Eversource Energy (ES) — Q3 2018 Earnings Call Transcript

Thank you, Hilda. Good morning and thank you for joining us. I'm Jeff Kotkin, Eversource Energy's Vice President for Investor Relations. During this call, we'll be referencing slides that we posted last night on our website. As you can see on slide 1, some of the statements made during this investor call may be forward-looking as defined within the meaning of the Safe Harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on management's current expectations and are subject to risk and uncertainty, which may cause the actual results to differ materially from forecasts and projections. Some of these factors are set forth in the news release issued yesterday. Additional information about the various factors that may cause actual results to differ can be found in our Annual Report on Form 10-K for the year ended December 31, 2017, and on Form 10-Q for the three months ended June 30, 2018. Additionally, our explanation of how and why we use certain non-GAAP measures is contained within our news release and the slides we posted last night and in our most recent 10-K. Speaking today will be Phil Lembo, our Executive Vice President and CFO. Also joining us today are John Moreira, our Treasurer and Senior VP for Finance and Regulatory; and Jay Buth, our VP and Controller. Now I will turn to slide 2 and turn over the call to Phil.

Thanks, Jeff. Good morning. This morning, I'll summarize our third quarter results and recap some recent state and federal regulatory proceedings. Overall, we're very pleased with the results for the quarter and for the first nine months of the year. We've been consistent with our expectations and we continue to target full-year earnings per share between $3.20 and $3.30 per share, as well as our 5% to 7% long-term earnings per share growth rate. We've also made very good progress on a number of important initiatives and continue to provide top-tier reliability and service to our customers. Starting with slide number 2, we earned $0.91 per share in the third quarter of 2018 compared with earnings of $0.82 per share in the third quarter last year. As noted in the earnings release, the $0.91 includes two non-recurring items. One involves the impairment of our investment in Access Northeast and the other involves some tax benefits. I'll provide more details on these impacts in a minute. Turning to our core business results, our electric distribution segment earned $0.55 per share in the third quarter of 2018 compared to $0.50 per share in the third quarter of last year. The primary driver behind the improvement was higher distribution margin. This resulted from new rate plans in effect in Connecticut and Massachusetts, and higher sales at Public Service of New Hampshire where we're not yet decoupled. Additionally, you may recall from our second quarter results that the implementation of decoupling this year for NSTAR Electric in lieu of our former loss-based revenue mechanism resulted in higher year-over-year revenues in peak use quarters, such as the third, and lower revenues in shoulder quarters, such as the second quarter. Partially offsetting the higher margin was the absence of the New Hampshire generation earnings, and higher depreciation, amortization and property tax expense, mostly at Connecticut Light and Power. Our electric transmission segment earned $0.34 per share in the third quarter of 2018 compared to $0.31 in the third quarter of 2017. Improved results were due primarily to an increased level of our investment in transmission facilities this year. Our natural gas distribution segment lost $0.04 per share in the third quarter compared to a loss of $0.02 per share in the third quarter of 2017. The change was primarily due to higher operation and maintenance expense in the gas business. Our water distribution segment, which is new this year as a result of our last December's acquisition of Aquarion Water, earned $0.06 per share in the third quarter of this year. More than half of Aquarion's earnings are typically realized in the third quarter when customer usage is at its highest. Eversource parent and other earned $1 million in the third quarter of 2018, or less than $0.01 a share, compared with earnings of $0.03 per share in the third quarter of 2017. Parent and other results reflect two significant non-recurring items. First, the Access Northeast impairment of $26 million after tax, or $0.08 per share, represents all of our investment in the project. While we've made progress in most New England states in seeking natural gas capacity contracts with electric distribution companies, the Massachusetts Supreme Judicial Court ruled in the summer of 2016 that the state electric utilities cannot sign such contracts without a change in law. At this time, despite projected regional energy savings of $1 billion a year, we do not see a clear path to achieving new legislation in Massachusetts, particularly in light of recent unfortunate events outside of Eversource's service territory in the Merrimack Valley region of the state. As a result, we've concluded that our investment in Access Northeast is impaired. Also in the third quarter of 2018, we filed our final 2017 federal and state corporate income tax returns. There were several discrete items related to legislative tax code changes that reduced our tax obligations. Together, these reductions totaled $18 million or about $0.06 per share. Tax reform had no material impact on our 2017 results and we do not expect additional impacts going forward. From financial results I'll turn to slide 3 in recent regulatory developments. In September, we joined with the Connecticut Office of Consumer Counsel and the prosecutorial unit of PURA in filing a settlement on our Yankee Gas three-year rate proposal. The settlement is now before regulators for a review, and we expect the final decision in the fourth quarter. The rate plan will be effective on November 15, 2018, and includes three moderate increases in distribution rates over a three-year period through calendar 2021. The authorized ROE will be 9.3%, a slight increase from existing levels. We will also implement revenue decoupling and a capital tracker that will enable us to accelerate the replacement of older cast iron and unprotected steel pipe. We consider the settlement to be a constructive outcome of the rate review and marks the second long-term rate settlement we've achieved in Connecticut just this year. The CL&P review, as you may recall, was settled in January and new rates were effective in May. When you also consider NSTAR Electric's five-year rate plan that was effective in February of this year, we find ourselves in a position of having long-term rate predictability in three of our largest distribution jurisdictions, with both decoupling and capital trackers for certain major investments. It means that for several years we'll be able to focus on just running the business to the best of our customers rather than spending substantial time and resources on rate reviews. We've also had what I would consider positive news at FERC in mid-October. FERC commissioners voted three to nil to implement a new methodology for reviewing and settling rate electric transmission ROE cases. Rather than solely relying on the commission's discounted cash flow methodology, FERC is now proposing that going forward it would average the DCF, the CAPM, and risk premium, and expected earnings methodologies in determining new authorized ROEs. FERC's proposed ruling was a result of four serial complaints that were filed between 2011 and 2016 by complainants who asked FERC to lower the ROEs earned by the New England Transmission Owners. You may recall that while all four complaints moved through the hearing process and secured ALJ recommended decisions, only the first one was voted on by FERC. That 2014 decision was appealed to the D.C. Circuit Court of Appeals, which vacated the decision and remanded the case back to FERC in April of 2017. FERC's new methodology addresses the issues raised by the appeals court in the first case, but has not yet produced a new authorized ROE for New England. In its ruling, FERC asked the parties through the ROE complaints to file briefs and their own calculations for a new ROE for the region using the core methodologies for each of the four complaint periods. The briefing process will likely continue through early next year, and it's not clear when FERC will actually decide on each of the four complaints, the oldest of which dates back to October of 2011. Until we receive final rulings, and as instructed by FERC, we'll continue to bill customers based on the commission's 2014 decision on the first complaint, which calls for a base ROE of 10.57% and a cap on what any single project can earn of 11.74%. Now FERC has not ruled on any of the four complaints yet, but in the illustrative calculation that FERC described in its order would result in a modestly lower base ROE of 10.41% and a higher cap of 13.08%. We are still a ways away from a final decision, but such levels, if ultimately approved by FERC, would not result in significant changes to our overall transmission ROEs. While we await FERC's actions settling our actual ROE, we applaud the commission's intention to reduce the volatility of its ROE methodology. Using a DCF methodology exclusively resulted in wide swings in potential results depending on which companies were at the high end or the low end of the peer analysis, and whether the subject company was widely or lightly covered by sell-side analysts. As you know, there were situations where a change in long-term growth rate estimates for a single company by just one analyst could result in tens of millions of dollars in higher or lower earnings for New England Transmission Owners. Additionally, it appears that FERC is tightening the threshold to be applied to existing ROEs before it sets an ROE complaint for hearing. We anticipate that changes will provide more stability in transmission returns, thereby encouraging more investment in a critical industry sector. This order follows the filing of a settlement in August regarding transparency of New England's transmission formula rates. The settlement provides increased transparency, simplicity, and the opportunity for various stakeholders to review the annual rates. The settlement is now before the ALJ awaiting certification and after that it will go to the commission for a decision. It followed a lengthy and successful negotiation process between transmission owners and representatives of customers and state regulators, but it does not affect our ROEs. Finally, I'll turn to our capital program in slide 4. As you probably recall during our August 1 earnings call, we updated our 2019 through 2021 capital program, adding about $600 million of spending in our core business. We continue to refine our estimates for those three years in anticipation of laying out a revised long-term capital investment plan during our February earnings call, one that will also include estimates for the year 2022. While we're not yet ready to provide revisions to years 2019, 2020, and 2021, I do expect that the February capital expenditures projections that we incorporate into our 10-K will be higher than the $7.1 billion estimate on this slide. More to come on that early next year as our plans get finalized. With that, I'll turn the call back over to Jeff for Q&A.

Thank you, Phil. And I'll turn the call back to Hilda to just to remind you how to enter your questions. Hilda?

Thank you very much. Our first question this morning is from Greg Gordon from Evercore. Good morning, Greg.

Hey. Good morning, guys. I apologize I dialed in a little bit late because the Vistro call went a little long there. A little bit higher beta than you might have expected, so you got to listen to all the Q&A. One, can you just orient us a little bit on where the earnings growth targets are now and where your $7.1 billion rate base growth projection you think puts you inside that guidance range?

Yes, Greg. Good morning. Thanks for taking this call. I missed this conference call. Our earnings growth target is driven by our core business. Our earnings growth is 5% to 7%, and we feel comfortable that we'll be in the middle of that range going forward. And really that is driven by the capital program that we have in place at the transmission business, as well as various operating companies. In addition, the strong emphasis and focus on controlling our costs. So really 5% to 7%, in the middle of that is where we've been guiding to.

Okay. So you're in the – you feel like you're tracking to the guidance range today but you just indicated that you're confident that there's additional capital spending that could be added to that plan that would be beneficial to customers. We'll see that in February. Is that going to sort of potentially extend the growth rate as you move from 2019 to 2021 to maybe 2022, or could that potentially be additive to earnings potential during the current forecast period?

Well, it could be both, Greg. In February we'll be adding a new year on so certainly we'll have to extend or talk about the extension of that 5% to 7% into that time period. Depending on where we land in terms of the customer program – the beneficial nature of these capital programs for our customers, depending on what that ultimately ends up being that could move you in the range. So, I do feel good about where we are and where we're headed.

Okay. One last question, then I'll cede to the queue. Customers must be really suffering with high overall energy costs in the region, especially during the winter months, given the potential for ongoing scarcity events in terms of gas supply. How do you think about managing customer rate impacts? How tight do you expect the winter of 2018, 2019 to be, and how might that impact reliability? How do you plan for that?

Well, certainly fuel security and pricing, especially during the winter are key considerations in New England and discussions have been ongoing for a while there as you pointed out. For our customers, as you know we're not in the generation business and we buy our customers who remain with us on last resort or basic service. We go out into the marketplace every six months to secure their energy needs. We do see that in the winter that the pricing of those contracts does spike as a result of constraints in the region. So, we're trying to work through FERC, which has dockets open on fuel security there at the ISO. New England is evaluating fuel security and certainly it's an issue that we've tried to be in front of in the region. In terms of reliability, our reliability is really top-tier and we continue to focus on that. But certainly, if you take units out of the system like Pilgrim, which is planning to retire in 2019, that just puts more and more pressure on the constraints in the region.

Thank you guys. Take care.

Thanks, Greg.

Thanks, Greg. Next question is from Mike Weinstein from Credit Suisse. Good morning, Mike.

Hi. Good morning guys.

Good morning.

Hey, I'm wondering if you could maybe bracket or talk a little bit about the annual capital spending that you anticipate from grid monetization in both Connecticut and Massachusetts going forward. I know that this is probably going to be a topic at the upcoming EI. But I just wanted to see if maybe you could start talking about it now in terms of how much you anticipate things increasing going forward.

Well, thanks, Mike. I guess it's different by state as you point out you're asking about. In Massachusetts, we really have approval in our current rate plan and additional grid modernization provisions for $233 million of spending. We're well underway of implementing, the core of that being our energy storage programs. We have two installations for that that are moving along well, as well as initiating our EV infrastructure build in addition to other automation types of projects. So right now that is the approved level in Massachusetts, $233 million. In the Massachusetts order, they set it up as just like we do more or less for our energy efficiency program where it's going to be an ongoing three-year cycle. As we get another year into this program, we'll be filing a plan for the next three-year cycle. So really at this stage, the only thing in our plan is what's approved, the $233 million. In Connecticut, there's a distribution planning and grid modernization docket that's been ongoing for many months, and really it concluded just recently at the end of October with some hearings. There will be some briefs filed by the end of November, and a decision on that is expected sometime in January of 2019. The decision likely will be more about what types of things should be put into a filing to go in; it won't be an approval of X amount of dollars for Y number of projects. So, I think we're a bit away on that in terms of Connecticut and New Hampshire is really in the early stages and has initiated a docket, but there haven't been any programs approved at this stage. Until we get a little bit more clarity, I don't think that by EI we'll have any more clarity than today. We think that the programs we've been implementing in terms of storage and EV infrastructure have a long runway and provide many benefits to customers over many years. So likely in the future in other grid modernization dockets, we'll be filing for programs that address those two issues as well as others. But at this stage, there's no further dollar level associated.

Got you. And on electric transmission, given the FERC current comments regarding the methodology in New England for determining ROEs, are there any specific projects or things that are being held back right now by a lack of a policy or the uncertainty over it that might come out once FERC actually solidifies how it's going to treat those assets?

Well, I think the direction is certainly seems to be converging around sort of the numbers that we have in place here in Massachusetts now or in New England now, and what FERC gave as an illustrative number in that order. Those numbers are good numbers for that business considering the risk profile and how long it takes to site and construct these projects, so certainly – it's in the appropriate range. So I'd say there's nothing really that's being held back or nothing that would be advanced per se given where the plus and minus of where that FERC ROE and the incentives are right now.

Okay. Thank you very much.

Thanks, Mike. Next question is from Angie Storozynski from Macquarie. Good morning, Angie.

Good morning. So I have two questions. One, if you could provide us with an update on your water growth plans, I'm talking M&A. What's the current status of your bid or interest in that Connecticut Water? And separately on offshore wind, we saw Ørsted's acquisition of Deepwater, and I'm just wondering if that's in any way reflective of growth prospects for your joint venture with Ørsted or is it completely unrelated. Thank you.

Yeah, sure. Well, thanks for those questions, Angie. In terms of the first one, regarding water growth, our outlook hasn't changed. We think that the opportunities in the water business are very synergistic with our business and we like this growth story. There are many infrastructure needs that require investment. We believe that most of the growth will come through the smaller roll-ups of distressed or local water companies in the region. We also mentioned that with that, there could be some opportunistic larger M&A. As you pointed out, regarding Connecticut Water, we are not involved in that at this stage. We had a bid that was trumped by the other party, and we stated that we would not put in a number that we didn't think created value for our shareholders. So we're not involved in that activity at this stage. I believe they are moving through their shareholder approval process at this stage, and also through their regulatory process in both Connecticut and Maine. For offshore wind, we have a very good relationship with Ørsted, and we're fully aligned on Bay State Wind. We do not see any limitations regarding opportunities there arising from what we expected when we first got involved with the partnership with them.

Just one follow-up, so on Connecticut Water: You are not even participating in the regulatory approval process. I thought that you were an intervener or you were planning to be an intervener in that case in Connecticut?

Yes, we are an intervener in the regulatory process, that's correct. But in terms of the bidding process for the company, we're not involved. As an interested party in the area where they operate, we are interveners in the case.

Very good. Thank you.

Thank you, Angie. Next question is from Julien Dumoulin-Smith from Bank of America. Good morning, Julien.

Hey. Good morning team. Just to clarify a little bit on the last question, can you elaborate more about the opportunities reported from the Deepwater acquisition and how you see it? Specifically, which project sites are you all considering for bidding as a joint venture for these upcoming auctions? Does it impede your plans, or does the added scale improve the JV's advantage for bidding into some of these upcoming RFPs? I want to be clear on that.

Sure. I believe you asked a number of things there. Ørsted and Deepwater are the combination there; it's not an Eversource activity. As I said, we're fully aligned on the Bay State Wind partnership, and our existing agreements with them anticipate this kind of scenario. We feel confident about the opportunities that exist for the Bay State Wind partnership moving forward. We do have more RFPs scheduled in Massachusetts. As you're aware, some of those contracts in New England are now progressing through the contracting phase, or in some cases like Massachusetts, through the regulatory approval process. There are opportunities arising in New York as well as an expected RFP in Massachusetts for around 800 megawatts probably in the first quarter of the upcoming year. In Connecticut, an open zero-carbon RFP exists. There are many opportunities for the Bay State Wind partnership to explore, and we feel optimistic about our prospects.

Got it. Excellent. And then just a follow-up here. Some of your peers in the state have encountered some fairly tragic events. How does that modify, if at all, any of your gas modernization efforts? I know there's a specific modernization filing in the state as well. I want to ensure we fully understand the read-throughs from the events that occurred and any potential upcoming filings that you might be making.

Sure. Just last night, it was announced there will be an independent evaluation statewide of the gas distribution network, and the Public Utilities Commission is overseeing that. This is expected to last 90 to 120 days. Some items that result from this review may impact capital plans, etc. At our gas property in Massachusetts and Connecticut, we've had a fairly active and aggressive program to remove and update our leak-prone infrastructure. We have doubled our spending on this since the program began, where we used to spend $30 million to $40 million, we're now spending $90 million to replace leak-prone infrastructure and move it out quicker than it would otherwise be. With that and other activities we've implemented regarding combining operations and a focus on quality assurance, we've done a lot and plan to do much more in this space going forward.

Got it. All right. Excellent. Thank you all.

Thank you, Julien. Our next question is from Michael Lapides from Goldman. Good morning, Michael.

Good morning, guys. Thank you for taking my question. I'm just curious when you think about the opportunities to manage operations and maintenance further. You've done a sizable job controlling costs since the combination with Northeast Utilities; where do you think the biggest opportunities are from here? I mean, it seems and looks like a lot of the low-hanging fruit has already been seized over the last few years. Where's the next incremental step change if there's one?

Well, Michael, thank you. We pride ourselves on being a leader in managing our business cost-effectively, benefiting our customers. Since the merger, we've eliminated $500 million of costs and improved our reliability and customer service levels dramatically compared to prior to the merger. It is possible to lower costs while improving service at the same time, and we continue to identify opportunities to do that. Much of this is driven by automation and standardizing operations between properties across states. As you pointed out, the runway gets harder; the low-hanging fruit, as you say, is certainly less common now. However, that doesn't mean we're not focused on it. We guided to about a 1% reduction this year, and we're currently on track to meet that target. The next wave of opportunities lies in changing systems and standardizing them. In the earlier phases post-merger, we initially focused on corporate systems, and now we are moving more towards our field operations with automation, providing better tools to serve customers and lower costs. These initiatives are being rolled out now and set for deployment next year.

Got it. Okay. One other question for you. We've seen in the Northeast many other water utilities consolidate some of the municipal water and wastewater systems. How are you thinking about that opportunity set? More importantly, how do you quantify how big of a potential addressable market that is for you over the coming years, and is it something that's easy to bolt into Aquarion or not?

Aquarion has regularly rolled in municipal systems, and I believe we could do more. Given its prior ownership model, some of this activity was inhibited, so it won't drive customer growth by 10%, but it's a steady 1% to 2% a year that we can grow by rolling up these systems. In the current environment, municipalities face tight budgets and more stringent environmental regulations. They may ponder the decision to invest in new infrastructure versus other town needs, like new schools or fire trucks. This creates opportunities, as there is a proactive need for utility integration. We currently have a few pending applications at PURA in Connecticut for regulatory approval regarding smaller systems, so we still see opportunities moving forward.

Got it. Thank you, guys. Much appreciated.

Thank you, Michael.

Thanks, Michael. The next question is from Paul Patterson from Glenrock. Good morning, Paul.

Good morning. How are you doing?

Good, Paul. How are you?

All right. I wanted to just follow up on the transmission ROE FERC issue, and I apologize, could you just describe the volatility potentially with respect to how that proposal might work? If I'm correct, could you describe your calculations for the more recent complaint periods? What would they be if the proposal were enacted as proposed? Do you follow me?

I do follow you, but I just want to clarify that when I spoke about volatility, it was regarding the introduction of an average of multiple methods, as well as setting the bar higher concerning introducing new complaints, which should mitigate some of the volatility.

Okay. I got you. Thanks for the clarification.

We have looked closely at the case and are reserving. We've examined all of the complaints and believe that the 10.57% and incentives cap level appropriately handles everything. If there's a change, we haven't projected all the details of the calculations yet, as the first calculation sets the basis for the second, etc. However, we don't foresee any major swings. We've disclosed that a 10-basis point change in the ROE could have a $3 million impact. However, the current proposal looks good for now.

Okay. So just to understand this, if the current outlook holds, it seems you'd be in the same ballpark, this 10.41% base ROE for the subsequent complaint periods, roughly speaking. Do I have that right?

That’s correct. We're assessing it currently from our preliminary observations and continue to collaborate with all of the transmission owners. This isn't just an Eversource item; it’s a regional concern.

Okay. And there was some discussion about incentives. Do you foresee any change in the incentives FERC has historically granted in combination with this order or following it, or do you have any sense about that at all?

Yes, I believe that they will be looking into that. That had been a silenced item prior, but I think it will be discussed in the upcoming briefs and reply briefs.

I noticed that Northern Pass remains a topic in New Hampshire. It was even mentioned in the gubernatorial debate recently. I am curious about where Northern Pass stands, particularly regarding its potential future.

The New Hampshire Supreme Court has accepted our appeal on the Site Evaluation Committee rulings. They directed the regulators to certify the record and return it next month. The process will be evaluated at the New Hampshire Supreme Court regarding our current Northern Pass proposal. This project is still very much in the works.

So, I know what happened there, but it's still out there, and some similar proposals to Northern Pass have encountered challenges. I'm just wondering how we should think about that going forward.

It's difficult enough for me to forecast the timing of existing projects as opposed to speculating on potential ones that may arise down the road. However, there are ambitious environmental targets for the region. There has been an increase—especially in Massachusetts, where the latest session authorized additional offshore wind projects. Overall, I believe the trend is moving towards seeking more projects that deliver clean energy into the region, but I can't point to any specific project currently.

I understand that. So as I see it, the next step would be waiting for the Site Evaluation Committee to respond to the Supreme Court ruling. Is that correct?

That is correct. Thank you, Paul.

Thank you, Paul. The next question is from Praful Mehta from Citi. Good morning, Praful.

Good morning. Hi, guys.

Hi.

So maybe we touch on offshore wind first. Regarding the price of $65 that cleared—how do you see pricing for offshore wind? There seems to be some disconnect in the market. Do you think those prices are too low or more broadly, how do you see the opportunity set for offshore wind relative to the prices we’ve been seeing?

Well, Praful, we did not win the bid, so the pricing that was accepted was below what we deemed appropriate for the risk profile and return levels. The determination of whether those prices are adequate is something best posed to the winning bidder. We observed that as more projects develop, the supply chain improves, leading to lower costs. However, I cannot speak to specifics regarding pricing; that's up for the party that won to explain why they chose to bid at that level.

Got you. So if prices were to remain at these levels, do you expect winning bids in the future, or is there, I guess, a disconnect?

Sure. I mean, when you say in the future, as I mentioned, costs change, and prices decrease due to better technologies and improvements in the supply chain. Regulatory uncertainties also play a role in the overall bid process. Bid calculations consider component pricing, among other factors. However, future tax credit availability may also affect pricing. So estimating future pricing without knowing tax policy changes is difficult.

Agreed. That’s very helpful. Appreciate the insight. One last quick question about Northern Pass. Just for clarification, does this mean that there is still an opportunity based on the legal process, or is that more of a check? Is there still a realistic possibility of Northern Pass coming back?

Yes, in short, yes.

All right. Thank you, Praful. The next question is from Andrew Weisel from Scotia Howard Weil. Good morning, Andrew.

Hey, good morning everyone. First just a quick one on the Access Northeast impairment: Is that an accounting item, or are you no longer going to pursue the project—or something similar?

Well, it is an accounting item. It's an accounting determination driven by the facts and circumstances and accounting guidance. Just to elaborate on that: Certainly, Massachusetts legislation would have to be instituted under the current system to enable a contract to be signed. No such legislation was enacted in the recent session that ended during the third quarter. Additionally, concerning previous events in Massachusetts, we believe that may create challenges in securing legislation in the future.

Okay. Understood. Then, lastly on the balance sheet: I'm not trying to get ahead of the February CapEx update, but how are you thinking about share repurchases? You've mentioned before that that was a safety net, yet some of these major projects seem unlikely to require near-term capital. How much of a cash stockpile do you want to hold?

As we said, our business focuses on developing infrastructure. Our capital plan has expanded, indicating that we plan to invest more in regulated infrastructure projects. That's where our focus will remain; share repurchase isn't a priority. However, we've done them in the past, and there are inquiries, but they aren't at the top of our agenda.

All right. Thank you.

Great.

Thank you, Andrew. That was the last question that we had in the queue. So I want to thank you for joining us today. If you have follow-ups, please give us a call later today. Good luck with the rest of the call. Take care.