Good morning. My name is Cassandra, and I will be your conference operator today. At this time, I would like to welcome everyone to the Midstates Petroleum First Quarter Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions) Thank you. At this time, I would like to turn the call over to Al Petrie, Investor Relations Coordinator. You may begin.

Midstates Petroleum’s first quarter 2013 earnings conference call. Joining me today as speakers on our call are John Crum, Chairman, President and CEO; Steve Pugh, our Executive Vice President and Chief Operating Officer; and Tom Mitchell, our Executive Vice President and CFO. John will begin today’s call with highlights of the first quarter. Steve will then provide more details on first quarter operational results and plans for drilling activity for the second quarter of 2013. Tom will follow with key financial highlights of the first quarter and provide guidance for the second quarter and full year 2013. John will then wrap up with some closing comments. Before we begin, let’s get the administrative details out of the way with our Safe Harbor statement. This conference call may contain forward-looking information and statements regarding Midstates. Any statements included in this conference call or in our press release that address activities, events or developments that Midstates expects, believes, plans, projects, estimates or anticipates will or may occur in the future are forward-looking statement. These include statements regarding reserve and production estimates, oil and natural gas prices, the impact of derivative positions, production expense estimates, cash flow estimate, future financial performance, planned capital expenditures and other matters that are discussed in Midstates filings with the Securities and Exchange Commission. These statements are based on current expectations and projections about future events, involve known and unknown risks, uncertainties and other factors, that may cause results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. Please refer to Midstates’ filings with the SEC in the first quarter Form 10-Q that will be filed shortly for discussion of these risks. Also please note that any non-GAAP financial measures discussed in this call are defined and reconciled to the most directly comparable GAAP measure in the table in yesterday’s earnings release. I will now turn the call over to John for his comments.

Thanks, Al. Good morning, everyone, and thanks for joining us today. We have just completed another fast paced quarter and as promised we try to keep you up to speed as new information was available. In January, we provided an initial view on first quarter and full year guidance. On our fourth quarter call in early March, we advised you of expected first quarter production impact from major storms we experienced in Northwest Oklahoma. Later in March, we advised you that the Louisiana Supreme Court had ruled in our favor on the Clovelly case removing a significant distraction. In early April, we announced the Panther Energy acquisition. At the same time, narrowed our first quarter guidance to fully reflect the actual production loss associated with those storms and provided the new expected full year guidance with the acquisition included. As such, much of what we have for you today will not big news to you. I feel like we had a very good first quarter. We couldn’t do anything about the weather issues but our teams executed well on the things they could control. We continue to be encouraged by the drilling results we have achieved across our portfolio in both Louisiana and Oklahoma. As we announced in yesterday’s release, while still early, our most recent horizontal well at North Cowards Gully in Louisiana, the Wood 10H-1 appears to be a success. This well target the same horizon as the prior two wells the Upper Wilcox “B”. Steve will discuss the well in more detail but it was drilled at substantially lower cost than the prior two wells. We continue to believe there is potential for more than 20 horizontal locations at North Cowards Gully. Results to date have encouraged us to spud two additional wells, which are presenting drilling.…

Thank you, John, and good morning. In keeping with our normal earnings call format, I will discuss first quarter results, some more recent well results and our operational plans for the second quarter of 2013. I will start with the Gulf Coast region. We have continued our horizontal Wilcox drilling program in Central Louisiana and are happy to announce the results of the previously mentioned Woods 10H-1 well in North Cowards Gully field. This well is the eastern most well in the field and was drilled to a measured depth of 15,366 feet and has a lateral length of about 3,000 feet. The well had a seven-day average rate of over 1,250 BOE per day of which 64% was oil and 78% was total liquids. The results of this well combined with the interpretation of our recently acquired 3D Seismic data, give us encouragement that there are additional wells to drill east of the Wood well. We are also very encouraged with our drilling and completion cost on the well, which were in the $9 million range including the vertical pilot. The well was drilled more than 30% faster than the previous two wells and we expect drilling performance on future wells to continue to improve. As I said on last quarter’s earnings call, we expect these wells to cost approximately $8 million as we continue our development program. As mentioned in our press release, we are currently drilling two more wells in the North Cowards Gully field. The Musser Davis 8H-2 is a west offset to the very successful Musser Davis 8H-1 well announced last year. Additionally, we are drilling the Olympia Minerals 16H-1, which will further delineate the field to the south. We expect to have results from both of these wells towards the end of the second…

Good morning, everyone. Earlier today we posted our updated guidance on our website in the Investors section under the Financial Information tab. My comments today will focus primarily on quarter highlights and new guidance or changes to previous guidance rather than reiterate all of the detail. This will allow more time to discuss items of importance or interest to you. To begin, adjusted EBITDA for the second quarter totaled $56.5 million, up 16% from $48.6 million in the fourth quarter. We reported a first quarter GAAP net loss of $7.9 million, compared with a net loss of $2.4 million in the fourth quarter of 2012. Adjusted net income, which excludes the impact of unrealized gains or losses on derivatives was $1.4 million, compared with $5.5 million in last year’s fourth quarter. Production in the first quarter was 16,208 barrels of oil per day with 58% coming from the Mid-Continent properties and 42% from our Louisiana properties. The product breakdown of production was in line with our guidance with the oil percentage in Louisiana being just a bit above our guidance mix. We continue to be very oil weighted at 68% for the quarter for oil and NGLs. Even with the difficulties with weather in the first quarter, we are reconfirming our annual guidance previously supplied in early April, when we announced the Panther acquisition at 24,000 to 26000 BOE per day, as well as the regional composition and product mix. Obviously, the downtime associated with the weather is impacting annual numbers, but we are confident we can continue to execute making up the negative impact throughout the remainder of the year. Again, the details associated with this guidance relating to regional contribution and product mix are found on our website. In terms of the second quarter, we’re expecting to be…

Thanks, Tom. As you’ve heard from our comments today, we have achieved some solid wins across our portfolio. We will continue to build on those successes and be a 100% focused on execution. In Louisiana, we are making progress in our horizontal drilling program and are gaining momentum with each well we drill and complete. The Louisiana horizontal program offers us some of our highest potential rates of return as well as significant upside potential and reserve growth. The past six to nine months have given us confidence that proceeding at a measured pace, we can build a very successful horizontal program especially on our core Wilcox acreage. In Oklahoma, we have also been pleased with our team’s progress cutting drilling times and improving efficiencies. We believe our acreage position in Woods and Alfalfa Counties is proving to be among the best. We will continue to exploit those de-risk areas while testing new concepts, horizons and areas to expose additional upside. We are on schedule for our May 31 closing of the Panther Energy Acquisition and are moving ahead with permanent all debt financing. As I said earlier, the properties are performing above expectations and we are confident in the smooth transition with the Panther team continuing to work the assets for at least six more months. We will deliver an aggressive drilling program that focuses on development of proved formations, primarily to Cleveland while testing additional upside in other formations across our new acreage. In closing, we are well aware that we have taken on significant leverage for this deal but believe the new assets justify it. With this acquisition, we have added more stability to our production base as well as the scale and scope of the opportunities needed to effectively allocate capital across the diverse well weighted portfolio. We will now focus 100% of our efforts on execution of our plans to drive organic growth and bring our debt ratios down quickly. We are extremely excited about the potential for our company and the value we know we can create for all of our shareholders. With that Al, we are ready to take questions.

Thanks, John. Operator, we are now ready to take questions. Participants please limit your question to one with one follow-up question. Thanks.

(Operator Instructions) Your first question comes from the line of Neal Dingmann from SunTrust.

Good morning, guys. Good quarter. Say, Tom, first question regards to just which you’ll go on like northwards -- north covers gully. I noticed oil and weight and just some of your other Gulf Coast, looks like in the horizontal, that one the 10H-1 was frac with the 10 stage. Just want to know, when you go forward either to that one or some of these others who are going to drill for the rest of the year. Just if you could talk about sort of completion that as we stay around -- give me an idea on lateral length stages, et cetera as well as well cost there.

Yeah. Neal, I think as we get little longer laterals, which we’re trying to working our way up to we’ll be adding stages and just to that point, the South Bearhead Creek well that Steve mentioned, we just completed our frac on. That’s a 4,300 foot lateral and we’ve actually 14 stages on it. So you should expect to see stages going up as we increase our lateral lengths.

Okay. And then just a follow-up over on the horizontal mist, I know you mentioned about adding the fifth rig there. I mean, can I guess -- give an idea I guess, John, you kind of stayed at that level based on your sort of guided CapEx that you and Tom spoke of today? And then just wondering current today, what are you seeing around kind of typical IP rates and has your kind of EUR estimates changed at all in the region?

No, our IP and type curve kind of information, we understand with what we’ve provided in the past because like on average that’s working up pretty well. The fifth rig, we’ve added will be working the course. So again, while we called, for the kind of center of our acreage position there kind of long like county line or Woods and Alfalfa Counties. So, we’d expect to get fairly consistent results in there, because as you know we’ve already drilled in most cases at least, one well in the section.

Got it, guys. Look forward to it. Okay. Thank you, all.

Your next question comes from the line of Ron Mills from Johnson Rice.

Good morning, Ron.

Good morning, Ron. A couple of questions. As part of one I guess in the Wilcox -- North Cowards Gully, it sounds like Willcox B is the target, South Bearhead is the C, what drives the decision there and in terms of relative desirability for horizontal locations? And I think you mentioned that the North Cowards Gully well extended that structure further to the east and one of the well is drilling now extends it to the south. With that drilling, is that really all that will be needed in that area to confirm the 20 plus locations?

Yeah. I think that’s going to give us a pretty serious feel for it. The 10-H well did confirm that indeed we got some structure to the East. We’ve also got some new seismic and that’s kind of indicating we can continue to move East from there. So we are feeling pretty good about it. The Olympia Minerals well is the one we are hoping will kind of confirm moving to the South. So all of those, when we get to talking about targets I guess what you’ve got to think about is in North Cowards Gully. The Wilcox B has always been the primary target there where we had the vertical wells. Once we moved to South Bearhead Creek, we’ve got a multitude of potential targets in South Bearhead Creek both in lower and upper Wilcox. So you will know one of our competitors is out there drilling the well as we speak.

Okay. And as it relates to the Woods, Alfalfa acreage it sounds like you, the rig you just added, you’ll have four rigs drilling in that core area and one, HBP acreage. Where are you on the infrastructure component, both within that core area and even as you march out with the HBP acreage and how can that -- and what steps are you taking to hopefully alleviate the electrical problems that you encountered, associated with those storms going forward?

Yeah. We are moving ahead at full speed with trying to make sure we don’t run into those same electrical problems. I would point out this appears to be a fairly unusual winter we just went through. So, we got some indications that that was a 50-year storm we just dealt with. So, hopefully we won’t deal with that as often in the future. But the key is getting the power lines well supported. So they don’t get blown over and then getting some additional capacity and from some of the core ops as well as putting in our own generation capacity. I think you’ve been hearing from none of the Mississippian players that diesel generators are expensive to run. That’s not a surprise to anybody out there. But so we will be moving to natural gas buyer in the future for our supplemental needs.

And did you say that Cleveland is a primary focus of your Panther activity over the remainder of the year. And it’s -- and at what point do you think you would look at some of the other formations given some recent results from offshore operators?

Yeah. I probably over sold that -- the Cleveland we kind of told you when we started we’ll probably have about half of the rigs running. It’s the most well understood of the plays that we’re working but by the end of the year we should have three more rigs running, drilling Marmaton, Tonkawa and Cottage Grove kind of interval. So we’re obviously watching what the rest of the industry is doing as well. But that would be the plan as about half the rigs working in the Cleveland and half -- another half working in the rest of those targets.

Perfect. Let me let someone else chip in. Thanks John.

Thank you.

Your next question comes from the line of Leo Mariani from RBC.

Your Gulf Coast production a little bit here. Just looking at some of the numbers you guys provided, I’m seeing that your oil production in the Gulf coast was down about 1,200 barrels a day this quarter versus the prior quarter. Just wanted to get a sense of kind of what was causing that you guys also mentioned, you weren’t doing anything in Pine Prairie in the second quarter. Trying to get a sense of when you’re going to get back to Pine Prairie and how we should expect that oil production will trend for rest of the year?

Leo, we had a pretty good fourth quarter in Louisiana and a lot of that was driven by some seven or eight shallow wells that we had bought on at Pine Prairie. The good news about those as they come on nice high rates. The bad news is they are not big EUR. So they tend to deplete fairly quickly. So good rate of return but they will bring your volumes down fairly quickly. The issue on Pine Prairie and continue drilling is we’ve just got an access to 3D survey there. And we would like to go ahead and make sure we’ve got that, interpret it and put it into our thinking as we go forward. We are obviously pretty pleased with where we ended up with on our lawsuit at Pine Prairie. And so we’ve got lots of plans to go forward there. We just want to make sure we are taking advantage of all the technology we have out there to pick the next locations.

Thanks. So when we should expect you guys to get active at Pine Prairie? Again what do you think a reasonable timeframe is for that?

I think you are going to see us back out there late summer.

Okay. I guess, in terms of downtime you guys talked about downtime in the Mid-Con lingering into April. Could you guys quantify how much -- how many barrels you expect to allude here in April?

Yeah. I don’t know that I’ve got that number but April was -- we did continue -- we had a couple extra storms in there. But just giving all this units back up and then getting kind of smooth out, we are seeing somewhat of a -- I think, I have mentioned to a number of you dewatering effect. If we can keep our -- if we can keep the production on steady then we tend to bring our oil cats up. When we have a well shut in for some period of time, we’ve got to produce a significant amount of water before we get back to the original cuts we have. So we think that’s affected us as well. On the overall, we still given you an indication of what we expect our -- our third quarter numbers to be and I mean, excuse me -- our second quarter numbers to be. And so you’re going to end up with about 19,000 to 21,000, I think so we’ve got out there. And you’ll see that we’re expecting 50% of that to come from the miss.

Yeah. And I guess, I mean are you still seeing downtime in the Mid-Con or is that over at this point that now we’re in May?

No. It’s pretty well over now. Still working on, trying to improve the infrastructure as we mentioned to Neil.

Thanks guys.

Thank you, Leo.

Your next question comes from the line of Chad Mabry from KLR Group.

Good morning, Chad.

Thanks. Good morning, guys. I just had a question follow-up on the Panther acquisition. Curious if you could help us out with kind of the timing of your acceleration to those six operated rigs up there in the Panhandle?

Well, we are planning on trying to get the first rig in there within a month or two of getting started and then just bringing one every other month after that.

Okay. Great. And then over in Louisiana, I was curious if you could update us on the status of your Fleetwood seismic sheet and maybe plans to test that large acreage position sometime this year?

Yeah. Thanks Chad for bring that up. Sometimes we forget we’ve got some of these other things going on. Yeah, so we’ve been working the seismic pretty well. We have confirmed a couple of the prospects that we had early on even with 2D. So we feel pretty good about that acquisition. I think I have indicated to you guys on some other calls that one of the things we deal with here is we are in the basically one of the spillways off the Mississippi river. And so consequently, we have to get wetlands permitting. So it’s a long hard process and frankly we are still arguing little bit over which would be the first location we drill. So it’s going to be late summer before you see us out there growing well.

Okay. Great. I’ll get back in queue. Thanks guys.

Thank you.

Your next question comes from the line of Hubert van der Heijden of Tudor, Pickering, Holt.

Hubert.

Yeah. Good morning guys. On the Woods Well, I was just wondering if you could comment in a little more detail on the oil cut of that well. And if this is still something that you see, I guess, trending up over the longer term to kind of 70% to 80% oil cut that you’ve had on the offsets there?

Yeah. I would think that’s going to be the case. Honestly, we had a debate because seven days is really pretty early. We’re still getting back a lot of our frac water and stuff. But since we have the information, we thought we ought to get that to you. We’ll come out with some additional information over the next month or so, so that you have a sense for what is doing. I don’t know why I would expect the EUR getting higher on this well. So, I’m expected to get a little higher well cut as we go forward.

Okay. Perfect. And then just on the -- I guess, on the -- from a high level on the Louisiana property, you had a lot of other expansion areas, I think, as I’ve kind of gotten a little less attention with the other two lags to the story that you have now in the Mid-Con. How should we think about it long-term? Is that just optionality that you over time will get back to, or how do you see those properties?

Yeah. Hubert, I think the lesson we learned is to take this a little bit slower and make sure we plan each of things we’ve learned as we move to the next well and so we’re going to concentrate this well. We think, we need continue to develop the horizontal drilling application in the Wilcox. So, consequently we’re going to concentrate on the structures that we actually know worked very well on the vertical basis and that’s why you see us North Cowards Gully and South Bearhead Creek. The other issue is, obviously, Fleetwood is such a big position there that we’ll be testing that. And so, bottom line is some of those other operations and some cases we’ve tested them and they haven’t work as well. But the bottom line is they’re kind of fallen to the bottom of the queue.

Okay. Perfect.

Your next question comes from the line of Ipsit Mohanty from Canaccord.

Good morning, Ipsit.

Thank you. My first one is a little bit broader question. And just if you could provide a little bit color on what led to canceling your equity offering? Was that due to confidence in the assets, the quality of assets that you have generating cash flows or is it the current market conditions? And I have a follow-up.

Well, Ipsit, I think all of the above. Obviously, we think these are great assets we’ve taken on. And we didn’t think our equity price were down to, was anywhere close to reflecting what we believe we own here. So it was frankly an illogical move to without equity of these kinds of levels. So we’re quite confident that we can cover what we’ve got with the assets. We’re going to have plenty of cash flow off them. These assets should generate very positive cash flows. And we certainly are comfortable going forward with all of that arrangement.

Well, John this is a multi-stack play and your positions in the different counties. Are there particularly counties that you’re going to focus more initially and just a plan on how you go above developing these assets?

All right. You’re talking about Panther, right.

That’s right.

Yeah. Look, I think we’re going to try to take the same position with the Panther assets that we’re kind of doing with the Eagle assets which is concentrate a lot of our activity in and around areas that we know it worked. So we can get our EBITDA up and get these debt metrics in shape as quickly as possible. We do have significant upside in some plays, in some other acreage, especially Hansford and some of our Oklahoma acreage -- Hansford County, Texas and some of our Oklahoma acreage. But we’re going to -- we will do that again at a measured pace.

And then my final one is on CapEx. John, you guys talked about drilling about 15 to 18 wells in the second quarter on this line. Are they all net, one? And secondly, the CapEx associated is about $70 million to $80 million suggests a little higher well cost and then 3 million you are trending towards the end of the year. Could you fill that gap for me?

Yeah. I think -- yeah, the bottom line is we’re at $3 million yet. And I think what Steve was trying to point to as he believes we can get there by the end of the year. But we’ve been average in more like 3.5 today.

Sure, John. But $70 million to $80 million suggests a little higher for the 16 to 18 wells, so is that infrastructure in there as well?

There is some infrastructure there. We have got a power plant in there. And we have put some…

All right. Great. Thank you, guys. I leave it at that.

Your next question comes from the line of Stephen Shepherd with Simmons & Company. Stephen Shepherd - Simmons & Company: Hey, guys. Good morning.

Good morning.

Good morning. Stephen Shepherd - Simmons & Company: What is your EUR assumption on the Woods well and North Cowards Gully? Is there any guidance you can give me on when you look at these factors you guys are using on those horizontal wells?

I guess, we’ve only got seven days. And there is one thing we’ve learnt about the Wilcox is, we need a little more time to kind of work through that. As a general rule, the B-factors would expect to use in Wilcox wells are going to somewhere around one. Stephen Shepherd - Simmons & Company: Okay. And my second question, this is more kind of high level I guess strategy question, any of your Louisiana properties potentially be considered divesture candidate going forward in an effort to kind of continue to refocus is more than Mid-Corn leverage producer. And still any funding gaps going forward, I just want to get your thoughts on that?

Well, I think first of all, you need to look at the amount of cash at the Louisiana properties generates. So it would be a big decision for us to do something like that. But that said, I mean, I think we’re businessman and if the right opportunity came along with right offer then obviously we take a look at it. But right now, they generate a lot of cash force. And so we think the important properties we maintained. And we think we are on to something with these horizontal drilling applications. So it doesn’t feel like right time to say we do something with those. Stephen Shepherd - Simmons & Company: Okay. That’s all I have. Thank you.

Thank you.

Your next question comes from the line of Chris McDougall with Westlake Security.

Hey, Chris.

Hi, guys. Thanks for taking the questions. First, on the horizontal Gulf Coast, so what are really the keys to success there. It looks like things have improved significantly. Is it seismic data, is it the kind of well packaged or completion solution?

Well, I think we are figuring out quite a few things about it. Don’t necessary want to share with the rest of the industry but bottom-line is we are looking for as a general rule for areas that have worked well as verticals and trying to apply the horizontal technology to it. Certainly, we’ve gotten better at drilling them. I would remind you that we’re typically at 13,000 feet vertically and then trying to do a horizontal of that. And we’re in over pressure at reservoir. So, these are not simple wells to drill and certainly not for the faint hearted. So, as we get better at each of these than we would expect to get better and better performance.

Okay. Thanks. And then generally across your basins how are service cost trending. Are they pretty flat on a sequential basis or are we seeing any trend either way?

Yeah. We get asked that quite a bit. I guess, I think Steve would tell you, we’re not really seeing anybody lowering their cost of service on a per job basis or per pound or per horsepower or anything like that. We had gotten some reduction in drilling rig rates probably last year end and really things are holding fairly flat. What we are getting better at is just getting more efficient. And so we’re seeing our overall cost to come down on a per frac job or per well basis. But I don’t know that I’ve seen -- we certainly haven’t seen the increase and probably as importantly as anything, we got all the equipment we need available to us.

Okay. Great. Thanks a lot.

Thank you, Chris.

Ladies and gentlemen, we’ve reached the allotted time for questions. I would now like to turn the call back over to Mr. Petrie.

Well, this is John Crum. I appreciate you guys joining us today. We’re pretty excited about where we’re going with this and really excited to get Panther in the door and start to drill wells on those assets as well. So I think going forward, thus continuing to deliver some solid quarters. Thank you.

This concludes today’s conference call. You may now disconnect.