Good morning, 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 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, we're 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, 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 unwelcome snow. Our crews braved long hours and whiteout conditions on a 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 the hurricane breeze as we experienced wind gusts exceeding 80 miles per hour. Again, we restored power to all customers with similar efficiency. Our results show the planning and dedication of our employees and why I believe we have the best storm response in the sector. We were pleased to share our expertise with others in their time of 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 the 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 costs by $25 million, progress has continued into 2018. Our fleet realized a capacity factor of 100% for the quarter and continues to find operating and cost efficiencies. Their continued operational excellence is 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 advance determination of prudence for the projected cost of our nuclear operation, which provides certainty to both customers and the company.
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.
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 are pleased where we are with our regulatory process. We are 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 one or two coal units, as well as our recommended portfolio and a least 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 costs 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. 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 a 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 dividends 6% in February, which is consistent with our annual dividend growth objective of 5%-7%. 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, 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 of last year, it was largely driven by $0.04 per share of weather and $0.03-$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.
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 and ETR variation explanations, as 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. 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 in 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 costs for our customers. Next, I'll provide a regulatory update. In Colorado, we have a multi-year natural gas case seeking $139 million increase over three 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 reform effects. We're awaiting the ALJ recommendation on our natural gas case and anticipate a commission decision 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. 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 had 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 cases 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 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 and 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 to refund approximately $42 million to customers in 2018. 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's 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, as to not have an impact on earnings. Our expectation is that our ETR will be lower as we begin 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. 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 New Mexico. Our Colorado Energy Plan is progressing as planned, and if approved, we continue our clean energy transition with no incremental cost to our customers.
We're making good progress in 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-$2.47 per share. This concludes our prepared remarks. Operator will now take questions.
Thank you, sir. To signal for a question on the phone, please press the star key followed by the digit 1. Again, it is star 1 to signal. We'll take our first question from Julien Dumoulin-Smith , Bank of America Merrill Lynch.
Hey, good morning.
Hey, Julien.
Hey. A couple 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 a, let's call it, a quasi-merchant basis as you look at the approval? I got a follow-up.
Julien, what we were seeking, as you know, is more concurrent recovery of the investment. With 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 agreed to in New Mexico. It's a little bit of a twist from what we originally proposed, but not much. 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. 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 plan for capacity factor, et cetera.
Yes.
Exactly.
Julien, just to be clear, once the project goes into rate base after the rate case, it'll just be traditional earning a return on that rate base. It's just the interim period that we're selling into the open market.
Absolutely. 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 2018 or 2019? It seems negligible, but I wanted to just check on the strategy and impact.
Hey, Julien, it's Bob. Yeah, with regard to the electric rate case in Colorado, we had already agreed with the OCC and the staff to defer 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, with a look at items like tax reform, Rush Creek, and other items. We'll be prepared to file that expeditiously.
Excellent. Lastly, just real quickly on the nuclear legislation, can you 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.
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. We just want a little additional clarity, both from a consumer and a shareholder perspective, that once we have a plan approved, that we can have confidence that if we execute on that plan, we're going to get recovery. Pretty simple. We're not asking for any sort of subsidy or anything like that. It's an advanced prudence determination, essentially. If we don't get it doesn't mean things change. I think we hope if we don't get it, that at least the dialogue is established that for an investment this significant and this important to these carbon-free goals, we need to have a fair shake when it comes to the regulatory process.
Excellent. Thank you all.
Thanks, Julien.
We'll go next to Ali Agha with SunTrust.
Thank you. Good morning.
Ali. Hey.
Morning. 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?
Hey, Ali, it's Bob. We're 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's 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. The timing's still a little bit in flux. We're still working through that, and we expect to file with the Colorado Commission an update in May, which will have some more details. With regard to the financing that plan, it's obviously a $1 billion investment that will likely need a modest amount of equity to support it. Again, the timing of that will dictate sort of how much and when.
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. We'd expect to include any capital updates and financing updates in our normal third quarter guidance discussion.
Okay. Bob, to be clear, 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.
I think if the $1 billion were approved, I think for the forecasted timeframe, all things equal, Ali, we would increase our rate base growth rate to about 7%.
I see. Okay. Second question, just understanding the timing of the equity issuance. If I read it right, you're assuming $375 million of equity this year, $75 million from the DRIP program, $300 million separate. First question, is that $300 million, should we think of that as the at-the-market sort of plan, or could that be a quick block? How are you thinking about that? For 2019 and 2020, should we assume that the $75 million run rate continues through the DRIP annually?
Ali, those are both good assumptions. Our sort of case to beat on the equity plan is an at-the-market program late this year. Could drift early in the next year, but our expectation was to get it done this year. With regard to the DRIP, 75 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. At 75, it grows to kind of 85 run rate in the last year.
I see. Okay. 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, which is authorized, is about 40, 45 basis points. Is that sort of the limit we should think about, just a 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've probably narrowed it by about half from when we set that out as a strategic goal. We've made a lot of progress. I think you should expect us to continue to work on that. There's some items, obviously filing rate cases helps. The concurrent recovery that Ben talked about with SPS wind should help regulatory lag in general. For now, I think that's probably a pretty good assumption, but know that we're always looking to narrow it.
Yeah, to Bob's point, Ali, it gets a little harder to close the remaining gap. There's some structural things and that sort of stuff. As Bob mentioned, longer-term regulatory compacts, I think we're doing a great job of finding cost efficiencies. Those all will contribute to it, but we've pretty much achieved the goal at this point.
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.
Okay.
We still have some more opportunity.
Okay. Thank you.
Thank you.
We'll go next to Paul Ridzon with KeyBanc.
Hey, Paul.
Morning. I just had a real quick question. First of all, congratulations on the solid quarter.
Thank you.
What exactly are you expecting in Texas tomorrow?
Approval. As I said on the call, we think the projects drive tremendous benefits for consumers. We think there's a lot of support from stakeholders. There were some questions that were asked, and they've been answered. We're optimistic that the commission will approve it.
Okay. I was just asking if you were actually expecting an approval or more discussion, it should be over by tomorrow.
You could always have more discussion, our thought is that it's approval.
Okay. Thank you very much.
Thanks, Paul.
We'll go next to Travis Miller with Morningstar.
Hey, Travis.
Good morning. I was wondering, as you go through and as the regulators, commissions go through the whole return 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?
Travis, I think if you have a deferral of rate cases, maybe there's some indirect look at that. 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 and then look at longer-term implications and things that make sense that will help our balance sheet but will also help customers. 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 and the King plant and doing a little more with low income and maybe being able to stay out of a rate case longer. Those are all things that'll benefit consumer and customer alike. I think that's where the focus is, and we're comfortable with it.
Okay, great. Then just real quick, the strength in the electric C&I usage. Wonder if you could just elaborate on what's going on there or if it's a trend or if it's just a one-time type of thing.
I'll turn it over to Bob, but I'll just leave you with a three-letter word, oil.
Yeah, look. We experienced C&I declines when oil prices dropped to below $40. When oil's above $60, we see increased activity in our Southwest business, and we see increased sand mining activity in our Wisconsin business. I think that's the lion's share of the improvements in large C&I across the company.
Great. I appreciate the conciseness.
We'll go next to Paul Fremont with Mizuho.
Thank you very much. Just trying to get a better handle on sort of the revised billion-dollar estimate on Colorado Energy Plan. When I look at page seven of your presentation, how much of each of those categories in terms of megawatts are you assuming in that billion dollars? Is it the full amount of 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 goalpost, if you will, were 50% of the renewables, 75% of the fossil gas generation. We're going through a number of iterations right now, 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. Can't be too much more specific at this point as how much of it is wind, how much of it is solar, how much of it is gas or transmission or battery. We feel comfortable that collectively it'll be around $1 billion.
In terms of MW, would it be less than the maximums here? Again, subject to the ownership limitations that you put out on the slide.
I will tell you, I think the trend will be that wind will probably be better for us to own than solar, we're well-positioned on the fossil side, I don't know if I can be much more specific than that.
Paul, just to be clear, the totals on slide seven of our investment plan are totals for the entire Colorado Energy Plan. They weren't totals for our proportional ownership targets.
Right. No, I totally understand that. 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 we could get it to you later, but we filed publicly the median prices for various categories. We filed the bids in our 30-day update in January, then re-updated it again in February. Those are public, and we can get that to you if that's helpful.
Great. The other last question from me is, you talked about timing, I guess, for O&M depreciation. 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 of 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 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. That's sort of the big driver of the timing of the differential.
Thank you very much.
Thanks.
We'll go next to Angie Storozynski with Macquarie.
Hi, Angie.
Thank you. How are you? I have one question, but no response. Given that you are developing numerous wind farms, I just wanted to get a sense, what has changed since the tax reform? Are you, for instance, seeing any changes throughout the economics of the projects that you're developing, bidding behavior from developers? Do 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? 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? Thank you.
All right. The first question, I believe, was how has tax reform generally impacted the economics of the renewable projects? Is that right, Angie? I'm going to assume that's right.
That's correct. Yep.
Yeah. 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 working the supply chain harder. I'm really pleased with where we are. 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'm sure 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.
I think renewables will continue to come down in price. 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?
Angie, on the second part of the question on O&M, you're right. Increased wind generation will add O&M pressure to the company. When I think about our goal to maintain flat O&M, it means that we're consciously and very aggressively working on the O&M of the rest of the business as we continue to lay new wind into our business. We have, as we've talked about in the past, we have natural O&M pressures from merit increases and bargaining unit wage increases. We're offsetting that as well as more to make room for the wind in our portfolio in advance of any retirements of any of our other generation fleet.
Remember, O&M does flow through the riders until we put it into base rate.
When you talk about the customer benefit, just excluding any emissions, the main driver of the customer benefit through additions of wind farms is the cost of fuel 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.
Okay.
When we look at that, just to finish that thought.
Please.
When we say that, it includes the O&M, and includes ancillary costs. It's a full package, it's still deeply in the money, compared to where gas is, even with gas being at very low prices today.
It is over basically the useful life of the wind farm. Right? 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.
Yeah. 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.
For the project, and this is the last question, I promise. 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 flexibility and can do more things when we self-build, but we're open to build-own-transfer. As you know, part of the near unanimous settlement that we obtained in Colorado was for us not to offer self-build renewables, but to get our ownership through a build-own-transfer. There's different paths that take you to the same place, and that's what you saw in Colorado.
Great. Thank you.
Thank you.
We'll go next to Christopher Turner with J.P. Morgan.
Good morning, guys. 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 to have 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 a margin in our credit metrics. We have margin in our operating capacities. 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 in 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 has twofold benefits. It supports credit metrics through more cash flow, but it also more quickly accelerates an asset that ultimately we are open to potentially retiring before the end of its service life currently scheduled. Bob?
No, I think Ben hit on all the high points, and we've had discussions in our other regulatory jurisdictions as well.
Okay, great. That's helpful. I guess, bigger picture question on the trajectory in Minnesota from a regulatory and maybe a political perspective as well. We've seen some 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 multi-year plan at the end of 2019. How do we think about how things have changed, if at all, and how your strategy might flex according?
Part of what we could do with tax reform is stay out another year. We do think multi-year plans have been demonstrated to be a success. Our cases increasingly would be for capital recovery. Done a really good job with O&M. I do believe that the commission really supports what we're trying to do in our carbon reduction programs, our pilot programs for things like the support EV or electric vehicle implementation. 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, it sounds like nothing to be overly concerned about at this point, given the broader picture.
I would say that's correct.
Okay. Thanks, Ben.
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 relations team with any follow-up questions.
That does conclude our call today. Thank you for your participation. You may disconnect at this time.