May 10, 2013
Executives
Fred L. Callon - Chairman, Chief Executive Officer, President, Chief Executive Officer of Callon Petroleum Operating Company and President of Callon Petroleum Operating Company Joseph C.
Gatto - Senior Vice President of Corporate Finance Gary A. Newberry - Senior Vice President of Operations Bobby F.
Weatherly - Chief Financial Officer, Executive Vice President, Corporate Secretary and Director
Analysts
Will Green - Stephens Inc., Research Division Joseph Bachmann - Howard Weil Incorporated, Research Division Hsulin Peng - Robert W. Baird & Co.
Incorporated, Research Division Stephen F. Berman - Canaccord Genuity, Research Division Richard M.
Tullis - Capital One Southcoast, Inc., Research Division Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division Jeffrey Connolly - Brean Capital LLC, Research Division Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Operator
Good morning and welcome to the Callon Petroleum First Quarter 2013 Conference Call. [Operator Instructions] Please note this event is being recorded.
I would now like to turn the conference over to Fred Callon. Please go ahead.
Fred L. Callon
Thank you and good morning. Thank you for taking time to call in to our first quarter conference call.
Before we begin, I'd like to ask that Joe Gatto, our Senior Vice President of Corporate Finance, to make a few comments.
Joseph C. Gatto
Thanks, Fred. We'd like to remind everyone that this conference call contains forward-looking statements, which may include statements regarding our reserves, as well as statements including the words believe, expect, plan and words of similar meaning.
These projections and statements reflect the company's current views with respect to future events and financial performance. Actual results could differ materially from those projected as a result of certain factors.
Some of these factors are discussed in our filings with the Securities and Exchange Commission, including our annual reports on Form 10-K, available on our website or the SEC's website at sec.gov. We may also discuss non-GAAP financial measures, such as discretionary cash flow, PV-10 measure and adjusted net income.
Reconciliation and calculation schedules for such non-GAAP financial measures are available on our first quarter 2013 results news release and our filings with the SEC. These documents are available on our website for review.
Fred?
Fred L. Callon
Thanks, Joe. Although it's been less than 60 days since our last call and operations update, I think we've made significant strides in executing our Permian plans.
I'd like to highlight a few of those before I turn the call over to Gary Newberry. The core of our 2013 operational plan is focused on capital efficiency program development in the Southern Midland Basin.
Since January 1, we've completed drilling 5 additional horizontal Wolfcamp wells as we've achieved significant reductions in drilling days per well. We've also completed 2 wells with 3 additional completions on track to be completed in the next 45 days.
This pace of completion will continue to increase as the year progresses, with final implementation of important infrastructure initiatives starting last year. In parallel with the Southern Midland activity, we continued to advance plans for horizontal drilling in the Midland County, as well as additional valuation work on our Northern Midland County acreage.
We expect these initiatives to take place later in 2013. Finally, we recently announced that we're changing our financial advisor for marketing brand interest in the Medusa field and spar production facility.
Our Medusa is a very attractive asset with numerous additional re-completes and some new drill opportunities to be pursued. We believe our current Permian portfolio provides us with a strong operational platform to essentially complete our transition to a pure-play onshore operator.
Now I'll turn the call over to Gary Newberry for an update on operations and a review of our recent well results.
Gary A. Newberry
Thank you, Fred, and good morning. As Fred mentioned, the Southern Midland Basin is our key focus area for our 2013 horizontal development.
Since our last update, we have completed 2 additional horizontal wells at our East Bloxom field. The latest test on the Neal 343H well produced over 1,000 barrels of oil equivalent per day while continuing to clean up.
The Neal 342H, the second well on the 3-well pad, is currently in the process of drilling out the plugs following a 25-stage fracture stimulation, and we expect to bring that well online in the next few days. Both of these wells were completed in the Wolfcamp B interval.
The third well on the pad, Neal 341H, has been drilled in the Wolfcamp A interval and will be completed in July. In support of our efficiency initiatives, during the final construction stages of a produced water recycle pit and related infrastructure at East Bloxom.
Upon completion, we will be positioned to accelerate the completion of wells using batch completions. This will not only result in cost savings and a pull forward of production, but also reduce the need to shut in horizontal wells that are producing on the same pad, as the well is being fracture-stimulated.
Moving east from Upton County to Southern Reagan County is our Taylor Draw field, where we have recently drilled wells targeting the upper and lower Wolfcamp B shales. The Pembrook 9121H well had an IP of 500 barrels of oil equivalent per day from a lateral length of just over 5,000 feet, while it continues to perform similar to nearby wells to the northwest, which have produced results that support estimated EURs in the range of 300,000 to 400,000 barrels of oil equivalent.
In addition, we have drilled 3 wells and are currently drilling the lateral section of the fourth well on the same pad at Taylor Draw, all with lateral lengths in excess of 5,000 feet. Two of these Taylor Draw wells that have been drilled, including a lower Wolfcamp B target, are scheduled to be fracture stimulated later this month.
The remaining 2 wells will be completed in the third quarter. Once our horizontal rig has completed the fourth well in the next few days, we will return to the East Bloxom field and the next 3-well pad.
Turning to the Central Midland Basin. Pecan Acres and Carpe Diem are a focus of our 2013 vertical drilling program.
We have drilled and completed 1 well at Pecan Acres, and we are currently drilling the second well. We've also recompleted the Pecan Acres 23-3 well uphole through the difficult Wolfberry intervals, combining those intervals with the deeper horizons down to the Woodford formation that were previously completed as part of an isolated deep test.
These wells continued to perform at or above our 150,000 barrels of oil equivalent type curve. We continue to monitor recent results of horizontal wells targeting the Wolfcamp B near our Carpe Diem field and are in the early stages of planning for horizontal development at Carpe Diem.
This activity has de-risked both Carpe Diem and Pecan Acres for horizontal development, adding 30 locations to our horizontal inventory from the Wolfcamp B interval. The Northern Midland area, the Shirly Newton 2301 #1H was drilled in the Mississippian formation with a lateral length of 4,107 feet, was fracture stimulated with 14 stages in January 2013.
The flowback was delayed due to stuck coiled tubing during the drill-out of the plugs. The well had a 24-hour peak oil rate of 136 barrels of oil per day with 2,000 barrels of water per day.
The oil rig quickly declined and stabilized at a rate of 10 to 15 barrels of oil per day while maintaining high water production. We recently set a mechanical plug in the lateral section of the wellbore to isolate the water production.
Currently, we are monitoring 4 fracture stimulation stages that are producing near the heel of the wellbore. We're planning to drill a vertical well later this year to further test the Mississippian potential on our Borden County acreage.
Our petrophysical analysis suggest there's a large in-place resource across this acreage position. Also in Borden County, our vertical science well, the Shirly Newton 4801, is in the process of being recompleted to test several prospective zones in the Wolfcamp, Spraberry and Clearfork formations.
In summary, we are on pace to achieve the cost efficiencies and production growth detailed in our last call. We expect to grow production by approximately 65% from the fourth quarter of 2012 to the fourth quarter of 2013 and exit the year at 3,000 barrels of oil equivalent per day.
This type of growth would deliver 15% top line growth for the entire company and more than replace the normal declines from our remaining offshore asset base. I will now turn the call over to Bob Weatherly, our Executive Vice President and CFO.
Bobby F. Weatherly
Thank you, Gary. For the quarter ended March 31, 2013, the company reported net loss of $0.02 per share.
After adjusting for the negative impact of mark-to-market derivative positions, net income after tax was essentially breakeven for the quarter. In addition, Callon generated discretionary cash flow, which is a non-GAAP measure, of $0.28 per share.
Operating revenue for the 3 months ended March 31, 2013, include oil and natural gas sales of $22.5 million on average production of 3,644 barrel equivalent per day. Crude oil revenues decreased 24% to $19.5 million for the 3 months ended December 31, 2013, compared to revenues of $25.7 million for the same period of 2012.
Contributing to the decrease in crude oil revenue was an 11% decrease in commodity price. This was compounded by a 15% decrease in production.
The decrease in production was primarily attributable to the sale of our Habanero Field in the fourth quarter of 2012, which produced 33,000 barrels during the first quarter of 2012. Partially offsetting the impact of this sale and other natural declines in our Gulf of Mexico and other properties was a 23,000-barrel increase in production from producing wells on our Permian properties.
The average price realized decreased to $94.85 per barrel compared to $106.84 for the same period of 2012. Included in this per-barrel price decrease was a temporary increase in the Permian oil discount differential in January and February of 2013 due to a refinery outage in the area.
This issue has now been resolved, and Midland differentials have recently been averaging less than $0.50 per barrel discount to WTI. Natural gas revenue of $3 million decreased 15% during the 3 months ended March 31, as compared to natural gas revenues of $3.5 million for the same period in 2012.
The decline primarily relates to an 18% decrease in natural gas production, once again primarily attributable to the sale of our Deepwater Habanero field in the fourth quarter of 2012, which produced 54 million cubic feet of natural gas during the first quarter of 2012, as well as other and expected declines in our Gulf of Mexico properties. These production decreases were partially offset by a 14 million cubic feet increase in natural gas production from our Haynesville well, which was shut down for 70 days during the first quarter of 2012, and a 30 million cubic feet increase in natural gas production in the Permian.
We experienced a 4% increase in the average price realized, which rose to $4.07 per 1,000 cubic feet of natural gas in the first quarter of 2013 from $3.92 per Mcf in the first quarter of 2012. Due to the value of the NGLs in our natural gas stream from our Permian Basin and offshore production, natural gas pricing realized a 17% uplift over benchmark NYMEX pricing for the first quarter.
On an overall basis, we received $68.72 per BOE of production in the first quarter of 2013, a decrease when compared to 2012 but 2% over benchmark pricing for the same commodity production profile priced at benchmark levels. On the expense side, we were within or below guidance on all of our key financial measures, resulting in a total reduction of $5 million in operating expenses as compared to the first quarter of 2012.
This reduction came primarily from a reduction in workover cost and expense G&A. As discussed in our March conference call, we have set a capital budget of $125 million for 2013.
In the normal course, we will be revisiting that plan with our board at midyear after reviewing the growth opportunities we have in front of us. While we continue to believe our initial capital budget can be funded in its entirety with cash flow from operations, in borrowings under our credit facility, a meaningful increase in our capital budget for the second half of 2013 to require additional capital to ensure an adequate cushion of liquidity this year and beyond.
To this end, we continue to consider plans for potential financing and will be providing an update prior to our next earnings call. We'll now take a minute to discuss guidance for the second quarter and full year 2013, which was detailed in a separate press release last night and is posted on our website in the Investors section.
We project total production for the second quarter to be 3,400 to 3,600 per day, with Permian volumes comprising 1,700 to 1,900 BOE per day. Included in these figures are 2 important factors that impact the second quarter: first, the Medusa field is anticipated to be shut in for the month of June for downstream pipeline repairs; second, for safety reasons, we continue to plan to shut in horizontal-producing wells while other wells are being completed from the same pad.
This practice, which defers production, will be reduced over the next few months as we finalize our capabilities to complete 3 to 4 wells simultaneously in batch completions. We are reaffirming our guidance for the full year 2013 to be 3,800 to 4,200 BOE per day with oil accounting for approximately 65% of these volumes.
The Permian is forecasted to be 2,000 to 2,300 BOE per day for the full year. As Gary discussed, we are targeting a fourth quarter 2013 exit rate of 3,000 BOE per day for our Permian operations.
On the expense side, our second quarter guidance is in line with our first quarter actual performance with the exception of these operating expenses, which in the second quarter includes approximately $1 million for routine facility maintenance at our Medusa field while the field is shut in for these downstream pipeline repairs. I'll now turn the call back to Fred for final comments.
Fred L. Callon
Thank you, Bob. That will open the call for questions.
Operator
[Operator Instructions] Our first question comes today from Will Green with Stephens.
Will Green - Stephens Inc., Research Division
I wonder if we could start on that third Neal well you guys talked about. How much of the frac load have you guys recovered so far on that, and how has the well held up since that test rate?
Gary A. Newberry
Yes, Will, as Bob mentioned in his discussion there, we've actually, for safety reasons, shut those wells in while we're frac-ing a second well. So that well flowed for about 15 days, and the important thing about that well is it went to oil pretty quick and ramped up in oil pretty quick too.
So it quickly went to right at 1,000 barrels of oil equivalent per day, and most of that being oil, with still pretty high water rates, and so we've only recovered about 10% to 12% of the load on that well with that type of performance prior to actually shutting it in to do the fracture stimulation for the 342H, and we'll bring that well back on once we drill out the plugs on the 342H this week.
Will Green - Stephens Inc., Research Division
Got you. Sorry for missing that.
And leasing efforts in the play, how is that going? Are there still packages to add and to core up there?
Fred L. Callon
Well, I think there are opportunities, and we continue to evaluate and look at opportunities. As we've mentioned before, I think there are particularly some -- perhaps some smaller bolt-on type opportunities that we think that we can find that will continue to add to our position out here, as well as we continue to look at opportunities for larger transactions, so I'd say there aren't as many maybe larger packages out that right off the nose go through a fairly competitive bid process anyway, but I do think there are a number of smaller opportunities out there.
We continue to evaluate and actually have several offers out on, again, on smaller-type opportunities, and hopefully we'll execute on some of those here in the next few months.
Operator
Our next question comes from Jeb Bachmann with Howard Weil.
Joseph Bachmann - Howard Weil Incorporated, Research Division
I had a couple of quick questions. First, looking in the Permian.
Gary, looking at the lateral lengths, I know they're around 7,000 feet in East Bloxom but only around 5,000, 5,500, and I guess your most recent one is 6,000 in Taylor Draw. Is that because of the lease lines there, or are you guys slowly working your way up to the longer laterals?
Gary A. Newberry
No, Jeff. That's entirely driven by our leasehold position there.
On the east side of Taylor Draw, we have 2 sections long. So we kind of thought at one time we would potentially drill some 10,000-foot wells, but we actually got to looking at our own experience with losing long laterals, as well as other competitors in the area, and we thought that it was probably best to just shoot for the just slightly over 5,000-foot lateral lengths in those wells for that 2-section area to the length pie in the east side of that Taylor Draw.
On the west side of the Taylor Draw, we have a section and a half high so we'll -- on the west side of that, once we get to developing that side, we'll be going back to the 7,500-foot laterals.
Joseph Bachmann - Howard Weil Incorporated, Research Division
Okay, great. And then I guess, Bob, this is probably a question for you.
On the firm -- do you guys have any firm transport out of the Permian to kind of realize some of the benefit of the Magellan lines coming online and taking crude over to the Gulf Coast basin?
Bobby F. Weatherly
Not yet, but obviously, we continue to look at that, Jeb.
Joseph Bachmann - Howard Weil Incorporated, Research Division
Okay, so you're basically just trading, I guess, in line with WTI, like you said, maybe a little bit below now. But that...
Bobby F. Weatherly
Yes.
Joseph Bachmann - Howard Weil Incorporated, Research Division
Okay. And then last one for me, on Medusa.
Does Murphy have pref rights on that asset, and have they indicated any interest in acquiring your interest?
Fred L. Callon
Yes, they do have pref rights. And I don't know what their position will be, but they certainly do have a pref right.
Joseph Bachmann - Howard Weil Incorporated, Research Division
And Fred, would you use proceeds from that to possibly accelerate the Permian program or basically to help fund the remainder of the program for this year?
Fred L. Callon
Certainly, Medusa would be an opportunity to accelerate the program through some of our organic growth, as well as some acquisition opportunities, and I'll look at that sort of as a final step in transitioning onshore. So yes, we look for that to give us the opportunity to accelerate what we're doing in the Permian.
Gary A. Newberry
Jeff, if I could -- it's Gary, but if I could just add one thing on the Medusa side. The other company that's part of that Medusa asset is ENI.
I can tell you, at least from all of our partner meetings, both Medusa and ENI are pretty excited about the new wells that are coming up in 2014. So there's a lot of interest in that asset, so it'll be interesting to see how they react to this marketing opportunity.
Operator
Next question comes from Hsulin Peng with Robert Baird.
Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division
So a follow-up on the Medusa question. Can you give us a timing of your marketing process, and when you would think when you expect to have indications of interest, too?
Fred L. Callon
Yes, Hsulin, I think the marketing process is -- it's going to take some time. I think we've been talking for the better part of last year about the quality of the asset, and we think that Medusa is a unique opportunity for someone.
So as a result, we're going to take our time and do a broad marketing process that will probably include some international potential buyers, so as a result, I think we're going to take our time, and we don't have a definitive time schedule as of now. Certainly, we hope we can -- to get something done this year, and to the extent we get it done sooner, that would be great, but at this point, we don't have a definitive bid date.
Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division
Okay. And then switch over to Central Midlands, you have talked about looking at a potential horizontal development on Carpe Diem and Pecan Acres.
I was just wondering if you can give us more color there. It sounds like there's a potential for you to accelerate activities there, and does that depend on additional, I guess, financing or the Medusa monetization?
Gary A. Newberry
Yes, Hsulin, this is Gary. Yes, We're really excited about the -- at least the well rates and the well results that we're seeing coming out of there from RSP and Diamondback.
That seems to be performing quite well, and we think there's really good potential at both of those areas for horizontal development. And as we mentioned on our last call, the budget that we've sent out for you is really very much focused on our Southern Midland Basin.
We want to get very good at what we do, and so we're certainly planning for acceleration there once we see kind of how this marketing opportunity comes up or potentially other forms of financing. So we're looking for ways to accelerate.
Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division
Okay. So then if I hear -- if I understand Bob correctly, so you guys are reviewing your CapEx budget in midyear, and given the time, the Medusa is not -- may not be there by midyear.
Are you thinking additional financing activities in addition to Medusa monetization?
Bobby F. Weatherly
Hsulin, I think we -- what I've tried to say is that we normally -- our directors like to see, certainly by the time of our August board meeting, an analysis of kind of how we executed in the first half of the year. We do that every year.
We'll do it this year. And I think what I was trying to indicate was that we will continue that this year, and as Gary's pointed out, some of the encouraging results around some of our Central Midland acreage, certainly with the excellent results that Gary is producing in the south, we'll look at it, see where the market is, see what our financing alternatives are and, at that time, may make a decision to move ahead.
Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division
Okay, understood. And then last question, just regarding the Miss well in Borden County, just wanted to see how -- what have you been able to learn from the nearby producers?
I believe SM is nearby. Just kind of trying to understand what you plan to do there with additional tests?
Gary A. Newberry
Yes, Hsulin, just to give you a little bit more detail around how that -- the well that we have was stimulated, it was 14 stages, and as we drilled that well, we actually went deeper in the Miss zone as we went further out in the lateral. And we were really encouraged with that really first couple of days of production, and then all of a sudden, it went to water, primarily.
And so we're -- think whether or not we may have frac-ed into some water -- blatant water in the Miss and some water in the deeper Ellenberger zone, and so we're a little unsure that -- about where that water's coming from. So in an attempt to check or test just the upper part of the Mississippian formation, we actually set a plug and isolated the lower part of that lateral.
Now what that means is we actually moved uphole in the Mississippian section about 20 feet. It's only about 20 feet higher, where we're producing now.
And right now, it's still a good bit of water with more oil, but still dominated by water, and hopefully that will pump off and we will see some more encouraging results. It's still too early to tell yet, and then if this kind of works part way, we'll recomplete even a little higher.
Because it looks like there's oil in the system and there's oil high in the system, and we've got to figure out a way to get access to that resource without producing so much water. So that's why we would then go in next time we go up to Borden County and actually drill a vertical test well to where we can then very -- test the interval in the vertical well at various levels and be very distinct about how that performs so that we can learn more about how we then implement a horizontal program for capturing that resource.
Operator
Our next question comes from Steve Berman with Canaccord Genuity.
Stephen F. Berman - Canaccord Genuity, Research Division
Gary, the Pembrook well at Taylor Draw, the IP rate was 98% oil, the 30-day rate, 81% oil. Was that in line with your expectations?
Or maybe asked a different way, the 300,000 to 400,000 BOE EUR, what's the assumed breakdown of that between oil, gas and NGLs?
Gary A. Newberry
Oh, man. I would say it's going to be 85% oil or liquids, Steve, but yes, we're looking in total, we -- that's a good well.
That's what we would call that. That's a pretty good average well.
We're going to get a good return on that well. We're happy with it.
Which -- it doesn't have a flashy IP, like we like to talk about. That's why we're anxious to see what the other wells that we've drilled there do in the next couple of months.
We're in a very good neighborhood. There's good wells to the north, to the west and to the south.
Then it gets some distance to the east, but we're still very, very excited about the potential there. But the well did get a little more gassy as it went further out, and so we'll have to see.
I mean, there's going to be -- the way I think about these things, Steve, is I think about the horizontal development very similar to the way I think about vertical development. It's going to be variable.
All wells aren't going to be the same, and you're going to have some really high IPs and really high-performing wells in and around areas that have average IPs or average-performing wells, and at the end of the day, the whole program is going to be a very nice return.
Stephen F. Berman - Canaccord Genuity, Research Division
And the $6 million to $7 million horizontal well cost you cite in the press release, how would you breakout an East Bloxom well, which seems to have a longer lateral and maybe some bigger rates, versus a Taylor Draw well? I assume that one's going to be higher and one's lower off that $6 million to $7 million number.
Fred L. Callon
You're absolutely right. We're at or just below $6 million at Taylor Draw, and we're at or below just $7 million at East Bloxom.
East Bloxom's a little deeper, as well as we have to run a little bit deeper intermediate casing and stripping there, and of course we run longer laterals there, and so we have a higher completion component for our cost. But those costs are coming in pretty well, just the way we forecast them, and I think they're pretty competitive with what other companies are doing.
And hopefully, as we continue to learn, we'll continue to get more efficient, especially once we get our recycle pit in. And then we can actually start recycling produced water, eliminate some disposal costs and actually accelerate the pace of our development.
Stephen F. Berman - Canaccord Genuity, Research Division
Okay, and then one more. The Neal 343H shorter lateral and the first 2 higher rated, did you do anything different in the completion of that well versus the first 2 Neal wells?
Gary A. Newberry
We did. Again, just to refresh your memory, the first Neal well was a slickwater frac, about 200,000 pounds of sand per stage.
The second Neal well was a linear gel frac, about 250,000 pounds of sand per stage. This Neal well was a slickwater frac, again, and we pumped about 250,000 pounds per stage, so we kind of combined the 2 previous wells into what we felt to be a more optimal completion, and it looks like it's working pretty well.
Operator
Our next question comes from Richard Tullis with Capital One Southcoast.
Richard M. Tullis - Capital One Southcoast, Inc., Research Division
Gary, do you know roughly what EBITDA the Medusa throws off on an annualized basis?
Gary A. Newberry
Bob, do you have that number?
Bobby F. Weatherly
I think it's around 20.
Richard M. Tullis - Capital One Southcoast, Inc., Research Division
Around $20 million?
Bobby F. Weatherly
Yes.
Richard M. Tullis - Capital One Southcoast, Inc., Research Division
Okay. And with the -- looking at the debt metrics, Bob, there'll -- debt-to-EBITDA, debt-to-cap, I guess, will continue to tick up this year with the outspend, assuming no sale at Medusa.
With the -- what level are you comfortable with on a longer-term basis? Which would be your -- some of your target debt goals?
Bobby F. Weatherly
I think we'd like to see debt-to-cap come down a little bit from where we are over the longer term. I think you've obviously got -- we've seen, with our increase in our borrowing base, from a cost standpoint, we're able to bring down our cost with the cost of the borrowing base, but clearly, we're going to go through a period of financing here that we will then overcome as production catches back up and we bring those down over the longer term.
Richard M. Tullis - Capital One Southcoast, Inc., Research Division
Okay. Assuming Medusa sells, say this year, would you guys just look to sell rest of your Gulf, including the shelf, and just exit altogether?
Fred L. Callon
Yes, I think certainly that's what we would like to do. I think the shelf is continuing to produce, as I mentioned.
It's really been more there just hasn't been a good market, and it's just made a lot more sense to continue to produce it. And that, certainly, that well's been hanging in there very well.
So if we don't get the like price, we'll at least get an acceptable price. And we may continue to produce them out, but certainly, we've seen the Gulf pick up in terms of interest in the Gulf, and particularly in the Deepwater areas, so we're hopeful that we're going to get to a price with Medusa.
Richard M. Tullis - Capital One Southcoast, Inc., Research Division
Okay. And then just lastly, Gary, if you could just roughly recap planned horizontal wells for the rest of this year by area and target zone.
Gary A. Newberry
Sure. We're finishing up the fourth well on the 4-well pad in the Taylor Draw now, and we'll be finished with it this week, actually, or middle of next week.
And that will be an inventory there of 4 wells all drilled in the Wolfcamp B interval. One of those wells was drilled about 300 feet deeper in the interval to test what we think was a very good result from a nearby Pioneer well.
So that's that, and still waiting to be completed is the Wolfcamp A well over at Bloxom. That is still on the same pad that we're completing the current wells on, and that will be in a couple of months, and that will help -- the recycle pit helps us move that along.
So when we go back to Bloxom, we'll drill 3 wells, and all 3 of those wells, pending the result of this Wolfcamp A test, will likely be focused on the Wolfcamp B. And then after we finish those 3 wells, which will be likely sometime late July, August timeframe, we'll go back to Taylor Draw and we'll drill 3 more wells.
And at that point in time, we'll likely be on the west side of Taylor Draw to drill the 7,500 foot wells. Then once we finish that, we'll go right back to Bloxom, but then we're getting closer to the end of the year.
I think we told you at our original call we would drill 15 and complete 14, and we're well on-track to do that or possibly even a little bit more.
Operator
Next question is from Ron Mills with Johnson Rice.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
A lot has been covered. A couple of questions, though.
On the Mississippian Lime well up in Borden County, have you guys been able to swap notes with SM or anyone else who's drilled wells? Did they encounter similar problems?
They've obviously -- it looked like they've figured out where the water was coming from and at least how to mitigate their risk. You were -- where are you in that learning curve from a conversation standpoint, in addition to trying to -- the vertical wells to test for the optimal lateral placement?
Gary A. Newberry
Yes, Ron, we've spent a good bit of time with them since we've drilled our well. It was a bit difficult to get some information before we drilled it, but once we were in the play, they've opened up quite a bit in how they go about drilling the wells and how they go about completing the wells, and I think that will be helpful to us over time.
The real issue is the vertical section. They're over in an area that's actually an area that is a known place for producing some vertical wells, so they have a specific trap there for the oil.
We have a large acreage position. We likely have a very similar trap, and so that's what we would be looking for from, at least, the way we're going to prospect our next well with some similar seismic attributes that we think that they're using, to really establish that high part of the structure production from the vertical well and then go in and use that information to ideally position our lateral, which is what they're doing.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
And when you look at your acreage position up there, I don't know if the Lynn County is also a Mississippian Lime perspective like the western 2/3 of your Borden County acreage. But if you look at it on the data that you have available right now, which I assume is 2D, does it look similar in terms of attributes to what you were just discussing in terms of what they are targeting?
Fred L. Callon
We believe so. Not all of it, Ron.
I think we've been pretty clear that not all of this acreage is probably prospective for the Mississippian Lime, but a good part of it is. I think we've reported, in our first quarter update, at least what we felt to be prospective would likely add about 72 horizontal wells in the Mississippian Lime across that acreage position, which is a pretty significant opportunity for us.
And that's just in the Borden County acreage. And if I get that number wrong, just look back on the slides that we provided to end the quarter.
So that's pretty significant for us, and then the Lynn County acreage, we would expect, would likely have some of the same potential.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
Has there been any Mississippian Lime up in Lynn County?
Fred L. Callon
Not that I'm aware of, but it's not that far away from where we're at, and it's -- again, we're at St. Mary's.
There's just not all that distance. So we'll see what happens when we go up into Lynn County.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
Okay. And then you've talked about 300,000 to 400,000 barrels for the Taylor Draw EURs.
Where do you think the East Bloxom EURs are now, and what do you think the commodity split is?
Gary A. Newberry
Well, we think East Bloxom's clearly still above 400,000. We think we're still around 430,000, is kind of generally what we're seeing around the average of our 2 completed wells that have the longer history, if not higher.
This well that we just completed is performing better than any of those 2 in the early life of it. So that's encouraging.
I would suggest we're still at 85% liquids at East Bloxom.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
And then I know you've talked about 3-well pads at Bloxom and Taylor Draw, and going back to Bloxom. But also, with the RSP and Diamondback activity up at Carpe Diem and Pecan Acres area, is -- even exclusive of accelerating a program, would there -- could there be a thought, at least, of taking the rig up to the Central Midland Basin for a well, or are you pretty set on wanting to do the 3-well pads?
And if you test Carpe Diem, it will be either later this year or next year?
Gary A. Newberry
Ron, I've got my team totally focused on being very efficient with what we do. We dragged that rigger across the basin last year, and it's a great rig.
It's a great opportunity for us to actually be very efficient. I don't know if we've posted it yet, but we've actually got a video that I think we will post out on our website that shows how quickly that rig walks, and we can move from well to well in now less than about 13 hours.
It's -- and to use that rig the way it was built and for the purpose of it, I would like to do that this year. Now I'm very confident with the results that RSP has, as well as the results that Diamondback has and the new wells that I know are coming.
Diamondback is going to drill a well immediately to the east of our Carpe Diem acreage, and RSP is going to drill a well one location only over the southwest of our Carpe Diem location. So then we would be surrounded by 4 high-performing wells.
That has clearly de-risked that area. I am very confident that's going to work.
I don't want to get distracted right now and take this rig up and drill a few wells in that area and then take it all the way back to Bloxom. I'd like to be able to grow PDP reserves, grow production and really demonstrate what we can do in a development mode, not only to you guys but to my team, because I think we can get even better.
So I think Carpe Diem, in my mind, is later in the year or early next year.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
And I know a lot of the activity's been right more around Carpe Diem, but if you -- distance-wise, it has a little smaller position but fairly blocky. Has there been much going on around Pecan Acres, or has it more been centralized around Carpe Diem?
Gary A. Newberry
It's all around Carpe Diem for now, all of the horizontal development, but recall, Pecan Acres is inside the city limits of Midland, that we own the surface, a good bit of the surface at Pecan Acres. We are actually in discussions with RSP on how we partner because we would prefer to drill longer laterals.
And RSP has the acreage to the south, but they have difficulty getting access too simply because it's in the city limits. So I think ultimately, I'd like to be able to partner with them to be able to actually jointly develop the couple of sections together, and I think that will come together over time.
Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division
Okay. And then lastly, just on the cost side, you all have done a great job of getting down to the $6 million to $7 million range, especially with the new service contracts.
Have you already cut a lot of meat off of that bone, or do you think there's still a little bit more to get rid of on the cost side?
Gary A. Newberry
Well, we took a big chunk of it off, but unfortunately, as you know, Ron, it takes a bit of time to get very efficient with a new partnership. So I think we're getting better on every well, but we're mostly there.
I'm real happy with the way it's performing. We're continuing to talk about how we always get better.
I mean, these next 2 wells at Taylor Draw, we just had a long, lengthy discussion with our Weatherford partner, both in the frac services as well as the wireline services, about doing the zipper frac technique on the 2 wells together to where you're frac-ing online while you're wirelining on the other, and it just compresses the timeframe even further. They've been doing it on a regular basis for Devon, and that's what we're going to do.
So I think there's more to get.
Operator
Our next question comes from Jeffrey Connolly with Brean Capital.
Jeffrey Connolly - Brean Capital LLC, Research Division
In Taylor Draw, what do you guys expect from that lower Wolfcamp B well? And how will that be spaced relative to the 2 other Wolfcamp B wells?
Gary A. Newberry
Again, until we actually get a result, we'd expect the same type of performance, but the reason we're drilling it is because Pioneer actually had a really good well up to the north and west of us that was drilled at that same structural elevation in the zone at, again, another -- it looks like an organic-rich area within that Wolfcamp B section. So again, we're targeting about 380 MBoe for those 5,000-foot wells, and it would be closer to 400 for the 7500-foot wells.
So that's kind of where we are until we see it.
Jeffrey Connolly - Brean Capital LLC, Research Division
All right, and then can you just comment a little bit on the spacing?
Gary A. Newberry
Well, spacing is the -- we have not really modified the spacing yet. We're still 6 wells a section so far.
So 6 wells horizontally across the section. So we're about 800 feet apart and last -- I guess I haven't done that calculation yet, but I think that's about 110 acres per well, but I don't remember.
Operator
In the interest of time, we have time for just one more question, and that question comes from Ryan Oatman with SunTrust.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Does Medusa's scheduled maintenance just -- very quickly, can you remind us on the oil versus gas split of that asset? And then can you talk about when you expect that to return?
Fred L. Callon
Yes, Medusa's really an oil asset in the deepwater Gulf of Mexico. I think we're 85% oil on Medusa, but Bob or Fred, correct me if I'm wrong on that number.
But it's an oily asset, and maintenance itself is all associated with the Shell oil pipeline. And it's really something that their -- the pipeline used to terminate at a certain spot.
They were adding to it a year ago, so we had some downtime last year associated with this same type of work. And now they're finishing that whole relocation of that line to another structure this time.
That asset will go down in early June and it will be down the whole month of June and it will be down another 8 to 10 days in July. But this should finish it.
This should be finished with that type of scheduled maintenance for the pipeline relocation, actually an enhancement. The other work at Medusa is really around maintaining the spar and doing -- while the wells are shut in, what we had planned to do was actually do some actually maintenance work on some of the wells.
We'll do a few stem jobs on some of those wells, where we'll actually pump down some solvent. We'll do a near wellbore stimulation.
These have worked very, very well in the past, and we'll let it soak during that whole downtime area to give it a little bit more effectiveness and then we'll bring those back on after the pipeline repair or their pipeline relocation has actually finished. Then shortly thereafter that, after the well's come back on in July, we'll be doing some gas lift optimization work to further enhance the production from Medusa.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Okay, very good. And you just mentioned gas lift, which reminds me, I know over in the Permian, Diamondback's looking at different lift optimization techniques.
Have you guys looked at different lift techniques, whether it's a gas lift or a submersible?
Gary A. Newberry
We have, and what we've relied on up to this point is submersible pumps. And they have worked pretty well, but we think they're a little bit more expensive than we really need.
We are now in the throes, since we are now getting very good at what we do and we're well consolidated there in East Bloxom along a 2-mile stretch of road, all of our facilities are located along that section right in the middle of our 3 sections north and south, and we're looking right now at converting over to gas lift optimization as we bring those on to minimize -- actually, further minimize the cost of our completions.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Okay. And then one last one for me.
On these notes that are outstanding, I believe they're now called -- well, maybe it's a question for Bob. Any color or thoughts there as well?
Bobby F. Weatherly
Well, the notes presently recallable at 1.06 and 0.5 drops to 1/2 of that the end of quarter, in September of this year, and -- but we don't have a plan right now to do anything with the notes at this moment.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Okay. And then just finally here, on this Taylor Draw test, do you feel like that first well was representative?
Was there anything in the drilling that would make that different than what we would expect from these next upcoming tests?
Gary A. Newberry
Well the one thing that happened in that first well was that we did -- we were drilling a longer lateral. We lost the hole.
We had to come back and redrill the lateral. So we're about 100 feet away from that old lateral.
We could've lost some frac pressure or some frac energy when we fracture stimulated that, but it's hard to tell. We're still very happy with the results of this well.
We'd love to be talking about a higher IP, but again, I think if you look at the entire database in the Southern Midland Basin, this is not unusual. And we're still going to get a good return here, and we're expecting even better results from the wells that we have.
We'll optimize the completion a little bit more, in line with what we just did on the 343H, and we're excited about the area.
Operator
This concludes our question-and-answer session. I would like to turn the conference back over to Fred Callon for any closing remarks.
Fred L. Callon
Again, we appreciate everyone taking the time to call in. Appreciate all the questions, and in the meantime, if anyone has questions, don't hesitate to give us a call.
Thank you.
Operator
The conference has now concluded. Thank you for attending today's presentation.
You may now disconnect.