Duane Grubert - EVP of IR and Strategy James Bennett - President and CEO Eddie LeBlanc- EVP and Chief Financial Officer Dave Lawler - EVP and Chief Operating Officer.

Neal Dingmann - SunTrust Charles Meade - Johnson Rice Stephen Shepherd - Simmons Robert Carlson - Janney Montgomery Scott.

Good day, ladies and gentlemen, and welcome to the First Quarter 2014 SandRidge Energy Earnings Conference Call. My name is Glen and I will be your moderator for today. At this time all participants are in listen-only mode. Later we will facilitate 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. Duane Grubert. Please proceed, sir..

Thank you. Welcome everyone. Thank you for joining us on our conference call. This is Duane Grubert, Executive Vice President of Investor Relations and Strategy.

With me today are James Bennett, our President and Chief Executive Officer; Eddie LeBlanc, Executive Vice President and Chief Financial Officer; and Dave Lawler, our Executive Vice President and Chief Operating Officer.

We would like to remind you that in conjunction with our earnings release and conference call we have posted slides on our website in the Investor Relations section.

Keep in mind that today's call contain forward-looking statements and assumptions, 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 the discussion of these measures can be found on the website. Please note that this call is intended to discuss SandRidge Energy and not our public royalty trust. So now let me turn the call over to our CEO, James Bennett.

Thanks Duane. Let me kick off by recapping the first quarter, some of the accomplishments we've made developing our asset base and how all of that positions us to continue to execute our three year plan. In February, we closed the divestiture of the Gulf of Mexico assets.

Now our focus is completely on the Mid-Continent, Oklahoma, Kansas and Permian Basin.

We want to operate and focus our people and our capital where we have real competitive advantages such as our acreage position and scale, the knowledge base of our teams and a well set of over 1,200 horizontal wells, having the lowest well costs in the basin and our extensive infrastructure. On this, our Mid-Continent asset base continues to perform.

The severe winter weather, which Dave will review in more details, slowed our production and well completions and drilling. But now the program’s back on track, thanks to the great work of our operational teams.

Notwithstanding the weather challenges, we managed to deliver an excellent quarter with a well set containing the second highest ever 30 day IP which is over 400 Boe per day and the most ever 7 wells over a 1,000 Boe per day 30 day IP. Next, we continue to improve and add to our opportunity set with Northern Garfield being example of this.

Thanks to the great work of our geology and engineering teams, we set up an appraisal well test program in this area. And after the successful 11 well appraisal program, we have now launched a full development effort here and added Northern Garfield into our focus area.

I like what this area brings to our asset mix as we're seeing more consistent results and our tighter distribution around our IP rates, higher oil percentage and the lower water cut; also in this area, we have identified additional stack pay opportunities.

So, adding these 10 townships increases our asset base, scope of the play and our opportunity set by adding another area of high rate, high return oil wells. Recall that early this year we also added Sumner County to our focus area and that area continues to perform with high oil content and IP rates above our type curve.

We continue to develop our multiple zones in the Mid-Continent. In addition to the upper Miss, we’re having success to middle and lower Miss and Dave will talk about our Chester and Woodford programs. Next, we continue to innovate in the play, and an example of this is our multilateral well program.

At Analyst Day two months ago, we showed you examples of our multilateral and stack lateral prototypes. While still in testing, these programs are taking hold and have delivered excellent results here, both in terms of cost and production rates.

We highlighted one in the earnings release, the Kansas stack lateral we had doing over 700 barrels of oil equivalent per day and on the cost side of these multilaterals by lowering the effective well cost to about 2.5 million per lateral.

This program has a potential to make already good areas of the play even better and importantly allow us to access other zones that otherwise would deliver lesser returns at a single well design with the standard $3 million well cost.

On another matter, we continue to develop our midstream saltwater disposal business and explore alternatives to that business. In the quarter, we added another third-party producer to the system. We also filed the private letter ruling with the IRS and are proceeding with an audit of the financial statements of that entity.

So, tying these together, our asset continues to perform and we deliver better results every quarter. We’re expanding opportunity set and growing our net asset value by adding, both geography to the play as well as exploiting our other zones. We continue to bring innovative solutions to bear on our asset base such as our multilateral program.

We’re funded with almost $2 billion of liquidity and growing cash flows. And we laid out a three year plan that we’re still confident in our ability to deliver 20% to 25% compound annual growth in production and a higher growth in EBITDA and cash flow over three years.

Recall that we rolled out a mission statement in Q1 of this year, which was to create the premier high return growth oriented resource conversion company focused in the Mid-Continent.

Our teams remain intensively focused on this and the themes we outlined at our March analyst day needed to execute this mission and we believe this mission will provide returns for our shareholders.

First and most important, we need to continue to deliver profitable growth and cash flows by converting our resource base into cash and asset value; we need to capitalize on our competitive advantages here in the Mid-Continent; we need to continue to drive innovation in the business and create more upside; continue to improve our per unit cost in all areas well cost, LOE and G&A; improve our leverage and balance sheet and getting closer to funding, CapEx within cash flow, and driving shareholder returns.

Our job as managers is to allocate capital in the highest risk adjusted returns and we come to work every day thinking about that point. And finally I want to thank our employees, both here in Oklahoma City and out in the field for their excellent work, dedication to safety and to our mission and commitment to delivering returns for our shareholders.

With that let me turn the call over to Dave Lawler..

Thank you, James. And good morning to everyone joining us on the call. During the first quarter we made significant progress on our value enhancement themes.

We improved well performance, expanded the resource base, increased capital efficiency with novel well designs and enhanced the value of our existing well set with the latest artificial lift technology. All of these initiatives directly support our three year plan and I will provide greater detail on each in just a few minutes.

The first quarter also included a number of challenges related to extreme weather in the midcontinent region. This was the 12th coldest winter on record and the prolonged freezing temperatures created disruptions in our development program.

As a result, our Mississippian production averaged 50.6 MBoe per day, which was 2% lower than in the fourth quarter of 2013. This decline is linked to weather and represents the deferment of 300,000 BOE. To give you a better feel for the impact on our efficiency, we connected only 71 wells versus the plan number of 94.

In addition the vast majority of these connects occurred late in the quarter, so the primary production benefit will be realized in Q2. In spite of the weather challenges, our teams responded quickly and connected 45 wells in April.

The production from these wells has put us back on track with our production targets, so we have elected to leave full year production guidance unchanged. To recover the deferred volume, we are accelerating key projects across the play and we believe these actions will allow us to make up the production in the coming months.

In terms of CapEx for the quarter, weather also slowed our expenditure rate and correlates with the decrease in production. Approximately $25 million was deferred and we anticipate the majority of this amount will be spent in Q2 and Q3 as we get caught up on our well delivery program.

For the 71 wells delivered to sales, the average cost was approximately $3 million. This cost includes 56 days of weather-related rig downtime. In many cases the downtime was due to county ordered moratoriums on heavy load permits or loss time to saw equipment. It also includes an ESP implementation rate of 97%.

We anticipate that our average well cost will be under $3 million in next few quarters as we improve efficiency and drill more second and third wells from multi-well pads. For reference, 20% of our Q1 wells were on single pads and 80% were drilled from multi-well pads.

Moving on to well performance, our midcontinent 30 day IPs averaged 410 BOE per day or 29% above type curve. This increase is primarily due to our sub surface modeling efforts and the use of Open Hole packer systems in our completion operations. We also delivered seven wells with 30 day IPs over 1,000 BOE per day.

This is the largest number of high rate wells in a single quarter since the inception of the play. One of the seven wells was drilled using 3D seismic and was positioned near several uneconomic wells. The seismic identified a settled structural feature and it has now allowed us to map additional targets in multiple sections surrounding the discovery.

It’s also important to note that this group of high rate wells is spread across the play located in Alfalfa and Woods County in Oklahoma and Harper County, Kansas. Beyond improved well performance, we have made significant progress on the value enhancement themes we’ve presented at Analyst Day.

As with [Sherman] County last year, we’ve been testing various geologic concepts in Northern Garfield in Southern Grant with the intent of expanding our resource base and adding high quality drilling inventory. This appraisal program has been highly successful.

During the first quarter our team drilled 11 test wells primarily in Northern Garfield, which delivered an average 30-day IP of 406 BOE per day or 28% above type curve, the oil content on these wells was 55% it helped deliver an aggregate rate of return of 66% with an average well cost of $3.1 million.

We are confident that we can increase this initial cost as we continue to develop our learning curve in the area and implement multi-lateral and pad drilling initiatives. With this appraisal success in Garfield, we are adding 10 townships to our focused area and nearly 40,000 net acres for near term development.

Further to the north we continue to see success in the Sumner County project area. Four laterals were brought online during the quarter with an average 30-day IP of 353 BOE per day or 11% above type curve while these wells didn’t contain high gas volumes, the oil content was impressive.

Of the 353 BOE per day the oil content was 67% or 236 barrels per day. Importantly with NGLs included we expect a total liquid content to be near 80%, we currently have five horizontal rigs drilling in the area with three rigs testing geologic concepts and we one rig drilling water disposal wells to support future development.

Our Chester horizontal program is up and running, but the group of wells drill back to back during the quarter. Presently one of these wells is online and delivered a robust 30-day oil IP of 194 barrels per day. Five additional wells are projected to be online over the next few weeks.

We were the first who pursue the horizontal Chester in the region and we're continuing to expand the concept along the regional sub crop. We also continue to see encouraging results from the Woodford program with two wells coming online during the quarter. The average 30-day IP was 133 BOE per day with the 71% oil content.

These are the last two wells based on our initial geologic model. As shared during Analyst Day, we have developed an updated geologic model that we will utilize to test the next three wells. This new model targets locations with proximity to Misner and Hunton production and where the Sylvan shale will provide a frac for you.

We now have a total 6 Woodford wells online as part of the 9 well appraisal programs we launched last year. In terms of capital efficiency, we completed a successful dual fracs lateral well and Harper County, Kansas. From a single surface well head, we landed one lateral in the upper Miss and one lateral in the lower Miss.

The total cost for this project was $5.2 million or $2.6 million per lateral, this cost can be compared with two separate wells that would typically be in a range of $6 million combined. The well delivered a 30 day IP of 707 BOE per day at 44% oil.

We believe this noble well design can be exported across the play where we have two stack zones to develop. In the second quarter, we will have three additional dual lateral wells online and we'll report on those at our next call.

We also pleased with production results of our first trial lateral well which was drilled late last year and Harper County Kansas. We believe this well design can be repeated in many parts of the play for around $4 million per section.

Learning from our initial work on the dual lateral and tri-lateral projects, we plan to develop two full sections by the end of Q3 that will have 4 to 5 laterals each and will extend from a single well head position in the corn of the section.

We're excited about these programs since they demonstrate our ability to conceive and execute innovative concepts and highlight our commitment to deliver breakthrough economic results which ultimately translates in the shareholder value.

We also made significant progress increasing the life cycle value and the EUR of our existing asset base with advanced artificial lift technology. During the quarter, we converted 34 existing wells from gas lift to ESP or from gas lift to beam pump. The results were stellar.

The projects increased production by 1,461 BOE per day and of this amount 402 barrels per day was oil. The single project conversion economics routinely exceed a 100% rate of return.

In closing, while our operations were impacted by the extreme weather, we have developed plans to recover the deferred volume and still expect to achieve year end production guidance. Our employees did an exceptional job working through the difficult situation in a safe manner and the extra effort is greatly appreciated and noted.

Perhaps more than any previous quarter, we achieved greater progress on our value enhancing teams.

We discovered yet another part of the play with premium economics in Northern Garfield County, accelerated Chester oil development, where we were the first mover, implemented the use of 3D seismic, developed high rate oil wells in Sumner and we are continuously improving our capital efficiency and economic returns through the use of novel well designs and advanced artificial lift technology and systems.

We look forward to sharing more as the year unfolds and we thank you again for joining us today. I will now turn the call over to Eddie LeBlanc, our chief financial officer..

Thanks Dave. We've ended this quarter having completed the divestiture of the Gulf assets. So, while we will discuss the actual EBITDA illustrating our reported performance, we'll additionally provide pro forma information for the currently owned and operated assets.

The first quarter of 2013 is being adjusted for the divestiture for both the Permian and the Gulf assets and the first quarter of 2014 is being adjusted only for the Gulf assets. Adjusted EBITDA as reported for the first quarter of 2014 was $230 million or $32 per BOE, as compared to $270 million or $30 per Boe for the first quarter of 2013.

Pro forma adjusted EBITDA for the first quarter 2014 was a $177 million or $30.49 per Boe compared to $112 million for the first quarter of 2013 or $22.77 per Boe. This $65 million increase in EBITDA was comprised of $53 million of improvement in revenues driven by an 18% increase in volumes, 72% of which was an increase in liquids.

This was partially offset by a $7 million increase in production expense associated with the increase in production, also included is an $8 million improvement in EBITDA for midstream and other and a reduction in G&A of $11 million. There were two other items of note for the first quarter.

First, G&A of $38 million included an $8 million severance expense associated with the Gulf assets divestiture; and second, we recorded a ceiling test impairment expense of a $165 million due to the Gulf asset sale as the PV-10 of the asset sold exceeded the net proceeds of the sale. We closed this first quarter with $1,180 million of cash.

Our capital expenditures during the quarter were $276 million which was under planned due to weather disruptions. Additionally we paid $7 million to unwind hedges associated with the Gulf sale. Our senior notes remained at $3.2 billion with the first maturity in 2020.

The bank leverage ratio covenant calculation includes debt, net debt of $2.25 billion and a last 12 months covenant EBITDA of $671 million, giving the leverage ratio of 3.0 times. On April 17th, our bank borrowing base was reaffirmed to $775 million.

Currently, our credit facility borrowing base is undrawn and used only to support our $29 million of letters of credit outstanding, which leaves us $746 million of availability. This availability when combined with our cash position at quarter end provides liquidity of $1.9 billion.

On hedging, 87% of the remainder of 2014 anticipated liquid volumes are hedged, the 27% in swaps and $99.49 per barrel, and 60% in three way collars where the first floor was $90.21 and ceiling of $100. 63% of anticipated natural gas volumes are hedged and 62% in swaps at $4.27 per Mcf and 1% in collars and floor of $4 ceiling is $7.78.

Given this position, you can understand why we remain confident in our 2014 revenue expectations. Additionally for 2015, we have liquids hedges of 2.92 million barrels and three way collars with the first floor of $90.82 and a ceiling of $103.13 as well as 5.59 million barrels of swaps at $92.44.

Natural gas hedges for 2015 are comprised of 15.4 Bcf of swaps at $4.50 and 1.1 Bcf of collars with floor of $4 and a ceiling of $8.55 per Mcf.

We are reaffirming our 2014 guidance which has only been updated to account for and increase the production from the Gulf assets, improved NGL realizations to account first quarter results and lowering of the total DD&A rate by $0.30 per Boe due to the Gulf asset sale and the related first quarter impairment effect.

Otherwise our guidance remains unchanged. Operator that concludes my remarks, please open the call for questions..

(Operator Instructions) And your first question comes from the line of Neal Dingmann with SunTrust. Please proceed..

Good morning, guys. Say, David for you or James, just wondering, you continue to outline a lot of different potential completion methods and I am just wondering the economics, how different I guess are you looking at now are those between the open hole and some of these others.

I am just wondering I guess when I look at sort of the type curves and some of your MPVs out there, I mean again how different could we see these or I guess potentially how much could we see these go up as you continue to excel with these?.

Sure Neal, this is Dave. The primary method of completing the wells right now, we have transitioned to the open hole packer system. And typically that system is a little bit more expensive than in and of itself than a typical perfect plug.

But when you look at the total cost of the operation over the completion period, it saves about $50,000 to $100,000. So not only do we think it supports greater EUR which we’ll be able to share hopefully in the future, but it does save $50,000 to $100,000.

And then the other benefit of open hole packer systems is we can typically -- how they save the money is we can typically complete that well in 48 hours where it used to take 5 to 7 days. So it’s a very rapid way of completing the well and we think ultimately more efficient..

Perfect.

And then last question I had for you just on infrastructure, just your thoughts on -- I know that the new acres that you’d added prior quarter and such, just your thoughts on infrastructure build outs, sort of where do you sit now and on CapEx wise James, kind of how much are you going to be attributing to that?.

Yes, we’re still -- we're keeping our infrastructure guidance where it was at about 12% of our D&C spending we had built in the budget, adding some infrastructure in some new areas, such as Northern Garfield area. So that’s accounted for in our budget and I don’t think you will see that change this year..

Very good. Thank you, all..

Welcome..

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

Good morning guys. I had a question that might be best for Dave. On that dual stacked lateral in Kansas, it seems that that’s both a technical success in the sense you got the well down completed and it’s flowing but also a commercial success.

But the question that leads me to is was this an area that was already known to be good? And I know that you have some -- a lot of clusters of good well results.

And so was it in an already known good area? And what I am aiming towards is how representative is this result of your larger acreage position?.

Sure, Charles. This was in an area that we had started to delineate, so we were fairly certain we would have a good outcome here, typically we wouldn’t spend 6 million on a pure appraisal program to test an upper and a lower zone. So we did have a good sense that the well would be an economic success.

And in terms of just the repeatability, there are multiple areas in the play that we’ve shared that have this dual stacked opportunity for us. And so as I mentioned, we have three more of those coming online here in the second quarter. And we believe that this is an opportunity set that has significant upside.

I can't say at the moment if it’s going to be 50% of our wells, or 20%, because the area is so vast and is so rich. But at this point, we're very pleased with the results. And the primary benefit here is we did see a greater than type curve results and these are wells that we would have drilled independent of each other.

So when you do it in the dual stacked format, we do say $400,000 per well or 800 grand. So we're not advertising this as an EUR initiative at the moment, but certainly capital efficiency is the leading issue here.

So if we can go in and knock $400,000 off a well, that's going to be a pretty impressive thing and hopefully we have a significant number of these coming through the system in the coming months..

Got it. And as I was -- look across other plays and look for an analog for what you guys are doing here, the closest that I’ve been able to come up with would be in those a while ago was Austin Chalk in the sense of the uncased holes with multi-laterals.

Is that a fair starting point to try to think about what you guys are doing here and maybe you can offer what -- if it is a fair starting point, what improvements you're doing, what distinguishes you from what operators were doing back then?.

We think this is the novel concept. There are analogies that you could pull from around the world. But where we think this is going to have a benefit for us, naturally this is a carbonate; it's a component rock which allows us to enter the hole multiple times and complete different sections.

And so, the opportunity to go in and out of these wells is where we think we have the real upside. So as we've mentioned where we think we can even develop an entire section and we think we can put up to 34,000 feet into one section from a single wellbore access point. And so that's the real upside; it's being able to go in and out.

So, recall if you're in a shale formation, that's a little more difficult because borehole or wellbore integrity becomes an issue to be able to come in and out that many times. So, given the competencies of rock is what allows us to do this.

So, it is fit for purpose, it is novel, we are the ones that originated this design and teams are pretty impressive..

Got it.

And David, I might have missed, but I meant to say Austin Chalk, maybe I didn't say Austin Chalk?.

No, you did. And I know they did a lot of interesting things there in the Chalk, but I think for us, this particular design is unique and custom and fit for purpose..

Got it. And then if I could sneak just one last one in here.

Can you guys -- I see you’ve maintained your overall, your guidance for the year, but with the, yet a little more than half of quarter the Gulf of Mexico, can you talk about what the quarter-to-quarter growth you think will look like for the rest of the year, if you can share that?.

Yes Charles, we've stopped short of giving quarterly guidance right now, we’ve given out annual and I think and hope we gave enough pieces where people can draw a line between the first and the last quarter. The Mid-Con production was down about 2%, completely weather-related.

We expect, as we noted in the press release, lot of those wells we got completed and brought on line in April, we think will have a similar robust level of completions in May. So, I expect some pretty good ramp up in the production in the second quarter.

But I think we're going to stop short of providing specific quarter-to-quarter guidance right now..

That's great color, James. Thanks a lot..

You’re welcome..

(Operator Instructions). And your next question comes from the line of Stephen Shepherd with Simmons. Please proceed..

Hey, good morning guys..

Good morning..

So, one of the defined characteristics of the Miss has been the variability clearly of the well results.

On one hand you’ve got the small handful of exceptional wells that come online at the huge IP rates greater than 1,000 BOE a day in some cases and then on the other hand you’ve got at least what appears to me to be a larger set of wells that come online at marginally economic rates.

So, it’s clear that you’ve been able to increase the average IP over time over the last few quarters.

I am just wondering if there is anything else or any other initiatives beyond what you’ve talked about in the past things like 3D seismic and what not that you’re doing to try to truncate that well distribution and create some more positive skew going forward?.

Sure. I think there are several initiatives; if you remember at our Analyst Day and even in our corporate presentation we showed you the EURs from our 2013 program and then wells prior to 2013. And you can see the distribution is shifting to the right. We’re drilling less and less every year uncommercial or lower EUR wells.

Remember when we started in the play in the first year, we had 37 wells in our data set then we had a 145 the next year and then 600 now approaching at 1,000. So when you’re dealing with 600,000 acres going from 37 wells to over 1,000, you learn a lot. So we’ve climbed up the learning curve.

We’ve changed our completion methods as Dave talked about, most of our wells are Open Hole now. The teams have done a great job of targeting specific areas within the zones, within the mist depending on where we are across the play.

And seismic, you mentioned seismic, we’ve shot over 1,100 miles of seismic that we’re processing another 700 this year and we think that’s going to be a valuable tool. So between all of those and the learnings that we have on these, over 1,000 wells, we think we’ve tightened that distribution and returns and we’ll continue to do that..

Okay. And one more if I can, also wanted to touch on down spacing in the play. In the past you’ve talked about that it remains to potentially increase location counts in the focus area.

What’s your average drilling density right now for the program in the focus area? And then are there opportunities for that to trend lower moving forward?.

Right now we’re on probably four wells per section there are some areas where we’re three, but we’re mostly four. I don’t think we’ve referenced down spacing more densely than that. So now we’re on roughly 160s in most of the areas..

Okay..

Stephen, this is Dave. I might kind of read into your question on the variability; one thing I would like to highlight is this Garfield area is very, very tight.

And so we’ve probably released the individual well results, but that region is very tight and our subsurface teams had just done an exceptional job identifying this area, drilling in this area. So in terms of just the variability, we think we’ve got that area understood and actually understood very quickly.

And we integrate 3D seismic, we’ll be surprised if we did see, continue to see improvements. So, it is the fractured carbonated, we do see some variability. But overall, we’re incorporating all the variables that contribute to a successful outcomes and we’re doing better I think overtime.

Each quarter we’re showing out results and it does show up in the IPs..

Okay, thanks..

Thank you..

Your next question comes from the line of Robert Carlson with Janney Montgomery Scott. Please proceed..

Hi. Just a quick comment regarding compliment to you and your staff, I’ve been following SandRidge for a number of years and the quality of your calls, the quality of your presentations have just improved dramatically.

It’s nice to see the improvements in operations too, but just with further good quality, your presentations are great just wanted to -- keep up the good work..

Well, thank you for that note, one of the changes we’ve tried to make here in the last year is little more clarity and visibility into the business, little more detail around some of our disclosures and even just changing the way we present things.

So, we want to make it easier for investors and analysts to comb their information and understand what we are doing and why we are doing it and layout the numbers clearly. So, thank you..

At this time we have no further questions. I will now turn the call over to Mr. James Bennett for closing remarks..

Well, thanks everyone for joining us on the call. Just in closing, we had quarter, year-over-year EBITDA was up over 50%, we have discovered another high return area of the play, we continue to drive innovations in the business, we had second highest IP rate ever in the quarter and seven wells over 1,000 BOE per day.

So, I am pleased with the way things are going and just want to complement the team, operational team doing a great job and across the Board whether that’s accounting or legal, we’ve got all the right people in the right spots and the team is moving forward to create value for the shareholders. So, thank you for joining the call..

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