Amplify Energy Corp (AMPY) 2012 Q1 法說會逐字稿

Good morning; my name is Regina and I will be your conference operator today. At this time I would like to welcome everyone to the Midstates Petroleum first-quarter earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer session. (Operator Instructions).

Today's call will be available for replay beginning at 1.00 pm Eastern Standard Time and will run through midnight Eastern Time on June 7, 2012. The number to dial for the replay is 800-585-8367 or 855-859-2056. The conference ID number for the replay is 799-48-731. Thank you. I would now like to turn the conference over to Mr. Al Petrie, Midstates' Investor Relations Coordinator. Sir, you may begin.

Thank you, Regina. And good morning, everyone, and welcome to Midstates Petroleum's first-quarter 2012 earnings conference call. Joining me today as speakers on our call are John Crum, President and CEO; Steve Pugh, our Executive Vice President and Chief Operating Officer; and Tom Mitchell, our Executive VP and CFO.

John will begin today's call with highlights of the first quarter and general comments on our drilling and lease acquisition program, Steve will then provide more detail on first-quarter operation results and a preview of drilling activity for the second quarter, Tom will follow with key financial highlights of the first quarter and provide guidance for the second quarter and the balance of the year and John will then wrap up with some closing comments and open up the call for questions.

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 within the meaning of the Private Securities Litigation Reform Act. 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 forward-looking 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 including our final prospectus filed on April 19, 2012 and the Form 10-Q for the quarter ending March 31, 2012, which we intend to file tomorrow, for a discussion of these risks and uncertainties. And forward-looking statements speak only as of the date hereof and we undertake no obligation to correct or update any forward-looking statement.

In addition, please note that we will reference certain non-GAAP measures during this conference call. Please see our earnings release for a reconciliation of these non-GAAP measures to their most directly comparable GAAP measure. I will now turn the call over to John for his comments.

Thank you, Al, and good morning, everyone, thank you for joining us today. I'd like to begin by welcoming our new shareholders who joined us through our recently completed IPO. We're very pleased with the confidence you've expressed in this management team with your investment.

We fully intend to live up to the commitments we made during our recent road show and look forward to growing Midstates and creating value for you as well as for our founder, management and employee shareholders who, as you know, remain very significant owners of Midstates' stock.

I also want to thank the lead managers and co-managers of our offering and their analyst teams. Once we received clearance from the SEC our IPO process went smoothly and we are pleased with how the stock has performed since initiation of trading.

We think we have an excellent group of sell side analysts who will help us communicate our story to you. We fully intend to be a proactive company through regular direct communication with our shareholders and analysts and by participation in industry conferences. We are excited about our growth plans at Midstates and look forward to sharing our progress in meeting our goals.

We reported our first-quarter earnings results yesterday afternoon; I'd like to focus on some of the highlights of the quarter and update you on our progress. Our IPO funding came almost two months later than we had anticipated; that delay caused us to hold off contracting for rigs and will push back our expected production round.

To help mitigate the production loss from those delays we have adjusted our plans to add more shallow targets primarily in our Pine Prairie field. With those adjustments and some reductions in drilling times being realized we think we can drill 76 wells by the end of the year while remaining within our forecasted capital spend of $380 million.

In the first quarter we spud 14 wells, nine of those were completed while two are waiting on completion. We have just deployed an additional two rigs for a total of five presently drilling. Since March 31 we spud an additional 12 wells, so you can see we are ramping up the activity level. Steve will go into more detail on this in a minute.

As you saw in the earnings release, we have some encouraging results to report from our latest two horizontal wells which were just completed. As we indicated during the road show, we planned 12 horizontal tests in a variety of different pay zones across our acreage portfolio. The first two of these included a Miocene test at South Bearhead Creek and a Wilcox lateral at South Fulton expansion area.

Steve will share some details in a moment, but I'm pleased to see a combined rate of over 1,000 barrels a day flowing from these two wells today. We will continue to monitor the results of these new completions, but we remain very enthused about the potential for horizontal completions in our play. We expect to spud three more horizontal wells for Wilcox targets at North Cowards Gully, South Bearhead Creek and West Gordon fields over the next two months.

Some of you will recall that all of the 974 potential drilling locations we discussed during the road show were vertical wells. As we move forward with testing our horizontal well potential we fully expect horizontals to make up a very significant portion of our inventory for future drilling programs as we develop the play.

As an overview of acreage acquisition effort, we have continued to add acreage since the March 31 figures you see there and now have a total of around 150,000 net acres, which includes plus or minus 100,000 acres under lease and the remaining 50,000 acres under option. The added acreage that has been acquired is primarily associated with the [Fleetwood] 3D survey which I will comment on shortly.

While our acreage focus remains primarily on the Wilcox, we have started to build a modest position to target attractive Austin Chalk and TMS prospects. Our 197 square mile Fleetwood 3D survey is now underway; we expect to complete shooting by fall and start receiving process data late this year. That survey will help us high-grade our acreage purchases in the area and ultimately select attractive drilling locations for the 2013 and 2014 exploration programs.

We have also started a 70-square-mile 3D survey to fill in the missing data at South Bearhead Creek in the North Cowards Gully area. Now Let me turn this over to Steve and he'll provide you even more details on what's happened in the quarter and what we have planned going forward.

Thank you, John, and good morning. As John said, we spud 14 oil wells in the first quarter; all of those were in our development areas. In the development areas eight were in Pine Prairie and six were in the Dequincy area. Since March 31 we have spud an additional 12 wells -- five in Pine Prairie, five in Dequincy and two in our expansion areas.

For the balance of the second quarter we expect to spud eight more wells -- five in Pine Prairie, one in the Dequincy area and two in the expansion areas. In Pine Prairie we are continuing to drill our Wilcox wells on 10-acre spacing and have moved further into our outboard or off structure program. Results have been good and we expect to drill 26 total wells in that program this year.

Since first-quarter end we have spud an additional five wells in Pine Prairie and are well into the program. We have made a significant change in our surface set up by going to pad drilling where possible. In the past we might have two wells on a pad; going forward, particularly in our outboard program, we expect to have eight to 10 wells per pad. We expect that to save on the order of 10% per well on cost due to quicker rig moves and less location and facilities costs.

Additionally, we have made some changes to our frac procedures, specifically proppant type and fluid type. We have gone from intermediate strength proppant to resin coated sand. Not only will this save approximately $100,000 per well, but we think it will result in an overall better frac job.

We've also changed the frac fluid from 7% KCl to four percentage 4% KCl which saves additional dollars. Overall we have reduced the cost of our frac stages in Pine Prairie from $240,000 per stage to $130,000 per stage. As I said earlier, the results so far have been good; the average of our wells completed this year are exceeding our modeled IP rates or initial production rates.

In addition to our Wilcox program in Pine Prairie we are continuing our shallow drilling program. Last year we drilled two Miocene and Frio wells, wells that range in depth from 2,000 feet to 6,000 feet. The third 2012 shallow well was spud last week and we anticipate drilling 16 total shallow oil wells this year.

Moving to the Dequincy area, we spud six vertical wells in the first quarter and five wells since quarter end. These wells are upper, middle and lower Wilcox wells and we expect to drill 21 total wells this year.

We have changed our flow back technique and think this is showing some good results. As many operators do in shale well flow backs, we have begun to limit the near well bore draw down we put on our wells.

In layman's terms, we are choking back the wells to make sure the frac sand stays in the formation and does not flow into the well bore. This technique has proven to improve recovery in shale wells and we believe it will do the same in our Wilcox oil wells.

In addition to restricting the rate of flow back on our wells we've revised our frac sand in the Dequincy area also. We now pump 80% of the job with intermediate strength proppant and tail in the final 20% with resin coated intermediate strength proppant. We believe the resin coated prop will help keep the sand and the formation as well.

Lastly, we have spud two wells in our expansion areas and we anticipate drilling a total of 13 expansionary wells this year. As John mentioned, we have also drilled one horizontal well and one horizontal side track out of an existing vertical well. The horizontal to new drill is in the Dequincy area and was landed in the Miocene sand at a TDD of approximately 5,000 feet.

The well has a lateral of just over 1,000 feet and has been on production for about three weeks. The three-week average rate on this well is over 550 barrels of oil per day and it continues to perform very well. Today's rate was 609 barrels of oil per day. Due to the high quality of the Miocene sand in this area the well did not require a frac but was gravel packed.

The horizontal side track is in the South Fulton expansion area. The side track was completed about a week ago and still cleaning up, but results are encouraging. Today's rate was 483 barrels of oil per day and the well is flowing up 4.5 inch frac string at approximately 3,000 PSI. We still have about 50% of the frac fluid to be recovered.

Going forward we plan to spud our next horizontal in about two weeks in the Dequincy area with two additional horizontal wells being spud within 45 days. As John said, we will continually evaluate our inventory to optimize recovery using both vertical and horizontal wells.

We are very encouraged with the results of both of these wells for a couple of reasons -- the production rates are strong, but, just as important, the wells drilled very well and confirmed our thoughts that the Wilcox will stay open as we drill longer and longer laterals.

That is an important point because horizontal plays start with relatively short laterals to prove the concept, then progress to longer laterals with more frac stages. The South Fulton well is producing in a lateral of only 1,300 feet and has five frac stages. For the year we plan to drill 12 horizontal projects and remain optimistic about the results.

Our plans for 2012 were impacted by the delay in our IPO, but we are now executing our revised drilling program. We started the year with three rigs and are currently at five rigs. We anticipate picking up a sixth rig in July and we also expect two run two small rigs in our Pine Prairie shallow program for a period of about three months before releasing them.

The rigs we are picking up are 1,000 horsepower and 1,200 horsepower rigs, smaller than the 1,500 horsepower rigs we started the year with. Not only is the day rate reduced, but the rigs are capable of moving faster which makes a difference in our cycle time.

Cycle time is an area we have put at a lot of focus on this year. In 2011 we averaged 93 days from rig release to full on stream date. Clearly we had some testing to do and that impacted our cycle time. But we have cut cycle times from 93 days down to 26 days this year in our development areas and we will continue to put emphasis on getting our wells online as soon as possible after the rig moves off location.

Now let me discuss lease operating expenses. Lease operating and workover expenses totaled $6.5 million for the first quarter of 2012 or $8.59 per Boe. Saltwater disposal costs totaled about $1.2 million or 18% of total Loe in the first quarter. We expect SWD costs to decline through the remainder of the year as we plan to drill two new SWD wells and convert a third well to a disposal well all in the second quarter.

We also expect our high water producing central fault block wells to water out and go off production by the end of the year. This will reduce our need for trucking saltwater, which is currently being done for approximately 50% of the water produced in our fields. After the new wells are drilled the need to truck water will be very minimal which will result in less cost.

Workovers, which rose during the first quarter, totaled about $900,000. We expect workover costs to be somewhat choppy as we plan to do work on wells on an as needed basis. Additionally, we expect to see a slight increase in operating expenses due to the implementation of a chemical program starting in the second quarter of 2012. We expect our unit LOE to go down as we add more wells in production while our absolute cost will rise at a slower pace.

Overall we had a good first five months of the year from an execution standpoint. We are securing the rigs and frac dates we need to execute our program and have made some key personnel hires to our team. At this time I'll turn the call over to Tom for the financial update.

Thank you, Steve, and good morning, everyone. I assume you've all read yesterday afternoon's earnings release, so I don't intend to repeat everything that was covered in the release. I'll go into detail year-over-year quarterly comparisons. I will focus on the key financial items in the release and provide you with guidance for the second quarter and for the full year 2012.

We preannounced first-quarter production of approximately 8,300 Boe per day in the recent development section of the prospectus so there was no surprise in our actual production of 8,275 Boe per day.

You may have noticed that in the first quarter we reported the mix of production as 54% oil, 17% NGLs and 29% natural gas; there was a temporary shift in the production mix to slightly more gas and NGLs and less crude oil than usual due to the central fault block wells we discussed in the prospectus and on the road. Those were more gas weighted producers.

As those wells have declined in production we have returned to our normal mix and expect it to back to about 60% to 65% oil, 10% to 15% NGLs and the balance in natural gas the second quarter and throughout 2012.

For future production volumes, as Steve mentioned, we had to slow the ramp up of our accelerated drilling program for about six to seven weeks when our IPO was delayed from early March until late April. We have recently ramped up drilling, but the production impact from that expanded program will take a little longer to get realized than would have been the case with an earlier IPO funding.

As a result we are guiding to a range of 40% to 50% growth this year to take into account the delayed drilling program, as well as other unforeseen factors that could arise during the year. Therefore, in the second quarter we expect production to range from 8,500 per day to 8,700 per day and 10,500 Boe per day to 11,200 Boe per day for the full calendar year 2012.

Keep in mind that because of our initial small base of producing wells we may have some lumpiness in our growth as opposed to a smooth upward trend month to month. Our production growth is weighted to the second half of the year as more wells get drilled, completed and placed on production.

Over the last week our production is averaging about 9,300 Boe per day, so we believe our targets for the second quarter and the full year are realistic. Midstates' average realized price per barrel of oil before realized commodity derivatives was $111.21 in the first quarter of 2012, benefiting from the premium to WTI of [DLLS] pricing. While we expect the premium to decline going forward, we still expect there to be a healthy premium for our crude production which is priced at LLS.

Our natural gas price realization of $2.61 per MCF compares favorably with the Henry Hub average during the first quarter due to the location and quality of our gas. We are also processing the majority of our gas production and the price realized for our NGLs average $49.23 per barrel.

The earnings release included detailed quarterly information on the hedges we now have been placed on our crude oil production. I'm not going to go over them in detail in my comments, but will answer any questions you may have on them during the Q&A session.

We intend to post our hedges on the website and update them periodically if we add new ones. We currently have about 5,500 barrels per day hedged in 2012 at an average price of around $95 a barrel, 4,700 barrels per day hedged at an average price of about $104 per barrel in 2013.

As we look at it today, our hedging target is around 50% of our anticipated annual production for the next couple of years. The company does not have hedges in place on its natural gas liquids or natural gas production.

Adjusted EBITDA for the quarter totaled $30.5 million and we reported a pre-tax net loss of $17.5 million. Our 2012 first-quarter results reflect an $18 million unrealized mark-to-market loss on commodity derivatives. Excluding that item the first-quarter 2012 adjusted net income before tax was around $1 million. Keep in mind that Midstates was not a taxpaying entity during the first quarter, therefore no tax benefit or expense was recorded. I'll talk about taxes going forward here in a minute.

We presented the reconciliations of net income to adjusted EBITDA and adjusted net income, both non-GAAP measures, in the supplemental information in the earnings release.

Let me now go through the expenses. Lease operating and workover expenses totaled $6.5 million for the first quarter of 2012 or $8.59 per barrel. Workovers which rose during the first quarter totaled $900,000. Steve reviewed the details of what occurred during the first quarter, so I won't go back through that. But going forward we expect our LOE rate per Boe to go down as we had more wells in production while our absolute costs rise at a slower pace.

For the second quarter we expect total LOE to be in the range of $6.5 million to $7 million which equates to a range of around $6.50 to $9 per Boe using our production guidance average. For the full year we would assume a rate of around $7 per barrel to $8 per barrel and we'll update that number quarterly if we anticipate more workover activity or other increased maintenance expenses.

Severance and ad valorem taxes totaled $5.5 million for the 2012 first quarter, that equals about 10% of oil, natural gas and NGL sales revenue and I would assume a rate of around 8% to 9% for the second quarter as well as the full year.

The Company's first-quarter general and administrative expenses were $6 million, all of which was in cash or about $8.05 a Boe. As you're aware, we have been adding to our staff and had 63 full-time employees at the quarter end compared to 43 employees as of March 31, 2011. We'll continue to add staff and get to around 100 employees by the end of 2012.

We expect our second-quarter G&A to be in the range of $7 million to $8 million of which $700,000 is expected to be non-cash. Our absolute G&A will rise during the balance of the year, so I would use $9 million to $11 million per quarter after the second quarter, of which about 12% to 15% will be non-cash comp expense.

Depreciation and depletion and amortization expense totaled $28 million for the first quarter of 2012 or $37.22 per Boe. For the second quarter and full year 2012 I would use $36 to $37 per Boe for DD&A.

Total interest during the quarter was $1.7 million net of the amount capitalized to unproved properties of $700,000. During the first quarter the outstanding balance on our revolving credit facility was $235 million plus we received $40 million in proceeds from interest-bearing preferred units issued to First Reserve.

I mentioned that we were not a taxpaying entity as of quarter end. On the IPO we reorganized the public company to a taxable corporation rather than a pass-through LLC, and we then had to report a provision for deferred income taxes to catch up to that point.

In the second quarter we will report a one-time non-cash charge to earnings of between $150 million to $160 million to set up that deferred tax liability.

For 2012 you should assume a tax rate of around 45% to 50% due to our adopting a taxable corporate form post IPO in the April time frame, so you have a mix in the year of taxes going forward from April and the balance of the year pre-April being included in this step up that I'm talking to you about.

In 2013 we will be at the statutory rate which is around 40%; that does include the Louisiana state income tax. We do not expect to pay cash taxes in the foreseeable future due to the drilling activity that we have planned. We will post the guidance that I just provided in the Investor section of our website later today so you'll have that detail.

Turning now to the balance sheet. In the second quarter before IPO we received an additional $25 million in proceeds from First Reserve in the form of preferred units. On April 25 we received net proceeds from our IPO of $216 million after expenses.

We used $67 million to redeem all of the preferred units plus accrued interest and reduce the borrowing against our $210 million credit facility by around $100 million. The balance of the proceeds were used as cash for working capital purposes. We currently have around $12 million in cash and unused capacity on our credit facility of $78 million.

Regarding liquidity, as you all know, our IPO priced below the range we were hoping for and consequently that leaves us with less equity funding than we had originally planned. Having said that, we have our credit facility in place with available funding, as I just mentioned.

With that current availability, coupled with borrowing base redeterminations this year, we believe that we will have adequate funding under the debt facility to execute our program well into 2013. We expect the regularly scheduled borrowing base redeterminations in 2013 to sufficiently cover our spending program.

Regarding capital spending, during the three months ended March 31, 2012 we invested $98 million in our 2012 capital program, that consisted of $72 million drilling and completion, $18 million for acquisition of acreage and seismic, $8 million from facilities that included gas transmission, compression and NGL equipment. That represents about 26% of the total CapEx for 2012 at $380 million.

As Steve and John mentioned, we have re-configured the drilling program and will now be drilling 76 wells rather than 67 but with the same total capital budget of $380 million. That revised drilling plan will enable us to make some of the production volumes up in 2012 due to the drilling slowdown we experienced because of the delayed IPO. We plan to invest $90 million to $100 million in CapEx in the second quarter. Thanks for your attention this morning and let me now turn it back over to John.

Thank you, Steve and Tom. Our first quarter has provided some challenges especially around the public offering process. Our team is excited to have those distractions of the IPO behind us so we can focus completely on executing our expanded drilling program and proving up the potential of our Central Louisiana play.

We've had good success in attracting the experienced talent that we need to undertake our expanded drilling program. As Tom mentioned we expect to have nearly 100 employees by the year end, more than double our workforce at year-end 2011. We believe the buzz around the recent IPO as well as the opportunity to be on the ground floor of building something special is providing the attraction necessary to build a first-class execution team. I think any of you that have visited our offices notice the enthusiasm exhibited by the entire team.

We appreciate your continued interest in our Company as well as your patience while we execute our program, grow our production and expand our portfolio. Growing a small company quickly is no easy task. At the present time, because of our size, everything we do has significant impact and things will not always go as planned.

However, because of the significant ownership position that all of our employees have in this Company, you can rest easy knowing that we will feel the impact of any missteps as well as share in the successes right alongside you. We are all committed to meeting the goals we have outlined for you today.

Before we open up the lines for questions I want to mention that we will be participating in the RBC Global Energy and Power Conference next week in New York as well as Al's Louisiana Energy Conference in New Orleans June 27 and 28. We hope to see a number of you there. With that I will turn it back to Al for questions.

Thanks, John. As we go forward, as a courtesy to others who may be in the queue, please limit your questions to one and a follow-up question. Regina will now open up the line for questions.

(Operator Instructions). Brian Singer, Goldman Sachs.

On the two horizontal wells, can you talk to the well costs associated with those two wells? And then what you think costs and production rates would be under your optimal frac design going forward?

Steve, you want to make a comment and then I might add in something?

Yes, the Miocene well, the horizontal well costs under $4 million, about $3.8 million. And then the sidetrack cost about -- a little over $5 million. Going forward we expect those to be in the range of $7.8 million to $8.5 million for a long lateral with 10 to 12 frac stages.

Brian, as I think we indicated as we've talked about this, we've got a whole range of horizontal opportunities here, so obviously we're going to try to -- we'll be doing every kind of option you can name including, as we get better at this, we would intend to do some longer and longer laterals with more and more frac stages and those costs will then probably drift up around the $10 million range.

Got it, thanks. And then secondly, you mentioned some of the acreage acquisitions you've made in the Chalk and the Tuscaloosa Marine Shale. Can you just talk to how big a player acreage wise you want to be and is acreage acquisition part of your capital budget or should we expect any kind of upside as we go through the year if opportunities avail?

Well, we still got our exploration work in these prospects. They're pretty excited about the potential they see. But just to kind of give you a sense for what we're talking about, we've -- about just under 30,000 acres of that 150,000 are associated with those new plays. It would be pretty hard for us to get one drilled before very late this year, potentially early next year to drill our first one.

Got it, thank you.

John Herrlin, Societe Generale.

In terms of the well designs that you've had and the changes in proppant, etc., what kind of a cost savings are you having versus what you were spending versus now for a vertical well? Because you only really addressed horizontal costs.

No, what I was talking about were the vertical wells, John --

Okay, that is vertical.

Yes, those are vertical. But really we don't expect to see material differences in cost in the horizontal frac jobs. They'll look very similar. Of course we'll have more of them per well, but the stages will look pretty similar.

Okay, that's fine.

John, we're getting some of that from -- I think we've indicated to you what Steve is pushing us to is doing back to back or stack and frac type frac jobs rather than our old way of doing it, which was produce a zone then go and frac the next one, which obviously takes longer and costs more.

Okay. One of the wells was a horizontal sidetrack. How much potential do you have in terms of the wells you have inventory to do more of that?

Yes, I'm glad you asked that. We have a tremendous opportunity to do that. So we've obviously got 110 well bores or so right now and as wells deplete that's sure a possibility if we can continue to prove that this works.

Steve talked about the Wilcox well, we're flowing at just under 500 barrels a day. But it's got 3,000 pounds of pressure and Steve is doing his best to make me hold my water because I want to open it up. But he's shown very clearly that we were producing back some of our frac sand when we opened these things up a little hard. So he's kind of getting us trained.

Okay, great. Thank you.

Neal Dingmann, SunTrust.

Two questions, quick. First, just on the LOE, it looked like it was up, but you mentioned about the saltwater and some things and just wondering (technical difficulty) [either a comment] from I guess either John or Steve, any of you all, as far as number of workovers you see sort of I guess for the remainder of the year. And then you did mention the saltwater, any other things to bring that cost down or basically how should we just think about that cost going forward?

Yes, if I could just make a quick comment on it. I hate to keep bringing up the central fault blocks, it sounds like blaming it on George Bush all the time. But when we drill those wells obviously we're making a significant amount of water out there. So we have plenty of saltwater capacity to handle most of our operations before we drill those wells.

But just to give you a sense for it, we produce 4,500 barrels of water a day out of our central fault block well. So that's obviously overloaded the systems we got. And so in fact Steve has got a couple of saltwater disposal wells he's working on right now. You can finish that, Steve.

Yes, as I said, we're drilling two saltwater disposal new drills in the Dequincy area and those will occur just in the next 30 days. And then we're re-working an existing well and converting it to a saltwater disposal well in the Pine Prairie area and that work is ongoing now. So we're working real hard to fix that problem.

Yes, we can cut saltwater disposal costs dramatically as we start pumping it down the hole instead of having to truck it around.

Okay, that's great color. Then just one follow-up. Just wondering -- on the horizontals you mentioned about nine more I guess for the year. John or Steve, any just idea as far as will you keep them all in kind of that same area around those first two or where will you -- location wise where are you thinking about?

Yes, so we've actually got 10 additional wells planned this year; the next three are over -- are all under Dequincy area. I mentioned in my statement that we would be doing one at South Bearhead, one at North Cowards Gully and one at West Gordon in the next three. We also have additional ones planned even at Pine Prairie and some of the expansion areas. But the next three are going to tell us a lot.

Perfect. Thank you all.

Evan Calio, Morgan Stanley.

Welcome or welcome back, John, to the quarterly conference call circuit. There's a lot of information here, guys; I appreciate it, I may just cycle back with -- on some questions. But a couple -- on the new acreage that you added, the 42.5, which is above the option amount, can you -- it looks like there was some bolt-on to core acreage. I mean could you give us a break down or an update of your acreage position across plays and maybe any color or tell us where the 100 new locations reside?

I may -- we've got -- Steve do you want to take that? He's got a spreadsheet in front of him here. There's a lot of detail here though, so we're going to try to get you what you need.

Sounds good.

As we indicated, a significant amount of that additional acreage was coming in our 3D option area. But you're exactly right, we've continued to add acreage around each one of our expansion areas as well as our core acreage where we -- Pine Prairie being a good example as we continue to prove up things there then we tend to add a little extra acreage around the edges because we think we can expand. The new locations are all associated with the Fleetwood expansion area.

Okay. So no new locations as of yet for -- within your core areas?

No, not really

Okay. I've got another question on the shallow wells, which are newer to the plan. Maybe just some color here on the decision to pick up the two lower horsepower rigs and can provide some color here on what I think you said were 16 shallower wells targeting the Miocene and the Frio; any kind of detail on those wells would be appreciated or your expectation.

Yes, the plan, Evan, is to drill those 16 shallow wells. We drilled two last year and had very good success, so we're ramping that up. As I said, they're ranging 2,000 feet to 6,000 feet and they'll cost under $1 million total all-in cost. So we've decided to pick up two rigs and drill those the middle of this year.

And then maybe if I could squeeze in one last one if I could. The [LSS] crude advantage of being pretty clear in the quarter versus peers, you get realizations excluding hedge as to the percentage of [LSS] was a little bit lower year on year, about 5%. I mean, could you just walk me through kind of what your cost is into market and how we should think about that for realization ex-hedge? Thank you. I'll leave it there.

Yes, we are getting, for the most part, the full difference between essentially Brent and the WTI mark for our crude oil price stock LLS. We do have an average trucking cost in that area, I had mentioned $1.50 on the road in the past, some of that crept up in this quarter to around $2. They've got some transportation costs in that.

Also the way that some of the crude is priced mechanically lags a little bit as far as the differential. So I think the primary difference for that is because of that lag. So in fact, as the prices pull back a little bit here we'll get the benefit of a lagging increased inferential as it comes down.

Right. But similar, like an LLS minus 2 is a good number to run with, is that --?

I think so.

Understood. Appreciate it. Thanks, guys.

Leo Mariani, RBC.

A couple quick questions. Can you speak to some of the recent well results in your expansion areas? You cited having a couple wells down in the first quarter. Have you got results on those? And I think you also had a couple spud sort of quarter to date here in 2Q.

Go ahead, Steve.

Yes, the only one that we have results on is the horizontal well and we talked about it, that's in the South Fulton area. The other one that is drilling it now is in the [Mamu] area and, like I said, the rig is on it right now.

And will move to [Doralt] --

Right after that.

Right after that.

Okay, is the Mamu well also a horizontal?

No, it's a vertical and the one to follow it is also vertical.

Okay. And in terms of the -- sort of the second horizontal you talked about today, you just brought it on I guess about a week ago, what was the lateral length on that well? I think it was previously about 480 barrels a day you said and still cleaning up?

Right. We're producing that one from about 1,300 feet of lateral and we're doing that math by what's in zone or close to zone. The lateral was a little bit longer than that, 1,500 feet.

And how many stages was that?

And it was Packers Plus type of completion.

Okay. In terms of the acreage you spoke about, what are you guys seeing in terms of what you've added here recently for acreage costs? Are they still reasonable?

Yes, they're still reasonable, in the end we're getting acreage kind of as low as kind of 300 and going as high as 500.

Okay, that's great. Thanks, guys.

Jessica Chipman, Tudor Pickering Holt.

A couple pretty granular questions on the horizontal side. I wanted to see if you could give us what the drawdown on the completion was for the first two wells. And then particularly on the first well, I think I heard you say a 1,000 foot lateral with no frac stages. I wondered if you could give a peak oil rate and then what the choke was on that well.

Sure. Let me talk about the Miocene well first. That well is [TVD'd] at about 5,000 feet, we've got just over 1,000 foot of lateral and that sand does not require a frac, it's a real high-quality sand. So we ran a pre-packed gravel -- gravel packer -- pre-packed screen in that well and just like John said, we've restricted the flow back on these wells to under about 25%.

That one we've started bumping the choke a little bit because it's looking nice. And the peak oil is about 610 barrels and that's just in the last -- it's yesterday's rate. So like I said, we're bumping the choke on that one and bringing it on a little more.

Jessica, as I indicated earlier, Steve has been slapping me pretty hard and making us kind of hold those back and bring them on slowly. So it's actually -- it's one of those unusual situations where the rate is higher now than it has been for the first three weeks.

And that one, Jessica, we got tubing in early, so it's flowing up tubing. The south Fulton well is in a lateral of about 1,300 feet and we had it on a [1264ths] until two days ago and we bumped it to a 13 and then a 14 yesterday morning. The peak rate was just under 500 barrels and I'm restricting the drawdown on that one to about -- between 20% and 25%. That one is [flowing] up 4.5 inch frac string and right now we're looking at timing to get the tubing in that well.

Because I think you'll know we're not getting -- we're not getting this fully unloaded at that kind of rate. So we're going to have to get some smaller tubing in there to be able to open it up a little better.

That's good detail. I guess my follow-up then, just trying to think bigger picture in terms of horizontal development and talking about longer laterals and more frac stages. How do we think about or what can we expect for your horizontal targets going forward? Will it be a mix of your high-quality sand Miocene targets and then maybe some horizontals that need fracs and longer laterals particularly in the Wilcox?

Well look, for the most part we're going to be working the Wilcox because, as we've indicated to you when we talk about these things, we've got 3,000 to 4,000 feet of sediment with literally dozens of potential sands in there. We wanted -- the reason we did the south Fulton horizontal was for a couple of reasons.

First of all, we wanted to see if that could improve the economics of what's a fairly skinny sand. We've got somewhere in the range of less than 20 feet on that interval. So that's one example, but it also gave us a chance to try it in one of our new areas.

The next three we will drill will be in more core areas; I told you South Bearhead, North Cowards Gully and West Gordon. In each of those we will be going for thicker intervals which we know have been prospective in the area in the past. So I have some real high hopes for what that's going to show for it.

And per John's question earlier, I think that's going to yield us some opportunities to go back into older well bores or even potentially some of our newer well bores and put laterals in and really improve the performance.

Okay, then just to be clear, the next three wells you're drilling horizontally will be targeting the Wilcox, is that correct?

Absolutely. The next three are all Wilcox. And for the most part, so -- we've got 10 more to go and I don't have all those numbers in front of me, but I think all but maybe one of those is going to be Wilcox type targets.

Perfect, thank you.

David Tameron, Wells Fargo.

A couple questions. Can you just talk about -- and I guess, Steve, you mentioned you went from 93 to 26 days in your development areas. How much -- and I realize you guys are just -- you've just had a year or so together as a team and you're trying to get some efficiencies down. How much more do you think you can drive that down and what's your target rate? Do we see that go down another five to 10 days and therefore well costs come in a little more -- or how should we think about that?

I think that's reasonable, David. Just this quarter we've dropped it two more days, so we're down to 24 days. The south Fulton well, the horizontal well was fracked and flowing back seven days after the rig moved off. So that's the target we're shooting for is immediate.

Now my only caution is in the core areas we can expect that. In the expansion areas, obviously the infrastructure might prohibit us and it's always a question of do we get the gas lines in before we see the log or do we wait? And we evaluate that on every single well in the expansion areas. So I think you can expect to see a little bit longer time in those areas.

Okay, so if I think about just like Pine Prairie -- I mean, I think the numbers you guys provided during the road show were just under $3 million a well. Is that -- am I thinking about that right? And if so, do you -- can you haircut another $300,000 or $400,000 off there?

I think it depends on the mix of the wells. And the only other caution I would give you is when we do the pad drilling our plan is to drill one well, skid the rig, which should be about a six hour to eight hours move, drill the second well and then move to another pad. And so we'll complete two wells back to back.

So it will delay the completion of the first well and speed up the completion of the second well. In total I think it will probably be kind of a wash. But I'm not ready to change the cost numbers on our type curve just yet. I want to see how these pad wells work out for us.

David, you didn't do any better job of getting him to commit to that reduction than I have.

I had to try. And then, John, on acquisitions. I guess one, how should we think about -- and maybe you mentioned this and I just missed it -- but how should we think about how aggressive you're going to be going forward? Would you expect another bolt-on -- would you expect to do any -- or would you expect acreage or would you expect any corporate type transactions? And then, is that already and that 300 -- is that already in your budget for this year as far as CapEx or would any additional acreage be additive?

There is some money in our budget for some additional acreage, but we certainly don't budget for any acquisitions. We have around $30 million total in the budget for land for the year and we -- let's say they just handed me -- yes, so we've got about $12 million left in our present land budget. Obviously if we do an acquisition then we'll be needing to look at things a lot differently.

Any color -- I mean, any color on the corporate side or anything you're looking at as far as outside of acreage?

Well, I couldn't talk about that if we were, but I can tell you we don't have anything in mind that you'll have to listen to any time soon.

All right. Thanks, thanks for all the detail too, I appreciate it.

[Adam Lawless], Simmons & Company.

Can you guys talk about how service costs are trending in the play just generally on a broadened macro view?

Yes, I think overall they're relatively flat just from a service cost standpoint. Now what we're doing in the area of cost cutting, we're -- like I mentioned, we're pulling and smaller rigs so we're getting a lower day rate. We're more efficient with our frac job, so our frac stages are costing us less dollars. But I think just on day rates and true service costs there, we're not seeing any material differences.

Okay, that's great, thanks. And kind of a follow-up question on your bank redetermination. You guys are talking about it's going to be redetermined in '13. When in '13 is that going to be and do you guys expect an increase in your borrowing base?

Yes, the redeterminations, there will be a fall redetermination this year and then we could do it as frequently as quarterly next year. It's set up to do semiannual, but we could do it quarterly if we choose to do that. And we do expect that it will be redetermined up as we get into the latter part of this year.

Great, thanks. That's all I had.

Ron Mills, Johnson Rice.

A lot has obviously been asked. A couple questions. Are you as -- any commentary or any color on other operators in the area? I know El Paso, we talked about it prior to the sale, and how Cohen has talked about the play and they're set to be drilling. Have you started to encounter them as you've gone through your leasing process or just trying to get a sense for potential increased competition as the information flow increases.

Well, our VP of land tells me that his brokers are running into other companies and he hasn't really focused on who they were or where they were at least so far. And I really don't know the exact acreage that [Halcomb] is working, but it appears to be west of -- north and west of some of the area we've been working. So we haven't really run into them on an individual basis.

El Paso, of course, is drilling and very close of the same area we're in. So there are some other -- you know, there are some other independents around that are drilling as well. So we are seeing some smaller guys leasing alongside us.

Okay. And as it relates with the production mix, as you talked about, the shift in capital program and the impact on the delays from the IPO on production. How quickly, Tom or Steve, do you think you can get back to that more normal oil/NGL gas split? Is that something that can occur as early as the second quarter or is that more of a second-half event as those central fault block wells continue to decline?

Ron, you're going to see it in the second quarter. So it -- the first quarter was an anomaly and it was because of the production that we talked about over and over again on those fault block wells. So we're back to what we had talked about on the road show, actually a little bit ahead of that in the way of oil production.

And longer term one of the things that we kind of think we're going to see pulling a few more shallow wells into the program; they typically are going to be a little less gassy. So overall we're certainly going to be in the 60s on the oil percentage.

Great, and then one follow-up on I think something that Jessica had asked. You had outlined your horizontal targets, the Miocene and Frio is -- granted this is more of a cartoon -- weren't necessarily identified as potential horizontal targets. What are you seeing in some of the shallower zones driving that decision to go horizontal in some of the shallower zones?

Well, honestly we really worked going into this year planning horizontals in those shallow intervals at all. As I indicated, we're focused really on the Wilcox just because of the sheer oil in place that's associated with that.

It just so happens we had drilled a vertical Wilcox well at South Bearhead and saw this little sand, it's about 15 feet thick. And so, it just looked like a good candidate to do a horizontal. It also let our drillers get their feet wet on a well that we thought we could drill pretty easily. And we were quite interested in the potential for that in some of those shallower sands that might have active water drives associated with them.

In those Miocene sands we can end up drawing in water, we can end up making sand because they're unconsolidated sediments. So the idea that we could try these pre-pack screens and get the pressure drop per foot down we thought would have some benefits and at least so far it looks pretty good. Where that's going to take us for the rest of the year I don't know. But it obviously is giving us some confidence that we can apply this in other areas.

And I assume you used rotary steerables in your plan going forward in the horizontals and, just to make sure, you mentioned water drives in some of the shallower zones. But your drilling inventory that you had talked about at an earlier -- or your overall inventory, that was all pressure depletion inventory, correct?

Yes. And thank you for clarifying that because I don't want anybody to leave with the impression we're going to be trying that as a general rule. We're going to be targeting pressure depletion type reservoirs and we are running rotary steerables and near bit visualization tools. So we got slapped pretty hard missing target last year and we're running state-of-the-art equipment on this stuff and feel pretty good about our ability to stay in the zone.

Great. All right, guys, thank you very much.

Thank you very much.

I will now turn the conference over to John Crum for closing remarks.

Well, I gave you the closing remarks already. But I really appreciate you guys sticking with us and we hope to give you some more good results shortly. Thank you.

Today's call will be available for replay beginning at 1.00 pm Eastern Standard Time and will run through midnight Eastern Time on June 7, 2012. The number to dial for the replay is 800-585-8367 or 855-859-2056. The conference ID number for the replay is 799-48-731. This concludes today's conference. Thank you all for your participation. You may now disconnect.