Good morning. My name is Amy and I will be your conference operator today. At this time, I would like to welcome everyone to the Midstates Petroleum fourth 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) Today's conference call will be available for replay beginning at 11 o'clock eastern time today through 11:59 pm eastern time on March 13, 2013. The conference ID number for the replay is 15741569. The number to dial for the replay is 1-800-585-8367 or 1-855-859-2056. Thank you. I would now like to turn the call over to Mr. Al Petrie, Investor Relations Coordinator. Please go ahead.

Thank you, Amy. Good morning everyone and welcome to Midstates Petroleum’s fourth quarter 2012 earning’s conference call. Joining me today as speakers on our call are John Crum, President and CEO, and Chairman; Stephen Pugh, our Executive Vice President and Chief Operating Officer; and Tom Mitchell, our EVP and CFO. John will begin today’s call with highlights of the fourth quarter and 2012. Steve will then provide more details on fourth quarter operation results and plans for drilling activity for the first quarter of 2013. Tom will follow with key financial highlights of the fourth quarter and provide guidance for the first quarter and 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, estimate or anticipates will or may occur in the future, are forward-looking statements. These include statements regarding reserve and production estimates, estimated timing of production restoration, oil and natural gas prices, the impact of derivative positions, production expense estimates, cash flow estimates, future financial performance, plan 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, and 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 and the 2012 Form 10-K that we filed later this month for a discussion of these risks. I will now turn the call over to John for his comments.

Thanks, Al. Good morning everyone and thanks for joining us today. From our earning release yesterday as well as our two earlier releases to pre-announce production volumes and the year-end reserve summary, you can see we ended 2012 on a very positive note. We continued to build on that momentum into 2013. Steve and Tom will give you some details but let me begin with a few highlights. We hit the ground running when we assumed control of the Eagle properties last October 1. Led by our Chief Operating Officer, Steve Pugh, the integration of the Eagle employees and properties in the mid-state has gone extremely well. While we still have plenty of things to complete before we are fully integrated, we have executed on our planned strategy and are continuing to implement processes and procedures to optimize operations. Given our results to date, our purchase is certainly delivering on the expectations from our acquisition case. I am personally more excited about the potential today than I was when we closed. Since taking over the assets on October 1, production is up over 50% to date. We have completed 17 wells that are on production for at least 30 days. Those 17 wells have delivered an average 30 day initial production figure of over 600 BOEs per day with liquids comprising 65% of the mix. You will note our fourth quarter reported Oklahoma oil percentages of 31% are not reflective of our actual or expected results from our drilling programs. Tom will go over the reasons for that in his comments. Our results to date compare very favorably with the [type] curves we used in analyzing the acquisition last summer and any industry experience in the play. As more data on the Mississippian Lime play becomes available, it becomes more…

Thank you, John, and good morning. The fourth quarter was an exciting quarter for our company as we closed and moved quickly to integrate the newly acquired assets of the Mississippian Lime, continued to see encouraging results in the horizontal program in Louisiana, further proved repeatable and profitable results in the Pine Prairie area, and made the top end of our guidance range on production. Additionally, as John mentioned, we had significant reserves growth, both from our acquisition and from our Louisiana assets. Keeping to our normal earnings call format, I will discuss Q4 results and our operational plans for 2013. Let me start with the Gulf Coast Region which includes our Louisiana properties. The company experienced solid results in the Pine Prairie area while continuing our horizontal program in the DeQuincy area. In the fourth quarter of 2012, we invested approximately $86 million in the Gulf Coast region. In the Pine Prairie area, we continued our active Wilcox program and our shallow Frio and Miocene drilling program, spudding six Wilcox wells and 8 shallow wells, all of which were vertical. Both programs delivered results that fit our modeled IP rates. Average cost for Wilcox wells in the quarter were in the $2.7 million range. In the first quarter of 2013, we are proceeding with the one rig program at Pine Prairie and will drill 5 to 6 wells. We are in the process of licensing a 3D shoot over the area and will reprocess the data. We anticipate getting the reprocessed data back in two to three months and expect the 3D to add to our Pine Prairie inventory. In the DeQuincy area, we have continued our evaluation of horizontal drilling. In the North Cowards Gully field, the McFatter 8H-1 was drilled to a total measured depth of 16,870…

Good morning everyone. As in the past, I will focus on the key financial items in yesterday's release and provide you with guidance for both the first quarter and the full year 2013. To begin, we were very pleased with our fourth quarter production of 15,592 BOE per day, which was on the high side of guidance. As you have heard from John and Steve, the Eagle property acquisition clearly provided us with a great new focus area to utilize our drilling and completion expertise to ramp up our production and cash flow, and optimize our capital. Adjusted EBITDA for the fourth quarter totaled $48.6 million, that’s up 48% from $32.7 million in the third quarter. And note these numbers include Eagle transaction cost. The key driver was the additional production from adding the Eagle properties in the fourth quarter as well as from our drilling activities in both Oklahoma and Louisiana. We reported a fourth quarter GAAP net loss of $2.4 million or $0.04 per share compared with a loss of $17.8 million in the third quarter. A large contributor to the net loss in the fourth quarter was the $12.2 million in acquisition and transaction cost we incurred associated with the Eagle property purchase and the related financing. Since we reported a net loss for the fourth quarter and the convertible preferred shares do not participate in losses, the additional common shares that would be issued upon conversion of the preferred shares would not include -- are not include in per share calculation. Keep in mind that when we report GAAP net income for a quarter as compared to a loss, the common shares issuable upon conversion must be included as if the preferred shares were converted and will increase the share count. Adjusted net income which excludes…

Thanks, Tom. As we all discussed today, the Eagle acquisition has provided us with the expanded geographical footprint, added significantly to our scope and scale and gave us the opportunity to further employ our strong operating and technical expertise. Just as importantly, it now provides us the with the ability to optimize our capital allocation. We have said repeatedly since we announced the acquisition, that we would direct capital to the region where we saw the best returns and opportunity for growth. The success we described today in Oklahoma leads us to allocate a bit more capital there as we await additional results from our horizontal drilling program in Louisiana. We have also consistently said we would continue to look at acquisitions as a means to add more scale and stability to Midstates. As you heard today, the Eagle acquisition has greatly increased our critical mass and provided the needed optionality for capital deployment. We are clearly enjoying the benefits of that transaction. We will continue to look for the chance to add to our existing core areas and we will carefully review opportunities that may arise in difference basins that fit our skill sets. I hope you can sense my enthusiasm for our company and the progress we made this past year. We have certainly had our challenges but I am extremely proud of the team we put together and I am confident we will continue to build on recent successes. I do want to make sure you leave our call with a few key messages. One, our Eagle acquisition is delivering very well on the promise we saw when we were evaluating the opportunity and we are exciting about the potential to expand on our position. Two, early results of our horizontal Wilcox drilling in Louisiana continues to be positive, and we have some key tests underway this quarter. Three, we will continue to find ways to profitably grow our company by expanding our inventory of investment options, both organically and by acquisition. And fourth, we have the right team in place to deliver on our promises. In closing, we will continue to be proactive in our investor relations efforts through meetings with our shareholders and participating in upcoming conferences. Over the next two months we will participate in the Howard Weil conference in New Orleans, and the IPAA in New York. We hope to see some of you at these venues. And with that, I will turn it over to Al to take questions.

Okay. Amy, we are ready to questions and I ask our participants to limit to one question and a follow-up. Thank you.

(Operator Instructions) Your first question comes from the line of Neil Dingmann with SunTrust. Neil, your line is open.

Amy, let's go the next one.

Your next question comes from the line of Ron Mills. Ron Mills - Johnson Rice & Company: Couple of questions. The first one would be from the Sand Ridge Analyst Meeting yesterday, they provided a lot of good color on the Mississippian and in particular surrounding your Woods and Alfalfa County areas. Maybe, Steve, this is for you. Can you walk through some of the differences in the Mississippian? It looks like your IP rate compares favorably to them and the EURs that they provide for those areas look above what apparently you used for your acquisition metrics. And is some of that related to the employment of ESPs on your wells from day one versus just starting? Just looking for some color there.

Ron, I might make a comment there and if Steve wants to add to it, he can. Look, first of all, we just got all that information ourselves, so I don’t know that we have got a full analysis of Sand Ridge's Day said. But I think we were pleased to see that they are also reflecting quality results in the same areas that we have been successful in. So I think it supports our premise that we are in the right area and that we will be able to continue to deliver the results we are expecting out of it. Ron Mills - Johnson Rice & Company: Okay.

If you want to add anything? We will get back with you when we know a little more about what Sand Ridge has said. Ron Mills - Johnson Rice & Company: Okay. And then when you look at your capital allocation, it sounds like the fifth rig that is coming in will be another development -- more in the development area. Just to clarify, Tom, the 60% Mid-Continent, 40% Gulf Coast for this year's CapEx, how does that compare to the prior guidance? I'm just saying, was your prior guidance 55% in Louisiana or 55% in Oklahoma?

Our prior guidance that we had out there for full year was 55% in Oklahoma.

We have just moved it up slightly.

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

Just a question on this McFatter well. You had talked about it being 80% liquids. Can you guys give us a split between oil and NGLs in that well?

Yes, I probably should have said it's very close to 80% oil, actually. And that was the case with the Musser-Davis 8H as well. So we have got liquids on top of that, they just don’t make the gas that we see in some of the other areas.

Okay. And I guess in terms of the Mississippian, can you give us some insight into where your well costs are running right now and where you think those could go by the end of the year?

Yeah. We are running at about $3.6 million year-to-date. And we are shooting to be in the low-3s for our full year.

Okay. I guess that's helpful. And I guess in terms of your CAPEX here, you had talked about $125 million for the first quarter full-year budget of $420 million to $450 million. I guess you guys are expecting to maybe slow down a little bit during the year on CAPEX?

Yeah, we have a slowdown towards the last part of the year. Obviously we are hoping for good results which would leave us with some additional EBITDA which would keep us running at pace towards the end of the year. But we don’t plan to outspend our capital budget right now unless we get outside EBITDA results.

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

Just had a quick follow-up on the Mississippi Lime. It's my understanding that your focus to date has been on the upper bench there. Wondering if you could comment on the prospectivity of the lower benches across your position? And do you also see the Woodford shale as being present in having the potential to be a separate producing formation there?

I am going to let Curtis Newstrom answer that. He has been studying this pretty hard.

Yeah, we have looked at the second bench. We haven’t actively planned a well to go to drill a lower bench. But we have seen encouraging results around and so we think it's prospective under our acreage. We have actually done a fairly large study of the Woodford potential and we think there is Woodford potential both in our acreage position in Woods and Alfalfa, and even down in Lincoln County. So we are trying to get our arms around that and see if there is some opportunities there.

Great. That's really helpful. And I guess just a quick follow-up to that. Can you comment on some of the year one declines? Any B factors that you are seeing on your wells in Woods and Alfalfa?

Yeah. As it relates to that, I mean we are carrying a B factor in the order of somewhere between 1.2 and 1.5. It’s still fairly early but that tends to be in line with what we are seeing in other areas.

Your next question comes from the line of Steven Shepherd with Simmons & Company. Steven Shepherd - Simmons & Company: I was wondering on what percent of your Mississippian wells are you using ESPs. Are you using them on all of your wells or just a select group? And if it's just a select group, have you seen any meaningful performance difference on the ones that have ESPs versus the ones that don't? Can you just provide any commentary on that?

Yeah, we pretty much go to ESPs early on. We have got wells that continue to flow. As soon as we quit flow rate, we get ESPs in the ground. So, Steve, 90% of our wells are on ESP?

Right. Steven Shepherd - Simmons & Company: And then I guess my follow-up there would be, on the 3,800 acres that you all of our recently in the mix, do you care to disclose a price per acre that you paid for that?

Yeah, I hate to get into giving out anything, but we paid around 1500 an acre for that, on average. Obviously, the closer it is to real good wells the more cost and further away the less the cost.

Your next question comes from the line of Neil Dingmann with SunTrust.

We may have to talk to Neil offline.

Your next question comes from the line of Drew Venker with Morgan Stanley.

Can you guys talk about the production growth trajectory over the year with production already running ahead of schedule?

Well, we have got a pretty big target for the year, obviously. We are maintaining our guidance at 20,000 to 23,000 total for the year. And that’s going to kind of imply pretty close to 50% growth this year. So that’s kind of what we expect. And obviously if we can get a fast start that will make us pretty comfortable we can deliver on that.

And just help me get some more color on the service cost side. I think you said Mississippian wells have cost $3.6 million year-to-date and you are targeting $3 million later in the year. Can you just provide some color where that is coming from? Is that efficiencies or costs driving that?

Yeah, I would say it's mostly efficiencies. As I have said, about 70% of our wells are going to be drilled off of multi-well pads or existing pads. So we will see certainly some efficiencies there. We are not seeing, I would say, material changes in service cost either way, although we are bidding more of the services that we use and I do expect that we will see some cost come down just because of that.

Your next question comes from the line of Ron Mills with Johnson Rice. Ron Mills - Johnson Rice & Company: John, I guess I can be Neil today. To follow up on that last question, I know part of the reason the Eagle's well costs were running a little bit higher, I think we talked in the past about they were using a greater level of acid in their frac jobs. As you now have had those properties for five months under your operations, how much of the cost improvement do you also think will just come from changing the completions in that area?

I don’t know that we are expecting the significant change there. You now I think what we see going on in those completions is we were using a little more acid in the Eagle Completions and other people were using more sand in their completions, and those costs kind of offset each other. I think where we would expect to see the gains is just purely in efficiency. Certainly, as we try to run four rigs kind of in close proximity to each other, we get some benefits out of just having our activity nearby and getting some scale out of that. And then we are going to be moving, as Steve indicated, to pad drilling operations which certainly is going to help us on rig moves etcetera. It still takes a long time to get a rig moved from well to well. Ron Mills - Johnson Rice & Company: Okay. And then the last one for me. On the infrastructure with your four rigs in the development area, that's where your infrastructure is more built out. What is the timeframe in terms of expanding your infrastructure and being able, as you move to the west or northwest through Woods County?

Well, I guess it depends on results. But you know the drill as we told you we are going to get our cash flow as quickly as possible this year by concentrating on the areas that we are confident about, that’s had lots of drilling notionally in that kind of county line area or right on the border of Woods and Alfalfa County. That has delivered on the results. The infrastructure is built out. But we will have one and sometimes two rigs running in the more outlying areas and that will require some additional build out of infrastructure. But our overall, I guess, capital associated with infrastructure in Oklahoma is $11 million or so. So it's not a big piece of our business.

Your next question comes from the line of (inaudible) with Global Credit Advisors.

Question for you. The two natural gas generation sets that you are installing, can you provide a cost of those and then how many ESPs they will be able to run each?

Yeah. Preliminary cost estimates are in the $3.5 million for each one. And we will run the ESPs -- I don’t know that we can give you a number of wells because some of that will be backup power for the co-ops. And then from (inaudible) in different well, obviously.

A rough ballpark?

Well, you can use probably 500 per well or so.

10 to 12.

Yeah. Maybe 20 wells total.

Okay. Perfect. Thanks. And have you ever broken out in your LOE what the cost of saltwater disposal is?

We continue to analyze that and I think when we do the math on this, is (inaudible) is a wonderful formation that takes water beautifully. We don’t have to actually pump it in, it actually goes in on vacuum. So when we kind of try to do that kind of all in costs, we end up with a number around $0.50 a barrel. But that would include the capital associated with drilling the salt water disposal wells and the pipelines laid in. Just ongoing operating cost after we have those facilities in place, it's less than $0.20.

(Operator Instructions) There are no further questions at this time.

Okay. Thank you, Amy, and thank you for joining us today. We look forward to seeing you at our upcoming conferences.

This concludes today's conference call, you may now disconnect.