埃克西爾能源 (XEL) 2018 Q1 法說會逐字稿

Good day, and welcome to the Xcel Energy First Quarter 2018 Earnings Conference Call. Today's conference is being recorded.

And at this time, I'd like to turn the conference over to Paul Johnson, Vice President of Investor Relations. Please go ahead, sir.

Good morning, and welcome to Xcel Energy's 2018 First Quarter Earnings Release Conference Call.

Joining me today are Ben Fowke, Chairman, President and Chief Executive Officer; and Bob Frenzel, Executive Vice President and Chief Financial Officer. In addition, we have other members of the management team in the room to answer your questions.

This morning, we'll review our first quarter results and update you on recent business and regulatory developments. Slides that accompany today's call are available on our website.

As a reminder, some of the comments during today's conference call may contain forward-looking information. Significant factors that could cause results to differ from those anticipated are described in our earnings release and our filings with the SEC.

With that, I'll turn the call over to Ben.

Well, thank you, Paul, and good morning. Today, we reported first quarter earnings of $0.57 per share compared to $0.47 per share last year. We're pleased with the solid start to the year, and we are well positioned to deliver on our 2018 guidance and our long-term financial objectives. Bob will provide details on our financial performance and a regulatory update in a moment. But I thought I'd share some recent successes and developments with you.

I'll start with storm response. Minnesota's legendary artist Prince once sang, "Sometimes It Snows In April." Well, that was certainly true this April. Two weeks ago, Winter Storm Xanto delivered over 15 inches of unwelcomed snow. Our crews braved long hours in wet-out conditions on the weekend, restoring power to all customers within 24 hours. Well, apparently it can also get really windy in April. Last week, we experienced, as Bob Dylan once sang, "Trees bent over backwards from a hurricane breeze," as we experienced wind gust exceeding 80 miles per hour. Again, we restored power to all customers with similar efficiency. Our results showed the planning and dedication of our employees, and why I believe we have the best storm response in the sector.

And we were pleased to share our expertise with others in their time and need. In the first quarter, we deployed over 200 employees to Puerto Rico to help restore power and rebuild their system after hurricane Irma. We worked side by side with 17 other utilities and FEMA providing mutual aid. I'm extremely proud of our employees, many of whom worked 16-hour days in this humanitarian effort as well as those that remained behind in our service territories carrying on their normal system requirements.

I'm also proud of the progress we've made in our nuclear operations. In 2017, our nuclear team had an exceptional year with our highest capacity factor since 2010, while simultaneously reducing cost by $25 million, and progress has continued into 2018. Our fleet realized a capacity factor of 100% for the quarter and continues to find operating and cost efficiencies. We have continued operational excellence that's why we believe nuclear is a key component of our carbon reduction strategy for the Upper Midwest.

We are working with our legislators in Minnesota to provide the commission with additional tools that they can use as they evaluate the future of nuclear plants in our next resource plan. The proposed legislation would allow the commission to establish an advanced determination of prudence for the projected cost of our nuclear operation, which provides certainty to both customers and the company. Now the bill has passed both the Senate and House Energy Committees and is on the floor of both chambers. We'll keep you posted on the bill's progress.

Strategically in addition to leading the clean energy transition and keeping our customers' bills low, we're focused on enhancing the customer experience. In the past few years, we've created an award-winning mobile app, developed industry-leading outage notification services, commenced our advanced grid initiatives in Colorado and Minnesota, and created customer choice programs for wind and solar.

To further this customer initiative, we hired Brett Carter to the new role of Executive Vice President, Chief Customer and Innovation Officer. Brett comes to Xcel Energy with an exceptional background to support our customer goals. He most recently held senior leadership roles at Bank of America where he oversaw key business areas, including operations, technology and shared services. And he previously held leadership roles in operations, marketing and technology at several utilities, including Duke Energy. Brett brings a unique set of skills that will help us deliver an outstanding experience for our customers.

Next, let me provide an update on our continued progress on leading the clean energy transition. We recently received approval from the New Mexico Commission on our proposal to add 1,230 megawatts of wind at SPS. The Texas Commission is scheduled to discuss our wind proposal tomorrow.

Last week, we filed supplemental testimony addressing questions from the commission. We believe we are delivering a project with significant customer benefits and are optimistic that the commission will approve the proposal. We still have permitting and transmission interconnection studies to complete, but we're pleased where we are with our regulatory process.

In addition, we're also making good progress on our Colorado Energy Plan. We crossed a milestone in March with the commission ruling to allow the company to submit a portfolio that considers a more aggressive transition of our coal fleet in Colorado. The commission requested that we provide analysis of several portfolios, which reflect the retirement of either 1 or 2 coal units as well as our recommended portfolio and a lease cost portfolio. The ultimate determination of the approved portfolio will impact the capital investment opportunity.

We received a strong response to the RFP with a high number of bids, many of which were at very attractive pricing levels and significantly lower capital cost than we initially expected. Based on the bids, our revised potential capital investment for the Colorado Energy Plan is estimated to be approximately $1 billion.

And as a reminder, the Colorado Energy Plan is not reflected in our current capital or financing forecast. We will submit the portfolios in May and expect the commission decision on the proposal in August.

Finally, we anticipate the Minnesota Commission will rule on our Dakota Range wind project proposal shortly. If approved, this would bring our wind capacity to an industry-leading level of -- in excess of 10,000 megawatts.

These projects are all part of our steel-for-fuel strategy. Because of the strong wind resources in our service territories, we have the unique opportunity to invest in renewable generation in which the capital cost could be more than offset by fuel savings. Finally, we increased our dividend 6% in February, which is consistent with our annual dividend growth objective of 5% to 7%. And I believe this is a reflection of the confidence we have in our long-term business plan and prospects.

With that, I'll turn the call over to Bob.

Thanks, Ben, and good morning. We had a strong quarter with earnings of $0.57 per share compared with $0.47 per share in 2017. While we're $0.10 ahead last year, it was largely driven by $0.04 per share of weather and $0.03 to $0.04 per share of expense timing. Our first quarter results were in line with our internal forecast. Most significant earnings drivers for the quarter include higher electric and natural gas margins, which increased earnings by $0.08 per share, including the impact of favorable year-over-year weather and rate increases in riders to recover our capital investments, partially offset by wind production tax credits that flow back to our customers.

Lower O&M expenses increased earnings by $0.03 per share, higher AFUDC increased earnings by $0.02 per share. And finally, a $0.01 per share benefit from increased wind production tax credits resulted in a lower effective tax rate, which flows back to our customers and doesn't have a material impact on net income.

Offsetting these positive drivers were increased depreciation expense reflecting our capital investment program, which reduced earnings by $0.02 per share and higher interest in other items combined reduced earnings by $0.02 per share.

Please note that we've excluded the impact of tax reform from our margin in ETR variation explanations. This tax reform is largely earnings neutral and would otherwise distort the trend in a line-by-line income statement analysis. For more detail, see our earnings release.

Our first quarter weather-adjusted electric sales grew 1.1%, reflecting strong growth of 1.8% in our commercial and industrial classes. Our weather-adjusted residential sales declined 0.6% as declining use per customer offset customer growth of approximately 1%.

Weather-adjusted natural gas sales increased 1.7% in the quarter, reflecting continued customer growth and increased customer usage. And while our electric and gas volumetric sales were better-than-expected, our revenue mix was modestly unfavorable and did not result in material margin improvement in our electric margin.

Turning to expenses. Our first quarter O&M expenses declined $23 million, largely due to timing of maintenance actions in both 2017 and 2018. We continue to improve the efficiency of our operations, particularly nuclear, which have offset cost increases in other areas. As a result, we continue to expect our O&M will be flat on an annual basis, although we always seek to improve efficiencies and lower cost for our customers.

Next I'll provide a regulatory update. In Colorado, we have a multiyear natural gas case seeking $139 million increase over 3 years. Provisional rates were implemented in January subject to refund. In the quarter, the ALJ approved a settlement we reached with various stakeholders to reduce interim rates by $20 million in response to tax reforming effects. We're awaiting the ALJ recommendation on our natural gas case and anticipate a commission decisions shortly thereafter.

In our electric case in Colorado, we reached a settlement with the staff and the OCC to amend our procedural schedule, which would have postponed the implementation of provisional rates and updated depreciation expense from June of 2018 to January of 2019. However, given multiple moving parts and limited impact to the company, the commission dismissed the case and suggested we file a new rate case. Dismissal of the case will not have a material impact on our results, as we'd already proposed postponing the implementation provisional rates from 2018 to 2019.

This summer, we anticipate filing a new electric case that includes the impacts of tax reform with provisional rates going into effect in the first quarter of 2019.

We also have pending electric rate case in Texas and New Mexico, which are in the early stage of the process. We anticipate commission decisions later in 2018. Please note there are additional details on each of these cases including in our earnings release.

As we've previously discussed, each state in our service territory opened a docket to determine appropriate tax reform treatment. We've provided detail on the regulatory status of tax reform in each of our states in our earnings release, so I'll just focus on a few of the highlights. In Colorado, we reached a settlement with the staff in OCC in which we identified a reduction in revenue requirements of approximately $101 million for our electric operations in 2018 as a result of tax reform.

In the settlement, we proposed a refund of approximately $42 million to customers in 2018 and the remaining $59 million would be used to accelerate the amortization of an existing prepaid pension asset. This is a good example of balanced treatment of tax reform that provides immediate customer benefit while reducing a regulatory asset and preserving cash flow to maintain credit metrics. The settlement is pending commission approval.

Similarly, last week in Minnesota we filed a proposal that recommends tax reform benefits are utilized for a combination of customer refunds, accelerated depreciation of our King coal plant, a deferral to enable a rate case stay-out, and funding of low income programs. The commission is anticipated to act on our tax reform proposal later this year.

As I mentioned, we have pending rate cases in both Texas and New Mexico. We filed supplemental testimony and expect that tax reform will be incorporated into both cases.

It's not my practice to get too technical on these calls, but I wanted to explain the nuance that we're likely to see in our income statement throughout the year.

As you expect tax reform will have an impact on our revenue and effective tax rate, which will create some complexity, but will not have a material impact on our net income. As determinations are made by our various commissions regarding the regulatory treatment of the excess deferred tax liability, our revenue and effective tax rate will fluctuate in tandem.

In the first quarter, we recognized revenue, established an offsetting regulatory liability. Subsequently, our effective tax rate was higher than our previous guidance so as to not have an impact on earnings. Our expectation is that our ETR will be lower as we began to flow cash back to our customers. Accordingly to improve transparency, we've added a table in the earnings release that provides additional detail on the components of our ETR.

Obviously, if there are any questions, please reach out to our Investor Relation team for clarification.

And with that, I'll wrap it up. Overall, it was an excellent quarter. We had strong operational performance. We've advanced our wind projects in SPS with approval in the Mexico. Our Colorado Energy Plan is progressing as planned. And if approved, we'd continue our clean energy transition with no incremental cost to our customers. We're making good progress and working with various commissions on the optimal way to return tax reform benefits to customers. Finally, we posted strong financial results for the quarter and are well positioned to deliver earnings within our 2018 guidance range of $2.37 to $2.47 per share.

This concludes our prepared remarks. Operator, we'll now take questions.

(Operator Instructions) We will take our first question from Julien Dumoulin-Smith, Bank of America Merrill Lynch.

So couple of quick items here. With respect to New Mexico and the wind here, obviously, a little bit of a different decision than typically done in the context of rate base. How do you think about the earnings impact in terms of operating the plant on, let's call it, a quasi-merchant basis as you look at the approval? And I have got a follow-up.

Julien, I mean, what we were seeking is, as you know, is not -- is more concurrent recovery of the investment. With an investment this large compared to the existing rate base, we thought that was essential to moving forward with the projects. I believe we got that with what we're -- what we agreed to in New Mexico. It's a little bit of a twist from what we originally proposed, but not much. I mean, we keep the PTCs, which are pretty significant, as you know, until we file a rate case with the agreement that we won't over earn in that interim period. So for us, I think that works pretty well.

Effectively as far as we're concerned, we should largely assume that you're earning at your ROE on the current plant for capacity factor, et cetera?

Yes. And, Julian, just to be clear, once the project goes into rate base after the rate case, it'll just be traditional earning return on that rate base. So it's just the interim period that we're selling into the open market.

Absolutely. And then secondly, could you comment a little bit on the Colorado plan here just with the rate case and the ability to refile this summer? How do you think about that impacting '18 or '19? It seems negligible, but I wanted to just check on the strategy and impact?

Julien, it's Bob. Yes, with regard to the electric rate case in Colorado, we had already agreed with the OCC and the staff to differ any interim rates from June to January of 2019. That reflects our view that the impact on margin in 2018 was de minimis and won't have an impact on our earnings in 2018. We expect to file the case, and we're working through the particulars right now with updated year-end actuals for 2017 and with a look at items like tax reform, Rush Creek and other items. So we'll be prepared to file that expeditiously.

Excellent. Lastly, just real quickly on the nuclear legislation. Can you just give us a little bit of a sense here as to sort of what's on the table, if you do not get this legislation done? I'm just trying to understand, how important the clarity you need is in order to move forward with these investments, if you could elaborate a little bit?

No, I think it's beneficial, Julien. It's an investment that has been frankly, probably, over scrutinized. It's very important to our 85% carbon-free energy goals by 2030. And we just want a little additional clarity, both from a consumer and a shareholder perspective that once we have a plan approved that we have -- can have confidence that if we execute on that plan we're going to get recovery. Pretty simple. We are not asking for any sort of subsidy or anything like that. It's just -- it's an advanced prudence determination essentially. Now if we don't get it, it doesn't mean things change. But I think we hope if we don't get it at least the dialogue is established that for an investment this significant and this important to this carbon-free goals, we need to have a fair shake when it comes to the regulatory process.

We'll go next to Ali Agha with SunTrust.

First question, can you remind us if the Colorado Energy Plan is approved as proposed by you guys that $1 billion. Over what period of time will that money get spent? And how should we think about the funding for that?

Ali, it's Bob. We are still working through the portfolio and the details and the timing of each of the assets that would be implemented as part of that plan. So I can't give you a definitive answer. Suffice to say that there is wind projects that are seeking 100% PTC, so there'll be some assets that are likely included by 2020. There's some other assets that could come back further in the plan. So the timing is still a little bit in flux. We're still working through that. We expect to file with the Colorado Commission an update in May, which will have some more details. With regard to the financing of that plan, it's, obviously, $1 billion investment that will likely need a modest amount of equity to support it. And again, the timing of that will dictate sort of how much and when. So give us some time to work through the details and the particulars. Once the commission reviews it, they're supposed to have it reviewed by August, which is in line with our normal capital planning process. And so we'd expect to include any capital updates and financing updates in our normal third quarter guidance discussion.

Okay. But, Bob, to be clear, I mean, you are looking at that as totally incremental. This wouldn't cause some other CapEx to perhaps move around or be taken out to be replaced by this?

No, I think if this were -- if the $1 billion were approved, I think for the forecasted time frame all things equal, Ali, we would increase our rate-based growth rate to about 7%.

I see. Okay. And then second question, just understanding the timing of the equity issuance. So if I read it right, you're assuming $375 million of equity this year, $75 million from the DRIP program, $300 million separate. I guess, first question is, that $300 million should we think of that as the market sort of plan? Or could that be a quick block? How are you thinking about that? And then from '19 and '20, should we assume that the $75 million run rate continues through the DRIP annually?

Yes. Ali, those are both good assumptions. Our sort of case to beat on the equity plan isn't at the market program late this year, could drip early in the next year, but our expectation was to get it done this year. With regard to the DRIP, yes, $75 million is a pretty good run rate. I think our previous guidance said it was going to be about $385 million over a 5-year period. So $75 million, it grows to kind of $85 million run rate in the last year.

I see. Okay. And last question when I look at the earned ROE over the last 12-month period that you report at the OpCo level, it looks like the regulatory lag right now versus authorized is about 40, 45 basis points. Does that -- is that sort of the limit we should think about just the practical limit? Or can this earned ROE trend go actually higher than what you're showing us right now?

Ali, we've made progress on closing that gap. We probably narrowed it by about half when we set that out of the strategic goal. We've made a lot of progress. I think you should expect us to continue to work on that. There is some items. Obviously, filing rate cases helps the concurrent recovery that Ben talked about with SPS wind should help regulatory lag in general. But for now, I think that's probably a pretty good assumption. But know that we're always looking to narrow it.

Yes, I mean, Bob's point, Ali. It gets a little harder to close the remaining gap. There is some -- the structural things and that sort of stuff. But I mean -- so as Bob mentioned, longer-term regulatory comp packs, I think we're doing a great job of finding cost efficiencies. Those all will contribute to it, but it's -- we pretty much achieved the goal at this point.

And, Ben, am I right in the math, it's about 40, 45 basis point, is where the lag is right now.

Probably, a little bit more than that, but you're real close. We still have some more opportunity.

We'll go next to Paul Ridzon with KeyBanc.

I just had a real quick question. But what exactly are you expecting in Texas tomorrow?

Approval. It's -- I mean, I think, as I said on the call, we think the projects drive tremendous benefits for consumers. We think there is a lot of support from stakeholders. There were some questions that were asked, and they have been answered. And so we're optimistic that the commission will approve it.

I was just asking if you're actually expecting an approval or more discussion, but it should be over by tomorrow?

You could always have more discussion, but our thought is that it's approval.

We'll go to Travis Miller with Morningstar.

I was wondering as you go through and as the regulators commissions go through the whole return to of this deferred tax liability chunk of money, how much are they looking at the earned ROE versus your allowed ROE and maybe using some of that money to close that gap so to speak?

Yes, Travis, I think it's -- they are more -- if you have a deferral rate cases maybe there is some indirect look at that. But I don't think that's really their focus. I think their focus is on, like, we talked about, refund a good portion of it immediately to customers. Then look at longer-term implications and things that make sense that will help our balance sheet, but it will also help customers. So paying off a prepaid pension asset in Colorado, that makes a lot of sense. Here in Minnesota, maybe accelerating some additional depreciation for our coal plant, the King plant and doing a little more of a low income and maybe being able to stay out of rate case longer. Those are all things that will benefit consumer and customer alike. So I think that's where the focus is, and we are comfortable with it.

Okay. Great. And then just real quick the strength in the electric C&I usage. I wonder if you could just elaborate on what's going on there, if it's a trend or if it's just a onetime type of thing?

I'll turn it over to Bob, but I'll just leave you with a 3-letter word, oil.

Yes, look, this was -- we experienced C&I declines when oil prices dropped to below $40. And when oil is above $60, we see increased activity in our Southwest business, and we see increased sand mining activity in our Wisconsin business. And I think that the lion share of the improvement in large C&I across the company.

And we'll go next to Paul Fremont with Mizuho.

Just trying to get a better handle on sort of the revised $1 billion estimate on Colorado Energy Plan. When I look at Page 7 of your presentation, how much of each of those categories in terms of megawatts are you assuming in that $1 billion? Is it the full amount, the 1,000 megawatts of wind, the 700 megawatts of solar, the 700 megawatts of natural gas? Or is it something less than that?

Well, you remember that the original objectives or goal posts, if you will, were 50% of the renewable, 75% of the fossil gas generation. That's -- we're going through a number of iterations right now, but we're comfortable that based upon what we think the recommended portfolio and additional options might be that we'll end up around that $1 billion, Paul. Not really too -- I can't be too much more specific at this point is how much of it is wind, how much of it is solar, how much of it gas or transmission or battery, but we feel comfortable that collectively it will be around $1 billion.

But in terms of megawatts, would be it less than the maximum here and, again, subject to the ownership limitations that you put out on the slide?

Well, I could -- I mean, it -- I would tell you, I think, the trend will be that wind will probably be better for us than owned and solar and we were well positioned on the fossil side, but I don't know if I can be much more specific than that.

And, Paul, just to be clear, the totals on Slide 7 of our investment plan are totals for the entire Colorado Energy Plan. They weren't totals for our proportional ownership targets.

Right. Now we -- I totally understand that. And then, is it also possible for you to give us maybe some parameters on cost per KW for each of those categories?

Paul, we filed and I can point you to the filing or could get to you later, but we filed publically the median prices for various categories. We filed the bids in our 30-day update in January and then reupdated it, again, in February. And those are public, and we can get that to you, if that's helpful.

Great. And then the other -- last question from me is, you talked about timing, I guess, for O&M appreciation. Should we expect that for the remainder of the year, the makeup of sort of the lower spending in the first quarter will be sort evenly spread? Or what's the pattern for the O&M to be made up and also the depreciation?

I think for the O&M portion, probably, even is probably the best way to think about it. On the depreciation, it's is a little bit more backdated, largely impacted by the in-servicing of our Rush Creek project in Colorado, which should happen in late October or early November. And that's sort of the big driver of the timing of the differential.

And we'll go next to Angie Storozynski with Macquarie.

I have one question, but numerous parts. So given that you are developing numerous wind farms. I just wanted to get a sense, what has changed since the tax reform? Are you since then seeing any changes in regards the economics of the project that you're developing, bidding behavior from developers? You feel the need, for instance, to tap the tax equity more often? Is there a sense, for instance, that -- for instance changes in the value of accelerated depreciation are making economics of these projects different to your customers? And also the second part would be given that you're adding so much renewables into your systems without necessarily retiring coal plants at the same time, How do you manage the O&M increase associated with the new renewables on your system?

All right. Let me -- the first question, I believe, was how is tax reform generally impacted the economics of the renewable projects. Is that right, Angie? I'm going to assume that.

That's correct. Yes, yes, yes.

Yes. And so I would say that there has been some impact when you lower the effective tax rate to 21%, the value of the PTC and the ITC is not as valuable as it used to be. That said, these projects are deeply in the money. And we've also had the opportunity to go through and look at some -- working the supply chain harder. And so I'm really pleased with where we are at least with all of our proposals and what we continue to see. By and large, at this point developers have held their pricing pretty constant. I am sure that supply and demand is changing a bit in the tax equity world. We continue to see the opportunities to own renewables as a rate base opportunity. And I think we're well positioned for that. Now ultimately, as you know, Angie, the PTCs and then ultimately the ITCs go away. And I think renewables will continue to come down in price. And while wind, I believe, is on sale today, it ultimately will be competitive, I think, into the next decade. What was the second part of the question?

So, Angie, on the second part of your question on O&M, you're right. Increased wind generation will add O&M pressure to the company. So when I think about our goal to maintain flat O&M, it means that we're cautiously and very aggressively working on the O&M of the rest of the business as we continue to lay new wind into our business. So we have, as we've talked about in the past, we have natural O&M pressure from merit increases and bargaining unit wage increases. We are offsetting that as well as more to make room for the wind in our portfolio in advance of any retirements of any of other generation fleet.

And remember, we do take -- O&M does flow through the riders until we put it into base rates.

But when you talk about the customer benefit, just excluding any emissions, the main driver of a customer benefit through additions of wind farms is the cost of fuel will be going down for conventional power plants. Is that right?

I look at it, Angie, as a deeply in the money hedge against fuel prices, exactly. So when we look at -- when we say -- just to finish that thought. We look at -- when we say that it includes the O&M and includes ancillary costs, it's a full package, and it's still deeply in the money compared to where gas is, even with gas being at very low prices today.

And it is over basically the useful life of the wind farm, right? So it's not -- so some of it could be back-end loaded when the coal plants that currently support the wind farm are retired and hence that O&M benefit shows up?

Yes. It's over the life of the project. There is some element of the benefits being more front-end loaded. But, as you know, most people still have natural gas being more expensive in the out periods, too.

And so the project -- and this is the last question, I promise. For the projects -- for the wind projects that you will own. Do you have any preference over self-development or build-to-transfer type of option?

That's a really good question, Angie. I think all things equal, we think we have more flexible and can do more things when we self-build, but we're open to build-on transfer. And as you know, part of the near unanimous settlement that we obtained in Colorado was to -- for us not to offer self-build renewables, but to get our ownership through build-own-transfer. So you always -- there's different paths that take you to the same place and that's what you saw in Colorado.

And we we'll go to turn with Christopher Turnure with JPMorgan.

Given the prominence of OpCo and for that matter Holdco credit agency ratings with some other jurisdictions for other companies in the tax reform discussions, I'm wondering if you can give us any sense as to how that might play into your discussions at SPS in both Texas and Minnesota knowing that it is, I think, relatively early stages in that process for you?

It's a great question. And I know even before tax reform you've heard me and other members of the management team talk about the fact that we like that dry powder, right? We don't take things close to the edge. We have a more conservative dividend payout ratio than many other companies. We've got margin in our credit metrics. We have margin in our operating capacities. So tax reform certainly had an impact on credit metrics. We are committed to our credit standings, that's why we're talking about $300 million worth of equity. And we also think it's important to have those dialogues with our regulators on what they need to do to help support the credit metrics that are so important for us to make the capital investments that bring economic development or economic benefits and sometimes development to the communities that we serve. We proposed an SPS, an equity ratio of 58%. We think a better equity ratio, particularly in SPS is needed to support the credit metrics there. In Minnesota, specifically to your question, we think the accelerated depreciation associated with King is -- has twofold benefits. It supports credit metrics through more cash flow, but it also gets a -- it more quickly accelerates an asset that ultimately we are open to potentially retiring before its -- the end of its service life is currently scheduled. So Bob or...

No, I think, Ben hit on all of the high points, and we've had discussions in our other regulatory jurisdictions as well.

Okay. Great. That's helpful. And then, I guess, bigger picture question on the trajectory in Minnesota from a regulatory and maybe a political perspective as well. We've seen more extreme intervener positions of late on ROE and other factors maybe a little bit of inconsistency in commission rulings for some of your peers and you're coming up on the end of your multiyear plan at the end of 2019. So how do we think about how things have changed, if at all, and how your strategy might flex accordingly?

Well, I mean, as part of what we could with tax reform is to stay out another year. We do think multiyear plans have been demonstrated to be a success. Our case is increasingly would be for capital recovery. We've done a really good job with O&M. And I do believe that the commission really supports what we're trying to do in our carbon reduction programs, our pilot programs or things like that support EV or electric vehicle implementation. So I think the strategic direction we're taking is supported by our commissions. You can always have some bumps in the road, but when you're aligned like that, I think, long-term you're in pretty good shape.

Okay. So it says like nothing to be overly concerned about, at this point, given the broader picture?

I would say that's correct.

And with no additional questions, I'd like to turn the call back to CFO, Bob Frenzel for closing comments.

Thank you all for participating in our earnings call this morning. Please contact our Investor Relation team with any follow-up questions.

This does conclude our call today. Thank you for your participation. You may disconnect at this time.