to thank the entire team for their laser focus on safety and bottom-line results.

Thank you again for joining us today. I will now turn the call over to Eddie LeBlanc, our Chief Financial Officer.

Thank you, Dave.

This being my first earnings call as a member of the SandRidge team, I'm extremely fortunate that our Mississippian production and our execution on operating cost savings initiatives have not only allowed us to exceed consensus estimates in each category, but have also provided strong financial results for me to discuss. Our second-quarter adjusted EBITDA of $268 million is basically flat. Not only with the $270 million for the first quarter of 2013, but results flat with the $269 million of adjusted EBITDA reported in the second quarter of 2012. However, it compares very favorably with those periods on a pro forma basis, considering the divestiture of the Permian assets in the first quarter of 2013 and the acquisition in April of 2012. On a pro forma basis, the $268 million of adjusted EBITDA in this quarter exceeded both the $219 million in the first quarter of 2013 and the $186 million for the second quarter of 2012, a 22% and 44% increase respectively.

Our last 12 months pro forma adjusted EBITDA is $897 million. Our adjusted net income of $44.6 million for this quarter results in adjusted net income per diluted share of $0.08, as compared to $37 million of adjusted net income, or $0.07 per diluted share for the second quarter of 2012. Adjusted operating cash flow for this quarter is $176 million, as compared to the $182 million for the first quarter of 2013 and $223 million for the second quarter of 2012. It is important to remember that in calculating adjusted operating cash flow, we only adjust for cash received or paid on certain commodity derivatives and for changes in operating assets and liabilities, and not for the effect of one-time items. The admirable operational performance that Dave has reviewed with you is the primary cause of these improved financial results. Our overall Company performance is best illustrated by the 5% oil and NGO production increase in the second quarter over the first quarter of 2013 on a pro forma basis.

Additionally, the 20% increase in Mississippian production over that same period added $45 million of revenue to the second quarter of 2013. 20% decrease in LOE per Boe in the Mississippian illustrates benefits realized from planning and engineering well locations and availability of infrastructure. In addition to our operational improvements, our hedging activities and redemption of debt earlier this year also benefited our results. Realized gains on derivative contracts totaled $17 million for this quarter, with oil hedges adding $4.50 per barrel or 5% to realized price.

Interest expense was approximately $25 million lower than the first quarter as a result of the redemption of the 2016 and 2018 senior notes following the closing of the Permian divestiture. The recent changes in personnel and strategy of our Company have resulted in a large amount of charges for one-time items in this quarter. We expect these types of charges to subside in the third quarter and be at least substantially complete by the fourth quarter of this year. Noteworthy adjustments used to arrive at adjusted EBITDA for this quarter were severance expense of $107.7 million, $14.7 million of expense associated with the new incentive compensation plan, $15.6 million of impairments of midstream inventory, as well as write-downs of drilling and other corporate assets held for sale, $7.4 million of solicitation expense and unrealized derivative gain of $85.9 million, and various other smaller items totalling less than $2 million.

Capital expenditures were $387 million for the quarter, which is a decrease of over 30% from the amount incurred in the second quarter of 2012. This quarter's capital expenditures illustrates our advancement in capital efficiency, as a greater percentage of this quarter's capital is invested in assets that will directly generate revenue. Only 27% of the first six month's capital was dedicated to leasehold and infrastructure, as compared to a 52% dedication in the first half of 2012. Our financial position remains strong with net debt of approximately $2.1 billion, consisting of $3.2 billion of senior notes, offset by $1.1 billion of cash. Liquidity remains solid at $1.8 billion, as our credit facility availability is at $746 million, net of outstanding letters of credit. Our leverage ratio of net debt to pro forma last 12 month's adjusted EBITDA at June 30 is 2.35 times.

Although our net leverage will be increasing over the coming quarters, we are comfortable with where leverage will trend over the next couple of years, given our liquidity, our strong oil hedge position, our growing Mississippian production and cash flows, and our lack of near-term maturities. We took advantage of the recent rally in crude prices and added hedges of just under 500,000 barrels at an average price of just under $98 per barrel in 2013 and '14. Our gas position remains essentially unhedged after 2013. You already heard we have updated our guidance for 2013. Our strong well performance and lower well costs encouraged us to increase our projected oil and liquids volumes by 5%. Our projected gas volumes decreased by 1% due to higher volumes of natural gas being processed and liquids extracted. Combined, this results in an increase in guidance to 33.3 million barrels of oil equivalent.

Our improved drilling and completion efficiencies allow us to maintain our prior capital expenditure guidance of $1.45 billion. Additionally we updated our differential forecast, widening our oil assumption to $9.50 per barrel, reflecting an increase in NGO recoveries and tighter LLS differentials, relative to WTI for our Gulf of Mexico business. G&A adjusted for one-time items total $45 million for the quarter or $5.40 per Boe. We remain confident in our expected $150 million run rate by the fourth quarter, as this second quarter adjusted G&A included approximately $5 million of compensation to personnel that are no longer with the Company and will not likely be replaced. This encouraging decline as compared to the second quarter of 2012, combined with our increased forecast for production volumes, allowed us to lower our guidance range for G&A by $0.10 per Boe.

Additionally we lowered our per unit guidance range for interest expense by $0.20 per Boe to reflect the increased forecast of production volumes. While our LOE per Boe of $14.03 was below the low range of guidance and does reflect our improved operating efficiency, we have not adjusted guidance for LOE per Boe. We remind you that in the fourth quarter we will accrue for a CO2 under-delivery for the Century plant that will likely be between $29.5 million and $36 million. This will result in an increase in LOE per Boe of about $1. Also please keep in mind that as a part of our strategic direction review earlier this year, we will continue to reduce our Mississippian rig count to average 22 rigs running for the second half of the year, which is below our second-quarter rig count of 26.

At this time, Tahisha, we'd like to open up the question-and-answer period of the call.

Thank you.

(Operator Instructions)

Neal Dingmann, SunTrust.

Good quarter. James, either for you or David. Obviously great results on this middle horizontal Miss. Was wondering if you would look at that acreage, any idea of what percent or total acreage you might have potential for this type of great play?

Hello, Neal, this is Dave. Won't give a number at this time because we're still in the early portion of developing the different zones in the testing program. But we have found one area that seems to be pretty strong, and so we're just continuing to push the envelopes of that particular region.

Okay. And then obviously, as you had mentioned, Dave, that the type curve obviously on the average is now up to 3 -- or it looks like the 30-day IP was up to 377. I guess what I'm wondering, will you put out any time soon, had the type curve overall improved or your thoughts on an average type curve improvement?

Neal, won't comment on type curve at this juncture. Every year at the end of the year is when we revise or make any edits that are needed. At this point we are encouraged and will continue to watch the wells. As then as we close out the year we will go through a formal process with our team and our auditors and come up with that answer.

Okay, and then --

One other thing, on the stacked pay, if you look on our presentation that we have up on the website, we have a detailed map in there of where we show the different members of the Miss, upper, middle and lower and how that extends across the play. While we don't have specific acreage, that can give you an idea of the stacked potential we see really across most of our leasehold.

That helps. Lastly, Eddie and James, you mentioned about cutting the costs, or just overall spending. Wondering on any thoughts you could give on potential acreage you think you will keep between now and on an end of the year exit rate.

In terms of acreage that we'll keep?

Yes, sir.

Let me just talk about acreage for a second and give you a few stats. With about a 425 well program, we are hold between 200,000 and 250,000 acres annually, depending on how many second and third laterals we're drilling. That's on an annual basis. On the total play, in 2013 we have 250,000 acres that are expiring. We have extensions on 60% of those at $131 an acre, and we think we will extend probably 75% of that 60%, if that makes sense. If we extended it all that would be $20 million. In 2014 we have, for the whole play, 740,000 acres expiring, but we have extensions on 80% of those at $127 an acre. That would be $75 million. We think our budget next year in land will be in the similar ZIP code of $100 million. In terms of what we've HBP'd, because we get that question too, for the total play we've HBP'd about 17% of the acreage, 40% in Oklahoma and 7% in Kansas. That's the total play, Neal.

Let me just talk about the focus areas for a minute. We have 925,000 gross with 615,000 net acres. That's roughly 200,000 on a net basis in Kansas and 420,000 in Oklahoma. We have HBP'd 42% of the focus areas, 48% in Oklahoma and 28% in Kansas. In 2013 we have 170,000 acres expiring in the focus areas again. We have extensions on 42% of that at $162 an acre and we anticipate we'll extend probably 80% of those. In 2014 we have 150,000 acres expiring in the focus areas. 42% again, we have extensions on and that's at $271 an acre. That would be $17 million if we extended it all.

So between the acreage that we're going to HBP by drilling, the extensions we have, which are very reasonable, again in the $130 million range, and the land budget we have, we feel very comfortable about our land position, the ability to keep what we want. Now, we will let some land expire that we don't plan to drill, or is not prospective, or we haven't had positive results. But, what we've also been able to do is add in acreage. Year to date, in our focus areas, we've added 35,000 acres at about $700 an acre, so about $23 million. These are in the best areas of the play that we like, offsetting our best producing wells. While we will let some acreage expire, we will renew the acreage that we like and we'll add in even better acreage. I know that's a long answer, but I hope that gets some of the acreage and HBP and extension data out there.

That's great color. Thanks, guys.

Charles Meade, Johnson Rice.

I'd like to ask a little more about the Middle Mississippian zone and try to decompose that 710 Boe average. Specifically, one, could you give us the product split on that average? And then the second thing I'm wondering there is what the variance behind that average is? And specifically if there's one well that's really pulling that average up or if alternatively those wells are pretty tightly clustered around that average?

Okay, Charles, this is Dave. First part of that question, the split is approximately 45% oil, consistent with what we've seen with the rest of the play. In terms of overall delivery, what we're seeing is when we target this part of the zone as we've expanded, naturally the primary interval is the one that we want to target first. As we started the play, we started at the top. As we started looking at the C and seeing the results that were coming in, we started moving more in that direction. So, again, what we're seeing is very strong production.

In terms of the repeatability, we are seeing some very tight performance. So overall, it looks like it's very strong and of course, we will have to watch other time how the other wells come in. At this point it's a pretty tight band. We don't have that production dominated by a single well by any stretch.

That's great. That's great color, David. I mean, really, of course it's early but it looks like it could be a step change. The second thing, I think you touched on this briefly, but I want to make sure I understand the nomenclature you're using when you're talking about the middle zone. It sounds like what you're talking about is the Warsaw C and you're targeting that in areas where that's not the member right below the unconformity. Is that correct?

That's correct, Charles. I can tell you've done a little research on it. We used the Middle Miss, but you can use the term C too to explain it. Yes, what you see are different processes, intervals within the Miss itself and even within the different benches. When we talk about Middle Miss, for clarity we try to break it really into upper, middle and lower. But in this case we are talking about the C.

Got it. This will be the last thing I try on this. If I look at your sub crop map here, what it looks like is that you've got a stretch perhaps, looks like right through your core of Woods, Alfalfa and Grant where that C would be the member that's not immediately the glow. Is that your fairway at this point, do you think?

You know, that's an area that we're certainly interested in. But you're correct in that as you move to different parts of the play, what could be characterized as middle is different than the C. But in particular, what we're talking about here, you've identified correctly, the C is the middle in that portion and that's something we're excited about.

Okay. Thank you for that color. We'll certainly stay tuned on this front. Thanks.

Dave Kistler, Simmons and Company.

Want to focus a little bit on the 3D that you've done. Can you talk a little bit about what that's done for increasing the probability of identifying better-performing wells? On that landscape, talk about it in terms of what that does to inventory. Is that taking up aggregate inventory? Or is that also identifying areas you don't want to go to and reducing a section of inventory? Trying to get a better picture on that.

Okay, thanks, Dave. I think the key issue with 3D, I think we've always said as we started the play we felt like there was sufficient historical production to be able to target the best intervals, the most prolific intervals. We found that really to be the case. As we progress through the play we're adding in all the tools available to us. So in Q2 we picked up a pretty significant 3D survey in one of our project areas. How we've used that, at least initially, there are pretty large fault zones that you can lose circulation in, and so we've been able to avoid drilling some wells that may have been problematic for us. We've also seen some trending and some success where production has been higher around some of those fractures. So we're starting to integrate that data and see if maybe we can repeat that performance.

Still a little bit early for us to claim success associated with the 3D itself in terms of higher rates, but our scientists have been looking hard at it. We've avoided a few wells that are in the area of those lost circulation zones. It does look like we're going to be able to pick some stronger production perhaps off that data. So we see it really as another tool available to our teams and we're going to continue to expand our inventory of 3D.

Okay. So if I'm trying to digest that, I know it's pretty early days, in aggregate you feel confident that that's reducing the statistical variability between the wells that you're drilling; is that a fair statement or too early to tell?

I think it's fair that it could, Dave, but I wouldn't say that at this moment. It's our intent that that would be the outcome.

Okay. Looking at the 111 wells that you guys drilled this last quarter, can you talk a little bit about the statistical variability? Was it tighter than it's been in the past? Any color there would be helpful.

We have reduced the variability. Since we're in our project areas we have more data, our teams are getting much better. I'd mentioned the seven variables. All those things are contributing to a tighter performance band. So, yes, we're seeing the result that we'd hoped for.

Okay, and on that 111 wells, it looks like there was a little bit of a mix shift of drilling, more Kansas wells versus Oklahoma. That probably ties to the HBP comments that James made earlier. Was there any kind of statistical deviation in terms of well results in the Kansas area versus the Oklahoma area of your six core areas?

Typically, no. With these focus areas, even if we're on the Kansas side we're seeing strong production as well. I would say it's fairly typical to what we've seen in the past and would be consistent across the border.

Okay. Appreciate that. One last one on the arial extent of that Middle Miss, it also looks like that works its way up into Kansas pretty dramatically. It doesn't look, at least in the map that you're laying out, that that's as stacked-oriented a pay zone. Is there a performance deviation because it gets shallower up there? Have you not tested it up there yet? Any kind of thoughts on that.

I think our program in Kansas to date has been very broad. So we haven't been specific enough to make that kind of conclusion. But as you know, that middle member, that specific zone or the C, whatever term we may use for it, it does cross the border and we do think that there's production in that interval along the whole trend.

Okay, great. I appreciate the color, guys. Thank you.

David Deckelbaum, Key Banc.

A couple of my questions just to start off, is what's your outlook for the Gulf of Mexico right now as you go into 2014? And given some of the declines you're seeing so far what sort of run rate CapEx do you think you need to put on those assets to keep production flat?

Sure. We did talk about a couple of the pipeline curtailments and other things we had in the second quarter that impacted our production a bit. We still see year over year about a 10% decline in the Gulf of Mexico business. Averaging about 31,000 barrels equivalent per day and we'll average about 28,000 this year. We do have the well that Dave mentioned that's about to come online. So again, we think we will average about that 28,000 a year. I wouldn't extrapolate a first-quarter to second-quarter decline as how the rest of the year is going to progress.

Into '14, I think we'll have a similar, call it, $150 million to $200 million CapEx plan. We haven't gone through our full 2014 budgeting process yet. We are doing that now. We will come out with an exact plan in the November time frame. I would expect something in the $150 million to $200 million range and keep that production relatively flat. If we're at the low end of that, we may have a small amount of declines in the Gulf of Mexico.

Okay. Could you just remind me, how much down time are you baking in in your guidance right now for hurricane season this year?

About 250,000 barrels of oil equivalent in the July, August, September time frame. August, September, October time frame.

Okay. My last one, on the successes in this quarter on the IP rate improvement. There was a discussion about the introduction of ESPs and someone else brought up EURs changing. Obviously it's early, but is the conclusion, at least from your perspective, other than being in the focus area, and perhaps there's a little bit more energy there that the increased IP rates are more related to the introduction of ESPs? Or do you think it's more geological?

Yes, David, we think it's a combination. We've ran a significant number of ESPs in the last 18 months. So just for reference, we have 285 in the ground as of today. So there wasn't, say, it was a slightly higher concentration of ESPs this quarter, but not significant. So really what we're seeing is a high-grading of the technology that we're using, our sub surface model coming together, and then mating up the appropriate artificial lift technology for the reservoirs that we're in.

I've heard that and wanted to spell that that's not the driver. We did have some very, very strong wells come on in the gas lift. One of our 1000-Boe-per-day wells was on gas lift. So there's no concentration or over weight of particular performance set that's ESP linked. You know they're certainly appropriate in parts of the field and in other parts after they're not. It's really the correct application and picking the right zone for development.

Great. Thanks for the color.

James Spicer, Wells Fargo.

I have a question on your guidance. It looks like your full-year guidance implies a slight decline in production during the second half of the year. Your rig count drops to 22 rigs from an average of 26 in the second quarter. And then in 2014 you're projecting double-digit production growth with an average of 25 rigs. Am I understanding that correctly?

That's right. You got it right.

So you're adding three more rigs from the second half of the year and your production is going from flat to declining to double-digit growth.

Keep in mind, the Miss this year, with our new guidance we will have 70% liquids growth and 66% total production growth. That's averaging that 25 rig count. If you think about next year averaging a similar 25 rig count, again that's just the Miss. We have slight declines in the some of our legacy Permian assets and a slight decline in Gulf of Mexico. But, yes, we can get to double-digit production with that 25 rig count next year.

Okay. Great. You talked about this for the Gulf of Mexico in terms of how much CapEx you thought you might need to spend to just keep production flat. What do you think that number would be for total corporate production?

It's not really a model that we run. We're trying to grow our production and net asset value and deploy our capital to get the best return for the shareholders. We don't have a number that would be, a case that would be flat production. It's not something we look at at this time. If the world would change and commodity price environment would change, or capital availability would change, it's something we'd look at, but it's not something we have right now.

Okay. My final question is, your net leverage is obviously going to be increasing here over time. Wondering what your comfort level is in terms of how high you'd like to see it go before you'd want to address that?

Well, I think we're pretty comfortable at 3.5 times. I think we get nervous as it exceeds that and would only do it for a short period of time. We would address the issue directly prior to getting to 3.5 times.

And, James, you know the leverage, you take a lot of variables into account there. When your debt maturities are coming up, we don't have any until 2020, how hedged you are, if I'm completely unhedged I'm pretty nervous at 3, 3.5 times. If I'm completely hedged for couple years, it gives me a little more cushion. So I think there's a few other variables that go into that, just depends on those.

Yes. Understand. Thank you.

Duane Grubert, Susquehanna Financial.

You guys are doing a lot of really interesting experimentation in use of stuff like the rotary steerables and all that. I heard some word that some operators are trying vertical wells. I would like you guys to comment on is there any applicability of verticals in the foreseeable future?

Yes a, Duane, this is Dave. We don't see the primary development as vertical. We do see segmentation or compartmentalization of the reservoirs. We do think you get the highest rate of return from a horizontal development. That said, there may be parts of the field where verticals could work. We've drilled some verticals, we'll probably drill some in the future. But as you can see by our CapEx program and where it's being spent, primarily we think it's a horizontal play. But we do know people who have drilled some verticals and done well. And we might drill some as well, just depending on the situation.

And then in terms of sub zones, Devon is out there this morning revealing its Woodford development. I know you guys have in the past acknowledged that there's some Woodford potential out there. What's your thinking specifically on the Woodford, where you're at in terms of feathering it into your thinking?

Okay, great. I'm glad you asked the question. We do have a significant amount of Woodford acreage in our play, very much similar to Devon's, particularly in Grant county. So we are actually a partner with Devon on one of those wells, or at least one of their wells in the area. And we actually spud our first Woodford well this week. So obviously it's very early and not something we really want to talk about until we get further down the path. Yes, we see this area as certainly prospective for Woodford.

Duane, if you remember we talked about the Woodford potential as part of the stacked pay program at our Analyst Day back in February. So it's something we've been working on for quite a while, getting it mapped out, getting the locations together. It's something the team has done a great job putting together. As Dave mentioned, we're start on that program this quarter.

Yes, great. Finally in the Gulf of Mexico, where you have chosen to do some exploration work, how might we think about you doing a proportion of your Gulf of Mexico program as exploration? How do you make that allocation choice? And might we see you do incremental acquisitions, given a lot of property acquisition activity out there lately?

Sure. So we'd caution the investor group that we're not out drilling sub-detachment wells, by any means. But we do have a significant amount of acreage that we have 3D seismic on. So we will participate in exploratory wells that are in and around our existing production. They may or may not be our own, but they could be others. We will be conservative with that exploration program. Certainly, where we feel like it's a lower risk opportunity we would pursue that. In terms of acquisitions, the team does look at small bolt-on acquisitions and certainly there's room for expansion as those make sense. James, did you want to follow up on that?

We do look at deals, Duane, in the Gulf of Mexico. They obviously have to compete with capital for the Mississippian and the rest of our program. We could boost our production quite a bit if we just wanted to do bolt-on acquisitions in the Gulf. We want to make sure that we're deploying capital in the best way and developing out the Miss in a balanced program with the Gulf.

Great. Thank you

Adam Leight, RBC Capital Markets.

A lot of stuff has been covered. I'll just tidy up. If I missed it, I want to get a sanity check on when you thought the production would bottom out and start to turn up again? Are we looking at second quarter next year?

Next year or this year, Adam?

Well, if we're looking at declines based on your guidance for this year, we bottom out end of year, early next year, and then start to creep back up again?

I see your question, thank you. Sorry. Yes. We hit the trough in production this year and start growing again certainly in the first quarter of next year. That's correct.

Okay. And on the -- if I missed this also -- on the Middle Miss zone did you A, give a D&C cost? Is it pretty similar?

It is. It's right in that $2.9 million to $3.0 million range with submersible pumps.

Okay. What about water? Is that also looking to be similar to what you're seeing in the other zones?

Yes.

All right. And then more on water. You've increased your ratio of producers to water wells. What is the maximum you've seen so far and what do you think is an optimal ratio, if there is a consistent?

We're clearly over 10. There may be areas where we are a little bit higher than that. I think ultimately the system is going to serve us well in is that all of SWDs or a good portion of SWDs are connected together. Even as you extend the field, you can continue to add wells and put it into the existing system. We have got two opportunities here. There's one of drilling additional wells within the focus areas themselves and then as we expand out, acquire others in the area. Then we can also flow back to that set. I really think that 20 horizontals to one producer is possible and really, perhaps higher than that as we proceed with the development and the water rates fall off over time. It's a valuable system to have.

Got it. Okay. And then have you gone anywhere on the monetization effort? Have you had any interest? Have you had any discussions or is that on hold for a while?

We have discussions, Adam, but it's really on hold. We think right now that the value that that system gives us in terms of keeping our costs low and consolidating the best acreage positions in the play, offsets any need to monetize it right now. We're still investing capital in it. We've still got it set up where we could monetize it at some time, but not something that we're going to do right now.

Okay. And then on the land acquisitions, particularly in the Miss, is this more in the six core counties? Is it tucked in acreage?

Yes it is. We've added about 35,000 acres in the focus areas. We have about another 30,000 acres that we've added year to date in the rest of the play. A lot of that was just roll-over acreage from the leasing activity last year that closed this year. Going forward, a vast majority of this tuck-in acreage, whether it's pooling or buying leases, has been in the six-county focus area.

Okay. Lastly, remind me, what do you think your inventory is of undrilled locations in the six core counties at this point?

It's about 3,000, roughly 3,000 locations. That's on about 615,000 net acres.

Okay, great. That's it for me. Thanks.

(Operator Instructions)

Tom O'Shea, Castle Hill.

Good quarter, guys. Just wanted today ask, most of my operating questions were answered. From a general perspective on cash flow you talk about you're comfortable at 3.5 times leverage, and if we project out next year the Street has you burning around $1 billion of cash. You have around $1 billion of cash now and that gets you to about 3.5 times leverage if your EBITDA goes up a little bit. What happens in 2015? Do you burn another $1 billion in 2015? How should we think about that year? And if so, what's your strategy to bridge that funding gap? My second question is, if that's the case should you find a larger partner out there to either merge or sell to? Thanks again.

You're welcome. Let me address it in a couple ways. Yes, we do have $1 billion in cash right now, but we also have an unused revolver of $775 million. We think we could even expend that revolver if needed. It's that liquidity that gets us through 2015. So we think we've got 2015 covered as well. Also our EBITDA and cash flow will be growing over this time, so our funding gap is shrinking every year.

That being said, funding past '15 is something that we think about often. We've talked about the other monetization tools we have, which would be maybe our infrastructure system that could be sold or MLP'd or monetized. There's possibilities still to do more joint ventures in the play. We have royalty trust units that we can sell, and there are other options available. So post '15, we do have several levers that we can use to fill that gap. I think we're comfortably funded between now and then with our available liquidity. In terms of longer term, should we merge into another partner, we'll do the best thing for the shareholders. We think the right course right now is to take this capital and to put it in the Miss, where we're seeing very good returns.

But I mean you'd have to -- but drawing on the revolver wouldn't help you keep your leverage at 3.5 times. As a bond holder, I'm just trying to figure out in 2015, how you stay within your guidance of 3.5 times leverage. You would have to get your EBITDA up 25%, 30% if you're adding $1 billion of revolver debt and you're spending your cash in 2014. From that perspective, as a bondholder, I'm thinking maybe this is better off in the hands of a larger company or I'm missing something. If you could just address that.

I don't think you're missing anything. The only thing I would say is 3.5 times is a comfortable spot to be. Should we bump up against a little higher than that for a short period of time, that would be okay. Again, it's going to depend on our hedges, our bond maturities, commodity price environments, other things. Keep in mind that as our production grows, our oil is growing at a higher rate than our total production. So we do get some pretty good growth in EBITDA. So I would think that between 3.5 and 4, we're comfortable with that, depending on our hedge position. As we get closer to that, we will look at ways to bring that down, whether it's monetizing, selling something, bringing in some additional capital.

Or selling. You could sell the whole Company to a larger company, right?

That's always an option.

Okay. Thanks for helping. Good quarter.

Craig Shere, Tuohy Brothers.

Congratulations on the quarter. A couple questions. First the 3,000 locations on the 615,000 net acres, you're still assuming close to three wells per section, not four. Is that correct?

No, we're assuming four. But we have about 550 wells drilled in that focus area. So I'm rounding a little bit. I think you could do the exact math, you get to 3,800 locations, back off 550, so you would be at 3,200 locations. I'm just calling it approximately three.

Okay, that's fair. Then of course, we have the stacked pay potential.

Yes. So I'm just talking about single zone locations here when I say 3,000. Not if you've got multiple zones or stacked pay, that obviously multiplies that number.

Fair enough. I want to understand a little more of this 25 average rig count this year and next. That's one way to look at it in terms of HBPing a specific amount of property that maybe you're comfortable with annually, and having an equal average between the years. Another way of looking at it is, we're ramping down very hard and then we're ramping up a little bit. I wonder if this is more tracking the drilling liabilities on the trust. As those dissipate and run out, and more and more of your drilling is cash flowing to the C-corp, that you have more and more comfort at raising that rig count. In other words, I'm asking about, would the direction of an up-tick in '14 likely lead to an up-tick again in '15?

Yes, it's a good question, Craig. You're right on the numbers. I can tell you're focused on it. We finished our drilling obligation for SDT in the second quarter. So that's three rigs that we'll continue to drill, all things being equal, but they will be drilling SandRidge wells, not SDT wells. While our total production won't change, because it's consolidated, they are going to be drilling 100% working interest, give or take obviously -- or revenue interest wells -- versus a net SandRidge 20% revenue interest wells. So that, while it's not going to change your production, again because it's consolidated, it has a very positive impact on your cash flow.

Scroll forward to next year. The SDR Trust will fulfill its drilling obligation in the first or second quarter. Similarly, you'll have three rigs that would have been drilling SDR wells that will now be drilling SandRidge wells. Scroll forward to the end of '14, the Permian Royalty Trust will finish its obligation. So again, those three rigs will be drilling SandRidge wells with a full revenue interest and not at 10% or 20% revenue interest. You're right, as those rigs roll off the trust we finish the trust capital obligation, we get a lot more earnings power and cash flow from those rigs than they would have been drilling trust wells.

Right, so there's two ways of thinking of this. One, staying flat with rigs, you're actually increasing net to SD's account. Two, as you are increasing net to SD's account, in other words, cash flowing better and better, do you have more and more comfort deploying more and more rigs?

Yes, we do. We have comfort now deploying many more rigs. We were at 32 earlier that year. We could deploy more rigs. We have plenty of locations to drill, and the infrastructure and resources and team here to do that. It's really a balance between growth rates and our capital allocation, keeping our couple years of liquidity and keeping our funding in check. So we could certainly deploy more rigs, it's just a matter of capital.

Understood. That dovetails pretty well for my next question. You've laid out a very good plan of where the money is coming from for 3 years forward, 2.5 years. But one question is long-term. Would you be interested in being opportunistic with the Gulf of Mexico or do you now see that as core?

Well, all of our assets are for sale at some price. We're capitalists, we're here to maximize the share price. If the valuations in any part of the business, Gulf of Mexico, Mississippian are high and people are willing to pay us a good price for those, more than we think they're worth in our enterprise, then we would certainly look at selling those, any of those. Yes.

But more specifically, you've repeatedly and appropriately emphasized the need to have financial bandwidth to invest appropriately in the highest return Mississippian opportunity, which you seem to be improving quarterly. So given the Gulf of Mexico was originally a bit of a 90 degree turn, at some point if you can get out at similar or better pricing than you got in over a 2, 3 year period, would that be an interest? Or do you just enjoy the free cash flow for the foreseeable future unless somebody gives you much better pricing than you paid, you're going to keep it?

I think it's probably somewhere in the middle. We'll weigh this option, the Gulf of Mexico with other options, monetizing our salt water disposal system or a joint venture. We will look at all those as we do every month and every quarter. Whichever one is the best option for the Company and for the funding, we will look at it. Yes, is that one of the options available to us to fill the gap post '15? Sure. It's not on the agenda right now. It's not the plan right now. But it's one possibility we have to fill that gap post '15.

Understood. Appreciate the answers.

Joe Allman, JPMorgan.

In terms of the higher-rate average well that you drilled in the second quarter, does that also lead to a higher EUR than for the wells in prior quarters?

Hey, Joe, this is Dave. We're not going to project at this point an extension to EUR. As you know, we just need an amount of time to evaluate a well's performance before we could do that. So even with the ESPs, our hope is that we can take the bottomhole pressure down lower over time and ultimately achieve greater returns from the well. But at this time, we're not trying to project an EUR increase.

Okay. Thanks, Dave. In terms of these higher-rate wells, how many of those do you have left in your inventory versus the lower-rate wells?

Well, I think I'll just speak to it from a program point of view. As James mentioned, we have close to 3,000 wells in our project areas. We would envision that those 3,000 wells would match our existing type curve performance.

Okay. Is the intention to use ESPs on pretty much all the wells going forward?

No. We think we will be at that consistent level between 40% and 50%. If we over-weighed in a particular area because we find it's very rich, we could go up to 60%, 65%. But I think going forward what from what we see today, it's going to be a 40% to 50% distribution for the foreseeable future.

Got you. On the cost side, you lowered the cost from $3.1 million to $2.95 million. If you include infrastructure what would the apples to apples cost be?

If you include infrastructure?

Yes.

We dropped back a significant number of disposal wells for the quarter as well. I think we'd probably layer in another $200,000, $250,000, if you wanted to make it apples to apples.

Joe, we'd use as a round number, $200,000, which is a 10 to 1 saltwater disposal ratio on a $2 million disposal well. I think our wells are a little bit higher than $2 million, because we're drilling some deviated, some high-angle wells, and some larger well bores. Our ratio is a lot higher, 14 to 1 in the first quarter, 12.5 to 1 in the second quarter. It would be somewhere in that ZIP code of $150,000, $200,000.

All right. Very helpful, thank you.

Ladies and gentlemen, that concludes the Q&A portion of this conference. I would like now like to turn the conference back over to James Bennett for any closing remarks.

Thank you. In summary, we're pleased with the progress we've made this quarter and think we're set up very nicely for the remainder of 2013 and 2014. I want to thank the excellent work and dedication of our talented teams of employees. Thank you for joining us on this call and we'll see you on our third-quarter call.

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