Callon Petroleum Company
Q3 2014 Earnings Call Transcript

Published: 6 Nov 2014

[Operator:]

Good afternoon, and welcome to the Callon Petroleum Third Quarter 2014 Earnings Conference Call. [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.

[Fred L. Callon:]

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

[Eric Williams:]

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 belief, 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 2013 annual report on Form 10-K available on our website or the SEC's 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.

[Fred L. Callon:]

Thank you, Eric. It's been a very eventful 3 months since our last quarterly call, both for Callon as well as broader commodity markets. Although the markets have been volatile, we remain focused on delivering our organic growth plans in our core fields, 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're currently on pace to produce 7,400 barrels of oil per day in the fourth quarter this year. Underlying the majority of that growth is our drillbit success from 3 distinct horizontal zones of the Wolfcamp shale that we have developed from multi-zone pads. We're also expanding the development of our portfolio of derisked zones and are currently in the process of drilling and completing 3 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 increased our production in an attractive area of the basin, we have raised over $425 million in long-term capital 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 is nearly all filled by production. As an example of this flexibility, we've already made changes within our 3-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're not on any pressure to hold acreage. At this point, we're not planning to accelerate activity beyond the current 3-rig program in 2015, and we'll continue to monitor the need for reduction in our base plan to preserve strength for our current liquidity position, as we await some stability in the commodity markets. Since our 3-rig program is comprised of a vertical rig, setting intermediate casing in preparation for subsequent lateral drilling of the 2 horizontal rigs, we are positioned to efficiently reduce the pace of our activity to 2 horizontal rigs by removing the vertical rig. This would defer our drilling schedule but not result in a complete reworking of our operational plans on locations. I will now ask Gary Newberry, Senior Vice President of Operations, to discuss our operational results for the third quarter and our integration of Casselman and Bohannon fields. Gary?

[Gary A. Newberry:]

Thanks, Fred, and good afternoon to everybody. I'll start with a few highlights from the quarter, and then I'll talk a bit about our ongoing activity. We delivered another quarter of solid production growth, producing an average of 5,641 barrels of oil equivalent per day with an oil content of 82%. We completed 6 horizontal wells in the quarter, with 3 of those wells run online in the last week of September. These recent horizontal wells include 4 Lower Wolfcamp B and 2 Upper Wolfcamp B wells, all of which were located in the Southern Midland basin. I'll start with the East Bloxom field in Upton County. The Neal 658 LH with 7,099 feet of completed lateral length, targeted the Lower Wolfcamp B zone from a 3-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 2 wells on the pad, the Neal 611 and 612, each with approximately 7,055 feet of completed 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 3 wells completed in the quarter were completed in the Lower Wolfcamp B zone at our Taylor Draw field in 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 2-well pad at Garrison Draw field in Reagan County late in the second quarter of 2014. The University 26-35 #15 AH at 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 at 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 26-35 #8H had 7,432 feet of completed lateral length and targeted the Upper Wolfcamp B zone. This well has now established 3 levels of performance at Garrison Draw and is in line with our type curve expectations. Beyond some strong initial production rates, I want to note a few additional points. First, I would emphasize, as I 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 2 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 our official lifts 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 drawdown during the critical early time performance of the well, which we believe results in shallower production declines. On this last point, we've 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 4 months after initial production and as 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 uptime, reduced workover issues on gas lift and program development mode will provide 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 2-quarter average. We experienced a higher level of well barriers in our existing vertical wells after experiencing water interference from our horizontal completions in the 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 offsetting completions, which has contributed to workover expense as well. The transitioning future horizontal production to gas lift systems should significantly reduce exposure to well barriers due to rod and tubing wire. Looking forward, we plan to complete 6 gross horizontal wells at Carpe Diem and Garrison Draw field in the fourth quarter as well as 2 gross wells at our newly acquired Casselman and Bohannon fields. Two horizontal 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, as we put them on sub pump and see longer-term production declines. We're also looking forward to 3 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 previously 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 barrels of oil equivalent per day. As a comparison, if we ultimately decide to reduce our operational plans to 2 horizontal rigs, we estimate an 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, and we're continuing to make improvements to our completion design and cost structure. We're certainly excited about the potential to see -- that we see at the Casselman and Bohannon fields and have been pleased with the recent meetings we've had with our 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.

[Joseph C. Gatto:]

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

[Fred L. Callon:]

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

[Operator:]

[Operator Instructions] The first question will come from Will Green of Stephens.

[Will Green:]

I appreciate you guys kind of laying out those different scenarios given that it's a little bit of an uncertain time. I know it's difficult to talk in definitives, but I wanted to touch on the 2 horizontal case and if you guys did decide to drop that kind of pilot hole core rig that you guys are using. Those 2 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's kind of the pressure point on the balance sheet that would push you to do that, if there is one?

[Fred L. Callon:]

Yes, well, the contracts on horizontal rigs. I think we've mentioned before we've 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 release the rig and somebody else doesn't pick it up, we'll pay the day rate fee for the rest of the term or if somebody picks it up, that provision goes away. Just -- and of course, there's 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'll let Joe talk about the pressure point because I guess I'm not feeling it.

[Joseph C. Gatto:]

Well, we've certainly looked at the case we've outlined here in the most detail with the producing -- the pace of activity by taking the vertical rig out of the equation. There's not necessarily a magic pressure point that we look at. We like to operate, as we talked about, at max sort of a 2.5x debt to an annualized quarter EBITDA number, around 2.5x, and we might go over that for a period of time, but on a longer-term planning 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 will have to change substantially from where we are now to even contemplate that, but something we'll keep an eye on for right now. We do have the base 3-rig program. We think with the balance sheet and the liquidity we have in the commodity price environment we live in today, we feel comfortable that our funding is well secure into 2016 and maybe a little bit longer than that. If things move down from there, we'll look at these other scenarios similar to the one we laid out on the call.

[Will Green:]

Okay. So you feel comfortable in that kind of 2.5x annualized debt to EBITDA, give or take a little bit here or there on a base 3 level or the 2 -- or base level 2-rig or 3-rig?

[Joseph C. Gatto:]

We think that while we get over that metric a little bit, as we ramp up the 3-rig program in next year that we'll trend down to that range that we'd like to operate by the end of the year.

[Will Green:]

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

[Fred L. Callon:]

Yes, we're sitting really nicely, Will. We've got -- even in our new assets we've got, the majority of our position is already held by production with no obligations. We have just a couple of areas. One's in our University Lands area down in Garrison Draw. We may have a couple of well requirements, and one's in our new [indiscernible] development in our new area in South Upton County, where we just drilled a well with Apache that may have a 1-well requirement. But other than that, we're sitting quite nicely for any required wells to meet an ongoing continuous drilling commitment.

[Operator:]

The next question will come from Ryan Oatman of SunTrust.

[Ryan Oatman:]

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

[Fred L. Callon:]

I think that $900 per lateral foot is...

[Joseph C. Gatto:]

The last 10 wells.

[Fred L. Callon:]

The last 10 wells D&C cost, and so that's very competitive in today's world. And service cost themselves, well, we've talked to our providers. Again, the rig rates that we're paying now on our drilling 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're sitting pretty good on rig rates today. And again, those contracts are through April 16, and there's still significant demand for those types of rigs. Pumping services is another story. We've recently gone through a significant increase in sand cost for fracking wells, and we know what caused that. It's really associated -- there's not an issue on supply, and there's really not an issue on logistics. It's all an issue of the transportation cost to get it from the mine to the Midland Basin significantly ramped up, and that's all associated with the railroads and getting more sand to that basin. I've talked to perpetual[ph] services. I've talked to them at length about how quickly we roll back what cost we do control, as we see this oil price market start to stabilize. And so we're talking on a regular basis, and I understand that it is a partnership and they will roll them back just as quickly as we can.

[Operator:]

Our next question will come from Phillips Johnston of Capital One.

[Phillips Johnston:]

Joe, you've mentioned the oil mix should eventually improve throughout '15. Can you give us a sense of what the progression might look like throughout the year to back up around that sort of 80% range?

[Joseph C. Gatto:]

Yes, we've laid out here we're in the high 70s. For the fourth quarter, about 67% of our production on the acquired properties was oil, so there's a little bit of contribution that we'll have to work against on day 1, but we should get close to 80 by second or third quarter next year. It's going to move pretty quickly back into that range after we get horizontal development going. So it's a couple of quarters at most out to get back to that 80% range.

[Phillips Johnston:]

And just a follow-up on the pressure point on letting go that vertical rig. If we assume $70 NYMEX for all of '15, it looks like your net debt-to-EBITDA ratio, I find, is a little bit above 3x by the end of next year. Is that too far out of your comfort zone? I mean is that a level at which you think 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?

[Fred L. Callon:]

Yes, if that's [indiscernible] in mix, the Midland Basin's differentials, well, it's assumed 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'd say that we see sustained $75 TI pricing. We're probably going to be thinking real hard about letting that vertical rig go, and we can make that decision very quickly. Gary can talk to -- I mean that's -- that's an exercise that could be done in a matter of days rather than weeks, I think, if we make that decision.

[Gary A. Newberry:]

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

[Fred L. Callon:]

Yes. We know -- I'd say, we want to see leverage to trend down, and we start getting down to those types of prices on a sustained basis, operating at an elevated 3-plus times and not seeing it come down, and that is a point where we're uncomfortable.

[Operator:]

The next question will come from Ron Mills of Johnson Rice.

[Ronald E. Mills:]

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

[Fred L. Callon:]

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 price level go. And again, the value that we have, the flexibility we have is fairly 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're still on track, as we've stated, to go forward with the 3-rig program today.

[Ronald E. Mills:]

Okay, and then Gary, you also mentioned, even if you remain status quo with that vertical rig and 2 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 because -- I think you said 50% growth versus I think you had been talking about 55% or 60%. Is that the rate -- is that just because of moving to some lower working interest areas?

[Gary A. Newberry:]

That's correct, Ron. Again, we purchased that acreage because it was a highly prospective acreage. It's in the great spot in the basin, some of the best wells we'll drill, and similar to what our Carpe Diem wells are. They are exceptional wells, and we do have a lower working interest there. And so we'll 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, a prospective. Yes it might be in total a little bit less growth, but it's much more profitable growth.

[Ronald E. Mills:]

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

[Gary A. Newberry:]

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

[Ronald E. Mills:]

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?

[Fred L. Callon:]

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

[Ronald E. Mills:]

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's 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?

[Joseph C. Gatto:]

Well, let me talk a little bit about that and Gary could jump in with his expectations around what wells we might have data on. But I think from a high level view and communication, between the third quarter and the fourth quarter, we always have obviously a lot of time there with not a lot of updates going on. So typically, what we would like to do is get out January, and especially in this environment, lot of eyes focused on what -- we will set our capital budget at formally for 2015, so we're going to give things a couple of months to settle out, see some additional data points from these new wells at the Ca-Bo area and come out of 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 of months, and Gary could probably talk about what we would expect. And again, there's -- we never know the timing of getting some of these on pumps and optimize, but I think there is probably a decent body of work, Gary, that we probably have some time in January to talk about.

[Gary A. Newberry:]

Yes, that's right, Joe. Again, Ryan, I'll just reiterate. That 658 LH well at Neal, that's a lower B well. That's the first lower B well there, and that's one of the best wells that we'll see in the field. It's a really good well. So that's, again, another area that's 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. That's just spectacular. So we're happy with that. We're really, really making some very good wells. And as far as physical timing of the Lower Spraberry results, it'll be January before you see any material numbers. Here's where we are just physically. We just fracture-stimulated the Lower Spraberry at Carpe Diem and finished up that 3-well pad a week ago. We're just raising it up to drill out the plugs, so that will be a couple of weeks to drill out 3 plugs. We'll start to flow back on those wells shortly thereafter, and you know how this works. We'll flow them back for 30 to 60 days before we get any real sense for what they're going to do. We're just now this week fracture-stimulating the Lower Spraberry at Casselman. We're already on our fourth or fifth stage, that's going quite well, and we're just drilling the Lower Spraberry at Bloxom. So it will be -- there may be some information, but I'm going to suggest it's going to be January easy before we get real definitive data that we see there that we'll see early indications of pressure and flow rates and sustainability, but it will be a little while.

[Operator:]

The next question will come from Andrew Smith of Seaport global.

[Andrew M. Smith:]

Just a question about the East Bloxom and Neal wells, you all talked about slowing it back under natural pressure and you mentioned that you 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.

[Fred L. Callon:]

Now that's 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're seeing some positive results. When we compare the 2, we think it's better to control that flow, and you ought to think about that across our position. That's one of the reasons, I think, ultimately, we'll 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 [indiscernible on that well, and it's a very controlled flowback, and I think that protects that new wellbore and somewhere a few inches into the reservoir, fracture[ph] stimulation more so than pulling them harder. So I would think about that across the bases.

[Andrew M. Smith:]

Okay, and then you talked about increasing your oil production that's flowing through pipelines and that reducing transportation cost. What percent of your oil production is currently flowing through pipeline? And where do you see that going?

[Gary A. Newberry:]

Yes, we've been focused on getting our legacy assets on the pipeline for some time and we are working with, primarily the 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 and Bohannon assets that we just integrated into our operation, it's about -- today, it's about 1,400 net barrels of oil equivalent per day. It's all along pipeline today. It's all along enterprise pipeline. So we've 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 that is on track today, Andrew.

[Operator:]

The next question will come from Chad Bachman of Howard Weil.

[Joseph Bachmann:]

A couple of quick ones from me. Just to follow on the last question, how much of your production is still being flared on the gas side?

[Fred L. Callon:]

We've taken care of all that, Jeff. We don't have any production being flared today. We've got -- we've increased capacity at various different pipeline companies, gathering systems and we've got everything going into a plan.

[Joseph Bachmann:]

So everything, I guess, in that northwestern portion of Midland County, there's no issue there. You guys, no problem with drilling actively there and putting that gas in the pipe.

[Gary A. Newberry:]

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 [indiscernible] Acres as well as to Carpe Diem, which is where we've had most of our flaring, and they're already connected to Casselman and Bohannon. So they seem to have capacity at their plant, and so far we have no restrictions.

[Joseph Bachmann:]

Okay. And last one from 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 when is the drop dead date for deciding that before Cactus goes out and looks for somebody else for that rig?

[Gary A. Newberry:]

No, Cactus, that's a good point, but what we've told Cactus is we just can't make that decision today given the volatility in prices. So they're out looking for another company to get that rig, and I think they'll find it. But the other thing is that if we can firm up what we believe to be the outlook, Cactus has always said, hey, we'll be there as a partner. Just give us a quarter or 2, and we'll likely maybe build you another one. But I would suggest that Cactus have lot of success in putting that thing to work, and they're probably already marketing it.

[Operator:]

And 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.

[Fred L. Callon:]

Again, we would like to thank everyone for taking time to call in this afternoon. We realized a lot of volatility, a lot of uncertainty and just want to assure that we're continuing to focus on the business and continue to keep you up-to-date. So thank you for taking time to call in.

[Operator:]

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