Amplify Energy Corp (AMPY) 2013 Q1 法說會逐字稿

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 question-and-answer session. (Operator instructions). At this time, I would like to turn the call over to Al Petrie, Investor Relations Coordinator. You may begin.

(technical difficulty) 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 expect, believes, plans, projects, estimates or anticipates will or may occur in the future are forward-looking statements. These include statements regarding reserve and production estimates, oil and natural gas prices, the impact of derivative positions, production expense estimates, cash flow estimates, future financial performance, planned capital expenditures and other matters 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 actual 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 a 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've tried to give 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, we 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 be news to you.

I feel like we had a very good first quarter. We couldn't do anything about the weather issues, but our team has executed well on the things that could control. We continue to be encouraged by the drilling results we 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 targeted 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's potential for more than 20 horizontal locations at North Cowards Gully. Results to date have encouraged us to spud two additional wells which are presently drilling.

We are also awaiting test rates from the first South Bearhead Creek horizontal Wilcox well, the Musser-Davis 33-28 HC 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 production. 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, location matters, and we remain 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 costs 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 with the fourth quarter of 2012.

In our call on April 4, we discussed in detail the pending $620 million acquisition of producing properties, as well as the 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 31. 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 the Panther assets into our organization. The Panther team has continued their three-rig operation and we are pleased to let you know that current production is above the 8000 BOEs per day 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 career.

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.

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 Wood 10H-1 well in North Cowards Gully Field. This well is the easternmost well in the field and was drilled to a measured depth of 15,366 feet and has a lateral length of about 3000 feet. The well had a seven-day average rate of over 1250 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 3-D seismic data, give us encouragement that there are additional wells to drill east of the Wood well. We're also very encouraged with our drilling and completion costs 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 Lower 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 4300 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're 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 the 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 3-D seismic data over the area and have begun our initial interpretive work. We expect this new data will contribute to our effort to build additional inventory. We do not plan to drill any wells in Pine Prairie during the second quarter while we concentrate on inventory generation, which could 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 3 to 4 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 rings 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 continued 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 pad drilling in our 2013 drilling program. This will help optimize facilities, infrastructure and rig moves. We are targeting drilling complete costs 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 saltwater disposal wells. This year, we have drilled three additional saltwater disposal wells to improve the efficiency of our SWD system and will 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 region. Over 90% of our wells produce with an electrical submersible pump, or ESP. As a result of the snowstorm, all of our producing wells with these pumps were shut in, which translated to an average of 1100 barrels of oil equivalent being deferred from the first quarter. We also experienced production down time in April. We are working on various options to improve reliability and redundancy, such as working with offset 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 work-over 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 went down due to power outages, cost did not. In fact, costs were up due to repairs and recovery expenses. The remaining overages 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 cost, cycle times and operating expenses.

I will now turn the call over to Tom for financial results and guidance.

Good morning, everyone. Earlier today, we placed 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 26,000 BOE per day, as well as the original composition and product mix. Obviously, the down time 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 are expecting to be in the range of 19,000 to 21,000 BOE per day with 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 1.

Again, I will 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 provide a detail of price realizations 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 have 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 oil hedges we can have in place until the May 31 closing of Panther. For oil, we currently have around 80% of our production hedged 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 a review of 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 work-over 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 work-over activity in the quarter as well as saltwater disposal costs 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 variable-ize with those short-term fluctuations in production volumes.

As a consequence, the LOE per BOE came in at $9.51 a barrel compared to our fourth-quarter level of $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 are guiding the second quarter to a level of $8.75 to $9.25 a BOE and moving the full-year 2013 annual guidance to $7.50 to $8.00 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. These tax decreases in total and the percentage of revenue, primarily because of 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 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 transition services cost 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 work-overs, 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're 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 2013. 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. 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 and Mid-Continent and $61 million in the Gulf Coast area. We expect to invest $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 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 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 will 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 would like to cover one housekeeping point before turning this back over to John. As is customary with new public companies, we became eligible to file a shelf registration statement with the SEC in May, roughly a year after IPO. That filing, which we intend 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 markets transaction. It is prudent for us to file the shelf now and work through the process with the SEC to have it become effective. 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 focus as we continue to grow Midstates going forward. With that, let me now turn the call back over to John.

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 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-risked 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 assets for at least six more months. We will deliver an aggressive drilling program that focuses on development of proved formations, primarily the 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 a diverse oil-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 questions to one with one follow-up question. Thanks.

(Operator instructions) Neal Dingmann, SunTrust.

Good morning, guys, good quarter. Say, John, first question regards to just what you all have going on like in North Cowards Gully. I noticed on that and just some of your other Gulf Coast, it looks like on the horizontals, that one, the 10H-1 was fracked with a 10-stage. I was wondering now when you go forward either to that one or some of these others you are going to drill for the rest of the year, just if you could talk about completion methods. Will you stay around -- give me an idea on lateral length stages, etc., as well as well costs there.

Yes. Neal, I think as we get a little longer laterals, which we are kind of working our way up to, we will be adding stages. And just to that point, South Bearhead Creek well that Steve mentioned we have just completed our frac on and we have actually done 14 stages on it. So you should expect to see stages going up as we increase our lateral lengths.

Okay, and then just to follow up over on the horizontal Miss, I know you mentioned about adding a fifth rig there. Give an idea, I guess, John, do you stay at that level based on your guided CapEx that you and Tom spoke of today? And then just wondering currently, today, what are you seeing around typical IP rates, and has your EUR estimates changed at all in the region?

No. Our IP and type curve kind of information -- we are staying with what we have provided you in the past. It feels like on average, that's working out pretty well. The fifth rig we've added we'll be working the core. So again -- well, we call it the core, the center of our acreage position there along that county line of Woods and Alfalfa Counties. So we would expect to get fairly consistent results in there because, as you know, we have already drilled in most cases at least one well in the section.

Got it, look forward to it, okay thank you all.

Ron Mills, Johnson Rice.

A couple of questions -- as part of one, I guess, in the Wilcox, North Cowards Gully, it sounds like you know Wilcox B is the target, South Bearhead is the C. What drives the decision there 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 wells 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?

Yes, I think that is going to get those us a pretty serious feel for it. The 10-H well did confirm that, indeed, we got some structure to the east. We have also got some new seismic in that is 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 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. It's where we had the vertical wells. Once we move to South Bearhead Creek, we've got a multitude of potential targets in South Bearhead Creek, both in the Lower and Upper Wilcox. So you will note one of our competitors is out there drilling a well as we speak.

Okay, and as it relates to the Woods/Alfalfa acreage, it sounds like the rig you just added -- you'll have four rigs drilling in that core area and one HBP-ing 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?

Yes, well, we are moving ahead full speed with trying to make sure we don't run into those same electrical problems. I would point out, these were -- 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 in from some of the co-ops as well as put in our own generation capacity.

I think you have been hearing from [under] the Mississippian players that diesel generators are expensive to run. That's not a surprise to anybody out there. So we will be moving to natural gas-fired in the future for our supplemental needs.

And did you say that Cleveland is the primary focus of your Panther activity over the remainder of the year? And at which point do you think you would look at some of the other formations, given some recent results from offset operators?

Yes, I probably oversold that, so -- the Cleveland, we kind of told you when we started we will probably have about half of the rigs running. It's the most well understood of the plays that we are 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 are obviously watching what the rest of the industry is doing as well, but that would be the plan is about half the rigs working in the Cleveland and another half working in the rest of those targets.

Perfect, let me let someone else jump in. Thanks, John.

Leo Mariani, RBC.

-- your Gulf Coast production a little bit here. Just looking at some of the numbers you guys provided, and I'm seeing that your oil production on the Gulf Coast was down about 1200 barrels a day this quarter versus the prior quarter. Just wanted to get a sense of what was causing that. You guys also mentioned that you wouldn't do anything in Pine Prairie in the second quarter. Trying to get a sense of when you are going to get back to Pine Prairie and how we should expect that oil production to trend for the 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 brought on at Pine Prairie. The good news about those is they come on at nice, high rates. The bad news is they are not big EURs, so they tend to deplete fairly quickly. So good rates of return out of them, but it will bring your volumes down fairly quickly.

The issue on Pine Prairie on continued drilling is we just got access to a 3-D survey there, and we would like to go ahead and make sure we've got that interpreted 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. So we've got lots of plans to go forward there. We just want to make sure we're taking advantage of all the technology we have out there to pick the next locations.

Okay, so when we should expect you guys to get active at Pine Prairie again? What do you think a reasonable time frame is for that?

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

Okay, and I guess in terms of down time, you guys talked about down time in the Mid-Con lingering into April. Could you guys quantify how much -- how many barrels you would expect to lose your in April?

Yes. I don't know that I've got that number, but April was -- we had a couple of extra storms in there, but just getting all these units back up and then getting smoothed out -- we are seeing somewhat of a -- I think I've mentioned to a number of you, de-watering effect. If we can keep the production on steady, then we tend to bring our oil cuts 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 had. So we think that has affected us as well.

On the overall, we've still given you an indication of what we expect our third quarter numbers to be, and -- I mean, excuse me, our second-quarter numbers to be. And so you are going to end up with about 19,000 to 21,000, I think, is what we've got out there, and you will see that we are expecting 50% of that to come from the Miss.

Okay, and I guess -- are you still seem down time in the Mid-Con, or is that over at this point, now that we are in May?

No, it's pretty well over now. Still working on trying to improve the infrastructure, as we mentioned to Neal.

Thanks, guys.

Chad Mabry, KLR Group.

I just had a question, a follow-up on the Panther acquisition. Curious if you could help us out with 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 bring in 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 shoot, and maybe your plans to test that large acreage position sometime this year.

Yes. Thanks, Chad, for bringing that up. Sometimes we forget we've got some of these other things going on. Yes, so we have been working the seismic pretty well. We have confirmed a couple of the prospects that we had early on, even with 2-D, so we feel pretty good about that position.

I think I've indicated to you guys on some other calls that one of the things we deal with here is we are in basically one of the spillways off the Mississippi River. And so consequently, we have to get wetlands permitting. So it's a long, arduous process and, frankly, we are still arguing a little bit over which will be the first location we drill. So it's going to be late summer before you see us out there drilling a well.

Okay, great, I'll get back in queue, thanks, guys.

Hubert van der Heijden, Tudor Pickering Holt.

Good morning, guys. On the Wood well, I was just wondering if you could comment in a little bit more detail on the oil cut off that well and if this is still something that you see trending up over the longer term, to the 70% to 80% oil cut that you've had on the offsets there.

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

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

Yes. Hubert, I think the lesson we learned is to take this a little bit slower and make sure we are applying each of the things we've learned as we move to the next well. And so we are going to concentrate this -- we think we need to continue to develop the horizontal drilling application in the Wilcox. So consequently, we are going to concentrate on the structures that we actually know worked very well on a vertical basis, and that's why you see us and North Cowards Gully and South Bearhead Creek.

The other issue is, obviously, Fleetwood is such a big position there that we will be testing that. And so bottom line is some of those other operations, in some cases we have tested them and they haven't worked as well, but the bottom line is they are kind of falling to the bottom of the queue.

Okay, perfect.

Ipsit Mohanty, Canaccord.

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

Well, I think all of the above. Obviously, we think these are great assets we've taken on, and we didn't think where our equity price had gone to was anywhere close to reflecting what we believe we own here. So it was frankly an illogical move to put out equity at these kind of levels. So we are quite confident that we can cover what we've got. With the assets we've got, we are going to have plenty of cash flow off them. These assets should generate very positive cash flows, and we certainly are comfortable with going forward with the all-debt arrangement.

Well, John, this is a multi-stack play, and you have positions in the different counties. Are there other particular counties that you are going to focus more initially, and just a plan on how you go about developing these assets?

Yes. Ipsit, now, you are talking about Panther; right?

That's right.

Look, I think we're going to try to take the same position with the Panther assets that we are doing with the Eagle assets, which is concentrate a lot of our activity in and around areas that we know have 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 other Oklahoma acreage -- Hansford County, Texas, and some of our Oklahoma acreage. But we are 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, so just a little higher well costs than the $3 million you are trending towards, towards the end of the year. Could you fill that gap for me?

Yes. I think the bottom line is we are not at $3 million yet, and I think what Steve was trying to point to see believes we can get there by the end of the year. But we have been averaging more like $3.5 million to date.

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

There is some infrastructure in there. We've got a power plant in there and we have put -- and (multiple speakers) there are some land costs in there as well.

Alright, great. Thank you, guys, I'll leave it at that.

Stephen Shepherd, Simmons & company.

What is your EUR assumption on the Wood well in North Cowards Gully? Is there any guidance you can give me on what kind of B factor you guys are using on those horizontal wells?

I guess we've only got seven days, and if there's one thing we've learned about the Wilcox is we need a little more time to work through that. As a general rule, the B factors we would expect to use in Wilcox-style wells are going to be somewhere around 1.

Okay, and so my second question -- this is more kind of a high-level, I guess, strategy question. But would any of your Louisiana properties potentially be considered divestiture candidates going forward in an effort to continue to refocus as more of a Mid-Con lever producer and fill any funding gaps going forward? I just wanted to get your thoughts on that.

Well, I think, first of all, you need to look at the amount of cash that the Louisiana properties generate. So it would be a big decision for us to do something like that. But, that said, I think we are businessmen, and if the right opportunity came along with the right offer, then obviously we would take a look at it. But right now, they generate a lot of cash for us, and so we think they are important properties to maintain. And we think we are onto something with these horizontal drilling applications. So it doesn't feel like the right time to say we would do something with those.

Okay, that's all I have, thank you.

Chris McDougall, Westlake Securities.

First, on the horizontal Gulf Coast, so what are really the keys to success there? It seems like things have improved significantly. Is it the seismic data? Is it the well package or completion solution?

Well, I think we are figuring out quite a few things about it; don't necessarily want to share it with the rest of the industry. But the 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 have gotten better at drilling them. I would remind you that we are typically at 13,000 feet vertically and then trying to do a horizontal off that and we are an overpressured reservoir. So these are not simple wells to drill, and certainly not for the fainthearted.

So as we get better at each of these, then we would expect to get better and better performance.

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

We get asked that quite a bit. I think Steve would tell you we are not really seeing anybody lowering their cost of service on a per-job basis or a per-pound or a per-horsepower or anything like that. We had gotten some reduction in drilling rig rates probably last year, and really things are holding fairly flat.

What we are getting better at is just getting more efficient, and so we are seeing our overall costs come down on a per-frac job or a 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've got all the equipment we need available to us.

Okay, great, thanks a lot.

Ladies and gentlemen, we have 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 are pretty excited about where we are 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 you can look forward to us continuing to deliver some solid quarters. Thank you.

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