Amplify Energy Corp (AMPY) 2013 Q2 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 second-quarter earnings 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). At this time I would like to turn the call over to Al Petrie, Investor Relations Coordinator.

Good morning, everyone, and welcome to Midstates Petroleum's second-quarter 2013 earnings conference call. Joining me today as speakers on our call are John Crum, Chairman, President and Chief Executive Officer; 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 second quarter. Steve will then provide more details on second-quarter operational results and plans for drilling activity for the third quarter of 2013. Tom will follow with key financial highlights of the second quarter and provide guidance for the third 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 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 that are discussed in Midstates' filings with the SEC. 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 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 and the second 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 tables 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. The second quarter of 2013 was a very busy one for all of us here at Midstates. We achieved encouraging results from a very active drilling program in each of our areas. The biggest news, though, was the close of our $620 million acquisition of properties from Panther Energy and their partners, giving us a new focus area in the prolific Anadarko Basin.

Before we get into specifics for the quarter, I would like to begin with some comments about the Company as a whole. As we have built our team at Midstates, we have been clear that we intended to grow the Company. Our growth is critical to attracting and retaining top talent. The individuals we are bringing into the Company are the kind other companies are trying to attract as well. We have been successful in putting a quality team together by shopping them the potential to be an integral part of the growth while continuing to expand their skill sets and to demonstrate their ability to create value for our shareholders and for themselves.

This time last year, we were producing less than 8000 BOEs per day. We were operating only in Louisiana and had just received concerning news associated with a lawsuit affecting Pine Prairie, our most valuable asset. Today, after two large acquisitions, we are producing about 27,000 BOEs per day from a diversified asset base in three states and have received an order from the Louisiana Supreme Court ruling unanimously in our favor on the Pine Prairie lawsuit. We are now firmly focused on execution of our drilling and development plans across our asset base to drive growth.

The newly acquired Anadarko Basin assets provide us with low-risk, proven drilling targets, primarily in the Cleveland sands as well as upside in the numerous known pay intervals present in the Anadarko Basin. We closed the Panther acquisition on May 31, as planned. As we have discussed, the entire Panther staff is under a transition services agreement for six months to allow for a smooth handover of operations. Panther has built a very strong team. We will be working hard to convince a significant number of those individuals that Midstates would be a good place to continue their career. We entered the Anadarko Basin with a robust inventory of identified drilling locations and have already started a ramp-up of activity, added a fourth rig in early July.

Operations in the Mississippian continue to move ahead as planned and within expectations. We now have 85 wells that have been on production more than 30 days. Those wells have delivered an average 30-day IP of 573 BOEs per day. Steve will provide more detail in a moment, but I am excited about the significant improvement in our drilling and completion costs and cycle times as well as to the infrastructure needed to remove the artificial production constraints.

Pad drilling has been a key driver for that success in gaining efficiency. Pad drilling operations obviously saves on location, roads, pipelines, electric line construction costs, but it also provides significant savings in our rig moves and reductions in our cycle times. As we continue to employ and optimize these techniques, I am confident more savings will be evident into 2014.

We recently received an initial look at the 3-D seismic data that was shot over the majority of our acreage and are encouraged that we will be able to use the data to assist us with better delineation and de-risking of future drilling locations. Full processing is underway. We expect to have the survey results significantly affecting our location and completion selection decisions before the end of the year.

Meanwhile, we will be concentrating our activity over the remainder of the year in the most proven of our acreage position in Woods and Alfalfa counties of Oklahoma. Production from the Mississippian continues to increase month to month, but there will be some lumpiness in the growth as we complete and bring on three to four wells on one pad at a time.

We have made meaningful progress in the horizontal Wilcox program in Louisiana during the quarter by completing four wells. Three of the wells were in North Cowards Gully, and one was in South Bearhead Creek. The first well completed during the well, the Wood 10H number 1 at North Cowards Gully, produced at strong initial rates, but then experienced a mechanical failure. The early flow rates experienced have led us to the decision to sidetrack the well during the third quarter. Steve will discuss how knowledge gained from drilling the Wood well and others was used in drilling and producing subsequent wells and the positive results we have experienced with them.

Importantly, we also completed our first horizontal lower Wilcox well in South Bearhead Creek during the quarter, the Musser Davis 33-20 8HC number 1. The well was drilled within budget and continues to flow at strong rates of over 400 BOEs per day after three months. We will have two more horizontal completions, one at North Cowards Gully and one at South Bearhead Creek, during the third quarter. We will monitor production results for a number of months before moving to full-scale development.

Horizontal Wilcox development is difficult, as indicated by recent industry colleague comments and by our own trials as we work to identify the necessary parameters to achieve commercial success. Our results to date indicate we can profitably develop North Cowards Gully and South Bearhead Creek fields with horizontal technology. But we will do so at a measured pace, incorporating learnings into each new well. That said, our results to date have also shown us that further development at our West Gordon field is not competitive with the other available investment options in our expanded portfolio at this time. As a result, in the second quarter we wrote off the pud reserves in that field, which totaled 4.6 million BOEs.

At Pine Prairie, we are continuing with inventory generation while taking full advantage of the new 3-D data recently acquired before doing any further drilling. We are also proceeding with plans for a pilot to evaluate the water flood potential.

At Fleetwood, we are developing prospects based on the new 200 square mile process 3-D seismic survey were received earlier this year.

I am pleased with the third-quarter production of 19,634 BOEs per day, which was well within our guidance range. We were able to reach this production rate in spite of some severe weather interruptions affecting those volumes negatively. Most importantly, we have continued to grow those volumes to around 27,000 BOEs per day as a result of both additional success in the Mississippian and in Louisiana, as well as adding one month of new Panther volumes. Many of the initiatives mentioned above will help provide more stability to the remainder of this year and into the future.

I will now turn the call over to Steve and Tom to provide you detailed information on our results.

Thank you, John, and good morning. In keeping with our normal earnings call format, I will discuss second-quarter results, some of our more recent well results and our operational plans for the third quarter. I will start with the Mid-Continent region, which includes our Mississippian Lime acreage and our newly acquired Anadarko Basin properties.

As we announced on the first quarter conference call, we ramped up activity by adding a fifth rig in the Mississippian Lime at the beginning of the second quarter. For the majority of the quarter, four of the rigs were focused on drilling in our most proven area, while the fifth was used to test and hold acreage in outlying areas. By the end of the quarter, all five rigs were drilling in the more proven area.

As John discussed, we participated in a 300 square mile 3-D shoot and we are excited about incorporating the results into our decision-making. We invested $77 million and spud 21 operated wells during the quarter, of which five were producing, 11 were awaiting completion and five were drilling.

Second-quarter production in the Mississippian Lime and the Hunton averaged 10,426 BOE per day, of which 33% was oil and 17% was NGLs. We recorded lower than normal liquids due to approximately 40% of our gas volumes being temporarily bypassed until the new [SimGas Hopeton] plant was operational, which was June 1. This bypassing of our gas stream resulted in short-term lower realized liquids yields and a higher gas percentage. We expect the production split to be back to normal in the third quarter.

We have continued to see significant improvement in our cycle times. During the second quarter, our average spud to rig release was below 20 days, a substantial improvement over the 26 days that we averaged during the first quarter of 2013. Three factors that continue to drive this efficiency are the use of top drives on our rigs, the use of rotary steerables in the curved section of the hole and additional experience in the play.

As John mentioned, pad drilling has been one of the key changes we have made in the Mississippian program. We are building pad sites with six-well capacity but are currently drilling a maximum of four wells per pad in an effort to minimize the amount of time needed to bring those wells onto production. Although pad drilling significantly reduces drilling time and provides other cost savings, the timing from spud of the first well to all four wells being brought unto production is roughly 100 to 110 days.

Moving forward, we will see spikes in production as a larger number of our wells are drilled off of pads and are brought on in groups, but we will also see periods with few completions, resulting in some quarter-to-quarter variability in our production growth.

We have been proactive with optimizing our SWD and power infrastructure in the region. One of the biggest challenges when operating in the Mississippian Lime is produced water. Fortunately, due to our concentrated acreage position and efforts to optimize our disposal system, 100% of our produced water goes to our SWD wells. Additionally, 95% of the frac water for our recent new completions is sourced from produced water, which significantly cuts the use of fresh water in the area. After the major snowstorms we experienced earlier in the year, increasing reliability of our power grid has been a key focus. We have programs in place to lower per-unit cost in the long-term, including replacing diesel generators with natural gas generators, working with local co-ops to upgrade electrical lines, working with other operators in the area to share costs an additional substations and a significant maintenance and upgrade program on our existing grid. We expect these initiatives to yield improved reliability to our power supply.

For the third quarter, we plan to spend approximately $105 million in the Mississippian, completing the wells awaiting completion and drilling at quarter end while spudding 20 to 25 new wells.

As you know, we assumed operations on the Panther acquisition properties during the quarter. The Company completed three wells during the quarter and spud three additional wells that we are still drilling on June 30. We are pleased with the results and plan to ramp up activity throughout the remainder of the year.

In the Anadarko properties, we plan to spend approximately $45 million completing wells awaiting completion and drilling at quarter end while spudding 15 to 18 new wells during the third quarter. We had a steady quarter in our Gulf Coast region as well. We completed a total of six wells during the quarter, of which two were verticals and four were Wilcox horizontals. One vertical well was in Pine Prairie and one was in the South Bearhead Creek field. Both wells are performing to our expectations. Of the four horizontals completed during the quarter, three were in North Cowards Gully, where we continued to see consistent results, and one was in South Bearhead Creek.

In North Cowards Gully, we completed the Musser Davis 8H number 2, the Olympian Minerals 16 H number 1 and the Wood 10H number 1. All three wells target to the Upper Wilcox B formation. As we previously announced, the Wood 10H number 1 was completed early in the quarter and produced a seven-day average IP of 1086 BOE per day but had mechanical issues that caused it to stop production. We believe we have identified the solution to the problem and have decided to sidetrack the well in the third quarter.

We managed the choke on the Musser Davis 8H number 2 and the Olympia mineral 16H number 1 wells as compared to previous wells in the area to allow a smoother transition as we declined through the over-pressured range of the reservoir. The Musser Davis 8H number 2 is an offset to the very successful Musser Davis 8H number 1 well and was brought on in early June and produced at a 30-day IP of 595 BOE per day, of which 81% was oil and 8% NGLs. The results are encouraging with the well now flowing above 625 BOE per day almost 60 days later.

The Olympia Minerals 16H number 1 well was drilled and completed with a 4500-foot lateral, which is the longest lateral we have drilled in the Louisiana Wilcox. It began production in early July and produced at an average 30-day IP of 751 BOE per day, of which 60% was oil and 16% NGLs. These results are also very encouraging as the well is now producing above 675 BOE per day.

Although the IPs are lower than previous results, the estimated ultimate recoveries remain consistent. We continue to evaluate the flowing pressures and will slowly open the chokes in order to maximize reservoir recovery.

We completed the Musser Davis 33-28 HC number 1 well in South Bearhead Creek, which was our first horizontal Wilcox well in the field and our first lower Wilcox horizontal. It was brought on in early May and recorded a 30-day IP of 882 BOE per day, of which 72% was oil and 11% NGLs. The results from our first lower Wilcox horizontal are encouraging with the well still flowing above 400 BOE per day after three months of production.

The second horizontal well in the field, the Musser Davis HC number 1, is approaching TD, targeting the lower Wilcox B Sand. During the third quarter, we expect to spend approximately $25 million drilling and completing two to three horizontal wells.

Turning to expenses, our lease operating and workover expenses for the quarter were $17.6 million or $9.83 per BOE, which was higher than guidance. We incurred workover expenses at the beginning of the quarter to bring wells back online following weather disruptions in the Mississippian coupled with lower-than-expected production during that period. In addition, electricity costs in the area have been more than we expected, which we are in the process of remedying with the initiatives I spoke about earlier.

In the Gulf Coast region, we had a higher-than-expected SWD and surface maintenance cost. We have seen our overall LOE costs come down recently as the initiatives we spoke about here and in previous calls take effect.

In closing, we are encouraged by our recent well results and plan to continue to optimize drilling and completion methods across our portfolio. We will remain focused on growing production and implementing additional cost reduction initiatives. As we begin integrating the Anadarko assets into our portfolio, we look forward to incorporating Panther's talented staff into our organization.

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

Good morning, everyone. My comments today will focus primarily on updating forward guidance with a few second-quarter highlights.

To begin, second-quarter adjusted EBITDA was $65 million after adding back the $11.5 million in acquisition and transaction costs we incurred with the Panther acquisition. This is up 15% from $57 million in the first quarter. The second quarter benefited from higher production volumes in the Mississippian and one month of production from the new Anadarko Basin properties.

We reported net income of $3.3 million in the second quarter compared with a net loss of $7.9 million in the first quarter. Adjusted income for the second quarter, which excludes the impact of unrealized gains or losses on derivatives, as well as the Panther acquisition transaction costs, was a net loss of $4.2 million.

Production in the second quarter rose 21% to 19,634 BOE per day from the prior quarter with 67% coming from Mid-Continent properties, 33% from our Gulf Coast properties. In Mid-Continent, our Mississippian and Hunton properties averaged 10,426 BOE per day, while our new Anadarko Basin properties contributed 2068 BOE per day for the quarter. That reflects one month only of production for Panther in June.

Our guidance for the product breakdowns remains as previously provided. As Steve discussed, we did experience a lower percentage of liquids in the Mississippian Hunton product breakdown during the second quarter, but the lower liquids weighting was temporary for the reasons we mentioned.

Looking ahead to the third quarter, we expect production to be in the range of 27,000 to 28,000 BOE per day with about 50% from our Mississippian and Hunton properties, 30% from our Anadarko properties and 20% from Louisiana. For the full year 2013, we have narrowed our range by reducing the upper end of our guidance range to reflect the weather-related downtime we faced in the first half of the year.

Annual guidance is now 24,000 to 25,000 BOE per day.

The impact of pad drilling in Oklahoma will result in a number of wells coming online concurrently in September, which tempers growth in the third quarter but will result in meaningful volume increases in the fourth. The regional product breakdowns as well as expected realization differentials, including transportation, remain unchanged from prior guidance and are all reflected in the updated guidance summary posted to our website.

In our last quarterly call, we discussed how intent to add new hedge positions to cover the Panther acquisition volumes. We added those positions shortly after closing the deal on May 31. For oil, we added positions covering 4500 barrels per day for the remainder of 2013, 5250 barrels per day in 2014 and 1000 barrels per day in 2015. For gas, we added 40,000 MMBTU per day for the remainder of 2013 and 25,000 MMBTU for the full year of 2014.

These trades take our hedge positions for oil and gas near the maximum allowed under our credit facility, which is our ongoing target. Going forward, we will add hedge position as -- hedge positions as production grows. The earnings release includes detailed information on price realizations as well as a summary of the current hedge position.

Let's now turn attention to a review of expenses. As Steve discussed, our lease operating and workover expenses of $9.83 a barrel for the second quarter was above expectations for the reasons mentioned. For the third quarter, as our cost initiatives take effect, we expect LOE to trend lower and coupled with higher quarterly volumes to be in the range of $8.50 to $8.75 per BOE. We are adjusting full-year LOE guidance up $0.50 per BOE to a range of $8 per BOE to $8.50 per BOE, taking into account the higher costs that we have already experienced.

Severance and ad valorem taxes were 6.4% of sales revenue, and that is before derivatives, a bit lower than the 7% to 8% rate we guided to for the quarter. For both third quarter and full-year 2013, we have lowered guidance to 6% to 7% of revenue, which should reflect the new blend of production from Louisiana, Oklahoma and now Texas.

Second-quarter general and administrative expense was $15.3 million, which was above guidance and is primarily due to the pace and headcount additions. The second quarter included non-cash compensation of $1.8 million and about $2.3 million of transition services cost with $1.7 million related to the Panther acquisition and the balance to the Eagle acquisition. We expect G&A in the third quarter to be in a range of $14 million to $16 million and the total year to be unchanged, in the range of $49 million to $53 million. 10% to 15% of that G&A amount will be non-cash compensation.

Our DD&A rate in the second quarter was $29.56 per BOE, in line with our expectations. Despite the impact of West Gordon, which John mentioned, the second quarter DD&A rate remained within our guidance. We have narrowed our guidance range for third quarter and full year 2013 to $28, $30 per BOE. Total interest expense incurred in the second quarter was $24.5 million. We expensed $16.6 million and capitalized 32%, or $7.9 million. Going forward, we expect to capitalize to unproved properties $10 million in the third quarter and $35 million to $40 million for the full year.

During the second quarter, we invested approximately $141 million in capital expenditures with $77 million in our Mississippian properties and $6 million to our new Anadarko Basin properties. The balance of $58 million was spent in the Gulf Coast area. For the third quarter, we expect to invest $170 million to $180 million with about 60% in the Mississippian, 25% in Anadarko and the balance in the Gulf coast. The full-year guidance was narrowed to $550 million to $575 million and the split by area is provided on our guidance page.

On May 31, concurrent with the closing of the Panther deal, we completed a private issuance of $700 million of 9.25% senior notes. The $683 million in net proceeds were used to fund the acquisition and to provide liquidity. Additionally, our revolver was amended to increase the borrowing base to $425 million. With our current drilling programs focused on efficiently adding PDP reserves, which is the primary support to the borrowing base, we expect to see a strong increase in the borrowing base during the coming September redetermination.

On June 30, 2013, liquidity was $216 million, consisting of $204 million of available borrowing base under the credit facility and $12 million of cash. Our strategy through the end of the year and into 2014 is to grow cash flow while employing conservative capital allocation. Not only have we put hedges in place to protect against commodity price exposure, we have lined out our rig programs to reflect the most optimal growth of EBITDA and cash flow. We feel that through these initiatives, we can actually manage our liquidity while also providing a sustainable growth profile.

And with that, let me now turn the call back over to John.

Thanks, Tom. As you have heard today, we had a very busy second quarter and an even more active third quarter is well underway. As we develop our plans for later this year and into 2014, we will incorporate the knowledge we are gaining in each of our three focus areas into our drilling and capital plans.

In Louisiana, we believe we have a much better understanding of what works in the Wilcox. In the Dequincy area, we will finalize our drilling plans after monitoring our horizontal well performance in the near-term. In the Pine Prairie and Fleetwood areas, we will develop our drilling program based on the new 3-D data we acquired. In the Mississippian, we will update our drilling program based on significant success we have had with reducing cycle times and focus our drilling in those areas where we have had the best results. In the Anadarko, we have used the knowledge we have gained in the Mississippian as we ramp up activity at a measured pace to optimize the drilling program in that new area.

In summary, we remain 100% focused on execution of our plan to drive organic growth and on closely managing our capital allocation process. With that, we turn it over for questions.

(Operator instructions) Neal Dingmann, SunTrust.

John, just going through a little bit you mentioned on -- I'm just wondering, on the Gulf Coast operations, it does sound like you are making some progress there in deciding what and where to drill. Give me an idea on well cost. I know that the Musser Davis, that 8H-2 was down to $10 million. What are you assuming, you and Tom, when you look at the budget now for the remainder of the year on these well costs? In order to be economic, what are you going to need a hit on a go-forward basis for some of these, maybe the upper or lower Wilcox?

Well, on the Upper Wilcox, first of all, the $10 million range will be economic. Obviously, we would like the economics to get better. We would expect to be able to drive those numbers back into the 8s before we are done, there at North Cowards Gully, especially as we get into a real program.

On the deeper -- in the lower Wilcox, obviously, we are setting another string of casing and we are going into an over-pressured zone. We did spend in excess of $13 million on that first South Bearhead well. But again, we expect those numbers to be pulling back and we would be in the $11 million range on an ongoing effort there.

The well we are drilling right now is right on schedule and we expect to TD it in the next day or so. They are within -- I guess they were 800 feet off TD yesterday. So we feel pretty good about it. It is AFE'd at $11.5 million.

Interesting. Okay, okay, and then just my follow-up. Moving over on just the Horizontal Miss, two things there, John. One, infrastructure wise, it still seems like you all are keeping up, if not ahead of where you need to be there. And then just on cycle times, can those continue to -- you really had a material improvement there. What are you assuming on a go-forward? Can that continue to improve beyond the 20 days, or are we at the rates now that you were hoping for?

Yes. We are a little bit nervous about putting the stick out there for you guys to measure us against. But I will tell you that third quarter to date, we are less than the number we told you about the second quarter. So we feel like -- obviously, this pad drilling helps a lot. When you are drilling three or four wells off the same pad, it makes all the difference in the world. Rig moves are typically taking about five days and we change that to one day, so good running start. Obviously, we don't build three or four pads, so those are all helping with the numbers. Go ahead, Steve. Have you got anything?

Yes. Neal, just another comment -- the numbers that we gave you, the 20 days -- that is spud to rig release, so that actually doesn't pull in the pad sites. We start that clock after spud, and that is the number that John is saying, in the third quarter, so far we are seeing numbers still below the 20 number that we showed you. And we will talk more about that on the next call.

Good, yes, that's great to hear. Thanks, Steve.

Jeb Bachmann, Howard Weil.

I just wanted to look at the go-forward EBITDA number. Looking into 2014, if you guys have -- I know you have internally probably looked at that and what you could potentially you could generate. Just give us some idea of how you think you can grow that number in 2014 and what your targeted debt-to-EBITDA coverage is for the end of 2014.

Yes; Jeb, I don't know that we are ready to give you those numbers yet. Obviously, we just took these Panther assets in. If you could bear with us a little while, while we put some thoughts together on that, we will be coming out with some better feels for it and another 2, 3 months. But we really feel like we need to see how that is performing before we give you a solid 2014 estimate.

Okay, and then just looking at -- you made a comment about the competitor and their commentary on central Louisiana assets; two questions there. One, would you guys look at these assets? And, two, if those assets are sold for a good price, would you guys look at potentially divesting your position there as well?

Oh, that's an interesting spin on it. I guess, first of all, I would tell you that we do like their acreage. But at the same time, as you are well aware, we have got our boat pretty loaded right now, so we would have to take a look at it. Obviously, if it was a number that blew your doors off, then you would probably have to think about whether or not it made sense for you as well.

Okay, great, thanks John.

Ron Mills, Johnson Rice.

Jeb just asked one of my questions; maybe I will tag along on the Wilcox. One of the things that I think Swift experienced was higher cost and some production issues. Is this similar to what you experienced early on? And, as you moved up the learning curve, is that something that prompts you to like their acreage as well? Or is it geologically similar? I'm just trying to get a sense as to comparing what happened to you initially in the horizontal program versus where you are now, having drilled a number of wells.

Yes. I think -- you listened to it. We went through some pain in this exercise as well. And they are not easy wells to drill, but our guys are -- knock on wood; we feel like we have got this figured out and we know what we are trying -- how to drill them and we think we know how to complete them and hopefully pick the right places.

As far as the acreage goes, obviously geology is what really counts. And we would argue that that South Bearhead structure is a big structure and they have a significant amount of it. So, yes, it's good geology. That's what we go for first.

Okay, good. And then with Mississippian sounding like it's in the middle of the fairway in terms of well performance, good to have moved to the Panther properties. You are just getting really started up there; you are going to be ramping activity. Is all of the activity over the remainder of this year going to remain focused on the Cleveland? Or, at what point do you think you start testing some of the other formations? And then, when you do that, are you guys -- as you have started to kick the tires, what do your guys think about the opportunity set and/or opportunity for improvements in your shop versus the prior operator?

Well, I think, as we described when we bought this asset, I think the Panther guys would tell you they were cut back on capital available to them. We think it's a great asset base that has lots of drilling potential. We have already added a fourth rig, and that rig is indeed drilling a Marmaton well. So we would expect to keep three rigs working on Cleveland, which is clearly the core of the play. We were pleased to see some other operators coming out with some recent information about performance in some of that area, and we hope they are dead right because, obviously, that would be good news for us.

Alright, everything else has been asked, thank you.

Brad Carpenter, Wells Fargo.

Two quick questions, I guess, both focused on Louisiana. The first one -- John, you had mentioned you would be looking towards that Olympia Minerals well as a guide for how far south the structure will go in the area for North Cowards Gully. I think you've put the location cap for horizontals around 20, or just above 20. Just curious -- I know it's still early with only 30 days on production or so, but what are your initial thoughts on that? And are you able to say now that you are pretty optimistic that the structure continues to the south there?

Yes, we sure are. The Olympia Minerals has turned out to be a very good well, and I think the issue is, we are just trying not to get ahead of ourselves. So we would like to produce it a few months before we jump off and drill another one that looks just like it. But we are very pleased with what we've seen.

Steve tried to describe some of the issues. That kind of goes back to one of Ron's questions about some of our colleagues. We end up -- in drilling these wells, we are learning a few tricks, and we think one of them is to bring the pressure down slowly, especially as we move out of the over-pressured region. So Steve talked about managing chokes, and that has been a big effort on our part. The catch with that, of course, is it limits the IPs that you are going to see. But I can assure you, those three wells that we have talked about would have absolutely had three digits on their IP if we had opened them up. There's not any question.

Okay, great, thank you. And then second one -- John, you touched on it during the prepared remarks. But going over to the Fleetwood seismic shoot, have you chosen the first location? And I was hoping you could give us some more color on any potential second-half activity over in that area.

Well, we've got a new Exploration VP that joined us during the quarter and we've got him working on that pretty hard. Have you got any comments, Greg?

Sure, Brad, thanks for the question.

I didn't tell him he would be on here.

Good to meet everyone. We have developed a number of leads on that inventory. There's probably six or seven opportunities. I would say we are maturing two or three of them and it's possible that we could be testing something later this year, but it's more likely early Q1 2014.

Got you, okay, thank you very much.

Brad, one thing, just to go back to the Olympia Minerals, we drilled that well from south to north and we drilled a pilot and got a real good-looking log on the south end. So that's why we are pretty optimistic that we still don't know where the down diplomat is on the south. And as we looked at our 3-D, we also see the same thing on the east side, which we didn't know before.

Okay, that's helpful, I appreciate your time, thank you.

John Herrlin, Societe Generale.

With the Gulf Coast, you are going in a more controlled flow-back manner with the horizontals. What kind of an EOR increase do you think you might get out of these wells, or is it just a matter of not having mechanical issues?

And then, with respect to the Wood well, what was the postmortem on those mechanical issues? What happened; did you just to sand it up, or what?

Well, we are not completely sure, but we did get some formation cuttings coming into the well bore. We went in with coiled tubing and couldn't get down. So whether the casing jumped a collar or collapsed or whatever, we don't know exactly what the answer is. But the well came on so strong, we feel very good about the location geologically.

And we have been -- I have got to say, we have been running the ported systems with the packers and we kind of have moved away from that. And you will see us doing all plug-and-perf going forward. We feel like putting the cemented liner may make a difference; flowing it back slower may make a difference. And I wish I could tell you exactly what is solving the problem, but we are attacking it from all fronts.

Okay, that's fine. Tom, you mentioned that your bank credit line would be reviewed in the fourth quarter. Do you have any idea, kind of ballpark, what you think it is going to?

I don't have a number, John, but we have been looking at it intently, too, since this is the first redetermination post the transaction with the new assets and everything. It looks very strong. I am expecting a pretty robust redetermination, which should bolster the liquidity.

One thing that helps there is the hedging transaction that we put on. That will add to it, as well was the program has been adding the heart of what supports the borrowing base, the PDP.

So my expectation is that it will be a pretty strong redetermination, and it comes in right at the end of September. So we will be working on an intently; in fact, we have already started with the reservoir engineering at the lead bank and expect to have a number late September, early October.

Okay, great. Last one for me -- with West Gordon, was that mainly puds you removed?

Yes, it was, John.

Alright, thank you.

Pavan Hoskote, Goldman Sachs.

Good morning, guys; I'm on for Brian Singer. In your opening remarks, you indicated that you had recently received 3-D seismic data in your Miss Lime play. How do you see 3-D seismic helping you reduce the volatility and IP rate from the play, given that some other operators appear more skeptical on the efficacy of 3-D seismic? And I have a follow-up, please.

I can tell you that we are well aware of the skepticism associated with it, but Midstates and Chesapeake went together and shot this fairly extensive survey covering a significant part of Woods and Alfalfa counties. All I can tell you is we are seeing things that are certainly interesting, if we haven't figured out exactly how they apply. But I think what we feel about 3-D seismic is, number one, it's going to answer a few questions for us. But what we are hoping, it will help us avoid the problem wells as much as find the best areas. So Greg, do you have anything to add to that?

Yes. I think that's an accurate statement, John. What I think I would add is, you know, 3-D seismic is a critical tool in understanding the whole reservoir characterization. So we have log data, we have some core data, and now we have some 3-D seismic data that allows us to integrate all three of those pieces of data to optimize well locations and understand the play better.

Great, thanks John and Greg. Moving on to the Anadarko Basin, at the time of the Panther acquisition, you indicated that the Cleveland formation was a primary target. Based on any additional work you may have done since, do you have more or less confidence in the prospectivity of other zones in the area?

Yes, I think we are feeling better about it. Curtis Newstrom, who has done our business development from the start -- as we told you, we are not buying anything right now, so he has been working full-time on this transition. I might have him make a comment or two about that.

Yes. As far as the objectives, the Cleveland is the primary of the first three rigs. But we do -- we have done a lot of studying of the other locations and we are pretty excited about the Marmaton and then stepping -- we have had some active Cottage Grove work going on. We haven't drilled a lot of Tonkawa at this point, but there has been a lot of offset performance that is very encouraging.

So we are probably more excited about the other intervals beyond the Cleveland than originally. And just as an integration point, we are still working with the Panther folks, transitioning through it and trying to figure out what our long-term plan is. We have picked up another rig and will be looking at what our plans are in some of the other areas beyond the Cleveland for the next couple of months.

Yes, and we are obviously watching other industry activity and we are well aware there are some pretty flashy numbers coming out there. So we hope to be mirroring those.

Thanks a lot.

Stephen Shepherd, Simmons and Company.

So the three horizontal wells that you all reported out of Louisiana for the quarter had an average 30-day rate of about 750 BOE a day. What type of EUR would you anticipate a 750-BOE-a-day well would produce, based on your average model type curve in Louisiana?

Yes; I don't think we've actually given you a type curve on our horizontal wells, and that is because I guess we needed to see a little performance before we could come up with something that would tell you anything.

I can tell you, the one well that we've had on for a significant amount of time, that Musser Davis 8H number 1, which came on in September of last year, does appear to be headed up certainly into the high 4s. We don't know what these others are going to do, and hopefully we are going to have some additional information in the future.

Keep in mind what we talked about earlier; we are holding those last three wells back. We could have flowed them at higher rates than that. None of them have any gas lift going to them yet. We are about to put it on one of them, but these have been flowing back up the frac strings for the last several months.

That's helpful, thank you. And one more, if I can -- at this point, how many engineered horizontal locations do you think you all have in the Gulf Coast region?

Well, I wish I could pin that down, but let me just say, we think we have an excess of 20 at North Cowards Gully and still feel very good about that number. Obviously, we want to flow them for a while and make sure they are going to hang in there because these are expensive wells.

At South Bearhead Creek, the game there is going to be how many of those intervals can we go into. So we've got a test in the C sand at South Bearhead Creek and we are about to test the D in the lower. But at South Bearhead Creek, there's seven different pay horizons that we produce out of. So I guess, as we test these and find out how many of them we can go horizontally in, that will determine how many ultimate locations we can put in.

Great information; I appreciate it, thank you.

Ipsit Mohanty, Canaccord.

If you just looked past this quarter and you spelled out why probably the gas sill was a little higher in the Miss Lime well, do you still retain the overall yield mix in the Miss Lime as 40 oil/20 NGL/40 gas? Is that consistent?

Yes, we still feel pretty good about those numbers. We did have this problem Steve described; we were putting in that new plant and so we had to bypass the plant for a significant amount of time.

My second question is just on the well costs. Given the various initiatives that you are doing, would you still maintain that the 3.7 number for Miss Lime and probably the 2 million number for the Cleveland well assets -- is that consistent; 2.50, probably?

Well, I think the Cleveland wells are higher than that. We would have said high 2's. On the Cleveland, it obviously depends on how many frac jobs you put on it. But I think it has been pretty standard to put 15 or 16 stages of fracs on those wells. So that kind of puts you 1.5 million or so just on the frac job. On the other wells, our target is still to bring the cost down into the low 3's on a Mississippian well, as we go along.

And do you still plan to end the year with six rigs in your Anadarko Basin assets? Is that still the plan?

We are working that right now. And what I would say is we've just put the fourth rig to work and we are confident we will put a fifth rig to work and we will see how it goes. If we are getting the kind of performance we hope, then we will have to make that call. But I guess I would say we are going to make sure we are proceeding at the right pace.

Thanks, guys.

Kyle Rhodes, RBC.

Most of mine have been asked, but just a quick housekeeping one from me. I noticed your basic share count picked up a little bit this quarter. Can you guys speak to that?

It would be restricted share grants, probably, is what you are seeing -- vesting, the first initial testing of the IPO grants, is what you are seeing.

Got it, okay, thanks, guys.

David Heikkinen, Heikkinen Energy.

Can you just walk through the buildup of your $105 million of capital in the third quarter? How much of that -- you have 20, 25 new wells, but how much is going to be in facilities; how much is completing the backlog of wells that you built in the second quarter? And just some granularity around that $105 million in the Miss Lime.

We may have to call you back, but in the Miss Lime, obviously, most of this is around drilling. But we are also installing some gas-fired generators and continuing to upgrade some of the power lines. So there is some -- how much should we guess, total of $9 million for the year? You'd better help me with this real quick. Just a second, David.

Okay, $86 million on D&C; seismic and land, $10 million; and facilities $9 million -- that's third quarter.

Okay, that's helpful, thanks, guys.

(multiple speakers)

That's all I needed, thanks.

Sean Sneeden, Oppenheimer.

Tom or John, you guys have done a pretty good job of building your inventory throughout the last six to nine months and really building scale. With just over $200 million of liquidity, can you talk about your appetite for any further acquisitions?

We don't -- I think we have made it pretty clear, we feel like our boat is pretty loaded. So you can expect us to just keep our nose down and perform on the assets we've got. We know that many of you investors out there, that's what you are looking for to show we can make that work. So that's what you are going to see us focused on. After we've put some, as one of our investors called it, some boring quarters together, then we can have another conversation. But we know we need to perform on what we've got right now.

Sure, that makes sense. And then just looking at your CapEx guidance, for the rest of the year, and it would appear that the Q4 level is going to be down sequentially from Q3. Are you dropping a rig, or what is the driver behind that?

Yes, that would be dropping some rigs. We have told you from the start we are going to try to show some capital discipline here. And the good news is, we are drilling these wells a little faster than we expected. So we are going to be able to get the number of wells in that we need to maintain the production rates, but we are just going to do it faster. So that's what you are seeing happening there.

Got you. And then, somewhat relatedly, on the leverage side, you are just over four times now on a pro forma basis. I guess, first, are you comfortable with that? And where would you like to be?

Nothing has really changed, Sean, from what we had talked about as far as our expectations and our targets going on into next year. And our view is that we will be down closer, if not below that 3 level, by the time we get to the end of 2014, and that's what we are driving for. And the efforts that you see right now are not just to grow the production, but risk mitigating. In that regard, you've got a pretty substantial hedge program; you can see what we have added. That won't be the end of that. We will follow that quarterly as the production goes up, and then we are drilling in the heart of our acreage right now to beef up that cash flow and earnings.

Okay, and would you guys ever consider asset sales or anything else to expedite the deleveraging plans that you outline there?

Right now, we will execute on what we've got, but we are looking at all a different alternatives, and that would certainly be one, which would not have been available to us at the small portfolio we had a year ago. So what we have got under our belt right now gives us the opportunity to look at that and optimize it. So we will look at everything to balance that. We are clearly aware of where it is and have got pretty strong targets to bring it down. That will be the effort here as we go forward.

Sure, that makes sense, thank you very much.

There are no further questions.

Well, thank you. With no further questions, I appreciate you all joining us this morning. We are extremely busy and we hope we are showing you that we are kind of hitting the numbers, and we'll continue to work those costs down, and you'll see better performance as we go forward. Thank you for your time this morning.

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