Callon Petroleum Co (CPE) 2014 Q3 法說會逐字稿

Good afternoon and welcome to the Callon Petroleum third quarter 2014 earnings conference call. All participants will be in listen-only mode. (Operator Instructions). After today's presentation, there will be an opportunity to ask questions. (Operator Instructions).

Please note this event is being recorded. I would now like to turn the conference over to Fred Callon, Chairman and Chief Executive Officer. Please go ahead, sir.

Thank you, and good afternoon. Thank you for taking the time to join our third-quarter results conference call. Before we begin, I would like to ask Eric Williams, our Manager of Finance, to make a few comments.

Thanks, Fred. At this point, I would 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 with 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 2013 Annual Report on Form 10-K, available on our website or the SEC website.

We may also discuss non-GAAP financial measures such as discretionary cash flow, adjusted EBITDA and adjusted net income. Reconciliation and calculation schedules for such non-GAAP financial measures are available in our third quarter 2014 results news release and in our filings with the SEC, both of which are available on our website.

Thank you, Eric. It has been a very eventful three months since our last quarterly call, both for Callon as well as the broader commodity markets. Although the markets have been volatile, we have remained focus on delivering our organic growth plans in our core fields and integrating our Central Midland Basin acquisition of approximately 4,000 net acres that closed in early October.

After entering 2014 producing approximately 3,600 barrels of oil a day, we are currently on pace to produce 7,400 barrels of oil per day in the fourth quarter of this year. Underlying a majority of that growth is our drill bit success from three distinct horizontal zones of the Wolfcamp shale that we have developed from multi-zone pads. We are also expanding the development of our portfolio of de-risked zones and are currently in the process of drilling and completing three lower Spraberry wells in both the Central and Southern Midland Basin.

With the production growth visibility that the program development of multiple zones provides, combined with the recent acquisition that increases our production in an attractive area of the basin, we have raised over $425 million in long-term capital since to solidify our balance sheet position. In addition to this long-term capital base, we have bolstered our current liquidity position to approximately $235 million, which is over 100% of our 2014 planned capital expenditures.

Like many of our peers, we are approaching 2015 capital plans on a measured basis. Fortunately, our asset position provides us with a great amount of flexibility, since almost all of our drilling activity is operated by us and our land position nearly all held by production. As an example of this flexibility we have already made changes within our three-rig program for 2015 by shifting activity to our highest return areas and targeting approximately 50% of our planned completions in 2015 to be at our recently acquired fields.

In addition, we have no current plans to drill any vertical obligation wells next year since we are not under any pressure to hold acreage. At this point, we are not planning to accelerate activity beyond the current three-rig program in 2015, and we will continue to monitor the need for reduction in our base plans to preserve strength of our current liquidity position as we await some stability in the commodity markets.

Since our three-rig program is comprised of a vertical rig setting intermediate pacing in preparation for subsequent lateral drilling of the two horizontal rigs, we are positioned to efficiently reduce the pace of our activity to two horizontal rigs by removing the vertical rig. This would defer our drilling schedule, but not result in a complete reworking of our operational plans and locations.

I will now ask Gary Newberry, Senior Vice President of Operations, to discuss our operational results for third quarter and our integration of the Casselman and Bohannon fields. Gary?

Thanks, Fred, and good afternoon to everybody. I will start with a few highlights for the quarter and then I will talk a bit about our ongoing activity. We delivered another quarter of solid production growth, producing an average of 5641 barrels of oil equivalent per day with an oil content of 82%. We completed six horizontal wells in the quarter, with three of those wells going online in the last week of September.

These recent horizontal wells include four Lower Wolfcamp B and two Upper Wolfcamp B wells, all of which were located in the Southern Midland Basin. I will start with the East Bloxom field in Upton County. The Neal 658 LH was 7,099 feet of completed lateral lengths, targeted the lower Wolfcamp B zone from a three-well pad. The Neal 658 LH produced at a peak 24-hour rate of 1,027 barrels of oil equivalent per day at 80% oil after being placed on submersible pump, following the cumulative production of 36,000 barrels of oil equivalent under natural flowing pressure over the first 71 days of production.

The other two wells on the pad, the Neal 611 and 612, each with approximately 7055 feet of complete lateral lengths, targeted the Upper Wolfcamp B zone and are currently being optimized using gas lift, and are both producing in line with our type curves. The remaining three wells completed in the quarter were completed in the Lower Wolfcamp B zone at our Taylor Draw Reagan County. These are the wells that came on in late September and are currently being optimized on the gas lift.

In addition, we completed a two-well pad at Garrison Draw field in Reagan County late in the second quarter of 2014. The University 2,635 number 15 AH had 7,072 feet -- 7,472 feet of completed lateral length and targeted the Wolfcamp A zone. The well produced at a peak 24-hour rate of 1,449 barrels of oil equivalent per day, and an average 60-day rate of approximately 595 barrels of oil equivalent per day, with 75% oil on submersible pump.

The other well on the pad, the University 2635 number 8H, had 7432 feet of completed lateral length and targeted the Upper Wolfcamp B zone. This well has now established three levels of performance at Garrison Draw and is in line with our type curve expectations.

Beyond some slowing initial production rates, I want to note a few additional points. First, I would emphasize that as I have previously stated, we are very disciplined in our approach to flowing back our wells and continue to limit the amount of total fluid produced to 2,400 barrels in any given day. Although we may be losing some amount of early time peak rate, we believe that we are more than compensated in longer-term performance.

Second, we continue to make meaningful strides on the multi-zone development front with an increasing amount of pads completed in two zones.

I will also highlight that we have been utilizing gas lift on several recent wells and comparing the results to offsetting submersible pump results, including wells using both artificial lift designs on the same pad. While gas lift does not typically result in 24-hour and 30-day rates as high as sub pumps, there are several benefits to using gas lift in certain areas, including improved production uptime by eliminating the need to install a sub pump and subsequent rod pump in the early life of a well; more efficient dewatering of offset horizontal wells when fracture-stimulating adjacent pads in the same zone; and the opportunity for controlled drill down during the critical early time performance of a well, which we believe resulted shallower production declines.

On this last point, we have been monitoring an East Bloxom pad with both a sub pump and gas lift well with adjacent completions in the Upper Wolfcamp B. The gas lift well crossed over the sub pump curve approximately four months after initial production, and its cumulative performance continues to increase over the sub pump curve. While we don't expect any meaningful increase in ultimate recoveries, we do believe that increased up time and reduced workovers using gas lift and program development mode will provide a positive economic impact.

As a result, we plan to incorporate gas lift in an increasing number of wells as we move forward, especially at our East Bloxom, Garrison Draw and Carpe Diem fields.

Keeping with the topics of plans to improve our LOE rates and predictability, I want to specifically address the increased lease operating expense realized in the third quarter, which was approximately $2 per BOE above the previous two-quarter average.

We experienced a higher level of well failures in our existing vertical wells after experiencing water interference from our horizontal completions in East Bloxom and Carpe Diem fields, which include the majority of our legacy vertical wells. The primary cause is related to corrosion and increased rod loading during dewatering vertical wells. We believe this exposure will be reduced by raising the rod pumps to reduce rod loading, and increasing our chemical treatment programs.

We also see some impact on producing horizontal wells for a period of time during offset and completions, which has contributed to workover expense as well. The transitioning future horizontal production to gas lift systems should significantly reduce exposure to well failures due to rod and tubing wear.

Looking forward, we plan to complete six gross horizontal wells at Carpe Diem and Garrison Draw fields in the fourth quarter as well as two gross wells at our newly acquired Casselman and Bohannon fields. Two horizontal upward Upper Wolfcamp B wells have been placed on production in these fields since we announced the transaction in early September. Both of the wells have demonstrated strong reservoir energy and continue to flow under their natural pressures. We should have additional production information on these wells in the coming weeks after we put them on sub pump and see longer-term production declines. We are also looking forward to the three lower Spraberry wells being progressed this quarter, one each at Casselman, Carpe Diem and East Bloxom fields.

While we have not adopted a final capital plan for 2015, we have been proactive in our efforts to further increase capital efficiency in the interim. As Fred noted, we have shifted an increased portion of our drilling activity to the Casselman and Bohannon fields for 2015. These fields carry a lower working interest than our legacy fields, and we currently expect to spend $10 million to $15 million less than the previous operational capital estimate of $270 million due to this shift, while still providing for approximately 50% annual growth over our forecasted 2014 midpoint of 5,675 oil barrels of oil equivalent per day.

As a comparison, if we ultimately decide to reduce our operational plans to two horizontal rigs, we estimate and operational capital level of $175 million while delivering 35% annual growth in 2015. Despite some recent commodity price challenges, we remain optimistic for Callon's prospects going forward.

We have demonstrated the ability to consistently grow production with contribution from a growing number of benches. We are continuing to make improvements to our completion designs and cost structure. We're certainly excited about the potential that we see at the Casselman and Bohannon fields, and have been pleased with the recent meetings we have had without working interest partners for future program development, which will start in early 2015.

I will now turn the call over to Joe Gatto, our Senior Vice President and CFO.

Thanks, Gary. Our reported net income for the quarter on GAAP presentation was $10.2 million or $0.23 per diluted share. This figure has included the impact of the following items on a pretax basis. Our non-cash unsettled gain of $10.4 million related to a mark to market of our hedging portfolio and a non-cash gain of $1.5 million related to the mark to market valuation of performance-based incentive compensation awards.

Excluding these items in the related statutory income tax rate of 35% for the quarter, our adjusted net income was $2.6 million or $0.06 per diluted share, based on our average diluted share count of 44.2 million shares following our common equity offering that was completed in mid-September.

Adjusted EBITDA for the quarter was $26.9 million and equates to an adjusted EBITDA margin of 68%. Pro forma for the recent acquisition, our adjusted EBITDA would have been approximately $33.2 million in the third quarter with an estimated margin of approximately 70%.

Discretionary cash flow for the three months ended September 30, 2014 totaled $23 million or $0.52 per diluted share. This number includes $1.8 million in payments related to an asset retirement obligation that was related to offshore oil and gas property sold in late 2013. Excluding these payments related to discontinued operations, our discretionary cash flow from continuing operations was $24.8 million or $0.56 per diluted share.

In terms of income statement detail, operating revenues for the three months ended September 30, 2014 include oil and natural gas sales of $39.7 million from an average two-stream production of 5,641 BOE per day, representing a sequential increase of 30% over our first quarter production. Oil production in the quarter represented 82% of our total production on a volume basis and contributed to 92% of our total revenues.

We expect that our oil contribution will be slightly lower for the next few quarters due to a mix of vertical production from the acquired properties. And we expect this percentage to increase throughout 2015 as horizontal development plans are advanced on those properties.

Our average realized commodity prices for the third quarter, excluding hedge impacts, were $85.52 per barrel of oil and $5.86 per MCF of natural gas, including BTU adjustment for NGLs. On a barrel of oil equivalent basis, this equates to $76.41 per BOE produced in the quarter.

We did experience a continuation of inflated Midland oil basis differentials for approximately $8.85 per barrel on average in the quarter. But we are seeing steady improvement in this metric as long haul pipeline and associated gathering infrastructure enter into service. To this point, we have seen Midland prices trade at a discount of approximately $4.10 per barrel over the last five days.

Also included in our realized oil prices was approximately $2.70 per barrel for transportation in the quarter. We expect to see a reduction in this figure over the next few quarters as we put more of our oil production on gathering pipelines, including the [Pablo] acquisition which is already on a system.

Moving to expenses, our total LOE, including workovers, was $12.08 per BOE for the quarter, which was above our expectations. As Gary discussed, we continue to focus on reducing a workover component of this number, which is difficult to forecast. However, with the progress made to date in the integration of the Casselman and Bohannon fields, we expect our LOE to be below $10 per BOE in the fourth quarter.

Adjusted G&A expense, which excludes the impact of mark to market valuation items, was $4.7 million in the third quarter of 2014, a modest decrease compared to the $4.9 million of adjusted expense in the second quarter of 2014. The cash component of this adjusted G&A was $4 million for the quarter compared to $3.9 million in the previous quarter.

DD&A expense for the quarter was $31.05 per BOE, which was an increase over the second quarter and our longer-term trend. The increase was primarily related to catch-up adjustments for future estimated development capital and to the second quarter estimates after the end of the quarter. As well, the impact of adding Northern Midland properties to the full cost pool, carrying the impact of these items in the quarter, we believe the year to date DD&A rate of approximately $28 per BOE is more representative of the current completion rate for our asset base.

I will now discuss CapEx in our outlook for the remainder of the year. Our total operational capital expenditures, including facilities and excluding capitalized expenses, for the third quarter were $57.3 million on a cash basis. Third quarter cash expenditures included the drilling of seven gross horizontal wells with an average working interest of 86%, and the completion of six gross horizontal wells with an average working interest of 88%, as well as a small amount of vertical drilling activity.

Looking out at the remainder of the year, we expect our total operational capital budget to approximate $47 million in the fourth quarter, inclusive of 8 gross and 6.5 net drilled wells, 9 gross and 7.4 net completions, which includes 1.3 net completions at the acquired Casselman and Bohannon fields and $5 million of facilities and infrastructure cost.

As discussed earlier, we are in the final stages of operational and capital planning process for 2015 and are well-positioned to address a broad range of scenarios from a financial perspective. Following the term debt offering completed in early October, our total liquidity position currently stands at approximately $235 million as of November 1. From a leverage and long-term capital perspective, total debt to trailing 12 months' EBITDA was an estimated 2.4 times, which is pro forma for the second Midland Basin acquisition at the end of the third quarter.

The industry is currently facing a fair amount of uncertainty on the commodity front, but we are comfortable that the Company's solid liquidity position and strong cash flow margins and hedging positions will prove to be an asset in the coming quarters.

From a cash flow margin perspective, our operating margin was $60 per BOE produced for the quarter. And our discretionary cash flow from continuing operations was approximately $48 per BOE, both of which compared very favorably to our peers.

On the hedging topic, we currently have 68% of our forecasted oil production and 64% of our forecasted natural gas production hedged under swap agreements tied to NYMEX prices for the fourth quarter of 2014. Our oil hedge agreements provide for weighted average swap prices of $93.58 per barrel, and our natural gas hedged swap agreements provide for a weighted average price of $4.10 per MMbtu for the balance of the year. For next year, we have an average of over 3,000 barrels of oil per day under hedge agreements that include a swap for book price protection at approximately $91 per barrel.

As part of the press release issued yesterday, we also increased fourth-quarter guidance from our estimate provided at the time of the acquisition announcement in early September. We included a production in the range of 7,300 barrels of oil equivalent per day to 7,500 barrels of oil equivalent per day with an estimated oil contribution of 76% to 78% (technical difficulty).

LOE, including workovers, is expected to normalize to a range of $9 to $10 per BOE after the elevator level workovers in the third quarter.

Adjusted G&A is expected to be in a range of $7.50 to $8.50 per BOE, which is a reduction of almost $1.50 per BOE as we lever an increased pro forma asset base across a large and unchanged G&A cost structure. Approximately 85% of this adjusted G&A amount is forecasted to be cash.

Now I will turn the call back over to Fred for final comments.

Thank you, Joe, Gary. We will now open the call to questions.

(Operator Instructions). Will Green, Stephens.

I appreciate you guys kind of laying out those different scenarios, given that it is a little bit of an uncertain time. I know it is difficult to talk in definitives, but I wanted to touch on the two horizontal pays. And if you guys did decide to drop that pilot hole rig that you guys are using, those two horizontal rigs that are running currently, what do those contracts look like? If you needed the flexibility to drop another one for whatever reason, how do those contracts look? And then, what is kind of the pressure point on the balance sheet that would push you to do that, if there is one?

Well, the contracts on horizontal rigs, I think we've mentioned before, we have got contracts through April of 2016. And both those contracts provide for early termination provisions. And the early termination provisions suggest that what happens is that if we released a rig and somebody else doesn't pick it up, we will pay the day rate fee for the rest of the term. Or if somebody picks it up, that provision goes away.

And of course there is going to be -- even in a market like today, these rigs are highly sought after. So I see minimal exposure for a rig of that type of capability and nature, if I chose to lay one of those rigs down. I will let Joe talk about the pressure point, because I guess I am not feeling it.

Hey, Will. We have certainly looked at the case we have outlined here in the most detail, what the producing -- the pace of activity by taking a vertical rig out of the equation. But there is not necessarily a magic pressure point that we look at.

We like to operate, as we have talked about, at max sort of a 2.5 times debt to an annualized quarter EBITDA number, around 2.5 times. And we might go over that for a period of time, but on our longer-term playing cycle, we would like to get back to that measure in a few quarters if we do exceed it. So, with the program of laying down the vertical rig, we see us operating comfortably in that metric for the planning period, so we haven't really looked at dropping another rig at this point.

I think that things would have to change substantially from where we are now to even contemplate that. But, it is something we will keep an eye on for right now. We do have the base three-rig program. We think with the balance sheet liquidity we have, in the commodity price environment we live in today, we feel comfortable that our funding is well secured into 2016 and maybe even a little bit longer than that. If things move down from there, we will look at these other scenarios similar to the one we laid out on the call.

Okay. So do you feel comfortable on that kind of 2.5 times annualized debt to EBITDA, give or take a little bit here or there on the base three level or the -- base level two-rig or three-rig?

We think that, while we will get over that metric a little bit as we ramp up the three-rig program in next year, that we'll trend down to that range that we like to operate by end of the year.

Got you. Then, how are you guys on leasehold obligations? How should we think about that kind of in that core position you guys have?

We are sitting really nicely, Will. We have got -- even in our new assets, we have got the majority of our position is already held by production with no obligations. We had just a couple of areas. One is in our university lands area down in Garrison Draw. We may have a couple of wells in requirements, and ones in our new Opal development in our new areas in South Upton County, where we just drilled a well with Apache. That may have a one-well requirement. But other than that, we are sitting quite nicely for any required wells to meet an ongoing continuous drilling commitment.

Got you. I appreciate the color, guys.

Ryan Oatman, SunTrust.

Can you speak to the service costs environment? You mentioned a $900 per lateral foot cost of these latest wells. Can you kind describe where that metric was previously and how you see the service cost trending recently?

Yes. I think that $900 per lateral flow is the (multiple speakers)

The last 10 wells.

The last 10 wells, B and C cost, and so that is very competitive in today's world. And service costs themselves, we have talked to our providers -- again, the rig rate that we are paying now on our going rigs is significantly lower than the rig rates that have been coming out for the last year. We know that for a fact because we were pricing some additional rigs before we committed to this vertical rig for setting the intermediate casings and accelerating the use of our horizontal rigs.

So we are sitting pretty good on rig rates today. And, again, those contracts are through April of 2016 and there is still significant demand for those types of rigs.

Public services is another story. We have recently gone through a significant increase in sand costs for fracking wells. And we know what caused that. It's really associated -- there is not an issue on supply and there is really not an issue on logistics. It is all an issue of the transportation cost to get it from the mine to the Midland Basin significantly ramped up. And that is all associated with the railroads and getting more sand to that basin.

I talked to petro services. I have talked to them at length about how quickly we roll back what costs we do control as we see this oil price market start to stabilize. And so we are talking on a regular basis. As I understand it, it is a partnership and they will roll them back just as quickly as we can.

Philip Johnston, Capital One.

Joe, you have mentioned the oil mix should eventually improved throughout 2015. Can you give us a sense of what the progression might look like throughout the year (technical difficulty) get back up around that sort of 80% range?

Yes. As we laid out here, we are in the high 70s for the fourth quarter. About 67% of our production on the acquired properties was oil. So there is a little bit of contribution that we will have to work against on day one. But we should get close to 80% by second or third quarter next year. It is going to move pretty quickly back into that range after we get horizontal development going. So it is a couple quarters at most out to get back to that 80% range.

Okay. Thanks. And just to follow-up on the pressure plan on letting go of that rig. If we assume $70 NYMEX for all of 2015, it looks like your net debt to EBITDA ratio (technical difficulty) a little bit above three times by the end of next year. Is that too far out of your comfort zone? I mean, is that a level at which you might drop that rig? Or, I mean, is it somewhere between 70% and 80%? Is that kind of the way to think about it?

Put that into the mix the Midland Basin differential as well. Let's assume that that continues to prove, and we think it probably settles in the $3 to $4 range for next year. So if we normalize for that, I would say that we see sustained $75 TI pricing we are probably going to be thinking real hard about letting that vertical rig go. And we can make that decision very quickly. Gary could talk to it. That is an exercise we know in a matter of days rather than weeks, I think, if we make that decision.

Exactly. We would finish the well we would be on and then we would be done with it. It would be very quickly. And if we see that thing stabilize in the mid-70s, like Joe referenced, that is a decision we would make.

We want to see leverage to trend down. And if we started getting down to those types of prices on a sustained basis, operating at an elevated three-plus times and not seeing it come down, that is a point where we are uncomfortable.

Ron Mills, Johnson Rice.

Just a clarification. I wanted to make sure that you haven't made the decision to drop that vertical rig. That is just something that is possible if commodity prices remain in this mid-$70 level, correct?

That is correct, Ron. We still plan to use that rig and still plan to actually start using it here in the next month, and watch this commodity level price go. And, again, the value that we have, the flexibility we have is fair to clear. We can pick it up and we can let it down as quickly as we decide. So -- but we haven't made that decision yet. We are still on track, as we have stated, to go forward with the three-rig program today.

Okay. And then, Gary, you also mentioned, even if you remain status quo with that vertical rig and two horizontals, you talked about maybe shifting some activity to the recently acquired acreage which has a little lower interest. Is that one way to manage a little bit lower CapEx? And I think you said 50% growth versus, I think you had been talking about, 55% or 60%. Is that the right -- is that just because moving to some lower working interest areas?

That is correct, Ron. Again, we purchased that acreage because it was -- it's highly prospective acreage. It is in a great spot in the basin. There are some of the best wells we will drill. And similar to what our Carpe Diem wells are, they are exceptional wells.

And we do have a lower working interest there. So we will be focused on an area that has good capital efficiency, good capital utilization, some of the best returns we have, but still a lower working interest with the same amount of rig fleet. It just gets you to a fewer number of net wells, so ultimately, a lower capital perspective. Yes, maybe it might be in total little bit less growth, but it is much more profitable growth.

And is that something that you would do even if commodity prices moved back up here in the short-term?

We would, simply because of how prospective it is, Ron.

Okay. And then from a third quarter production standpoint coming in ahead of plan, your fourth quarter guidance moving higher, is that purely a function of continued well performance above your type curves?

Yes, it is. It is that, as well as recognizing we are now integrating in fourth quarter the full impact of Casselman and Bohannon, even though we don't have a full month of October because it closed on the 8th. But, that is still what we believe to be coming from these new wells, even at Casselman and Bohannon that are coming online.

Okay. And then just from a news release standpoint, you have a number of wells that are either flowing back or about to be flowing back, including the Spraberry wells. What is the expected timeframe in terms of coming to market with those results? Is it something later this year? Or would it really be kind of early next year, maybe in January or February?

Well, I will talk a little bit about that and that Gary can jump in, as to expectations around what wells we might have data on. But I think from a high level view, and communication between the third quarter and fourth quarter, we always have obviously a lot of time there with not a lot of updates going on. So, typically, what we like to do is get out in January and especially in this environment a lot of eyes focused on what we will set our capital budget at formally for 2015.

So we are going to give things a couple of months to settle out, see some additional data points from these new wells at the (technical difficulty) area and come out with the capital budget sometime in January. With that, it is a natural time, I think, to come out with some other well data over the next couple months. Gary can probably talk about what we would expect.

And, again, we never know the timing of getting some of these on pumps and optimized. But I think there is probably a decent body of work, Gary, that we probably have sometime in January to talk about.

Yes. That is right, Joe. I will just reiterate. That 658 LH well at Neal, that is a Lower B well. That is the first Lower B well there. That is what of the best wells that we see in the field. It is a really good well. So that is, again, another area that has just kind of proved up even deeper B works, where we have another even Upper B above it.

The A well at Garrison Draw is a phenomenal well. It is just spectacular. So we are happy with that. We are really making some very good wells.

And as far as physical timing of the lower Spraberry results, it will be January before you see any material numbers. Here is where we are just physically. We just fracture-stimulated the lower Spraberry at Carpe Diem and finished up that three-well pad a week ago. We are just rigging up to drill out the plugs. So we -- that will be a couple of weeks to dole out three plugs.

We will start to flow back on those wells shortly thereafter, and you know how this works. We will flow them back for 30, 60 days before we get any real sense of what they are going to do. We are just now this week fracture-stimulating the lower Spraberry at Casselman and we are already on our fourth or fifth stage. That is doing quite well.

And we are just drilling the Lower Spraberry at Bloxom. So it will be -- there may be some information, but I am going to suggest it is going to be January, easy, before we get real definitive data that we see there. And we will see early indications of pressure and flow rates and sustainability, but it will be a little while.

Andrew Smith, Sea Port Global.

Just a question about the deep blocks in the Neal well. You all talked about flowing it back under natural pressure and mentioned that you would like to keep the liquids at 2,400 barrels a day or less. Is this just in the East Bloxom area or is this kind of across your acreage? And how should we think about that going forward?

No. That is something that we believe really helps us, actually. And I know other companies have suggested that we need to really let them flow harder, but we are seeing some positive results. When we compare the two, we think it is better to control that flow and you know, I think about that across our position. That is one of the reasons I think ultimately we will transition to gas lift in most of our legacy assets.

And that really allows us to draw down those wells at a very controlled pace as we step down to each gas lift style in that well. And it is a very controlled flow back and I think that protects that new wellbore and somewhere a few inches into the reservoir fracture stimulation, more so than pulling harder. So I would think about that across the basin.

Okay. Thanks. Then you talked about increasing your oil production that is flowing through your pipelines, and that reducing transportation costs. What percent of your oil production is currently flowing through your pipeline and where do you see that going?

We have been focused on getting our legacy assets on pipeline for some time and we are working with the primarily Plains pipeline company to get that done in the Southern Midland Basin. So, a majority of our legacy assets are on trucking today. The Casselman, Bohannon assets that we just integrated into our operation, today is about 1,400 net barrel of oil equivalent per day. It is all on pipeline today. It is all on enterprise pipeline.

So we have got a good bit to go to get our Southern Midland Basin as well as our Carpe Diem field on pipeline. So the majority of it is on truck today, Andrew.

Joe Bachman, Howard Weil.

A couple of quick ones for me, just to follow on that last question; how much of your production is still being flared on the gas side?

We are taking care of all that. We don't have any production being flared today. We have got -- we increased capacity at various different pipeline companies' gathering systems and we have got everything going into the pipe.

So everything in that northwestern portion of Midland County, there is no issue there that you guys -- no problems with drilling actively there and putting that gas in the pipe?

No. There may be a temporary timeframe here or there, but not that we can see right now. And, again, in that Central Midland Basin, the Coronado Pipeline Company is connecting to both the Pecan Acres as well as to Carpe Diem, which is where we had most of our flaring. And they are already connected to Casselman and Bohannon. So they seem to have capacity at their plant and so far we have no restrictions.

Okay. Last one for me; I think during 3Q you guys talked about possibly adding a third horizontal sometime in the second half of next year. Understanding you hadn't committed to that rig at this point, just wondering what is the when drop dead date for deciding that before Cactus goes out and looks for somebody else for that rig?

Cactus, that is a good point. But what we told Cactus is that we just can't make that decision today given the volatility in prices. So they are out looking for another company to get that rig, and I think they will find it.

But the other thing is that with we can if we can firm up what we believe to be the outlook, Cactus has always said, hey, we will be there as a partner. Just give us a quarter or two and we will likely maybe build you another one. But, I would suggest that Cactus will have a lot of success in putting that thing to work and they are probably already marketing it.

Ladies and gentlemen, this will conclude our question and answer session. I would like to turn the conference back over to Fred Callon for any closing remarks.

Again, I would like to thank everyone for taking time to call in this afternoon. We realize there is a lot of volatility and a lot of uncertainty, and just want to make sure that we are continuing to focus on the business and continue to keep you up to date. Thank you for taking time to call in.

Ladies gentlemen, the conference has now concluded. We thank you for attending today's presentation. You may now disconnect your lines.