Amplify Energy Corp.
Q1 2013 Earnings Call Transcript

Published: 7 May 2013

[Operator:]

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.

[Al Petrie:]

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.

[John Crum:]

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. We’re also awaiting test rates from the first South Bearhead Creek horizontal Wilcox well, the Musser Davis 33-28HC-1. The well was just completed over the weekend, under budget and flow back operations are underway, as we speak. We will have results from these last three horizontal wells over the next month or so and remain very enthusiastic about the potential for horizontal drilling application across our entire Louisiana portfolio. In the Mississippian Lime, our drilling program continues to meet the expectations we planned for when we acquired the assets late last year. While we have experienced a few hiccups from weather and teething problems from bringing in new rigs, a number of important initiatives are starting to make a difference. Our drilling days are coming down and more importantly, we are really gaining on the days to first product. We expect to have additional time and cost improvements from pad drilling and from our concentration of activity around the center of our acreage position where we have most of our infrastructure already in place. As in most things, local matters and we remained very enthusiastic about our premium acreage position in Woods and Alfalfa counties. Steve will discuss LOE per BOE in detail, but we did come in above our expectations for the quarter, primarily due to lower volumes. Higher cost associated with getting recovery from the storms added to the impact on a per barrel basis. Despite the higher LOE costs, our total cash operating expenses for the quarter were flat and the -- flat with the fourth quarter of 2012. In our call on April 4th, we discussed in detail the pending $620 million acquisition of producing properties, as well as developed and undeveloped acreage in Western Anadarko Basin from Panther Energy and their partners. We are right on track to close the acquisition as scheduled on May 31st. Tom will talk more about the financing of the deal, but we have decided to finance the acquisition fully with debt. We believe the current price of our stock does not come close to reflecting the true value of our company and as such, we are unwilling to issue equity. We have already begun planning the integration of Panther assets into our organization. The Panther team has continued to their three rig operation and we are pleased to let you know that current production is above the 8,000 BOEs per day with that we reported on the announcement. The entire Panther organization will be available to work a smooth transition for at least six months and we hope to convince many of them that Midstates Petroleum would be a good place to continue their carrier. I will come back at the end of this call with additional comments about our strategy for the remainder of 2013. Let’s move ahead now with Steve and Tom giving you more details on the first quarter and what to expect in the second quarter and the balance of 2013. Steve will now go over operations.

[Steve Pugh:]

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 quarter. In the South Bearhead Creek field, we drilled our first -- Wilcox horizontal in less than 60 days, which was targeted for the well. It reached total measured depth of 18,156 feet and has a lateral length of over 4,300 feet. The well was completed with 14 frac stages just yesterday and will be flowing back on test this week. The lateral is laid out in the Lower Wilcox “C”, which has been very prolific in vertical wells. We are very excited about the horizontal potential in South Bearhead Creek, especially since there are up to six additional horizons that we can target with horizontal drilling. In the Pine Prairie field, we drilled and completed five wells with results coming in line with our expectations. All the wells targeted to Wilcox formation. Average well costs have improved from just over $3 million last year to $2.7 million in our most recent wells. We licensed and received 3D Seismic data over the area and have begun our initial interpretive work. We expect this new data will contribute to our efforts to build additional inventory. We do not plan to drill any wells in Pine Prairie during the second quarter, but we concentrate on inventory generation, which can increase drilling opportunities later this year. For the Gulf Coast region, in the first quarter of 2013, we invested approximately $61 million. We will invest $55 million to $60 million in the Gulf Coast region during the second quarter, completing wells drilled in the first quarter and drilling three to four additional horizontal wells. Now let me move to the Mid-Continent region, which includes our Oklahoma and Kansas Mississippian Lime acreage. During the first quarter, we had four rigs active, spud 10 wells and placed nine wells on production. Three of the rigs were focused on drilling in our most proven area while the fourth was used to test an HBP acreage in the outlying areas. We invested approximately $65 million in the Mid-Continent region during the first quarter. We continue to see results in our Mississippian Lime program that are consistent with our acquisition model. These results further confirm our high graded position as we continue to delineate our acreage. Well cost reduction initiatives continue to be a top priority for our Oklahoma teams. As mentioned in previous calls, we have transitioned all of our rigs to include top drives to improve efficiencies and will continue to make improvements to the process. Additionally, we have begun using rotary steerables to drill quicker, smoother and more accurate curves. As I said on our last earnings call, we are transitioning to bad drilling in our 2013 drilling program. This will help optimize facilities, infrastructure and rig moves. We are targeting drilling complete cost in the $3 million range by year end 2013. Midstates has an 80,000 acre concentrated position in the play that helps us optimize our infrastructure. We currently have over 75 wells producing in the Mississippian Lime play and eight salt water disposal wells. This year, we have drilled three additional salt water disposal wells to improve the efficiency of our SWD system and we’ll continue to evaluate optimization opportunities. During the first quarter of 2013, Northwest Oklahoma experienced two significant snowstorms that knocked out power to most of the regions. Over 90% of our wells produced within electrical submersible pump or ESP. As a result of the snowstorm, all of our producing wells with these pumps were shutting, which translated to an average of 1,100 barrels of oil equivalent being deferred from the first quarter. We also experienced production downtime in April. We are working on various options to improve reliability and redundancy, such as working with outside operators, local power suppliers and building our own natural gas generation sets. In early April, we added a fifth rig to our fleet. This rig will also drill in the more developed heart of our acreage. We will invest $70 million to $80 million in the Mississippian Lime assets during the second quarter and expect to drill 16 to 18 wells during the quarter. Turning to expenses, our lease operating and workover expenses for the quarter were $13.9 million, which resulted in a unit cost of $9.51 per BOE, which was higher than our Q1 guidance. The higher than expected costs were due primarily to the storms in Northwest Oklahoma. While volumes were down due to power outages, cost did not, in fact costs were up due to repairs and recovery expenses. The remaining outages were due to short-term water disposal and chemical costs in Louisiana, which we have discussed in previous calls. We expect those costs to be significantly less as we go through the year due to additional piping and well conversions. In closing, let me reiterate, it remains our sole focus to execute on our drilling and completion plans by reducing our capital costs, cycle times and operating expenses. I will now turn the call over to Tom for financial results and guidance.

[Tom Mitchell:]

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 in the range of 19,000 to 21,000 BOE per day was about 50% coming from our Mississippian properties, 35% from Louisiana and about 15% from the new Anadarko properties. For the quarter, this includes the Panther properties beginning June 1st. Again, I’ll refer you to the guidance page for details of the relative production components, but these remain the same as we provided in early April. The tables in our press release provided detail of price utilization for the first quarter. In addition, the guidance page provides the expected realization differentials including transportation for your modeling purposes. These differentials have not changed from previous comments. The earnings release included detailed information on the hedges we have in place. We’ve not added any positions since we provided a hedging update during our Panther acquisition call in April. At this point, we have essentially maxed out the amount of well hedges we can have in place until the May 31st closing of Panther. For oil, we currently have around 80% of our production hedge for the balance of 2013, around 70% in 2014 and around 28% in 2015, all excluding anticipated Panther volumes. We do expect to add more hedges once the transaction closes assuming the commodity market cooperates. The target is to hedge the maximum allowed under our credit facility, which equates to around 50% of our production over the next couple of years. Let’s now turn to review the expenses. While we do split our production guidance by area, I will provide guidance on expense items in total for the company. For the reasons Steve discussed, we did see an increase in first quarter lease operating workover expenses of about $2.4 million, up from the fourth quarter. The increased expenses experienced are short term in nature, and we are taking corrective actions to bring those dollars back in line with more normal run rates. Those short term impacts came from higher workover activity in the quarter as well as salt water disposal cost in Louisiana, and of course the storm-related repair costs. However, on a BOE basis, the increase was more exaggerated as we lost significant BOEs in the quarter due to the storms. Obviously, when the field is down for a short period of time, much of that cost is fixed and doesn’t variablize with those short-term fluctuations in production volumes. As a consequence, the LOE per BOE came in at $9.51 of barrel compared to our fourth quarter level at $8.05. While most of the storm impact was felt in the first quarter, we do expect some minor bleed over impacts as well. So we’re guiding the second quarter to a level of $8.75 to $9.25 of BOE and moving the full-year 2013 annual guidance to $7.50 to $8 per BOE. Severance and ad valorem taxes were 6.6% of sales revenue before derivatives, lower than the 8% to 9% we guided to for the quarter. This tax decreases in total and as a percentage of revenue primarily because of the increased production from our Oklahoma properties which are subject to a lower, effective severance tax rate compared to our Louisiana properties. Going forward, for both the second quarter and full-year 2013, you should expect the rate to be 7% to 8% of revenue, which reflects the lower rate in Oklahoma and also the expected taxes on our new Anadarko properties. Our first quarter general and administrative expenses were $11 million or $7.56 per barrel lower than the $8.07 per barrel in the fourth quarter. The first quarter included non-cash compensation of $1.2 million and about $800,000 of transaction services costs for the Eagle deal. We expect G&A in the second quarter of 2013 to be in the range of $11 million to $13 million, and the total year to be unchanged in the range of $49 million to $53 million. 10% to 15% of our G&A will be non-cash compensation. In addition to these costs, we expect about $10 million to $15 million in Panther transaction expenses in 2013, primarily in the second quarter. As John mentioned, our cash operating expenses which include LOE workovers, severance and ad valorem taxes and cash G&A were $20.29 per BOE, which is roughly flat with the fourth quarter. Our DD&A rate in the first quarter was $27 or $28.77 per BOE in line with our guidance. We are reducing the top-end of our previous guidance a bit, with the new range of $27 to $30 per BOE for the second quarter and full-year 2013. For the first quarter, our effective tax rate was 39% and you should expect around 40% for the second quarter and the full-year of 2013. And we do not expect to have a cash income tax liability for the foreseeable future. Turning to our capital structure, on March 31, 2013, liquidity was $139 million consisting of $88 million of available borrowing base under the company’s revolving credit facility and $51 million in cash and cash equivalents, so at quarter end our borrowing base was $285 million. Total interest expense incurred in the quarter was $17.9 million. We expensed $10.9 million and capitalized about 40%, or $7.1 million to unproved properties. Going forward, we will again capitalize around 40% to 50% of it to unproved properties. During the first quarter, we invested approximately $126 million in capital expenditures, with $65 million in Mid-Continent and $61 million on the Gulf Coast area. We expect to invest a $145 million to $165 million in the second quarter with about 50% in the Mississippian, about 40% in Gulf Coast and the remainder in Anadarko. The full-year guidance is unchanged at $525 million to $575 million and the split by area is provided on our guidance page. As John mentioned, we have canceled our plans to issue equity. We now expect to raise around $700 million fully through debt financing to fund the acquisition purchase price of $620 million in cash and to provide funding for our capital investment program. Proceeds from the debt financing, combined with internally generated cash flow and the commitment from the bank group to increase the borrowing base under our revolving credit facility to $425 million at closing of the transaction. We will provide sufficient liquidity to fund the investment program for at least a year well into 2014. Even though, we will have over a year of liquidity visibility, we would expect our borrowing base to increase during that time as well. While we are very conscious that our debt to EBITDA will peak around 4.1 times at closing, we’ll be highly focused on executing our programs and bringing our balance sheet back to more desirable levels as soon as possible. We remain committed to achieving our long-term debt target of 2.5 to 3 times EBITDA within 18 to 24 months following closing. I’d like to cover one housekeeping point before turning this back over to John. As it is customary with new public companies, we became eligible to file the shelf registration statement with SEC in May, roughly a year after IPO. That filing which we intent to make here in early May allows us to issue public securities under the shelf in the future without the need for SEC review at such time, which can sometimes turn into a lengthy process, risking execution of a capital market’s transaction. It is prudent for us to file the shelf now and work through the process with the SEC to have it become affective. As both John and I have mentioned, we will not be issuing equity so the shelf filing is not signaling an equity offering. We remain excited and focused as we continued to grow Midstates going forward. And with that, let me now turn the call back over to John.

[John Crum:]

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.

[Al Petrie:]

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

[Operator:]

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

[Neal Dingmann:]

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.

[Tom Mitchell:]

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.

[Neal Dingmann:]

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?

[John Crum:]

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.

[Neal Dingmann:]

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

[Operator:]

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

[John Crum:]

Good morning, Ron.

[Ron Mills:]

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?

[John Crum:]

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.

[Ron Mills:]

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?

[John Crum:]

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.

[Ron Mills:]

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?

[John Crum:]

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.

[Ron Mills:]

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

[John Crum:]

Thank you.

[Operator:]

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

[Leo Mariani:]

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?

[John Crum:]

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.

[Leo Mariani:]

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?

[John Crum:]

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

[Leo Mariani:]

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?

[John Crum:]

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.

[Leo Mariani:]

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?

[John Crum:]

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

[Leo Mariani:]

Thanks guys.

[John Crum:]

Thank you, Leo.

[Operator:]

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

[John Crum:]

Good morning, Chad.

[Chad Mabry:]

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?

[John Crum:]

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.

[Chad Mabry:]

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?

[John Crum:]

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.

[Chad Mabry:]

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

[John Crum:]

Thank you.

[Operator:]

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

[John Crum:]

Hubert.

[Hubert van der Heijden:]

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?

[John Crum:]

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.

[Hubert van der Heijden:]

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?

[John Crum:]

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.

[Hubert van der Heijden:]

Okay. Perfect.

[Operator:]

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

[John Crum:]

Good morning, Ipsit.

[Ipsit Mohanty:]

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.

[John Crum:]

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.

[Ipsit Mohanty:]

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?

[John Crum:]

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

[Ipsit Mohanty:]

That’s right.

[John Crum:]

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.

[Ipsit Mohanty:]

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?

[John Crum:]

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.

[Ipsit Mohanty:]

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?

[John Crum:]

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

[Ipsit Mohanty:]

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

[Operator:]

Your next question comes from the line of Stephen Shepherd with Simmons & Company.

[Stephen Shepherd:]

Hey, guys. Good morning.

[John Crum:]

Good morning.

[Steve Pugh:]

Good morning.

[Stephen Shepherd:]

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?

[John Crum:]

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:]

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?

[John Crum:]

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:]

Okay. That’s all I have. Thank you.

[John Crum:]

Thank you.

[Operator:]

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

[John Crum:]

Hey, Chris.

[Chris McDougall:]

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?

[John Crum:]

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.

[Chris McDougall:]

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?

[John Crum:]

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.

[Chris McDougall:]

Okay. Great. Thanks a lot.

[John Crum:]

Thank you, Chris.

[Operator:]

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

[John Crum:]

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.

[Operator:]

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