Delphi Energy's (DPGYF) CEO David Reid on Q2 2014 Results - Earnings Call Transcript

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Delphi Energy (OTCPK:DPGYF)

Q2 2014 Earnings Conference Call

August 14, 2014 11:00 a.m. ET


David Reid - President and CEO

Brian Kohlhammer - VP Finance & CFO


Kurt Molnar - Raymond James


Good morning ladies and gentlemen, welcome to the Delphi Energy Corp. second quarter conference call and webcast. I would now like to turn the meeting over to Mr. David Reid, President and Chief Executive Officer of Delphi Energy Corp. Please go ahead Mr. Reid.

David Reid

Thank you, Maloney and good morning everyone and welcome to our second quarter conference call. As mentioned, I am David Reid, I'm the President and CEO. I am joined here this morning with Brian Kohlhammer, our Senior VP Finance and CFO.

We'll start the call with some general remarks as usual and Brian will spend some time walking through some of the financial information and then we will spend some more time afterwards talking about the Montney development program and then we will open it up for questions after that.

As always please be advised, that statements made in this call other than statements of historical fact may contain forward-looking information and I do refer you to the forward-looking statements disclaimer included in the MD&A of the second quarter results and inform you that this disclaimer applies to any forward-looking information disclosed in today's call.

Again a brief background on Delphi, if there are some folks on the line that are less familiar with us, we’re exclusively a deep focused E&P company with over 95% of our production in reserves and undeveloped lands in the deeper areas of the basin in Northwest Alberta, and we operate approximately 90% of our production and consistently operate over 95% of our field capital programs.

Our success at Bigstone with Montney continues to have a significant and accelerating impact on the growth profile of the company. As we pointed out in previous calls, we’ve kind of generated a theme for 2014 of a financial transformation, where the operational transformation we felt began last year. The continued operational success through the second quarter with another record production of over 35% growth. We doubled our field condensate. Our total NGLs are up over 60%. So we continue to perform operationally.

And then when you look towards the financial side that Brian will get into and you look at the growth in the revenue and cash flow streams coming mostly from the growth in these liquids at Bigstone, it’s easy to conclude that really we’re no longer a gas company even though our production weighting were 70% gas, our revenue was only 45% gas, 55% of it now coming from our liquid streams and with the opportunity to continue to grow that even more significantly. And this really comes from the quality of the production mix at the Montney with the well productivities that continue to impress us over time as we get more and more data and look at decline profiles.

As we reported in the quarter, our NGLs at Bigstone have been running through the first six months of the year at about 100 barrels a million with most of that 75% or so being condensate and the Montney represented over 75% of the field operating income in the second quarter, so very significant contributor now to the financial success of the company.

And you look at the netbacks of about $33 a BOE in the second quarter we have great visibility and opportunity in front of us to take that through $40 a BOE with some strategic facility optimization and like the K3 plant that will be going to imminently and some of the other things we outlined in the press release and really that's because we have some pretty significant infrastructure in the area with ownership in some of those very key pieces. So it’s pretty easy to see the continued growth in cash flow and strengthening of the balance sheet through this growth and the growth in the PDP value.

While we’ve been holding our absolute debt relatively flat at the current levels without any dilution to our shareholders, it really comes down to the strength of the Montney economics. We’ve shown that in our presentation consistently the economics of this thing but even when you look at through the first half of the year our recycle ratio on a PDP basis is looking something north of two and we think again with the continued growth in those netbacks we can see that potentially going through three times on a PDP basis. So those are very very strong economics, probably some of the best in the industry. So we’re very confident where we sit today.

So before I get into some of the operational side of things, I am now going to turn it over to Brian to talk about the financial aspects of the quarter.

Brian Kohlhammer

Thanks, David and good morning everyone. There is certainly lot of detailed information in the financials and MD&A that I won’t go over. However if you have any further questions on the quarter, that information in there, also we may answer them end of our call.

So a few items I would like to talk about is the risk management and the cash generating capability of the Montney that Dave made reference to earlier. US natural gas storage levels continue to be a deficit relative to last year and the five year average for this time of year with lots of chatter in the market about continued growth in US by cooler than average or desired somewhere in the US this year to absorb all these additional supply and the possibility of an El Nino winter. The winter’s weather will be a big driver of winter’s natural gas pricing and summer of 2015 natural gas pricing as well driven by the storage level at the end of March next year.

Our natural gas production is hedged approximately 60% to 65% through October of this year with approximately 30% hedged through the upcoming winter. Over that time period our average price to receive is around 315 Mcf but with the possibility of an El Nino winter and continued US supply growth, our greatest near-term pricing period of concern is the summer of 2015 when US supplies have potentially restored the storage levels to an average level due to a warmer winter than expected.

So consequently we have begun undertaking some fixed price hedges for the summer of 2015. Longer-term as our debt to cash flow comes down to our target of 1.5 to 1, or we would see reducing regarding our risk management program from – protection of the balance sheet with the commodity and using different hedging tools, so that we remain exposed to the upside of the commodity price.

As you read in the press release and Dave has mentioned the Montney development is rapidly transforming Delphi from a natural gas company to a liquids company and transforming our financial position as well as we had talked about starting last year already as we went through the operational transformation. Not based on production volumes but rather on how our revenue and ultimately cash flow as being generated.

In the second quarter on a total company basis, liquids revenue represented 55% of total product revenue but only with liquids production only being a 32% of production. Natural gas production represented 45% of revenue on 68% of production. Natural gas production and the rate is still a critically important, as higher natural gas rates will deliver more liquids on a per day basis and hence more revenue generated from the total production stream.

For the second quarter, the average liquids yield per million cubic feet of natural gas for the Montney was over 100 barrels, of almost 70% of the yield being field and planned condensate priced at over $100 per barrel, with the balance being butane and propane. The composition of the production mix from Montney wells becomes very apparent in the netbacks being achieved on this production.

In the second quarter, the operating netbacks for the Montney was 32.99 per BOE and for the first half of the year has been 34.33 per BOE. This compares to $15.18 per BOE and $20.69 per BOE for the company’s other assets over those same time periods respectively. And 77% of the second quarter cash operating income was generated from the Montney and only 61% of corporate production.

Now that we’ve established the production and reserve potential of the Montney play, we’ve begun working on facilities and infrastructure projects and looking at our marketing arrangements to further enhance the netbacks to be realized from area. These projects require significant lead time for approvals, ordering and construction of equipment and construction of the facilities but the benefits may not be realized for several years. However we believe there is the opportunity to potentially enhance the netback of the Montney production to over $40 per BOE in the future in a price environment that would be consistent with the second quarter.

Sa I said earlier, if you have any further questions for the quarter feel free to ask them at the end of the conference call. Dave, that’s all. I will pass it back to you.

David Reid

Thanks, Brian. So just in terms of operations, relative to last year at this time spring breakup was very good to us, this year it was very dry and we were able to run the drilling rig right through breakup. So we really accelerated two of the wells for the year into the first half and those are now on production, one of those show up in the table as 8 of 21. So we’re really ahead of schedule and we will talk little bit about that as we get through – on my comments, so that's been a very positive and it cost us very little incremental dollars because breakup was so dry and short for us and we continue to run the drilling operations and completion operations relatively problem free. So we’ve been able to execute on budget and get the results that we’re looking for with really no problems.

On the completion side, we continue to refine on the margin, the frac design ,there's a lot of things we are looking forward to trying to continue to improve well productivities. And we will do that in a gradual step to really to find the value of some of the ideas that we have come up with, so that’s going to take some time. But we’re looking forward to implementing some of that and we continue to drive some of the frac costs down through both design and logistics and water handling continues to be a significant cost both getting the 60 or 70,000 barrels through the lease and then ultimately getting that to disposal after the frac. So we continue to work on that aggressively.

From a facilities perspective we did complete our expansion in early in the spring at the 7 of 11 dehy compression facility to 45 million a day. We have another compressor on order and it will be here at year-end to take that facility up to the 55 million to 60 million a day likely to be commissioned early in the new year, so sometime in Q1 of ’15. We’ve also completed our tie-in to be able to take us to K3, with SemCAMS rather than going from the K2 where we have been over the last several years and we have stated in the past that savings we expect to see a $2 to $3 a BOE savings on our Montney production and transportation and processing by going to K3.

We’re just waiting on repair actually of the Pembina NGL line that takes the NGLs out to K3 to be repaired and that's so – as soon as that's done and we are told that’s kind of imminent that we will be shifting production from to K3 – the KA turnaround did start this week, so our Montney production did get shut in the other day as the KA turnaround is in progress. So the Pembina thing is a bit of a hiccup for us in terms of – we were to have a seamless transition from KA to K3 without any downtime through the spring and early summer. So we look forward to getting that production on imminently and I think it will ultimately with really only September in the third quarter seeing some of these cost savings it’d really take fourth quarter before we start to see a visible impact on our OpEx in netbacks at with the Montney.

As I mentioned the frac mentioned disposal it’s a significant cost to both the completions and our own operating costs. We see an opportunity to reduce our operating costs on the Montney by about $2 a BOE just in the disposing of frac water from our 7 of 11 facilities. So right now that gets struck out and just by putting in our own infrastructure to dispose the water without trucking and having the wait time at places like secure, we can do that much much cheaper on our own project that would pay out somewhere in the 18 months range. So that’s something that we’re working on and hope to have up and running sometime in ’15.

In terms of other initiatives that we’re working on, SemCAMS really just represents one of the several longer-term processing options we’re working on, because the Montney is slightly sour, SemCAMS is a great strategic partner for us to move our sour Montney to them. But because we already own sweet infrastructure in the area we have 25% ownership in the 80 million a day sweet plan at, what’s called, West Bigstone, that Talisman operates and we have a significant excess capacity there and we could displace some third-party volumes as well. So we are working on our engineering to put our own amine sweetening system and right at Bigstone where we could then take sweetened Montney gas and move a portion of that through our own infrastructure and we would probably see another $2 to $3 a BOE savings in OpEx on that volume. So we would still run volumes to SemCAMS but we would be splitting and taking some sweet to our own plant.

And it also then provides an option for us to deliver the sweetened Montney gas to midstreamer’s deep cut plants in the area that is looking for the kind of gas that the sweetened Montney would be with its very high liquids content of C2s, 3s and 4s that would be a great addition to their deep cut process. So that is another option that ultimately we want to have access to, so really we’d have three very solid egress options to deliver gas from the Montney to shales and as we look forward it's not just the gas that is important; it’s the condensate and the NGLS in the markets that we need to attempt to get into both through alliance down into the Chicago area as well as our local market. So we think we’re in a great position. I think where we are from an area perspective there is already existing infrastructure and we own some of it, so it gives us great advantage and pretty quickly to put these in place, ultimately we would view ourselves as having pretty modest capital tied up in that infrastructure but have pretty significant control of it. So I think that's a very important part of the long-term growth strategy that we are putting in place here for the Montney.

In terms of well performance, it's great for our guys to see month over month go by and allow us to get more and more production data from the wells. We now have five of the slickwater frac wells that have been on production for 180 days or more and they continue to impress us, we continue to see a three fold increase above where the old-style smaller conventional fracs put us out that far and the declines continue to moderate and impress our guys. So those five wells are at day 180 or out six months or are about 15% better than our type curve or about 850 barrels a day on average versus the 746 that we show on the table for our type curve that we revised early in the spring. So we’re pleased with the way these wells are producing over time and what we're seeing in the later months after we get through a pretty significant cleanup period.

The NGL ratios remain very robust, as you saw in the quarter with average yields in the 100 barrel per million and a big chunk of that being condensate. The observations that we would make from the now 13 wells that are on production is that we’re tracking on average at or slightly above our type curve .The average conde yields are also slightly ahead but the yields -- we do see some pretty significant variability and you see that in the table, which is our 15 to 21 is 170 barrels a million on the IP 30 and it's still our richest well out there and on a revenue basis, it’s really running as a type well even though productivity is slightly below. So each well has its own character in terms of rates.

And I think probably the other conclusion we’re seeing is that with each one of these wells personalities being shown in the early time in the initial cleanup test rates where we’re still – we reported test and we’re still making upwards of 1000 barrels a day of water. Even the early time IP 30 rates we’re still in pretty significant cleanup mode in terms of water recoveries and really it isn’t until you get out into the six months where your water rates have declined to the point where you frac water is pretty negligible and you’re just producing water condensation with the gas. And so it’s at that point where you start to see the true performance of these wells and we have some very good wells out there that have tracked consistently over the type curve and we’ve had wells, now have three wells 15 to 25 is a great – the best example where it started at about 75% of the type curve and it’s now at six months is crossing over the type curve. It may be our -- ultimately be one of our best wells and so what we’re concluding and talking to some other industry operators, the best test rate or the best IP 30 rate may not – and I repeat may not ultimately be your best well .So it's very important for us and the shareholders to not get too hung up on some of these initial rates and really look for performance over time because it really is important to see how these things perform once you get through a clean-up phase. But we’re very happy overall with everything that we’re seeing 201 is the only one that is a bit disappointing and our conclusion there is that 201 and 207 are both toe-down configuration and whereas everything else has been drilled toe up, so the heel is actually in a toe-op configurations is lower than the toe. So gravity drainage back to the heel where the water especially the frac water can cleanup and be pulled out of the wellbore a lot easier.

So I think our conclusion is that certainly an early time toe-op is a much more efficient way to clean things up. And possibly there may even be some longer-term productivity recovery effects of the toe-down, only time will tell on that but our guys are looking at the overall program of the – we’re ready to go out and survey 50 to 70 locations and we’re really looking to optimize the well-design and well paths in a toe up to minimize any near-term or longer-term issues that we may see.

The reservoir quality itself that we’re drilling, although we don't have any new core, it appears pretty consistent although we do see some very subtle variations in reservoir quality and that may ultimately play an impact on how fast these wells cleanup. And that would slower cleanup means slower -- lower test rates and probably a lower IP 30 but ultimately a lower decline profile and over time ultimately catching up to our type curve.

So in conclusion of all that we remain very positive on the outlook the play and the production we’re seeing from these wells. The economics remain very very robust and we still have a tremendous amount of opportunity from a technology perspective to further improve recoveries and rates as we see what industry is doing, not around us but further to the northwest, there is a lot of very interesting things going on.

Shifting from Bigstone East, just talk briefly about Bigstone West, we have seen as a matter fact yesterday Chronicle licensed the third well on their 100% lands, very near their very first horizontal that they drilled. So that looks like it will probably be drilled in the second half. We did decline the opportunity to drill a joint well with Chronicle down in the very southwest corner of what we could call Bigstone East, we would have been 45% of that. But we decided that just where it was situated the risk profile was really not what we wanted to do today and on top of that Chronicle would have been the operator and the production would have gone to their plant. So when we opted to not participate they actually canceled that location and moved it over to a 100%, Chronicle well closer to the plant that they would be producing.

But we're very confident the right recipes are going to be unlocked for Bigstone West and as we continue to work on other opportunities out there from an infrastructure perspective we do think that we will be out there drilling sometime in ‘15 to test 30s.

So in terms of the plan for the rest of the year, the budgeted program we had a seven well program but really the seventh well was really just going to be started late in the year, the sixth well was going to be completed at year-end or even early into 2015. But we are now – we’re drilling through breakup, we now have five of those drilled and four on production. So we are a little bit ahead of schedule. We have decided to kind of wait on formally approving an increase in the capital program until we get some visibility or better clarity around the A&D processes that are going on right now, the important one is certainly the Wapiti disposition that we've been working on with the party. And we did try to provide as much information as we could given that these kind of processes are very sensitive and need to remain very confidential but it is moving along as we would expect with really no hiccups and we’re hoping that as we get through the summer here and early September we’re into the signing of the T&S and closing a month or so after that.

So all is going well there, there are some other things we’re working on as well. We communicated in the past our desired shopping list of opportunities that we like to pursue in Bigstone, we continue to do that, some of which are moving forward and we do need to see clarity on some of that as well kind of before we formalize any change to the capital program and guidance for that matter for the rest of ‘14 and looking in 2015. So but everything is proceeding as we would've expected.

So when we look at we were able to achieve in through the breakup of this year and if we can get these next the last two wells done before year-end do the same thing next year even with one rig we could be four wells or 50% ahead of schedule of our 2015 program as we laid out in the five-year plan .So we’re ahead of schedule, we can get these dispositions and some of the acquisition work done and have clarity on capital, I think we’re in a position to very at least be well ahead of what we had originally forecast in the five-year plans, very excited about reporting that as we get into September.

So in terms of the 2014 drilling program we did communicate that we’re fully funded for that program, the expansion to a second rig really does tie closely to the sale of the Wapiti assets and we really need to see that.

So with that, I will close. I would like to say that we continue to see significant value creation. Our internal estimates on our reserves are double what they were last year, approaching 800 million of reserve value or NAV is slightly over $4 a BOE at June 30 and we are almost 70% bigger than we were at year-end ‘13 on a production reserve basis. So things are going extremely well and we’re very happy with the progress we’re making.

So with that, I'd like to open it up for questions.

Question-and-Answer Session


(Operator Instructions) Kurt Molnar of Raymond James.

Kurt Molnar - Raymond James

Just a couple questions. Dave, you spent some time on the variability of the performance of the curves and the makeup of the hydrocarbons. Just also wanted to check in on any correlation you’re seeing on length of lateral having impact to type curves simply because the newest well that you’re fracing as we speak is certainly one of your longer laterals. And then also wanted to see if you’ve seen any correlations in terms of the thicknesses of pay given that the new well drilling I believe is into one of the area thicker sections of the East Bigstone, Montney. So those are my two for you. And then for Brian, was just curious as to whether you’ve run any NPV curves under a scenario where you've optimized the netbacks/gas [ph] on the Montney volumes?

David Reid

In terms of well lengths, difficult in early time here to quantify benefits of horizontal length from the actual production but we have done some pretty significant reservoir modeling and history matching on with the data we do have. And Rod and his group are very convinced that certainly the longer the well the greater access to reserves are there. So length does matter here from our perspective. One of the things that the guys are anxious to try and we may see that on the next couple of wells, maybe it's second or third well out but we do have technology changing such that it’s early stages we could be going to 40 or 50 just because of that change in some of the technology around the ball drop acre system, so increased density is something that we do want to test with our – bind with our longer extended reach laterals. We do think that in terms of ultimate recovery the longer horizontals will ultimately do better.

Thickness is important and we do think that the benefit of the hybrid part of this -- of our frac program is very important in the thicker part of this. We do think that 326 on a 5HM and permeability thickness is a great location because it is in one of the thickest very clean looking sand bodies of the east Bigstone. So we’re very excited to test that. 821 is a good example of looking at pay thickness because as you -- this was the west to east well on the east side of Bigstone, so the pay thickness at the toe was actually some of the thinness that we have drilled and we don't see prospectivity go much beyond two or three sections in the east of that and it has been. So we are looking forward to seeing the longer-term productivity of that well. And although it's flattening out nicely and really starting to look like a 15 to 24, 15 to 21 in terms of decline profile and we think it will ultimately crossover our type curve, maybe it's not six months but it might be nine months or a year but we do think that the pay thickness probably plays a bigger role in there than the horizontal length in terms of performance.

Brian Kohlhammer

On the NPV of the yield economics [ph], incremental savings that we see from the additional projects –

Kurt Molnar - Raymond James

Yeah, if you get out to $45 kind of netbacks if everything else just pushed and pulled, have you run any kind of NPV math as to what that might mean?

Brian Kohlhammer

Yeah, we still haven’t got an updated case that we’re just putting on those projects, we’re getting engineering work done on them. I don’t have a revised type well to take into account what might the cost savings be on an average type curve.

Kurt Molnar - Raymond James

That can wait, I was just curious as to whether you’ve run it. One final question you made reference as well in terms of egress that a future date you might find yourselves going through deep cut facility, have you guys done any initial work as to what the NGL cocktail would be in terms of barrels per million under a deep cut scenario?

David Reid

I don't have that in hand but yes, the guys in our discussions with Pembina they have taken our gas analysis and run it through their system in terms of recovery. We would see pretty good bump in our propane recovery and then C2 in our gas is quite rich as well, I don’t have a number off the top of my head but it will be quite significant for us. And the reason that they like our Montney gas composition is that it’s going to help their overall deep cut process because of the threes and fours that we have in the system. Even going through K3 because of their lean oil NGL recoveries we’re going to see an improved propane recovery that we -- over and above what KA was providing. So there's benefit both through the deep cut as well as some of the gases that will continue to go through SemCAMS.


(Operator Instructions) There are no further questions registered at this time. I would like to turn the meeting back over to Mr. Reid.

David Reid

Thank you, Melanie and I’d like to thank everybody for joining us today, and if there's anything that we haven't addressed please feel free to give Brian or myself a call and look forward to communicating as we get into September some time just where we've gone with the disposition process and looking at the capital program for the remainder of the year. So hopefully we will have that visibility in September sometime. So again thank you very much and you guys have a great day.


Thank you. The conference has now ended. Please disconnect your lines at this time. We thank you for your participation.

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