Ladies and gentlemen, thank you for standing by, and welcome to the Pembina Pipeline Corporation's third quarter results conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star one on your telephone. Please be advised that today's conference is being recorded. If you require any further assistance, please press star zero. I would now like to hand the conference over to your speaker today, Scott Burrows, Senior Vice President and Chief Financial Officer. Thank you. Please go ahead.
Thank you, Christina. Good morning, everyone, and welcome to Pembina's conference call and webcast to review highlights from the third quarter of 2019. I'm Scott Burrows, Pembina's Vice President and Chief Financial Officer. On the call with me today are Mick Dilger, Pembina's President and Chief Executive Officer, Jason Wiun, Senior Vice President and Chief Operating Officer, Pipelines, Jaret Sprott, Senior Vice President and Chief Operating Officer, Facilities, and Stu Taylor, Senior Vice President, Marketing and New Ventures and Corporate Development Officer. Before we start, I'd like to remind you that some of the comments made today may be forward-looking in nature and are based on Pembina's current expectations, estimates, judgments, and projections. Forward-looking statements we may express or imply today are subject to risks and uncertainties, which could cause actual results to differ materially from expectations. Further, some of the information provided refers to non-GAAP measures.
To learn more about these forward-looking statements and non-GAAP measures, please see the company's various financial reports, which are available at pembina.com and on both SEDAR and EDGAR. Earnings during the quarter were positively impacted by higher gross profit in both facilities and marketing and new ventures due to higher terminalling revenue, combined with realized and unrealized gains from commodity-related derivative contracts, respectively, partially offset by lower pipeline gross profit as a result of higher deferred revenue recognition during the third quarter of 2018 compared to the third quarter of 2019. Pembina's third-quarter results included adjusted EBITDA of CAD 736 million, which was consistent with the same period in 2018. Quarterly results were driven by period-over-period increases in the pipelines and facilities divisions as a result of new assets being placed into service, including Phase IV and V Peace expansions, Redwater Cogeneration, and Burstall Ethane Storage.
Also impacting adjusted EBITDA was the adoption of IFRS 16, offset by decreased NGL and crude margins in marketing and new ventures due to a lower pricing environment and a CAD 5 million one-time payment within one of our joint ventures. Adjusted cash flow from operating activities was also consistent with the same period in 2018 at CAD 530 million, primarily due to an increase in operating results after adjusting for non-cash items, offset by an increase in current tax expense, timing of preferred share dividend payments, and lower distributions from our equity-accounted investees. Based on year-to-date results and our outlook for the balance of the year, we have raised the low end of our adjusted EBITDA guidance range by CAD 100 million. The revised guidance range is now CAD 2.95 billion-CAD 3.05 billion.
Further, current income tax expense in 2019 is now anticipated to be CAD 250 million to CAD 270 million, with the increase over prior guidance related to higher taxable income in the current year and adjustments to prior period tax deductions. Now I will turn things over to Mick for an update on some of our key growth projects and business development activities.
Thanks, Scott. Good morning, everyone. The highlight of the quarter was, of course, the announcement of our CAD 4.35 billion acquisition of Kinder Morgan Canada and the U.S. portion of Cochin Pipeline. This acquisition is highly strategic for Pembina, providing enhanced integration with our existing franchise, extension of our value chain, and clear visibility to creating long-term value for all stakeholders. Since our initial announcement, we have received clearance under the Canada Transportation Act and early termination from the U.S. Federal Trade Commission pursuant to the Hart-Scott-Rodino Act. We are making progress on satisfying the remaining closing conditions and look forward to the December 10, 2019, Kinder Morgan Canada shareholder vote. Our teams are busy preparing for closing, which we now expect will occur in the first quarter of 2020. We remain solidly of the view this transaction will make us better, not just bigger.
We are also pleased to announce that we have approved the first stage of the Peace Phase IX expansion. Since our Phase VIII announcement earlier this year, we have continued to secure additional long-term contracts with producers operating in the Montney. The first stage of Phase IX includes pipelines to bottleneck the corridor north of Gordondale, as well as upgrade one pump station. This will allow us to access approximately 100,000 barrels a day of latent downstream capacity. Phase IX also enables us to complete our vision of full product segregation across Peace Pipeline. This will drive operational and capital efficiencies, strengthen Pembina's competitive advantage, and ultimately benefit our customers. This all leads to further very low-cost bottlenecking opportunities throughout the system, which we call Phase 10, and which we are working on next.
We have now approximately CAD 1.8 billion of Peace expansions underway, which in aggregate are trending on time and on budget. Also announced was the approval of CAD 120 million cogeneration facility at Empress, Alberta, which will provide heat and power to the extraction and fractionation facilities and reduce overall operating costs, and in addition, will provide a reduction in GHG emissions intensity. With this newly announced project and our recently completed project at Redwater, cogeneration is becoming an area of growing competency for Pembina, and we see more opportunities ahead. We're continuing to progress our potential Alliance Pipeline and Aux Sable expansions as well as the Northeast BC Fractionation Facility and look forward to updating the market in due course. Our PDH/PP project continues to progress as engineering, procurement, and construction bids have been received and are currently being evaluated.
Jordan Cove LNG, federal and state permitting process are ongoing. Subsequent to the quarter, FERC revised the schedule for issuance of the final environmental impact statement, now we're expecting that on February 13th of next year. In closing, I'm pleased to report we have released our 2018 ESG performance metrics, which are now available on our website. Recognizing a growing focus on ESG, we are pleased to share our progress in developing two new ESG stands, including a carbon stand and a diversity inclusion stand, where a stand means what we stand for. We're looking forward to providing further information on these developing strategies in future reporting. As always, I would like to thank all of our stakeholders, our customers, our investors, our communities, and our employees for their ongoing support.
With that, we'll wrap things up. Operator, please open up the line for questions.
Certainly. Thank you. At this time, I would like to remind everyone, in order to ask a question, please press star, then the number 1 on your telephone keypad. Our first question comes from Jeremy Tonet from J.P. Morgan. Please go ahead. Your line is open.
Hi, this is Joe for Jeremy. I wanted to start off with the, Peace Phase IX. Congrats on getting that sanctioned and, but you mentioned it's the 1st stage there. Could you talk about what the 2nd stage could look like and, maybe in a timeline for potentially announcing that?
Sure, Joe. This is Jason. Really, if you think about what Phase IX, the broader project that we talked about earlier in the year was, it was really debottlenecking on the west end of our Peace Pipeline system, and then it was a power-up of our pipeline system going into Edmonton from Fox Creek. The portion of the project that we're really talking about is the debottlenecking on the west end of the pipeline, and that really accesses the capacity that we're creating with Phase VII and VIII. The downstream power-up is sort of, I guess, is volume-dependent as our volumes begin to ramp up. We have a fair bit of running room that's been created with our expansions up to this point. The first phase of this really accesses 100,000 barrels of capacity that's there available for us.
Mick introduced the concept of Phase 10. We're probably gonna be looking at optimization opportunities now that we have the ability to segregate our products all the way from La Glace in. We're not batching, we'll be able to tune the way that we operate our pipeline system, and we expect to be able to leverage some more capacity out of the assets that are already in the ground. Ideally, we'll be able to, before we have to proceed with the downstream expansion, which we formerly referred to as Phase IX, we'll be looking at the optimization projects and seeing how much capacity we can get, which is very cheap, effectively free, I guess.
Okay, thanks. That's helpful. Also wanted to ask quickly on the Alliance expansion. You mentioned discussions with customers continuing, anything more you can say there? When you expect discussions with customers to conclude, how that's progressing.
I guess we've been working on that project for a while now. There's a physical separation between production north and south of a large river in the U.S. that sort of segregates that play. We're really focused on the northern side of that. We're talking to the customers producing on that side. The development up there is starting to become more clear as we get towards the end of the year and producers put their budgets together and things like that. We think as we come to the close of the year or very early next year, I think that's when we'll be able to give some more concrete information about it.
Thanks. That's helpful. That's all for me.
Our next question comes from Matthew Taylor from Tudor, Pickering, Holt & Co. Your line is open. Please go ahead.
Hey, good morning, guys. Looks like volumes are down in pipelines because of take or pay recognition that was last year year-over-year. I'm just trying to work through how do you explain that in the context of Phase IV and V coming on, and are you seeing less volumes than you expected there as customers slow drilling plans?
Matt, I would say it's more of a timing issue. Obviously, IFRS 15 came into account last year, and the recognition and the timing of those barrels was more back-end loaded. We didn't really recognize any take or pay revenue in Q1 or Q2 last year, and then we took almost all of it into account in Q3 last year. If you look at this year, there's been more of a smoothing of the recognition of that, just as we've refined some estimates and volume profiles. On a full year basis, when it's all said and done, we obviously will be up in our conventional pipelines because of Phase Four and Five. Really, if you look at the difference between this quarter
Q3 of last year, there's about a CAD 20 million difference. If you normalize that, pipelines would actually be up close to CAD 20 million this quarter. It's really just the timing of the recognition.
Got you. What about the physical volumes? Are you guys seeing the volumes that you expected?
Yeah, the physical volumes are ramping up, throughout each quarter. We're seeing volumes, increments. They're progressing as we expect. On our contract profiles as well, we see a ramp in 2020 and 2021 in terms of the firm contract and take-or-pay profiles as we go forward. If you recall, we put Phase IV and Phase V into service at the end of 2019. The first year of the contract is really the end of 2018 and 2019. As we go into 2020, 2021, that's when volumes continue to ramp on a contract basis.
Okay, that's helpful. Over to LPG. Is that expected to be primarily sourced, just from Redwater being propane? Or would you also consider exporting butane there as well? I just wanted to get some color on how you're thinking about improved Edmonton NGL spreads relative to U.S. benchmarks, and how that would impact other pieces of your business. Specifically, how has this improved domestic pricing been accounted for in your PDH PP assumptions?
Good morning, Matt, Jaret here. With respect to the Prince Rupert Terminal, currently we're only focused on exporting propane from that facility. Customer demand, though, and with some soft pricing on butane in Western Canada, there are a lot of people asking us about the opportunities to export other LPG products off of that. Primarily, right now, we're focused on just the propane molecule. I'll let Stu talk about some of the pricing.
Yeah, Matt, we obviously are watching all of the commodity markets. Yes, we take into account as we update our economics. We are always updating with the most recent. There has been some uplift in some of the commodity value in recent days, and we do account for all of that as we look at it. We still see the basin with an abundant resource and are confident of the feedstock value feeding the PDH and our export facilities being low-cost opportunities that we can get to better net-back pricing in international markets or within better value-added commodities. We watch it all the time. We adjust all our economics and are still excited about both opportunities.
Yeah. Maybe just to clarify, were you guys anticipating or expecting improved domestic pricing here in some of your PDH/PP assumptions, so this is kind of as expected?
Yeah, it's pretty much as expected there. Again, it's a long-term. We're a long ways from being in service. We watch it. Again, it's more relative to what the other opportunities are. What is Mont Belvieu pricing and Conway pricing versus Edmonton pricing? We still believe that we will be advantaged feedstock in the Edmonton area, which supports the PDH/PP economics.
Yeah, Matt, maybe just one incremental comment I'd make is when we sanctioned these projects, we obviously ran multiple scenario analysis and Monte Carlo analysis to take a long-term view of the pricing. It wasn't based off of strip pricing at a point in time that sanctioned the economics. We took a very long-term view of it. That should give you some comfort around that.
Great. Thanks for taking my questions, guys.
Thank you.
Our next question comes from Robert Hope from Scotiabank. Your line is open. Please go ahead.
Morning, everyone. First question is just on the KML transaction. Can you give us an update on any status of the ROFRs there? As a follow-up there, if they are not exercised, would those be of interest to acquire additional interest in?
In terms of your first question, obviously, we're willing to acknowledge that there's a ROFR. We really can't talk about the dynamics of that. We're covered under confidentiality agreements, so can't comment on the specifics, but we would hope to have that wrapped up one way or another by the end of this year. In terms of interest on the other assets, obviously we bought KML overall, so we like all the assets. We haven't had those discussions, but certainly we do like those assets.
All right. Just more broadly speaking, with KML, it does add some additional assets, let's call it in the Chicago area region. With the Alliance expansion and potential Aux Sable expansion, just want to get a sense of how you're thinking about your assets in that region and whether or not that could be a new platform to build off of down there.
Clearly, since we did the Veresen deal and stepped into Aux Sable, we just took over operatorship of that asset, and we're starting to focus on what is possible around that asset. The east leg of Cochin is proximate to the asset, and we're looking at that. It's nothing we paid for in the acquisition, but that certainly is an asset we're studying. We're studying all possibilities downstream. Rob, you know that's how we do it, right? We buy something, we study it, and then we look for additional vertical integration opportunities. Absolutely, we're looking.
All right. I may be a little early there. Appreciate the color. Thank you.
Thank you.
Our next question comes from Robert Catellier from CIBC Capital Markets. Your line is open. Please go ahead.
Rob Catellier from CIBC. Just a couple of questions here. Obviously, we saw Encana re-domicile. I wondered if you can make a comment on what your expectations are for the Veresen Midstream partnership, and specifically their commitment to invest more capital in the area.
Jaret, do you want to take that?
Sure. Good morning, Robert. Jaret here.
Hi, Jaret.
Through Veresen Midstream, we're still seeing CRP, the partnership with Mitsubishi and Encana. We're still seeing a lot of drilling up in that area. This is well documented. They are extremely focused on the liquid-rich portion of that and obviously Pembina benefits. Jason talked about having to debottleneck going west of Gordondale. Obviously, that is primarily due to a significant amount of liquids being found up in that Dawson Creek, Pouce Coupe, all the way up into Fort St. John area. Right now, we don't see any changes based on that announcement yesterday at all. Further to that, we are extremely well-positioned, obviously, on the dry gas side with LNG Canada, phase one going to be coming on stream, and then the one side of that partnership, Mitsubishi's ownership in that and their desire, obviously, to fill drier gas molecules to take those west.
It's business as usual from what we know.
I wonder if you could just comment longer term, what happens with Ruby Pipeline? I think the big leverage point is whether or not Jordan Cove moves forward. Failing that, we're seeing some expansion from GTN, et cetera, coming in the market. What's your updated view on the outlook for Ruby Pipeline?
Rob, this is Jason. With Ruby Pipeline, the contract renewals start coming up at middle to end of 2021, we're working with Kinder Morgan on that. There's a number of different things going on, including there's the ONEOK Pipeline that could be reversed, that goes down into the Rockies space, and it'll create a need for more egress for gas. There's conversions that certain parties are considering of gas egress pipelines to crude service. We're definitely looking at it and we're looking at the options and working really closely with Kinder Morgan, who's the operator of that asset, and looking at all the different scenarios there. Obviously, Jordan Cove would be a really positive outcome there, and the timing of that is still unknown at the moment. I think at the moment it's a bit of a wait and see. Yeah.
It's just my view, but I think that for buyers of gas at Malin, Ruby is an important diversification. If they have a single source of gas, that hub is not nearly as valuable to buyers of gas of having multiple inlets. That really goes back to the reason it was built in the first place. My personal view is that people are not going to abandon diversification. It's just too risky for the buyers at that hub.
Yeah, that makes sense. My last comment is just thank you for putting out that ESG update. Thank you.
Yeah. Thank you. Thanks for noticing.
Our next question comes from Robert Kwan from RBC Capital Markets. Your line is open. Please go ahead.
Good morning. Coming back to KML and the timing. You've tightened it up here into the first quarter of 2020. I'm just wondering, is that based on specific feedback and interactions with the Competition Bureau?
Yes.
Okay. I guess turning to the Empress Cogen facility, you've talked about it reducing costs. I'm just wondering, the economics around that from your perspective, is that based on current math or do you have concerns about future delivered power costs?
What we see happening in the future is wire costs continuing to go up, and this particular cogen will not be on the grid. We'll have demand in excess of this production, and because we're capturing waste heat to offset other natural gas we'd otherwise have to buy, ergo, there's great economics in it. It's just a model. We're very pleased with how the Redwater Cogeneration plant worked out, and we see this as a strong analogy to that. It's the identical unit. Robert, how we build stuff, we build one, we like it, and then we build a lot of them, and we see two, maybe three future opportunities. These are just solid base hits for us to self-supply.
Consider that other projects, like Suncor and other projects like this, are going to continue to pull demand off the grid, which in turn will make the wire costs higher. I think this may be the start of that kind of a trend.
You're clearly developing and constructing these facilities, but is owning the cogen a long-term business strategy? Just given how much private capital is running around low cost of capital, would you look to monetize these things?
It's an option. Scott's got layers of protection if anything ever went wrong at Pembina. We've got layers of stuff that we could do, and that could be one of them. We're in the business of constructing and operating infrastructure, and so this is right down the fairway. As I say, these are solid economics, and we learn something about the electricity business while we're at it, and it's an upstream vertical integration behind our assets into the value chain, so directly connected. For now, it's right down the fairway. It wouldn't be the first thing we would sell, put it that way.
Got it. If I can just finish with guidance and you tightening up the range outside of things like commodity prices and, say, some volumes of the facilities, are there any other key drivers that would move you around in the range or potentially even take you out of the range? How much would those drivers actually have to move to do that?
Robert, the only thing that would really take us out of the range is an absolute crash in commodity prices. Recall that we've put in close to 50% hedges on our NGL business, as well as some pretty significant hedges on our storage book over the winter. It would have to be a pretty dramatic falloff in commodity prices.
Got it. Okay. Thank you very much.
Again, if you would like to ask a question, please press star, then the number one on your telephone keypad. Our next question comes from Andrew Kuske from Credit Suisse. Your line is open. Please go ahead.
Thank you. Good morning. Maybe just following up on the power conversation. To the extent you had cogens that were actually physically connected to the grid, do you see a market environment in the future that's more volatile and that you'd actually sell power into the grid that's excess for you?
We're not in this to be a merchant power player. We're just in it to self-supply and off-grid facilities are clearly more attractive. That's possible, but it's certainly not how we presented it to our board as a merchant power play. With our guardrails of being 80% fee-for-service, that would not be something we would be entering into the merchant power business.
Okay. Appreciate the clarity on that. Maybe just on the budget status on a couple projects. Prince Rupert's trending a little over budget, and I think Duvernay is under budget. What are the drivers that are happening on those two projects? Everything else is sort of down the fairway on time and on budget.
We take more of a portfolio approach, and if everything's under budget, then it means our guys are sandbagging their costs, so that's not good. The inverse. We're focusing from here forward about what the portfolio looks like, and I think that that's the most important guidance that we can give the Street. What's happening or the minutia of what's going on in any given project can be related to scope changes. Maybe we're pre-building. Can be weather related and all that. Our guidance is going to be generic in that regard looking forward.
Okay. One final one, if I may. With the rail curtailment announcement that came out, do you see any major benefit to your business?
Well, if Kinder closes, we're co-owners in really the marquee rail facility in Canada. We don't really know what that means, but it has our attention for sure.
I would just add, any incremental heavy oil production usually comes with condensate demand. Obviously not a direct benefit, but an indirect benefit through hopefully higher produced volumes.
Okay, great. Thank you.
Our next question comes from Patrick Kenny from National Bank Financial. Your line is open. Please go ahead.
Thanks. Hey, guys. Just to follow up on Alliance Pipeline outside of the expansion, and sorry if I missed it here, but when do you expect to extend the existing contracts? How should we think about tolls and term relative to the existing five-year deal?
The first round of contract renewals come up at the end of October, and we've been in active discussion with all our customers, and I think we've made good progress on the extension of some of those terms. I think maybe in the fourth quarter, we can provide an update in terms of what the term of the overall average terms and things like that look like.
Okay, great. Just with KML closing right around the corner here, curious to get your thoughts on what might be the most attractive market right now. Maybe for Scott here, just in terms of the purchase price for US Cochin and thinking about Canadian versus U.S. public debt or perhaps new bank debt or private debt.
Yeah. We have multiple options on that front. To start off, we hedged over 50 or just about 50% of the purchase price at economics, slightly better than our board economics. That was a good start to the funding plan. We obviously took a lot of money off the table back in September with the bond deal we did then at pretty attractive rates to pre-fund a portion of it. As we sit here today, we have an undrawn credit facility. We have an accordion with that credit facility to increase it even further. We have a billion-dollar term loan that we've negotiated that we could draw on as well. From a pure liquidity on closing, obviously no issues there. We have ample capacity.
Longer term, right now we are doing that exact analysis between looking at the U.S. public, the U.S. private, and the Canadian public, and just kind of going through the pros and cons. If you put me on the spot today, I'd say that we're probably likely going to do an issue in the U.S. private placement market.
Okay. That's perfect. Thanks, guys.
Our next question is from Elias Foscolos from Industrial Alliance Securities. Your line is open. Please go ahead.
Good morning.
Morning.
I would like to focus a bit on the cogen facilities, because I sort of clearly see a pattern here with Redwater Empress today and the central utility block. Do you see a further trap line that's internal? I'll push it a bit further. Would they roughly be the same size in terms of dollars, or how do you look at that? You mentioned that you see a trap line.
Yeah. Again, you look at our history, we build the same gas plant over and over, the same frac over and over. You might see us keep building the same kind of 100 million plus or minus unit in a bunch of different locations. A cogen is not part of our PDH PP now, it very well could be in the years to come. Certainly, there'll be sufficient power demand to support that. That's just another example of the opportunities. Again, our focus in the plan we have in front of us is self-supply. It's not merchant power.
Okay. Thanks for that. Moving a bit to PDH PP, a large capital project that I would consider moderately complex. What are you doing on the construction cost mitigation side that might be different to Or what you would consider maybe standard practice, but still like to hear it, to keep those costs in line?
Elias, it's Stuart Taylor talking. We've been very clear from the outset of our EPC contracting strategy to be a lump sum process, lump sum contracts for us. Our model at this point in time is that for the two large packages, the PDH and the PP, we are seeking and working with EPC contractors to receive those lump sum bids. We continue to look at and work with those parties, at this point in time, to look at all cost reductions from watching our labor rates. We've negotiated labor rates in advance. We've ordered our long-lead equipment to remove cost and uncertainty. We're following a process of, as you described, removing cost uncertainty from the project, and we continue to evolve and press that forward.
Great. No change in strategy, correct?
No change in strategy.
Okay. One last thing. Just wondering if, within six weeks or so, you'll provide another capital budget update or not. Could there be potentially new projects, I know there were two announced today, that might come up?
Yeah. We typically put out our capital press release in early December, so you should expect to see that.
Great.
We may have some color on our business and what we're up to, that won't be in the form of promises, but more directional, similar to what you would see in an investor day as part of that release.
Great. Thank you very much for all those answers. That's it for me.
Our next question comes from Ian Gillies from GMP. Your line is open. Please go ahead.
Morning, everyone.
Morning.
With respect to the Watson Island LPG terminal, I know it's not up and running yet, obviously, but are you able to provide a bit of an update on what the potential scope and size could be if the first phase is successful, and what you have room for there?
Yeah, absolutely, Ian. Jaret here. Obviously, customer demand to get products off of the West Coast of British Columbia to either Latin America and/or Asian markets is extremely high. I do want to make sure that we're very focused on getting Phase 1 on stream as per the timeline that we've publicly disclosed and getting all of our permits in place. With respect to that, in the Northeast BC area, as that increased condensate and crude is coming on to fill Jason's pipelines, with that comes incremental associated gas and a lot of NGLs, which is driving a lot of the customer requests with respect to Northeast BC Frac and tying it to potentially a Watson Island expansion in the future. The demand is definitely there, but we are extremely focused on getting Phase 1 up and running.
To be clear, there are expansion opportunities there, but we're evaluating those in concert with Northeast BC Frac development.
Got it. It's perhaps too early to talk about this, but are you able to provide any high-level details around some of, I guess, the operational optimization opportunities with running condensate out of Cochin and also having some of, obviously, the P system running in Edmonton and some of the benefits you may be able to realize there?
We'll do that if and when we close. It's not our place to do that at this time. We've got to focus on closing, and then we'll talk more about our plans there. Realistically, we have our investor day in May. That'd probably be a good time to further outline in detail what our plans are. We stand by that we should be able to realize CAD 50 million of synergies at a very low nominal cost through this acquisition, and then another CAD 50 million according to the types of metrics you've seen from Pembina on average in terms of capital deployment.
Okay. Last one from me. Scott, obviously, the cash tax guidance got bumped up for 2019. Are you able to provide any insights into 2020? I know EBITDA guidance hasn't been provided, but that could be helpful.
Yeah. On a current tax expense basis, we would expect it to be lower than what we're seeing in 2019. Again, that's just the timing of when certain assets are in deferral partnerships, some aren't, as well as some accelerated CCA deductions that start to come into place in 2020. As we sit today, you could expect it to be marginally lower than 2019.
Perfect. Thank you very much. I'll turn it back over.
There are no further questions at this time. I turn the call back over to the presenters.
Well, thanks everybody. Hope you had a great Halloween last night, and thanks for your ongoing support. Have a great weekend.
Ladies and gentlemen, this concludes today's conference call. You may now disconnect.