Amplify Energy Corp (AMPY) 2012 Q3 法說會逐字稿

Good morning. My name is Jennifer, and I will be your conference operator today. At this time, I'd like to welcome everyone to the Midstates Petroleum third-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).

As a reminder, this call is being recorded, and it will be available for replay beginning today and ending November 15, 2012. The conference ID number for the replay is 56686295. Again, that conference ID is 56686295. The number to dial for the replay is 855-859-2056 or 404-537-3406.

Thank you. And I'll now turn the call over to Mr. Petrie, Investor Relations Coordinator. Please go ahead.

Thanks, Jennifer. Good morning, everyone, and welcome to Midstates Petroleum's third-quarter 2012 earnings conference call.

Joining me today as speakers on our call are John Crum, the President and CEO; Steve Pugh, our Executive Vice President and CEO; and Tom Mitchell, our Executive VP and CFO. John will begin today's call with highlights of the third quarter. Steve will then provide more details on third-quarter operational results and plans for drilling activity for the fourth quarter. Tom will follow with key financial highlights of the third quarter and provide guidance for the fourth quarter. John will then wrap up with some closing comments and a preview of 2013.

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 are 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; estimated timing of production restoration; 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's filings with the SEC. These statements are based on current expectations and projections about future events, involve known and unknown risks, uncertainties and other factors that may cause actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. Please refer to Midstates's filings with the SEC in the Forms 10-Q as of September 30, 2012, to be filed shortly for a discussion of these risks.

I will now turn the call over to John for his comments.

Thank you, Al. Good morning, everyone, and thanks for joining us today. As we said in the release, the last few months at Midstates have been particularly busy.

Just since the last call in August, we've completed a number of important initiatives, including closing on the earlier announced acquisition of the assets of Eagle Energy of Oklahoma, giving us another core area with significant growth potential. We completed an upsized private offering of $600 million in senior notes to fund the cash portion of the Eagle transaction and to provide funding for our ongoing capital programs this year and through 2013.

We also completed an excellent first horizontal Wilcox well at North Cowards Gully, which we announced last month, and most importantly, we met our production and cash operating cost target for the quarter.

While Tom and Steve will reveal the quarter in more detail, here are a few of the highlights. Our total production was 8182 Boes per day, a 4% increase from the second quarter. More importantly, however, our liquids production was up almost 14%, driving a 10% increase in revenues. Our oil and natural gas liquid volumes continued to increase as a percentage of our overall daily Boe production mix, yielding higher value on a Boe basis.

From the operations side, our Pine Prairie program continued to produce solid and dependable results in our shallow Miocene and Frio programs, as well as the deeper Wilcox program. The 28 wells we have drilled this year to date have generated over $25 million of net present value.

At West Gordon, as we indicated earlier, we expect to complete our evaluation of possible solutions to the vertical well performance and for potential application of horizontal technology in that field by the end of this year. We have just completed the horizontal four-star 7H number one in the Wilcox E sand and are presently early in the flow back after a five-stage frac simulation.

We expect to move back onto the AKS 5H-1 for a sidetrack around the Packers liner assembly, which we were unable to recover through fishing operations. We remain very optimistic about that well given the strong shows seen in the drilling of the original lateral, as well as recent results in nearby North Cowards Gully.

Our first horizontal success in North Cowards Gully, the Musser-Davis 8H-1, was completed on September 15 and has averaged 1411 Boes per day for almost two months since with a production mix of 73% oil and 12% natural gas liquids.

We will spud the McFatter 8H-1 as a follow-up to that success at North Cowards Gully within the next week. Continued positive results could lead to over 20 additional horizontal locations in that field alone and gives us encouragement for horizontal drilling application in our other Wilcox acreage positions within Louisiana.

We also recently spud the Musser-Davis 33H-2 in South Bearhead Creek for a horizontal test of the Cockfield formation following our successful Musser-Davis 33H-1 Miocene horizontal well, which has averaged 550 barrels equivalent per day for the first six months of production with 90% of that being black oil.

Our fourth-quarter results will be the first to include our new properties in Oklahoma just acquired from Eagle Energy. We're moving ahead at full speed with the integration of the assets and staff into the Midstates organization. We have had excellent support and corporation from the Eagle team. We will be supplementing their efforts with additional hires, as well as transfers of several Midstates technical leaders from Houston to Tulsa. We have already added a fourth rig to the drilling program in Oklahoma and plan to drill at least 12 wells there in the fourth quarter.

After experiencing some down time in October associated with saltwater disposal facility problems, including a lightening strike, production is back up, and we still expect to make our originally-projected 4Q production volumes. Some of you have asked about Eagle's updated Netherland, Sewell & Associates reserve report. That report has now been delivered and indicated SEC proved reserves of 33.3 million barrels as of June 30, 2012. The difference between that figure and the 37 million barrels announced with the acquisition is associated with timings of the bookings for wells that were not yet on production as of June 30.

Looking ahead to fourth-quarter volumes, we are expecting to produce in the range of 15,100 to 15,600 per day, reflecting growth in volumes from both our Louisiana and Oklahoma properties. We feel quite confident about those numbers. In Louisiana, we have averaged 8325 Boes per day since the beginning of the quarter through yesterday and expect to add two strong Pine Prairie wells by the end of this week.

In Oklahoma, after repairs to several of saltwater disposal facilities, we are again fully operational, and production has averaged 7400 Boes per day for the first week of November with new wells being added weekly.

We plan to invest $115 million to $125 million during the quarter, which reflects adding a fourth rig in Oklahoma this quarter rather than first quarter of 2013 and also drilling follow-up wells to our prior Louisiana horizontal successes in North Cowards Gully and South Bearhead Creek.

I will come back at the end of the call with comments about 2013, but let's move ahead with Steve giving you more details on what has occurred during the quarter and what to expect for the balance of the year.

Thank you, John, and good morning. The third quarter was an exciting quarter for our Company as we prepared to integrate our newly acquired assets in the Mississippian Lime in Oklahoma; drilled a successful horizontal well in North Cowards Gully Field in Louisiana; continued to see strong performance in our Pine Prairie area; and met our production and operating expense targets.

In the Pine Prairie area, we continued our active Wilcox program and our shallow Frio and Miocene drilling program, spudding nine Wilcox wells and 10 shallow wells, all of which were vertical. Both programs continue to deliver at or above our modeled IP rates, and both programs have delivered solid returns in 2012.

As mentioned in the past, we continue to find efficiencies in the Pine Prairie Wilcox program as evidenced by our recent drilling results on accrual 2714. The well was drilled to a depth of 11,844 feet in 6.1 days. Average cost per Wilcox wells in the quarter were in the $3 million range, and average cost for the shallow wells were in the $1.3 million range. We continue to be optimistic about the Pine Prairie programs and expect them to continue to be part of our core drilling program next year.

In the Dequincy area, we continued our shift from vertical to horizontal drilling. In the third quarter, we spud one new drill horizontal well in North Cowards Gully and two horizontal sidetracks of existing wells in West Gordon.

In the North Cowards Gully area, we brought the Musser-Davis 8H-1 online with very strong results. This well was drilled into the Upper Wilcox B formation and had an initial 30-day average gross production rate of 1481 Boe per day of which 85% were liquids. The well production is still strong, producing at an average over the last seven days, of 1263 Boe per day with cum production of over 73,000 barrels Boe since the well came on in mid-September.

As previously released, the well calls for this well were just over $10 million. We think the go-forward well cost for this type of well will be in the $7 million to $8 million range. We are continuing to delineate the field, but believe we may have over 20 potential horizontal locations in North Cowards Gully. This well is a good example of what we think horizontal technology in the Wilcox is capable of in central Louisiana.

Additionally, during the third quarter, we spud two horizontal sidetracks of existing well bores in the West Gordon area. The first well, which was spud in July, was the AKS 5H-1 sidetrack. This well was drilled in the Upper Wilcox C sand with an approximate 3300-foot lateral.

As we have mentioned previously, we encountered mechanical issues during the installation of the Packers Plus system, and we have worked to clean out the well to a point from which we can sidetrack. The lateral was drilled in the thickest net pay area in the field, and the hot oil and gas shows during the drilling of the original sidetrack have encouraged us to drill a new lateral, and we expect the well to provide good production results. We are currently planning to commence sidetrack operations in mid-November.

The second horizontal project spud in the West Gordon area was the four-star 7H-1 sidetrack. This well was drilled to a measured depth of 13,653 feet in the Upper Wilcox east end with a lateral length of approximately 1900 feet. The well was recently fracked with five stages and is currently testing.

In the previous two earnings calls, we have discussed the strong results from the Musser-Davis 33H-1 horizontal well in South Bearhead Creek. The well targeted the Miocene sand at a vertical depth of 5000 feet, and I wanted to give you a quick update. This well came online in May at a peak rate of over 700 Boes per day and is still producing at rates over 425 Boe per day.

Over the six months the well has been producing, it has cumulative production of over 97,000 Boe. The well did not require a frack based on the high quality of the Miocene sand.

To help identify additional future drilling locations in both Louisiana and Oklahoma, we have three 3D seismic shoots underway. The first is the 200-square mile Fleetwood survey just west of Baton Rouge, Louisiana. We expect to receive the full dataset from that survey next month and are expediting the processing and interpretation. We already have a prospect identified that we will drill as soon as we get confirmation from the data.

We also have a 61-square mile survey underway at South Bearhead Creek in Louisiana. We also expect to receive data from that survey next month.

In Oklahoma, we recently committed to participate in a 304-square mile 3-D shoot in Woods and Alfalfa Counties for 6.4 million that is scheduled for completion in the latter half of 2013. This will help us with our infield drilling program, as well as our efforts to extend the limits of the field.

Shifting gears from the third quarter, in the fourth quarter, we plan to invest about $70 million to $75 million in Louisiana. We are currently operating five rigs in Louisiana, but are in the process of optimizing our rig fleet and expect to level out around three rigs to start the year.

In Pine Prairie, we plan to drill five Wilcox and seven shallow vertical wells, and we expect to see similar results to our third-quarter wells.

In the Dequincy area, we expect to spud our second North Cowards Gully horizontal well tomorrow -- the McFatter 8H-1 as a follow-on to the very successful Musser-Davis 8H-1 that we mentioned previously. This was a western offset to the 8H-1 in the Upper Wilcox B sand and will be drilled to a measured depth of 16,200 feet and has a planned lateral of 3700 feet. This well will be on strike with the Musser-Davis 8H-1 and should have similar reservoir characteristics and rock quality. Drilling complete costs are expected to be $8 million.

Additionally, we have spud the Musser-Davis 33H-2 horizontal sidetrack in South Bearhead Creek, targeting the Cockfield mystic sand. We are currently drilling the well, and we planned a 1500 foot lateral.

As noted earlier in my comments, at West Gordon, we will be drilling the second horizontal sidetrack of the AKS 5H-1 in the Upper Wilcox C sand.

Shifting now to Oklahoma, this part of the fourth quarter was a busy time for us as we closed on the Eagle Energy acquisition and added the Mississippian Lime assets to our portfolio. In the third quarter, Eagle drilled six horizontal wells and a high capacity SWD in the core area using three rigs.

Since closing the deal, we have added a fourth rig and plan to invest $45 million to $50 million in Oklahoma and drill 12 horizontal wells this quarter. We plan to use three rigs in the heart of the play in Woods County and have a fourth rig drilling to HPB acreage in Woods and Alfalfa Counties.

As we said when we announced the acquisition, for the foreseeable future, we plan to focus primarily on lower-risk infield drilling in the core area of our acreage to build volumes and cash flow.

We have a great start on the integration of operating in accounting personnel. We are fortunate to have the entire Eagle Energy staff working on the assets for the next year through the transition services agreement and hope to convince many of them to join Midstates.

In addition to those employees, we plan to have 8 to 10 current Midstates employees working in the Tulsa office on either a full-time or a part-time basis.

Turning briefly to LOE, our lease operating and workover expenses for the quarter were $6.6 million, which resulted in a unit cost of $8.72 per Boe, which was within our Q3 guidance range of $8.25 to $9.25 per Boe.

Let me now turn the call over to Tom for financial results and Q4 guidance.

Good morning, everyone. As in the past, I'll focus on the key financial items in the release and provide you with guidance for the fourth quarter. If there are any questions about other items in the release, I'm happy to take your questions, and Al and I will be available after the call.

To begin, as John mentioned, we were pleased that our reported production volumes and key recurring cash expense items were within our guidance ranges, and I will go through the third-quarter details before discussing the financial implications of the Eagle acquisition.

Adjusted EBITDA for the third quarter totaled $33 million. We reported a GAAP net loss of $18 million or $0.27 loss per share. Adjusted net income, which excludes the impact of unrealized gains or losses on derivatives and the related income tax effects, totaled $100,000. We presented the reconciliations of net income to adjusted EBITDA and adjusted net income in the supplemental information in the earnings release.

In the second quarter, we reported the mix of production as 62% oil, 14% natural gas liquids and 24% natural gas. In the third quarter, we improved that mix again with our production being 68% oil, 15% NGLs and 17% natural gas. We had higher relative oil production due to the further decline in the high gas volume central fault block wells and the fact that the wells we drilled recently had a lower gas/oil ratio and processed a higher percentage of our natural gas production. While we certainly like that mix in today's price environment, our total Company mix will change in the fourth quarter as we include the Oklahoma volumes in our reported production.

John indicated that we expect the total production to average between 15,100 and 115,600 Boe per day in the fourth quarter. And I'll add that we expect Louisiana to average between 8,300 and 8,500 Boe per day and Oklahoma to average between 6,800 and 7,100 Boe per day.

For Louisiana, I would assume the fourth-quarter mix to be about 65% to 70% oil, 15% to 20% NGLs, and 15% to 20% natural gas. In Oklahoma, I'd assume the mix to be about 35% to 40% oil, 15% to 25% NGLs and 40% to 45% natural gas.

Midstates' average realized price per barrel of oil before our commodity derivatives was $104.32 in the third quarter of 2012 compared to $107.56 in the second quarter.

Remember that our contracts for the sale of our Louisiana oil provide that we are paid the LOS differential to WTI on about a 30-day delayed basis. As a result, we will continue to have a one-month lag in the Louisiana price realizations. Our Louisiana realizations also reflect about $2.35 a barrel in transportation costs for trucking.

As we add Oklahoma production in the fourth quarter, you should assume about a $6 discount to WTI for our Mississippian Lime production, and that does include transportation also.

Our third-quarter natural gas price realization rose to $2.95 an Mcf from $2.27 in the second quarter. Our natural gas price in Louisiana compares favorably with the Henry Hub average price and to the location and quality of our gas. For the fourth quarter, when we add our Oklahoma natural gas production, you should assume about a $0.20 discount to Henry Hub pricing for those Oklahoma volumes.

We are now processing the majority of our Louisiana gas production as the price realized for NGLs fell to $35.46 per barrel in the third quarter from $39.83 in the second quarter. The earnings release included detailed information on the hedges we now have in place.

Since the last call in August, we added about 1500 barrels per day of new hedges on our Louisiana oil production for the 2014 time period, and we assumed all the oil, NGL, and natural gas hedges Eagle had in place when the transaction closed on October 1.

We do not have any hedges on our NGLs or natural gas for our Louisiana production. I won't discuss our hedges in detail now, but will be happy to answer any questions after our prepared remarks. I have posted the detail of the latest hedging information on our website that should give you all the information you need to work for your models, along with a guidance summary.

As we look at it today, for the next couple of years, our hedging target continues to be around 50% of our total anticipated production.

Let me now turn to expenses.

While we split our production guidance between Louisiana and Oklahoma, I will provide guidance on expense items on a total Company basis. Lease operating and workover expenses totaled $7 million for the third quarter of 2012 or $8.72 a barrel compared to $6 million or $8.24 per barrel during the second quarter. Workovers totaled $771,000 and were up slightly from the second quarter.

With the addition of the lower operating cost Oklahoma properties, we expect our combined fourth-quarter LOE to be in the range of $6.50 to $7.50 per Boe.

Severance and ad valorem taxes totaled $7 million in the 2012 third quarter compared to $6 million in the second quarter. That is about 10.8% of sales revenue before derivatives, slightly lower than the 11.5% rate reported in the second quarter.

Louisiana severance taxes for oil are applied as a percentage of revenue with a top rate at 12.5%, while for natural gas, the severance taxes are applied at a flat rate per Mcf produced.

In Oklahoma, the severance tax rate on both oil and natural gas is 7% of revenue, but horizontal wells incur only 1% for the first 48 months of production. Combining the impact of production-related taxes in both states on our total production, for the fourth quarter, I would use 8.5% to 9.5% of revenue.

Our third-quarter general and administrative expenses before costs associated with the Eagle property acquisition where $8 million or $10.56 per Boe compared with $5 million or $6.89 a barrel in the second quarter.

Third-quarter cash G&A totaled $7 million, and non-cash compensation was $900,000. We expect our recurring fourth-quarter G&A to be in the range of $10 million to $11 million, of which about 15% to 20% will be non-cash compensation. The increase primarily reflects additional costs under the acquisition transition services agreement, as well as headcount growth in our Houston office.

Acquisition and transition costs associated with the Eagle transaction totaled $3 million in the third quarter. We also expect there to be about $14 million of additional costs in the fourth quarter related to the closing of the Eagle acquisition that occurred on October 1, which includes legal and advisory fees and fees associated with the bridge facility that was ultimately replaced with the $600 million notes offering.

DD&A expense of $31 million was up about $3 million compared to the $28 million in the second quarter of 2012, and the DD&A rate for the third quarter was $40.76 per Boe compared to $38.78 per Boe in the second quarter.

In conjunction with the Eagle transaction, we are currently working on the final allocation of the purchase price. As a result, our estimate of DD&A in the fourth quarter is based on preliminary numbers and may be subject to change once we have the allocation finalized. I would assume the rate to be $30 to $36 per Boe in the fourth quarter.

For the third quarter, our effective tax rate was about 40%, and you should expect that same rate for the fourth quarter. We do not expect to have a cash income tax liability for the foreseeable future.

Since our last call, we have greatly improved our overall capital structure. We were excited to finally approach the bond market, and we were very pleased with our reception as was evidenced with our up-sized private issuance of $600 million in senior notes. These notes mature on October 1, 2020 with a coupon of 10.75% and were issued at 100% of face.

With the $182 million of net proceeds from the offering, we funded the cash portion of the acquisition and related expenses, repaid $183 million in outstanding borrowings under the revolving credit facility, and with the remainder going to general corporate purposes.

On October 1, 2012, in connection with the deal, our bank group showed strong support for the Company by increasing our borrowing base under our revolver to $250 million and extending the maturity date to October 1, 2017. The revolver is subject to re-determination in March of 2013.

Additionally, associated with the transaction, the Company issued 325,000 shares of Series A Preferred Stock with an initial liquidation preference value of $1000 per share and a dividend rate of 8%.

In the fourth quarter for GAAP per-share calculations, we will have to assume that all of the preferred shares have been converted to common at their lowest conversion price of $11 per share, even though they are not comfortable for at least one year. Those additional 29.5 million shares should be included in any modeling. If we report a loss for the quarter, the preferred shares do not participate in losses, so the shares are not included in any of those per-share calculations.

At this point, we intend to pick the semi-annual dividend on the preferred, and the first dividend date is March 20 of 2013.

After taking into account all of these capital transactions, on October 1 we had approximately $38 million of cash and cash equivalents and $216 million of borrowing availability under our revolving credit facility. We are confident that this capital structure, together with future cash flows from ops, will provide us sufficient liquidity to fund our drilling and development programs to the end of 2013.

Total interest expense was $1 million for the third quarter, flat with the second quarter, and we capitalized $800,000 in interest to unproved properties during the third quarter.

For the fourth quarter, we will have our $600 million and 10.75% notes outstanding for the full quarter, as well as advances on our revolver.

In total, we expect fourth-quarter interest expense of $17 million to $18 million before capitalized interest. We will likely capitalize about 40% to 50% of it to unproved properties.

During the third quarter, we invested $108 million in capital expenditures and, as John mentioned, expect to invest $115 million to $125 million in the fourth quarter.

In closing, hopefully my enthusiasm for the Company's direction and our current financial outlook is evident. We are looking forward to delivering on our plans and continuing to strengthen our balance sheet.

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

Thanks, Tom. As you've heard this morning, we intend to have another extremely busy quarterly ahead of us. Our primary focus now and for the foreseeable future is execution of our drilling program and the integration of the Eagle assets and team into Midstates.

But we will continue to look at opportunities to add acreage to our existing core areas, and we'll review opportunities that may arise in different basins. Our time and effort will be spent almost exclusively on our existing asset base.

We are committed to proving we can meet our production and expense targets, and we'll be laser-focus on achieving results that will increase your confidence in the Midstates team and build shareholder value.

Looking ahead to 2013, we are affirming the same preliminary preview of production and expenses that we provided during our last guidance update in September, before we began our senior notes offering roadshow. The key points are production for the full year of 2013 at 20,000 to 23,000 Boes per day, LOE at $5.50 to $7.00 per Boe, and capital projected at $400 million to $450 million for the year. The guidance is provided in full on our website for additional line item details.

We plan to have three rigs active in Louisiana for most of 2013. In Oklahoma, we will have four to five rigs running. Three of those rigs would be primarily focused on infield drilling in the heart of the play with one to two rigs used to convert acreage to HBP status and test the more unproven areas.

Our fourth-quarter 2012 activity with horizontal tests in Louisiana and the focus on infield activity in Oklahoma has the potential to positively impact our final 2013 plans. As such, you can expect us to firm up guidance for the full-year 2013 in January.

In closing, we will continue to be proactive in our investor relations efforts through meetings with our shareholders and participating in upcoming conferences. Over the next month, we plan to attend the BofA fixed-income conference in Miami, the Wells Fargo conference in New York, and the Capital One Southcoast conference in New Orleans. We hope to see some of you at these venues.

With that, Al, we'll turn it over to you, and we are ready to take questions.

Thank you, John. Participants, please limit your questions to one with a follow-up. And Jennifer, we're ready to get started.

(Operator Instructions). Neal Dingmann, SunTrust.

Great color this morning. Say, John, first question just wondering you laid out in the press release about the number of horizontals still coming on besides obviously the one in the North Cowards, talking about one coming on here shortly in South Bearhead and the other at West Gordon. What are your thoughts as you look -- once you'll see the success on those two, you have a better idea of what you think the number of potential locations could be in those two fields? Or maybe just give us some color on what your thoughts once those two -- once those are all drilled out?

Sure, Neal. Thanks. First of all, we've given you direction on what we think North Cowards Gully could be. Obviously, that was such a good result, we're pretty excited about it.

In Bearhead, we've tested -- we've got a horizontal in the Miocene that obviously worked beautifully. We are now testing the Cockfield, which for those of you that don't know, the Cockfield is a big producer across Louisiana for years, and it's now just being started to start testing horizontal concept in that play. So we think it has some very solid potential across the entire trend.

But obviously in the end, what we're looking for is to develop Wilcox targets because of the shared thickness and the oil in place numbers that come out of the Wilcox. So the tests we're going to be doing at West Gordon are very critical, and we will be doing some horizontal Wilcox wells at Bearhead, as well, as time goes on.

To give you a guess at where that will end up, we're trying not to get too far out on our skis again this year. So we would like to go ahead and get some tests in place, see some real results over a number of months before we make any real calls.

Great. And then just one follow-up. Just over on the horizontal mist, you mentioned, I think, around 7400 current production here in November. Obviously now with four rigs, I guess two questions around that field.

One, your thoughts on the need for some seismic there? And the number two, if you are going to four rigs -- again, not really asking for guidance yet for next year, it's a little premature maybe for that -- but just what type of -- how was Eagle -- remind us how many rigs they were running in all versus what you all have? And I don't know if you expect any sort of issues there.

Eagle ran three for part of the year, and we're back to two for a little while and then back up to three. So they've tried to maintain a three-rig program. We had always planned to go to four to five for 2013, and we've just decided to pull that fourth rig in just a little bit early. So obviously, that could help with our numbers next year. But, again, we'll firm those up in January. Does that give you what you need?

That's exactly right. That's perfect. Thank you all.

Leo Mariani, RBC.

I wanted to see if you all had an EUR yet on that North Cowards Gully horizontal well?

Well, we've got several, but I don't know that we're ready to give that out yet. We really want to get some solid production.

Leo, I'll tell you we are just now bringing this saying -- is still flowing up the frac stream, so we really haven't even got it down to the level where I can really put some solid estimates for it. It certainly looks like it's going to be significantly better than we've seen and certainly north of 300,000 Boes per day.

Okay, that's helpful. And in terms of your plan in Louisiana in 2013, you talked about three rigs. Can you give us an indication of how you may split up those rigs?

Yes, I think it's pretty much a given that we'll keep one rig running at Pine Prairie. And then we'd have two other rigs working a combination of the Dequincy area and, importantly, our new Fleetwood survey that we are just starting to get data out of and would expect to have some targets are.

And then finally, we told you we picked up some Austin Chalk acreage that we're working pretty hard, as well.

Okay. So I guess would it be fair to assume that the other two rigs are going to be drilling largely horizontal wells in 2013? How should we think about that? e

There will be a combination, but yes, we are moving to -- given the successes we've seen, we are kind of moving to a horizontal approach, certainly in the West side of the state. Obviously, when we go into tests, a new area like Fleetwood, the first wells are certainly going to be vertical, and we'd like to confirm we've got something there and then make a decision on whether we go horizontal or not.

All right. Thanks, guys.

Thank you, Leo.

Hubert van der Heijden, Tudor, Pickering.

Just based on the early results at North Cowards Gully, can you talk how the original vertical locations may be impacted by the additional 20 horizontal locations? Is there any cannibalism there?

Yes, do you mean the vertical proved undeveloped locations we would have seen?

Right.

Look, yes, we intend to be able to drain the reservoir with fewer horizontal wells than we would have taken to use vertical wells in the field. So that's the whole reason we would do this.

And then just on a quick follow-up there, did the longer term pace and split between horizontal and vertical, is it just the 20th horizontals completely displacing the verticals, or are you still planning on a full-scale split between the two?

No, I would anticipate -- and it is early, so please don't pin me down too hard here, but it is early -- but I would anticipate many of the vertical locations going away and being replaced with horizontals with the exception of there are some areas that we're going to need to do verticals just because of the reservoir geometry.

Okay. Perfect. And then could you real quickly mention like what proportion of the Oklahoma production was offline in October? On the (multiple speakers) water disposal?

Yes, we had a significant drop in October. We averaged about 5800 Boes -- a little over 1000 Boes per day were off in October.

Perfect. Thanks so much.

Adam Lawlis, Simmons & Company.

Can you guys rank the different areas in Louisiana on a projected rate-of-return basis and how you see those potentially comparing to the Miss Lime?

Yes, probably. Look, I think what we like about the Mississippian Lime is that we're seeing solid rates of return, and we are seeing it at the work capital investment on a per-well basis. The wells that compete with that straight up on costs and rates of return would be most of the Pine Prairie complex where, indeed, our costs are typically going to be $3 million or less.

As we move into the Dequincy area and some of these horizontal wells and stuff, the jury is still out. But obviously if we can make some more wells like that North Cowards Gully well, it will compete with just about anything that's out there. So yes -- and certainly these little shallow Miocene wells don't have to make much to generate big rates of return.

Right. And on your NGL hedges, what is the composition of your hedged NGL buckets?

It was mostly placed on propane. About 50% of the hedge was on propane and then 25% butane, and I think the other 25% was in natural gasoline.

Very helpful. Thanks, guys.

Brian Singer, Goldman Sachs.

John, did you get all your trees chopped down?

It is Brian.

Brian, you too? Did you get yours?

No, it is an apartment, so no trees. Yes, I guess, in this case, it's a good thing. But just wanted to -- you mentioned on your comments that Fleetwood, you could drill some wells there next year, and that you're starting to get some of that 3D seismic back. Can you just add more some color on what you're seeing there and what that could mean for the reservoir that you could see compares to what you are drilling today in Pine Prairie and elsewhere?

Well, Brian, I think we've talked to a number of you about why we are over there. As a general rule, the east side of the state, the Wilcox tends to be a better reservoir and some of the bigger fields that are out there.

And so when we look at Fleetwood, we look at a field like Fordoche as our analogy, and that's actually the biggest Wilcox field in Louisiana.

So what you tend to get is thicker sediments with better porosity, which, obviously, can yield better results.

So from a Wilcox standpoint, we feel pretty comfortable. There are people drilling horizontal Cockfield wells in the area as we speak, and that's an upside. We also have targets potentially at Sparta, and ultimately, I think we've told you that -- we would not want to do it today -- but we certainly have Tuscaloosa targets in the area as well.

So this is a very structured-up area. You can see it very easily on 2-D seismic. We had a very good Wilcox target that we probably would have drilled by now had we not shopped the 3-D called Kenmore. And we were just kind of -- we put that off because obviously getting this 3D seismic we thought it was critical. We looked at that first.

We've already got a little bit -- we got our first volume back and starting to work on that. So we are feeling pretty good about getting some data. But it is probably going to be the first of the year before we're ready to start making some calls.

Okay. Have you seen any difference in the 3D seismic that would confirms your thesis that you just alliterated?

No, we're just starting to get a little bit of the data. So the geophysicist is our data, but it's going to be several months of her working that before we can make any calls.

Okay, thanks. And then any acquisitions or expansion opportunities that you're looking at here that you think come to the forefront? Are there, in the two areas in which you are focused, are other areas?

Say that again, Brian?

Are you pursuing any acquisitions, or do you see any further acquisitions either in the Mississippian Lime, in the Upper Gulf Coast tertiary or other areas?

Well, look, we're always looking, but no, we don't have anything in the queue right now. And as we indicated on the call, we've got a pretty well-loaded boat right now, and we're all rowing as hard as we can to make sure we've got that in line before we add anything else to it.

One other point on seismic because I am sorry, somebody else asked about Oklahoma seismic, didn't they? And I think Steve indicated in his call notes that we've just agreed to participate in a fairly significant 3D seismic shoot in Woods and Alfalfa County, which we think is going to be quite useful in helping determine the best places to put our horizontal well bores. And we'd expect -- that's going to cover 300 sections, so it's a big area. So we are feeling pretty good about getting that information in.

Thank you.

John Herrlin, Societe Generale.

Sorry, John. I got the --

The answer to your question is, I've gotten rid of the trees but not the stumps.

Okay.

Anyway, just some quick ones. On a going-forward basis for reporting because you have wellhead revenue differentials between Oklahoma and Louisiana, are you going to report the volume separately?

Yes, there is no way for you to break it out without us doing that since the margins are so different. So we will give you volume -- we will give costs in total, but the volume is broken out.

Okay, that's fine. And during the third quarter in the Wilcox, you had more well treatment, so where you running acid? Did you have skin damage or whatever it may be? And if so, going forward have you changed your well designs so you don't incur those costs? Because I noticed you were having lower guidance on the costs with that.

Yes, I think you are seeing chemical costs. You'll recall the last couple of calls we've been trying to figure out some of the issues we're dealing with at West Gordon and actually seeing some scale in paraffin buildup and same issues in some other areas. So we have increased our chemical injection kind of across the region. Our new production manager has been all over that and working it real hard.

And that has enhanced your recoveries?

Well, it's going to stop us from doing workovers as quickly and hopefully keep our rates coming on.

Okay. And then the last one for me is on the Mississippian Lime, are you still adding working interest to the individual wells you drilled beyond what your contracted interest is?

Thanks, John, that's a really good point. For some of you that we've talked on the road about, one of the things that happens in Oklahoma is they have forced pooling rules up there. So you tend to end up with a little higher interest in your wells than the acreage would indicate as we go forward.

So we're showing somewhere in the 55% range on ownership in the sections we're involved in. But just to tell you, we've been close to 70% Eagle has been able to play at over the last year. So we think there is some significant room to add interest in the individual wells. And we are actively buying acreage in the core of our area as we speak.

Great. That's it for me. Thank you.

Jeb Bachmann, Howard Weil.

Just a quick one for me, John. On the Netherland, Sewell report, just wondering if they provide you guys with a 2P, 3P estimate on those assets?

Yes, they did. Curtis, do you want to talk about that?

Yes, the practice at Eagle was a 3P report. We internally here at Midstates have been having a -- I do 1P and 2P for us. So we'll decide going forward on the entire asset base what's the best answer. But yes, as far as Oklahoma goes, they've been preparing 3P reports for us.

Okay. You guys can't provide those numbers at this point? You are going to hold off until later?

Yes, at this point, we are going to hold off because we are in a tweener point right now. We will be -- we're actively right now preparing for year-end reserves, so we'll have the fulsome reports by year end on both asset areas.

Okay. Great. Thanks, guys.

And as you might guess, they were higher. When you add the probable and possible, it makes a big difference.

Okay. Great. Thanks.

David Tameron, Wells Fargo.

John, can you just go back and remind me of the water infrastructure that you have Mississippi Lime to get rid of that water and where you guys sit there and if that's a limiting -- if that is a governor at all going forward?

Well, we don't think so. We think we're going to be able to stay up with that quite well.

We had a fairly unusual thing happen here. They had a lightning strike at their Longhurst saltwater disposal facility. Eagle had taken the position that they would work with larger volume centralized saltwater disposal facilities. And when lightning struck that tank battery, we were down for about 60 days, roughly, trying to get that battery back up. So, again, we try to reroute to other batteries, but that certainly affected us.

And the other issue we dealt with is we had some injection wells in our Lincoln County acreage that didn't pass what we call the integrity test. So we had to go in and make some tubing changeups. But nothing significant. We don't really anticipate that being a problem going forward.

Okay. And what about NGL processing? Where do you guys stand on that as far as getting those NGLs in, and where do those end up getting priced?

Steve, do you want to take that?

Yes, we're in discussions with SemGas as we've stated. All the Oklahoma acreage is dedicated to SemGas. So we are in the process of working a contract for a bigger plant, and those discussions are ongoing. We expect those to finalize soon.

All right. And one more question, John, and I don't know if this is the appropriate forum to ask, but since I have been getting questions on it, I'll throw it out.

First Reserve owns a big chunk -- still a big chunk of the Company. Can you talk about -- investors have seen private equity firms get out of other MPs where they had investment. Can you talk at all about --?

I am somewhat nervous about speaking for First Reserve, but I have talked to them a lot. And I think that investors should feel pretty comfortable that you are not going to see First Reserve leaving anytime soon. They had a hard time selling at their IPO price, so at this level, I don't see anything happening.

You may recall when we talked about this, this is part of their Fund 12, which has a life that goes through 2018 with the potential to add two years to that. So they are under no pressure to sell any of those shares.

So I would leave you to talk to Alex Krueger or someone like that about their real feelings on it, but I don't anticipate any selling by First Reserve.

All right. I appreciate that. That's all I got. Nice quarter.

Thank you.

Ron Mills, Johnson Rice.

Just in the Mississippian Lime, can you provide a little bit more color on the core versus the non-core and how that might impact your ability to move from the Eagle-type costs down to where other people in the industry are talking of costs in terms of low 3s versus upper 3s and the ability to accelerate rig release to first production-type numbers and the impact that has on you all?

Yes, thank you, Ron. That is an excellent point. Look, Eagle has done just like many of the other players in the Mississippian Lime, they have been trying to convert acreage to HBP status, and by definition, that means you drill a well in every section. So it obviously spreads out your operations and is certainly not the way to make things the cheapest.

So what we feel good about is we're now in a position where one to two rigs is going to be able to convert the rest of the acreage we have there, and we can keep 38 rigs running in the core of the activity where we have had outside results. But just as importantly, we've got pipeline infrastructure in place, we've got power infrastructure in place, and we've got saltwater infrastructure in place.

So that should allow us to bring down the time to first production dramatically. And it's not a real surprise. I think everybody goes through this. As you're putting in your initial infrastructure, you've got to wait for pipelines to come to you; you've got to build your water disposal facilities; you've got to build your power facilities. Once we start into the infield program, we should be able to cut those numbers pretty dramatically, and we would certainly expect to get our numbers down from high 3s to low 3s and potentially below that.

Okay, good. In Louisiana, if you look at the horizontal program in North Cowards Gully versus West Gordon versus as you evaluate the other areas, especially at North Cowards Gully, what do you think is driving the outperformance? Is it something geologic? When you talk about the 20-plus locations in that area, from a structural standpoint, do you think that those characteristics cover that whole structure, or are there reasons to expect some variability?

We can map this Wilcox B sand across the entire structure. That 20, and I can tell you, it's actually a few more than 20 locations that the geologist has shown us are capably putting in there is to lowest known oil. We really haven't defined how low that can go, so there's potential for that to grow even some more.

I will tell you that North Cowards Gully is a little bit different reservoir than we're seeing in some of the other fields, and that is evidenced by we make very little water in this field. So this 8H well we're talking about makes less than 100 barrels of water a day, actually close to 50 to 60 barrels a day. So it is a little different cow, I guess, and we hope we can find some more look just like it.

Okay, good. Let me let someone else jump in. Thanks, John.

Thanks, Ron.

Todd Firestone, Morgan Stanley.

I had just a quick question on maybe you can provide a little color on the Mississippian Lime results that you've seen. What I was thinking maybe some color on flow rates and maybe you have seen a big variability in looking at initial annualized decline and how you are extrapolating the curve going forward from your data you seen over the last few months.

Well, there is certainly variability on a well-to-well basis. There's not any question about that, and I think you are seeing that across the industry. So what we have to do is we have to put a program together and, on average, come up with numbers that make some sense.

The program we've laid out for you for 2013 is intended to reduce that variability by concentrating within the core. We still see some variability, but we would expect last. I guess the one statistic -- and I guess I haven't updated it recently -- that I like to point to is that Eagle's last 30 wells had averaged over 600 Boes per day as an IP, and that puts it in a pretty strong area for making the numbers work.

We do have some solid support for high B factors. We think we can back up 1.5 B factors pretty easily and maybe as much as 2 in some cases.

Great. That is super helpful. And one other question. Maybe you could provide a little bit of what you see -- how you have evolved in your -- you've got a high OF in your -- across the Louisiana acreage, how that might evolve and how you might think about recovery rates going in and looking at Fleetwood, that might be helpful.

You are saying --?

Yes, how your knowledge may have evolved in recovery rates for Fleetwood based on your experience in the last six months drilling across Louisiana.

Yes, I think -- obviously, we still think horizontal drilling is going to be a great application for these reservoirs overall.

Again, one of the things that is interesting as you move to the east side of the state is you tend to get a little better porosities and permeabilities, and that will help in the horizontal sense, as well as in the vertical sense.

One of the things we are finding is that some of these reservoirs, it is such tight rock that you sometimes don't get the water separated from the oil. And if we get -- as we move east, that should be less of a problem for us.

Okay. That's helpful. That's all I have. Thanks.

Thank you very much. I think -- is that all the questions we've got, Operator?

There are no further questions.

Well, thanks to all of you for joining us today. We hope we left you with a sense that we're on track and we're going to continue to improve as we go forward. I appreciate all your support. Thank you.

This does conclude today's conference call. You may now disconnect.