Al Petrie - IR
John Crum - President & CEO
Steve Pugh - EVP & COO
Tom Mitchell - VP & CFO
Neil Dingmann - SunTrust
Leo Mariani - RBC
Adam Lawlis - Simmons & Co.
Brian Singer - Goldman Sachs
David Helen - Wells Fargo
Ron Mill - Johnson Rice
Todd Firestone - Morgan Stanley
Midstates Petroleum Company (MPO) Q3 2012 Earnings Call November 8, 2012 9:00 PM ET
Good morning. My name is Jennifer and I will be your conference operator today. At this time, I 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). This call is being recorded and will be available for replay beginning today and ending November 15, 2012. The conference ID number for the reply is 56686295. Again the conference I'd is 56686295. The number to dial for the replay is 855-859-2056 or 404-537-3406. Thank you. I would now like to 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 earning’s conference call. Joining me today as speakers on our call are John Crum, President and CEO; Stephen Pugh, our Executive Vice President and COO 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 operation results and plans for drilling activity for the fourth quarter. Tom will follow with key financial highlights for 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 including this conference call, or in our press release that address activities, events or developments that Midstates expects, believes, plans, projects, estimate or anticipates will or may occur in the future are forward-looking statement. 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, plan capital expenditures and other matters that are discussed in the Midstates 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 filings with the SEC and 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 of 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 upsize 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 until 2013.
We also completed an excellent first horizontal well, Wilcox well in North Cowards Gully which we announced last month. And most importantly, we met our production in cash operation 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 8,182 net Boe 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 Boe basis. From the operation side, our Pine Prairie program continued to produce solid and dependable results in our shallow well (inaudible) 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 on that field by the end of this year. We have just completed the horizontal four Star 78- 1 in the Wilcox sand and are presently early in the flow back after a five stage frac stimulation. We expect to move back on to the AKS5H-1 for a sidetrack around the stuck packer liner assembly which we’re 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 1,411 Boe’s per day for almost two months since with the production mix of 73% oil and 12% nitro gas liquids. We will start to make fatter 8H-1 as a follow up to that success in 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 spot the Musser-Davis 33H-2, instead of Bearhead Creek for horizontal test of the Cockfield information following our successful Musser-Davis 33H-1, myosin horizontal Well, which is 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 stuff into the Midstates’ organization. We have had excellent support and cooperation 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 salt water disposal facility problems including a lighting 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's school associates reserve report, that report has now been delivered and indicated SEC approved reserves of 33.3 barrels, as of June 30th 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 on June 30th.
Looking ahead to fourth quarter volumes, we're 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 and Louisiana with average stated 325 Boe 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, we perished to several Salt Water disposed after repairs to several of The Salt Water disposal facilities, we are again fully operational and production is average 7,400 Boe per day for the first week of November with new wells being added weekly.
We plan to invest a 115 to 125 million during the quarter which reflects adding a fourth rig In Oklahoma this quarter rather than first quarter 2013, and also drilling follow-up wells to our prior Louisiana horizontal successes in North Coward's Gully in 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 or production and operating expense targets.
In the Pine Prairie area we continued our active Wilcox program and our shallow well and (inaudible) drilling program, (inaudible) 9 Wilcox wells and 10 shallow wells all of which were vertical. Both programs continue to delivery at or above our modeled IP rates and both programs have delivered solid returns in 2012.
As mentioned in the past, we continued to find efficiencies in Pine Prairie Wilcox program as evidenced by our recent drilling results on (inaudible). The well was drilled to a depth of 11,844 feet in 6.1 days. Average cost for 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 continued 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 spent one new drill horizontal well in North Cowards Gully and two horizontal side tracks of existing wells in West Gordon.
In the North Cowards Gully area we brought the Musser-Davis 8H online with very strong results. This well was drilled into upper Wilcox (B) formation and had an initial 30 day average gross production rate of 1,481 Boe per day of which 85% were liquids.
Well production is still strong producing at an average over the last seven days of 1,263 Boe per day with keen production above our 73,000 barrels Boe, since the well came on in mid-September.
As previously released, the well cost 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 the Lake field, I 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 AKS5H-1 sidetrack. This well was drilled in the upper Wilcox sea sand with an approximate 3,300 foot lateral.
As we mentioned previously, we encountered mechanical issues during the installation of the Packers Plus system and we’ve 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 high oil and gas shales 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 projects 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 sea sand with the lateral length of approximately 1,900 feet. The well was recently fraced with five stages and is currently testing.
In the previous two earning 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 5,000 feet and I wanted to give you a quick update. This well came on line in May at a peak rate of over 7,000 Boe per day and is still producing at rates over 425 Boe per day. Over the six months, the well has been producing it is cumulative production of over 97,000 Boe. The well did not require frac 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 for that survey next month and are expediting and the processing and interpretation. We already have a prospect identify that we will drill as soon as we get conformation 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’re recently committed to particulate in a 304 square mile 3D shoot in Woods & 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 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 are we expect to start our second North Cowards Gully horizontal well tomorrow? The McFatter 8H-1 is a follow on to the very successful Musser-Davis 8H-1 that we mentioned previously. This well is 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 3,700 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 plan a 1,500 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 Sea sand.
Shifting now to Oklahoma, the start 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 in 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-$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 HPP 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 by acreage to build volumes and cash flow.
We have a great start on the integration of operating and 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 8-10 current Midstates employees working in the Tulsa office on either a fulltime or a part-time basis.
Turning briefly to LOE, our lease operating and work over 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 in 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 am 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 to 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 related income tax effect totaled $100,000.
We presented the reconciliations of net income to adjust EBITDA and adjusted net income of supplemental information in the earning’s 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 in central fault block wells and the fact that wells we drilled recently had a lower gas oil ratio and processed a higher percentage of a 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 15,600 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 that 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 were as $104.32 in the third quarter of ‘12 compared to a $107.56 in the second quarter. Remember that our contracts for the sale of our Louisiana oil provide that we are paid LLS differential 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 and transportation cost for trucking.
As we add Oklahoma production in the fourth quarter, you should assume about a $6 discount to WTI for our Mississippian line production and that does include transportation also.
Our third quarter natural gas price realization rose to $2.97 in mcf from $2.27 in the second quarter. Our natural gas price in Louisiana compares favorably with the Henry Hub average price to the location and quality of our gas. For the fourth quarter when we add our Oklahoma natural gas production, you should assume about $0.20 discount to Henry Hub pricing for those Oklahoma volumes.
We are now processing the majority of our Louisiana gas production; 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 1,500 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 1st. we did 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 a detail of our 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's about 10.8% of sales revenue before derivates, slightly lower than the 11.5% rate reported in the second quarter.
Louisiana severances taxes for oil are applied as a percentage of revenue with a top rate of 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, 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 cost associated with the Eagle property acquisition were 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 noncash compensation was 900,000. We expect our recovering fourth quarter G&A to be in the range of 10 million to 11 million of which about 15% to 20% will be noncash compensation. The increase primarily reflects additional cost under the acquisition transition services agreement as well as headcount growth in our Huston office.
Acquisition and transition cost 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 1st, which includes legal and advisory fees and fees associated with the bridge facility that was ultimately replaced with a $600 million note offering
DD&A expense of 31 million was up about 3 million compared to the 28 million in the second quarter of 2012 and 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 estimates 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 above 40% and you should expect that same rate for the fourth quarter. We did 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 evidence what our upsize private issuance of 600 million senior notes. These notes mature on October 1st, 2020 with a coupon of 10, 75 and were issued at a 100% of phase.
With the 182 million of net proceeds from the offering, we funded the cash portion of the acquisition and related expenses. Repaid a 183 million in the Balkan outstanding borrowings under the revolving credit facility and with the remainder going to general corporate proposes. On October 1st, 2012, in connection with the deal, our bank growth strong support for the company by increasing our borrowing base under our revolver to 250 million and extending the maturity date to October 1st, 2017. The revolver is subject to redetermination in March of 2013.
Additionally associated with the transaction, the company issued 325,000 shares of series A preferred stock with an initial liquidation preferred value of a $1,000 per share on a dividend rate of 8%. In the fourth quarter for GAAP per share calculations, we will have to assume that all of the prepared shares have been converted to common at the lowest conversion price of $11 per share, even though they are not convertible 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 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 as 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 borrowing availability under our revolving credit facility. We are confident that this capital structure together with future cash flows from us will provide us sufficient liquidity to fund our drilling and development programs at the end of 2013.
Total interest expense was 1 million for the third quarter flat with the second quarter and we capitalized 800,000 interest unproved properties during the third quarter. For the fourth quarter, we will have our 600 million and 10.75% notes outstanding for the fourth 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 a $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, are up current financial outlook is evident. We're 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 quarter ahead of us. Our primary focus now for the foreseeable future is execution of our drilling program and the integration of an Eagle assets and team in the mid states. We will continue to look at opportunities to acreage to our core areas and will 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 will be laser focused 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 of production for the full year of 2013 at 20,000 to 23,000 Boe per day, LOE at 550 to $7 per Boe and capital projected at $400 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 will be primarily focused on in-fill drilling in the heart of the play with one to two rigs used to convert acreage to HPP status and test the more unproven areas.
Our fourth quarter 2012 activity with horizontal test in Louisiana and the focus on in-fill 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 BOA fixed income conference in Miami, the Wells Fargo conference in New York and the Capital One South coast 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’re ready to take questions.
Thank you, John. Participants please limit your questions to one with the follow up and Jennifer, we’re ready to get started.
(Operator Instructions) your first question comes from Neil Dingmann with SunTrust.
Neil Dingmann - SunTrust
John first question, just wondering you read on 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 I guess as you look once you’ll see the success on those two you’ll have a better idea of kind of what you think the number of potential locations could be in those two fields or maybe just give us some color on kind of what your thoughts are once those all drilled out?
I guess first of all on we’ve given you kind of 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 the, we’ve got a horizontal in the Miocene that obviously worked beautifully. We’re now testing the Cockfield which for those of you that don’t know the Cockfield is a big producers across Louisiana for years and is now just being started to start testing horizontal concept in that place. So we think it has some very solid potential across the entire trend but obviously in the end what we’re looking for is, is to develop Wilcox targets because of the share thickness and the all 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’ll be doing some horizontal Wilcox wells at Bearhead as well as time go on. To kind of give you a guess of where that will end up, we’re trying not to do get too far out on our skis again this year so we’d like to go ahead and get some test in place see some real results over a number of months before we make any real car holes (ph).
Neil Dingmann - SunTrust
Great and then just one follow up just over on the horizontal miss, you mentioned I think around 7,400 current production in here November. obviously now with four rigs, I guess two questions around that, that field, one, your thoughts on the need for some seismic there and then number two if you are going to four rigs again not really asking for guidance yet for next year it’s a little pretty mature maybe for that but how was Eagle, remind us how many rigs they were running and all versus what you all have and if you expect any sort of issues there?
Yes Neil, Eagle ran three for a part of the year and were back to two for a little while then back up to three, so they tried to maintain kind of a three rig program. We had always planned to go to four to five for 2013 and we have 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 kind of firm turn from those up in January, does that give you a (inaudible)?
Your next question comes from Leo Mariani with RBC.
Leo Mariani - RBC
Hey, wanted to see if you all had a (inaudible) 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 thing, it’s still flowing up the frac-string. So, we really haven't even got it down to a level where I can really put some solid estimates for it. It certainly looks like its going to be significantly better than we've seen and certainly north of 300,000 Boe.
Leo Mariani - RBC
Okay in terms of you planning on in Louisiana in ‘13 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 at combination at 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 there. And then finally we've told you we have picked some awesome (inaudible) acreage that we’re working pretty hard as well so…
Leo Mariani - RBC
Okay. So I guess, would it be fair to assume that (inaudible) rigs are going to be drilling largely horizontal wells in 2013, how should we think about that?
There will be a combination but yes we are kind of moving to, given the success as we are seeing, we are kind of moving to horizontal approach certainly in the west side of the state. Obviously, when we go into test a new area like Fleetwood, the first wells are certainly going to be vertical and we’d like to confirm we have got some there and then make the decision on whether we go horizontal or not.
Your next question comes from (inaudible).
Just based on the early results of North Cowards Gully, can you talk how the original work locations maybe impacted by the additional 20 horizontal locations? Is there any cannibalism there?
Yes. You mean the vertical proved undeveloped locations we were to sync?
Yes. Look, yes, we intend to be able to join the reservoir with fewer horizontal wells than we would have taken these vertical wells in the field. So, that’s the only reason we would do this.
Okay. And then, just on a quick follow up there. The longer term pace and split between horizontal and vertical, is it just that 20 horizontal is completely displacing the verticals? 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 will 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 kind of like what proportion of the Oklahoma production was outlined in October?
We had a significant drop in October, we averaged about 5,800 Boe. Little over 1,000 Boe per day were off in October.
Your next question comes from Adam Lawlis with Simmons Company.
Adam Lawlis - Simmons & Co.
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 (inaudible)?
Yes probably. I think what we like about the Mississippi Lime is that we’re seeing solid rates of return and we’re seeing at lower capital investment on a per well basis. The wells it compete with that straight up on cost 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 is, the jury is still out but obviously if we can make some more wells like the North Coward's Gulley Well. It will compete with just about anything that's out there so. And certainly these little shallow Miocene wells don't have to make much to generate big rates of return.
Adam Lawlis - Simmons & Co.
Right and on your NGL hedges, what is the composition of your hedged NGL by the way?
It was mostly placed on propane around 50% of the hedge was on propane and then 25% butane and I think the other 25% was in natural gasoline.
Your next question comes from Brian Singer with Goldman Sachs.
Brian Singer - Goldman Sachs
You mentioned on your comments that Fleetwood, you could drill some wells there next year, and you're starting to get some of that 3D seismic back. Can you just add some more color on what's your scene there and what that can mean for that, how the reservoir that you could see compared to what you’re drilling today in Pine Prairie elsewhere.
Well Brian I think we talked a number to you about why we're over there, as a general rule, the side of the state, the Wilcox tends to 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 (inaudible) are as an analogy and that's actually the biggest Wilcox field in Louisiana so what you can get is thicker sediments with better ferocity which obviously can yield better results. so from the Wilcox standpoint we feel pretty comfortable that our people drilling horizontal Cockfield wells in the area as we speak and that’s an upside. We also have targets potentially at Spartan and ultimately I think we've told you told you that we wouldn’t want to do it today but we certainly have (inaudible) targets in the areas as well. so this is a very structured, you can see it very clearly on 2D seismic. we had a very good Wilcox target that we probably would have drilled by now had we not shot to 3D called (inaudible) and we put that off because obviously getting this 3D seismic we thought it was critical we look at first. We’ve already got a little bit, we got our first volume back and started to work on that so we’re feeling pretty good by getting some data but it’s probably going to be the first the year before we’re ready to start making some calls.
Brian Singer - Goldman Sachs
Okay, have you seen anything from the 3D seismic that would say confirms your thesis that you just alluded to?
No, we’re just starting to get a little bit of the data in so the geophysicists is hard at it, but it’s going to be several months of her working that before we can make any calls.
Brian Singer - Goldman Sachs
Okay thanks and then any acquisitions or expansion opportunities that you’re looking at here that you think could come to the forefront either in the two areas in which you’re focused other areas?
Say again Bob?
Brian Singer - Goldman Sachs
Are you pursing any acquisitions or do you see further acquisitions either in the Mississippi Lime in the Upper Gulf Coast (inaudible) or other?
Well, look we’re always looking and but now 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 rolling as hard as we can to make sure we’ve got that in line before kind of add anything else to it. One another point on seismic because I sorry somebody else asked about Oklahoma seismic, didn’t they? And I think Steve indicated in his call notes that we just agree 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 wellbores and that going to cover 300 sections, so it’s a big area, so we’re feeling pretty good by getting that information in, thank you.
Your next question comes from John (inaudible).
The answer to your question here is I’ve got rid of trees but not the storms. Anyway just some quick ones. on a going forward basis reporting could you have revenue differentials between Oklahoma and in 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 constant total but the volumes broke out.
And during the third quarter in the Wilcox you had more well treatment. So, were you running acid, did you have skin damage or whatever it may be and if so, going forward have you changed your well design, so you don’t incur this cost because I notice you are having lower guidance on the cost for that?
Yes, I think you are seeing chemical cost, you’ll recall the last couple of calls we've being trying to figure out some of the issues we are dealing with it at West Gordon and actually seeing some scale and paraffin build up, 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’s enhanced your recoveries?
Well it’s going to stop us from doing work overs as quick in. hopefully keep our rates coming on.
Okay. And then last one from me is on the Mississippi Lime, are you are still adding working interest to the individual wells you drilled beyond what your contract of interest is?
Yes John that’s a really good point. for some of you that we've talked on the road about, I mean, one of the things that happens in Oklahoma is they have force pulling 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 are showing somewhere in 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 out 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.
Your next question comes from (inaudible).
Good morning guys. Just a quick one from me John, on the Netherland sea 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 it?
Yes the practice at Eagle was a 3P report. we internally here at Midstates have been having NSAI 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 to this point, are you going to hold off till later?
Yes I think well at this point we are going to hold off, because we are kind of in a (inaudible) point right now, we’re actively right now preparing for yearend reserves. So, we’ll have the wholesome reports by year end on both asset areas.
But as you might guess, they were higher when you have the problem impossible, it makes big difference.
Your next comes from David Helen with Wells Fargo.
David Helen - Wells Fargo
John, can you just go back and remind me of the water infrastructure that you have Mississippi Lime to give her that water and where you guys sit there and if that’s a governed at all going forward.
Well, we don’t think so. We think we’re going to be able to stay with that quite well. we had a very unusual plan happen here. They had a lighting strike at their long (inaudible) salt water disposal facility. Eagle was taking position that that they would work with larger volume kind of centralize salt water disposal facilities and when lightning struck that tank battery we were down for about 60 days roughly, trying to get that battery backup. so again we try to reroute to other batteries but that certainly affected this and the other issue we dealt with is we have some injection wells in our (inaudible) county acreage that didn’t pass what we probably integrity test, so we had to go and make some tubing change outs. but nothing significant, we don’t really anticipate that being a problem going forward.
David Helen - Wells Fargo
Okay. And what about NGLs processing. Where do you guys stand on that as far as getting those NGLs? I mean where do those end up getting priced?
Yes, we’re in discussions with Sim Gas as we’ve stated all of the Oklahoma acreage is dedicated to Sim Gas. So, we’re in the process of working a contract for a bigger plant and those discussions are ongoing. We expect those to finalize soon.
David Helen - Wells Fargo
Alright. And one more question John, And I don't know if this the appropriate form to ask but you’ve answered some good questions on it. I’ll throw it out. First reserve, obviously still big chunk of the company. Can you talk about; I think investors have seen private equity firms get out of other (inaudible) investment. Can you talk at all about…?
I guess, I’m 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’re not going to see First Reserve leaving in time soon. they had a hard time selling at our IPL 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 fall into those shares. so I would leave you to talk to Alex (inaudible) or someone like that about their real feelings on it but I don’t anticipate any selling by first reserve.
Your next question comes from Ron Mill with Johnson Rice.
Ron Mill - Johnson Rice
Morning John, just on the Mississippi 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 cost down to where other people in the industry it was a document cost those were little (inaudible) and the ability to accelerate a rig release to first production type numbers and the impact that has on you?
Yes thank you, that’s an excellent point, look Eagle has done just like many of the other players in the Mississippi Lime, they've been trying to covert acreage to HPP status and by definition I mean to grow a well in every section. so it kind of and obviously spread out your operations and is certainly not the way to make things achieve this. 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 kind of three rigs running in the core of the activity where we have kind of outsized results but just as importantly, we've got pipeline infrastructure in place, we've got power infrastructure in place, and we got salt water disposal infrastructure in place. So, that should allow us to bring down the time of the first production dramatically and it’s not a real surprise, I think everybody goes through this as you are putting in your initial infrastructure; you got away for pipelines to come to you, you got to build your water disposal facilities, you got to build your power facilities. Once we start the in-fill program we should be able to cut those numbers pretty dramatically and we would certainly expect to get our numbers down from kind of high threes to the low threes and potentially below that.
Okay good and in Louisiana if you look at the horizontal program in North Cowards Gully versus West Gordon versus you know as you evaluate the other areas especially at North Cowards Gully, what do you think is driving the outperformance, is it something geologic and 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, there are reasons to expect some variability?
We can map this Wilcox (B) sand across entire structure that 20 and I can tell you it’s actually a few more than 20 locations, that the geologists have shown us, are capable of putting in there is to low us known oil, we really haven’t defined how low that could go so there is 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’s evidenced by we make very little water in this field, so this 88H well we’re talking about make less than a 100 barrels of water a day actually close to 50-60 barrels a day, so it is a little different count I guess and we hope we could find some more just like it.
Your next question comes from Todd Firestone with Morgan Stanley.
Todd Firestone - Morgan Stanley
I have just a quick question on maybe you could drive a little color on Mississippian Lime results that you’ve seen, maybe some color on flow rates and maybe you’ve seen a bit variability and looking at it annualized decline how you’re extrapolating the curve going forward from your data you’ve seen over the last few months?
Well, there is certainly variability on a well-to-well basis. There is not any question about that and I think you’re 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 kind of reduce that variability by concentrating within the core. We still see some variability that we would expect less. I guess the one statistic in a week, I guess I haven't updated it recently that I like to point is that Eagle’s last 30 wells at averaged over 600 Boe per day as an IP and that puts in pretty strong area for making the numbers work. We do have some solid support for high B factors. We think we can back up kind of one and half B factors pretty easily and maybe as much as two in some cases.
Todd Firestone - Morgan Stanley
One other question, maybe you could provide a little bit what you see, how you’ve evolved in your, if you got high (inaudible) in your across Louisiana acreage, how that might evolve, how you might think about recovery rates look going in to looking at Fleetwood, that might be helpful? I am saying your knowledge may have evolved on recovery rates for Fleetwood based on your experience in 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's interesting as you moved to the east side of state is you tend to get a little better process and from your abilities and that will help in the horizontal sense as well as in the vertical sense. so one of the things we’re 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.
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.
That concludes today’s conference call. You may now disconnect.
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