埃克西爾能源 (XEL) 2018 Q2 法說會逐字稿

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

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 Second 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 questions.

This morning, we will review our 2018 second 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.

I'll now turn the call over to Ben.

Well, thank you, Paul, and good morning, everyone. Today, we reported another solid quarter with EPS of $0.52 per share compared with $0.45 per share last year. We're off to a great start this year and have raised our EPS guidance range to $2.41 to $2.51 per share from our original guidance range of $2.37 to $2.47 per share. Bob will provide more detail on our financial performance as well as a regulatory update. I will now briefly discuss some important recent developments.

In May, we received approval in Texas for our SPS wind proposal. We now have final approvals from both the Texas and the New Mexico commission to add 1,000 megawatts of new wind generation at SPS. Construction on the house site began this month, and we expect it to achieve commercial operation in 2019. We're currently working on permitting and waiting for the transmission interconnection study for Sagamore, which is expected to go into commercial operation in 2020. As a reminder, the total capital investment for these 2 wind projects is $1.6 billion and it is included in our base capital plan. In addition, our 300-megawatt Dakota Range project was approved by the Minnesota Commission during the quarter. The estimated $350 million of capital investment is also included in our base plan. In June, we filed our Colorado Energy Plan. The most ambitious utility renewable plan in the country. It would allow our Colorado company to achieve a 55% renewable energy mix. We propose to add 1,100 megawatts of wind, 700 megawatts of solar, and 275 megawatts of battery storage and retire 660 megawatts of coal generation under our preferred CEP portfolio. PSCo would own 500 megawatts of new wind generation, acquire 380 megawatts of existing natural gas generation and invest a new transmission for a total investment of about $1 billion. And please note that this CapEx is not included in our base capital forecast and represents incremental investment to our plans. Our preferred portfolio is based on a settlement with a diverse group of parties and balances company ownership with customer benefit. It will provide over $200 million of customer savings while reducing carbon 60% in Colorado by 2026 from the 2005 base level. The commission decision is expected early in September, and we will update our capital forecast and financing plans later in the year. We anticipate funding the Colorado Energy Plan with a combination of internally generated funds, incremental debt and $300 million to $400 million of equity, if the commission approves our proposal. And we expect most of the external financing to occur in 2020 and beyond, given the Build-Own-Transfer nature of the plan.

So as you can see, we continue to make great progress on our steel-for-fuel strategy. Based on our approved projects, we're on track to have over 10,000 megawatts of wind on our system by 2021. In addition approval of the Colorado Energy Plan will increase our overall wind capacity to approximately 11,500 megawatts, solidifying our position as the leading renewable generation utility in the United States, while providing significant customer benefit. As a company, we strive to be an industry leader and provide a safe, reliable and affordable energy supply to our customers. Our people are the greatest resource and they were instrumental in achieving this goal. So I'm very pleased that Xcel Energy was included in the 2018 Forbes Best Employers in the America list, reflecting our continued focus on company culture and our employees.

So with that, let me turn the call over to Bob, and he'll provide more detail on our financial results and outlook as well as a regulatory update. Bob?

Thanks, Ben, and good morning. We've realized another solid quarter with earnings of $0.52 per share in 2018 compared with $0.45 per share in 2017. Impacts of weather, both hot and cold, increased electric and natural gas sales and increased earnings by $0.03 per share in the quarter. The most significant earnings drivers for the quarter included higher electric and natural gas margins, which increased earnings by $0.10 per share, including the impact of favorable year-over-year weather and rate increases in riders to recover our capital investments, partly offset by wind production tax credits, which flow back to our customers. And higher AFUDC, which increased earnings by $0.02 per share. Offsetting these positive drivers were higher O&M expenses, which decreased earnings by $0.01 per share. Higher depreciation interest in other items combined to reduce earnings by a total of $0.04 per share.

Turning to sales. On a weather-adjusted basis, our year-to-date electric sales increased 1.1%, reflecting strong sales growth to our commercial and industrial classes and relatively flat residential sales. Year-to-date, natural gas sales increased 2% on a weather-adjusted basis, reflecting continued customer growth and increasing customer use. Based on our year-to-date results, we've revised our annual weather-adjusted sales guidance to growth of up to 1% for electric and 1% to 1.5% for natural gas.

Turning to expenses. Our second quarter O&M expenses increased by $6 million, largely due to the timing of cost at our generating plants. We've experienced a hot and wet summer, which has resulted in increased generation, unanticipated vegetation growth and extra stress on our system. While our respective systems have performed extremely well, we plan to invest incremental O&M to ensure that we continue to maintain the high levels of reliability that our customers expect. As a result, we expect our full year O&M expenses to be 1% to 2% higher over the prior year.

Next, let me provide a regulatory update. Earlier this month, the Colorado Commission ruled on our natural gas case and upheld the majority of the ALJ's recommendation, with a few exceptions. The commission approved a rate increase of approximately $47 million based on a historic test year, an equity ratio of 54.6% and an ROE of 9.35%. We're disappointed with the commission decision, including their denial of a multi-year plan and a forward test year. To mitigate this impact, we have filed for an extension of our pipeline integrity rider through 2020. This will provide timely recovery of about half of our capital investment in the natural gas business. We've requested the commission decision on our rider extension by November.

Turning to our electric operations in Colorado, we're looking at 2 different timing options. We're prepared to file electric case in the fall with rates going into effect in mid-2019. However, we are working with parties on a potential alternative, which would allow us to delay the filing of our Colorado electric case until the spring of 2019 with rates going into effect in early 2020. We expect to have more clarity on our regulatory plans in the next few months.

Moving to SPS. In June, we reached a settlement with various interveners in our Texas rate case, in which there'll be no change in rates as we will use the benefits of tax reform to offset our projected revenue deficiency. While it was a black box settlement, we agreed to use the 57% equity ratio and an ROE of 9.5% for AFUDC purposes. We will accelerate the depreciation of our Tolk coal plant, and we'll continue to use the transmission rider to recover investments. We also committed to file a rate case by the end of 2019, which coincides with the in-service date of our Hale Wind Project. The commission is expected to rule on the settlement in the third quarter.

In New Mexico, we're seeking to increase our revenue by approximately $27 million, including tax reform impact and a 58% equity ratio and a 10.25% ROE. In June, the New Mexico hearing examiner recommended a rate increase of $12 million based on an equity ratio of 53.97% and an ROE of 9.4%. We anticipate a commission decision and implementation of final rates in the third quarter.

Next, I want to provide an update on regulatory proceedings related to tax reform treatment. We are working closely with the commissioners -- commissions to achieve balance outcomes that provide customer benefit and also help us to maintain credit metrics in each of our operating companies. You can find a detailed discussion of each jurisdiction in the earnings release, so I'll just focus on a few recent developments.

In July, the South Dakota Commission received a tax reform settlement, which includes the onetime customer refund of about $11 million in 2018. We will then use the benefits of tax reform to offset projected revenue deficiencies for 2019 and 2020. In Wisconsin, the commission decided to refund $27 million and defer $5 million of the tax benefit until the next rate case proceeding. In Colorado, we reached tax reform settlement with the staff and the OCC for our electric operations. The commission approved a $42 million customer refund and directed an ALJ to provide a recommendation on the proposed $59 million of accelerated amortization of a prepaid pension asset. In Minnesota, we proposed to refund approximately half of the tax reform benefit, while utilizing the remainder of the benefit to accelerate depreciation of the King coal plant, recover MGP deferrals and avoid a rate case in 2020. We anticipate a commission decision later this summer.

With the first 2 solid quarters now behind us, we're $0.17 ahead of last year. It's important to note that although favorable weather has been a driver, we plan to spend incremental O&M, which will mitigate some of the positive weather impact. We're raising our full year EPS guidance to a range of $2.41 to $2.51 per share from the previous range of $2.37 to $2.47 per share, reflecting our strong performance so far this year.

With that, I will wrap it up, and overall, it was an excellent quarter. We received final regulatory approvals for 1,000 megawatts of wind at SPS. We filed a proposal for the Coronado Energy Plan, which, if approved, would result in adding more renewable generation and continuing our clean energy transition. We reached constructive settlements in both Texas and South Dakota that resolved tax reform and rate deficiencies. Finally, we're well positioned to deliver earnings within our revised guidance range, while achieving long-term earnings growth of 5% to 6% and dividend growth of 5% to 7% annually.

This concludes our prepared remarks. And operator, we will take a few questions.

(Operator Instructions) Our first question comes from Stephen Byrd with Morgan Stanley.

I wanted to just check in, in terms of the mix of owned renewables versus renewables under PPA. Just sort of, broadly, where we are in terms of that mix? Where you see that over time? There's been a lot of moving parts, I just thought I will level set again on that.

You're talking about most recently or just overall, Stephen?

I'd just say overall, just to make sure we understand kind of the overall mix.

Yes. Okay. I see Bob flipping through some of that materials, so I'll stall a little bit here. As you know, we started out not owning any renewables as we've been on this journey for quite a while now. But in recent years, last 4 years, we've owned more than we've acquired through PPA. Overall, we like to own going forward at least 50% of the renewables that come online. And that's what we've -- so we've kept in catching up over the last 4 years. Bob, are you able to find the exact number?

So Stephen, right now, we currently own about 850 megawatts out of 6,700 megawatts. Of the new amount that we proposed, we would own about 74%.

That was start to...

So it's going to say you have -- okay. And you have a long trajectory had been in terms of being able to continue to look at the ownership option in terms of as you think about your overall mix?

Absolutely.

Is that fair to say? Yes. Just thought I check in on that. Great. And then just on demand growth. Understand kind of the near-term changes. Would you mind just talking at a high level in terms of the long-term trends you see in terms of the demand growth outlook in your service territories?

Yes. I mean, I'll let Bob add as well. I mean, I think the trend we're seeing generally is, we're seeing good customer growth. So new stores, if you will. But within those -- that -- the customer usage, it's actually declining. I think, primarily driven by energy efficiencies, some of which we're leading through our own programs. And I think that's a trend that will continue. Now clearly, we are optimistic and want to help lead the clean energy transition, particularly as it relates to electric vehicles, which will be great load for the utility industry. But I think, the long-term trend is relatively flat sales going forward and that's what we're planning for.

Yes. Stephen, I would just add that we've had good consumer industrial class sales, particularly in our Wisconsin and our Southwestern business over the past year. We are focused on economic development and what usually lags the large C&I sales is often residential sales, and I think you're seeing a pickup in residential in the Southwestern business as well, as the jobs and the opportunities continue to move into the Southwest. So we're bullied by that. I don't know if I -- I totally agree with Ben's overall assessment on trend, which is relatively flat for some period of time.

We're fortunate we have territories, where we're experiencing good customer growth.

Our next question comes from Greg Gordon with Evercore ISI.

The trailing 12-month ROEs -- earned ROEs across the whole company are improved from first quarter. Is that just because of the weather boost? Or are you seeing underlying improvement in gross margin as you continue to try to control costs?

Greg, it's a good question. It's weather growth, it was favorable sales in the first half of the year. I'd say there's some timing of equity. I think our full year regulated forecast looks slightly above 9% right now, and some of that's expected equity infusions into SPS as we increase the equity ratio there as well.

Okay. And then you -- can you give us some more guidance on the effective tax rate situation and what's going on there?

Yes. There's extensive disclosure on where we are with our respective jurisdictions, and I won't go into all of them. I think the way we characterize the effective tax rate disclosure in the earnings release is, as we've given kind of 2 ranges, and as we work through regulatory settlements in each of our jurisdiction, our long-term rate is the -- effective tax rate looks probably like 8% to 10%. But with where we are with regulatory outcomes, we're still in that 15% to 17% with the differential being revenue and revenue retention. But longer term, it's in that single-digit number, high single digits.

But your revenue requirements would ultimately reflect whatever tax rate your -- whatever your effective tax rate ultimately is, or?

That's exactly right. We put a pretty good disclosure in the earnings release around how we've recognized the lower tax rate and then we changed the revenue assumptions accordingly. And you can see that give-and-take in the disclosure, and I just -- what I said that our longer-term tax rate was single digit. I meant the -- for full year 2018 assuming full regulatory outcomes in all of our jurisdictions where we refund the benefits of tax reform to our customers, we'd expect that to be in the 8% to 10% range.

Our next question comes from Christopher Turnure with JPMorgan.

I wanted to see if you guys could give us a little bit more color on the guidance change for the year. We're only about halfway through even though we have another month of summer. In the books, almost already here, by my calculation, the O&M increase alone could be another $0.03 to $0.04 or maybe even a little bit more of drag versus your original guidance. So that would offset a lot of the weather year-to-date. So are other things just going right for you that you feel confident at this point or is there something we're missing?

Yes. No, I think, that's right, Chris. We expect when the weather turns favorable that we will invest. We do have higher needs and so we'll invest some of that back into our system. But other favorability, we're seeing year-to-date sales favorability, year-to-date depreciation favorability from the pace of in-servicing and year-to-date favorability and expected favorability in property taxes and other items. And so with that, we feel comfortable with the increase in the range.

Okay. Great. And then could you remind us of, I guess, the exact mandate on you coming out of the Colorado electric settlement for filing whether there was a -- an agreement to file or whether there was a kind of optionality on your part? And how that kind of led into this potential settlement that you're talking about now to delay the filing until, I guess, next spring?

Are you talking about under the multiyear plan from a few years ago where we were required to file?

No. From the -- I think, it was the April settlement that you had on tax reform there?

Do you want to take that, David?

So this is David Eves. So the April settlement, the commission approved part of that.

(technical difficulty)

Excuse me, my mic was off. The commission approved part of that, and we're refunding $42 million per year to the customers. The balance, which was to go to the prepaid pension asset amortization, the commission referred that to a judge.

I think, you're talking about the -- you're asking the question to file the general rate case, and our decision whether to -- what year and what the timing of that case would be and if we are required to do it. Is that your question? I think we're...

Right, exactly. You guys had mentioned that, that's now potentially going to be settled with interveners or talked about with interveners to not file until early next year. And my understanding was that April tax settlement that you had this year had some kind of agreement and it related to when you would file in Colorado electric next.

Yes, Chris, I don't think in our settlement agreement we had agreed to file a case. I do think -- we expect to file a case for revenue purposes and the settlement or the discussions we're having with stakeholders around, when and how and what to file is really more around exactly those 3 questions. Not necessarily whether we have to file. We had an obligation to file in 2018 -- or 2017 under the Clean Air-Clean Jobs Act, we did file. We indicated that we didn't have a significant revenue need in '18, but that the revenue need would be larger in '19 and '20. And we're working with all the stakeholders to come up with a plan and a proposal to move that electric case forward. But there's no obligation on our side that we reached in the April agreement on tax reform.

Our next question comes from Ali Agha with SunTrust.

First question, I wanted to clarify, Bob, when you talk about the 5% to 6% growth rate on earnings going forward, should we base that off your higher 2018 guidance right now? Is that fair that off that higher base we should see 5% to 6% going forward?

Well, no, Ali. We're talking -- you should base it off the last year. That's what we're basing our 5% to 6% long-term growth rate on. That said, I think we are well positioned in this forecast period, the 5-year forecast period to be at the top end, potentially even exceeding that 5% to 6% range. Clearly, the approval of the CEP plan would be helpful in that goal.

Right. And also, Ben, is it fair to say that somewhat linear that we should see that kind of growth rate year-in and year-out? Or how do you see that trajectories over that 4-year, 5-year plan?

Ali, I think there's a bit of volatility in that number. But I don't think it's significant. I mean, I think we expect to be in and around, as Ben said, the high-end of the range and potentially exceed it. But there'll be some years where we'll be below and some years, we'll be above it. And won't be 6.000.

Yes, got it. And then on the Colorado...

If it were, you should be skeptical.

Fair enough. Yes. On the Colorado gas case, when you look at the fact that they modestly reduced the authorized ROE as well as the equity ratio. One, was that somewhat of a surprise? And should we sort of think that when you do get to file the Colorado electric case so that would have implications, i.e. some reduction potential for ROEs and equity ratios on the electric side as well?

I would say, if I remember right, that was a 2-to-1 decision. So that wasn't a unanimous decision by the commission to bring it down to 9.35%. And as Bob said on the -- his prepared remarks, we're disappointed with that. We run a top quartile utility in terms of cost, reliability and safety. And I think, as everybody knows, that takes investment and that's exactly what we're trying to do in Colorado, and other jurisdictions. And long term, you need a good constructive regulatory outcomes to continue to be at top quartile utility, which is what we want to be. So that was a disappointment. But Ali, the treasury rates continue to rise, and I think we'll have to have continued dialogue with our commissions about the need for -- that ROE does matter in our business. So what it tells me, we need to do, is we need to be more persuasive and communicate better the importance of good regulatory outcomes to achieve the kind of results that, I think, our customers really appreciate and benefit from.

I think I'll just add one thing to that, Ali, which is as part of the gas case, we did agree to defer the TCJA impact to a separate proceeding, and we've got another opportunity to work with the commission and the staff on the impacts of the tax reform on our credit in Colorado. And so we have another opportunity, and our proposal is to raise that equity ratio at 57%, and we'll do that in that follow-on tax proceeding.

I see. And from a timing perspective, would that potentially get wrapped up before the electric proceedings? Because, as I recall, the electric equity ratio right now is 56% and -- which would be higher than where the gas was currently authorized to be?

I think the proceedings will be bifurcated. I think our schedule for the gas tax reform proceeding is, hearings in August -- or filings in August, hearings in September, and the commission decision later this year.

Our next question comes from Julien Dumoulin-Smith with Bank of America Merrill Lynch.

So maybe if I can, can I follow up on Ali's questions a little bit on the Colorado case. And just, if you can expand on your thoughts as to the implications to the electric case, specifically on the -- on a multiyear and forward-looking terms and perhaps elaborating on what alternatives or mitigation plans. You already described, to a certain extent, the mitigation strategies on the gas side. Can you talk about some of the levers on the electric side as well, if possible? Or how you see that kind of flowing through?

Well, I mean we're talking right know about the timing of the rate case and how we would file that. So I mean, those discussions are already ongoing. Our history there is, we've had 2 successful multiyear rate case filings. So I don't think we're breaking new ground, if we choose to follow a multiyear plan. I also would say, I mean, I think we've got opportunities to move that ROE up. And if you look at, I think, the perception of the commission on ROE, they tend to think that gas -- the gas side of the business can get by, if you will, don't necessarily agree with, but get by with a lower ROE. So I wouldn't use the outcome in the gas case as the proxy for how the electric case is going to go.

And to be clear, actually the mitigation plan you described for the gas side of the equation. Does that meaningfully change your CapEx at all? I mean, I suspect not, right? I mean, you are largely intending to continue to spend at the same level?

Yes. I don't -- If you don't get good recovery in the long term, you have to adjust for. But this should not impact our short-term plans. And remember, we also filed for a pipeline integrity rider, which covers about half of our CapEx. So we got another bite of the gas apple, if you will, too in addition to tax reform -- the tax reform filing Bob mentioned.

Excellent. And just a quick follow-up here on EVRAZ, as an industrial customer. I know that there've been some headlines around this through the course of the year. Are there negotiations ongoing about a tariff there? And to the extent which that there have, obviously, been some tariff changes in helping out the prospects of steel customers nationally, how does that impact the situation there, and potentially, the viability of that customer for you?

Well, thanks for the question, Julien. It's something I'm really -- we are doing, I think, a very innovative deal for EVRAZ, which is located just outside of Pueblo and employs, I believe, 1,000 people. That is innovative and it gives low-cost renewables to the steel mill, which allows them to expand versus contract. We've developed the program. I think, it's great when you can use renewables to help an industrial stay economic, and I'm really proud of it, and it is part -- it is tied into our overall preferred Colorado energy portfolio, which in itself, I think, is incredibly innovative. I mean, we're saving customers $200 million. And that's on top of an ERP plan that already leans heavily on renewables, and if you looked at what our traditional thermal RFP would be, if we went the fossil route, to be placed or to provide additional capacity of 450 megawatts, it would -- we're saving $500 million there. So this is $200 million on top of that. So -- and then we do a deal that you mentioned for EVRAZ. I'm pretty proud of what we're accomplishing. Not to mention, the environmental benefits, which 55% renewables, 60% carbon reduction. I can't be more proud of the team for what they've put together for our customers in Colorado. And we didn't -- we're not developing, if you will, special tariff. We're using existing rate structures within Colorado. Is that right, David?

That's correct.

Thank you. Did I answer your question? I know it went on a little bit of a ramble there.

No, but since you mentioned it, I mean, you talked about not using a special tariff here. I mean, they're clearly your largest industrial. I mean, are there others who're going to look at this and follow their lean on, sort of, following you guys at the special renewable deal?

No. Because this is pretty unique to the site. This is essentially behind-the-meter solar opportunity. I think, it's like 200 megawatts. Isn't it?

240.

Yes. So it's -- I don't know necessarily if it's replicable. That said, we want to have those kinds of discussions with our commissions. But again, this is a pretty unique deal, very innovative.

Actually just quick follow-up related to that, actually. On the solar ITC commenced construction. I mean, obviously, you got several 100 megawatts of solar pending under the Colorado Energy Plan. Can you comment a little bit about potentially expediting some of the solar CapEx just given what seems like, obviously, a generous package of ITCs available on the -- into the earlier 2020s now?

Yes. It is. But I do solar little bit differently than wind, Julien. And then I think with wind, we're probably locking in with the 100% or in the case of Dakota range, the 80% PTC wind prices that, as those PTCs start to diminish, and ultimately, fall off, I think it will take the technology a while to catch back up. And a decade. And I don't bet against technology, but I think that's probably where we are. So we wanted to lock into that economic energy source. Solar, of course, has a capacity element to it. And I believe, solar is going to continue to fall in price and very quickly offset the fall off of the ITC. So I'm more inclined to match our solar resources with our capacity needs. And as you know, our capacity needs tend to be more in the mid-2020s and beyond. So we're doing some solar, but as you know, we made an alternative recommendation in our preferred portfolio in Colorado, which should just go a little bit lighter on solar and some of the storage elements. Because we think the technology is going to continue to improve, and we'll have other opportunities to lock in great prices.

Our next question comes from Travis Miller with Morningstar.

One more follow-up here on the Colorado issue. If you were to get a disappointing outcome in the electric case, classified disappointing, however, you want to think about it. How would that impact potentially the investment that you make in the Colorado Energy Plan? Could you see perhaps taking it down a bit?

Well, I mean, there is different degrees of disappointment, right? But I mean, I think, it's been a reasonable zone. I don't see us -- and we would move forward with this plan. We'd have to look at what the revenue requirements and how they relate to the rest of our business. So I mean, I don't see -- I don't -- I think if the -- I think you can count on us. Let me answer this way, you can count on us. Barring some really extreme circumstances, we'd move forward with the CEP plan, and we do expect it to get approved, and we're excited about where it's going to put us in terms of the environmental improvements we're going to make on the behalf of our customers.

Okay. It's good. And then a broader question here. If we look beyond what you're doing on the wind side in Colorado and the new projects there in Southwest. How much more wind capacity is available? I don't mean capacity in terms of megawatts, I mean, just integrating on your system. How much more wind could you put on your system? So another way, could you double it, could you triple it?

I don't think you can double or triple it. I think what you'd be more inclined is some of the older wind projects start to roll off, you upgrade and through repowering. But when I look at where we're probably focus on in the 20s, it will probably be more oriented towards solar, as, again, we start the need -- the capacity to replace retiring coal plants. Doesn't mean we can't do more wind, we will. But as I have said before, Travis, this was an opportunity to buy wind on sale, and I don't think that prices are going to be this compelling for a while. So we really -- we loaded up.

Our next question comes from Jonathan Arnold with Deutsche Bank.

A lot of my questions were answered. But just on the Colorado plan and some of the staff commentary that you had in response, any thoughts around the issues raised and whether you could see the plan evolving through the process? So how confident are you that's going to emerge as filed?

Well, I mean, the staff set up was viable option, and they had some questions about what the actual level of savings are, but back to my earlier comment. I mean, this is a great place to be when we're providing -- when we're talking about well, maybe the savings aren't going to be as high as what your modeling assumption is. Of course, modeling has many different assumptions in it. But the reality is, I mean, we're talking about saving customer's money, while we replacing a coal plant and improving the environment. I mean, it's just an amazing story. So yes, I'm really excited about it, and I have to believe our commission's really excited about it too.

Okay. And then just reading some of the discussion. It sounds like that the delays were largely attributed to having more solar in storage bid than you anticipated and complexities of modeling that? Is that sort of the right read of what went on here? And how are you sort of thinking of working that going forward as you try to adapt to that need resource effectively?

Yes, we wanted to get it right. And there was a lot of different bids that came in and a lot of -- and the commission, of course, asked for different scenarios and iterations, and we wanted to be responsive to that. And it took time. That's all the delay was about.

Okay. And then just one. You said that we should still think about the 5% to 6%, the high end or potentially exceeding that off of last year. Are we talking about '17 actual or '17 guidance? I just don't recall what you said at the starting point.

That's all for the actual.

2/3, Jonathan.

Our next question comes from Andrew Levi with ExodusPoint.

So obviously, a lot of my questions were asked, and obviously, someone also asked the growth rate question several times. So I get all that and it's good answer. The only thing that I want to discuss, I guess, is just back to Colorado. Just talking among my peers and talking, sort of people on the sell-side, I guess -- and you did talk about a little bit. But just again back to the equity ratio in Colorado. Is that something that we should be concerned about longer term? I know you talked about the gap, the equity ratio may be going up to 57% because of the tax reform. But just overall, there's been like a lot of chatter about the equity ratio partly coming down in Colorado, which, obviously, wouldn't be good. So can you just kind of discuss that in a little bit more detail and kind of what the genesis of that? And when will we kind of know which direction, ultimately, it's going to go longer term?

Yes, Andy, let me give you just a little bit of perspective. We have been as high as an equity ratio in Colorado with 60%, of the commission and the staff there have historically recognized that the strong credit profile of the company is important. We've been stepping down from 60% over many years and then this last rate case proceeding with both the gas and the electric. We had agreed to file with the commission a lower rate than 56%, which is where we were in our last cases. And that was we filed 55% and 55% in a quarter, respectively, in those 2 cases. That was before tax reform. And so we all recognized the tax reform challenges, the credit profile of those companies a little bit. So we've asked in our proceedings whether they're in the case or whether they're in separate tax dockets to increase the ratio that company to preserve its credit rating. Those are ongoing. And I do think that over time, I think the trend that the commission would like to see is the equity ratio to come down mildly, but I don't think I'd be concerned. I think we've been pacing it for the past 5 or 6 years. But I do think we have taken a pause with regard to tax reform, and we do believe in our recommendation to the commission and the staffs are that 57% is actually the right number to be at for the time being.

Why is it that the commission wants the equity ratio to come down? I mean, obviously, it's a high level. But kind of what's the thinking on that?

Well, one thing I'd point out, Andy, this is Ben, is that, that 60% ratio when we obtained that, that was, if you remember, back in the mid-2000s, S&P was imputing capacity as a -- capacity payments as a form of debt on the balance sheet. So we were successful -- we successfully argued that the equity ratio needed to be higher, again, from a credit metric standpoint. And over time, we actually purchased some of those PPAs or they rolled off. And so there was a legitimate reason why you could take the equity ratio down. I think now, to Bob's point, we've got another credit issue. We'd say that the credit ratio has to be at least paused and then 57% is the level we're recommending. There's always going to be a push-pull though. I mean, for the obvious revenue requirement reason. So I don't think it's like a burning desire. I just think it's something that requires a continued dialogue.

Okay. And then just on the credit issue. I mean -- and I understand with tax reform, but does your Colorado utility actually have a credit issue or you just kind of stating that just because of tax reform?

Well, I think, broadly speaking, tax reform, as we change bonus depreciation and the impacts on deferred taxes that your primary credit metrics of FFO to debt or CFO to debt, all declined. And so on a net-net basis, I think that, absolutely, our cash flow metrics for both S&P and Moody's have declined. And so we want to preserve the credit ratios of these companies, then there's a couple of alternatives, one of which is improve the cash flow, and you can do that through accelerated depreciation, which we filed for in our Colorado electric utility and that's at the ALJ for determination if we can amortize the prepaid pension benefit. That will have cash flow benefits and that will have credit benefits. The other way to do it is with equity ratios or higher ROEs. In our estimation, the higher equity ratio is the cheapest way for the customers to preserve the credit rating of that company. And that's been our recommendation. Some portfolio have both accelerated depreciation and higher equity ratios to preserve the credit ratios at the public service Colorado company.

We're not in trouble, Andy, to...

No, no. I guess, that -- I mean, I guess there's just been a lot of chatter about it. I mean, I guess, my thinking is, tell me if I'm right or wrong, even with the lower equity ratio, I guess you have enough things to kind of offset that in other parts of your business or CapEx, like you said, to at the -- to be able to still achieve -- now if you ask 300 or 400 basis points on the equity ratio, I would assume you'd be able to achieve the high-end of your growth rate. Is that correct or not?

Well, I mean, yes, I mean -- but all that -- you have to work harder to achieve it, obviously. You broke up a little bit. But I think you were saying if the equity ratio fell 300 to 400 basis points, it wouldn't knock out our long-term growth plans. I mean, it wouldn't be favorable for us. But we've got other things, other levers to pull. As you know, Andy, because you pushed those many times to raise that long-term growth rate, we don't plan for a perfect performance and everything when we put out projections. We like to run a conservative company. We do that in almost every aspect of the business. How we run the systems, how we plan for the systems, having margin in your credit accounts, making sure we have lines of credits that are always available. So I mean, there's -- I don't think there is any one thing that knocks, that derails us from our long-term growth rate.

Our next question comes from Vedula Murti with Avon Capital.

In terms of the -- in Colorado again. You're talking about trying to either achieve settlements such that you file in mid '19 for rates in '20 or you'll be filing sooner than that. What are you trying to achieve or what's -- what are the major items that would -- that you're seeking such that you could delay the filings prior these discussions?

Vedula, thanks for the question. When we look back at our electric case that we had filed previously and some of the guidance and some of the issues that we heard from the commission, there was a real desire for us to file both a revenue case as well as a rate design case, and there's some complications with doing that for some of the previously decided issues. We've already decided depreciation in revenue associated with the Clean Air-Clean Jobs Act. We've got rider and revenue recovery associated with the Rush Creek assets that will go in service in October, November this year. And we have tax reform out there. And so those 3 large considerations factor into how we want to approach our next rate case with the commission. We want to satisfy their request, which is revenue and rate design, but there are some complications, and we're trying to resolve some of them in advance of the rate case.

Okay. I'm wondering in terms of the earned ROE in Colorado, as I would call it. There has been a gap of some materiality. Can you remind us in terms of, either whether its structural or some other reasons for the spread between the earned ROE regulatory in Colorado and the authorized and what can be done to get those more aligned?

Sure. Broadly speaking, Colorado as well as some of our other jurisdictions have, what I call -- what I've, historically, called leakage and lag. There are some items that aren't recovered under our normal jurisdictional revenue, and then there are, there is lag in terms of capital implementation. So our gas business has historically been a historic test year. And so there is lag associated with investments in the gas business. On the electric side, there are some items that we don't get full recovery on like a prepaid pension asset, which we, historically, earned a debt return on. And so that drives down the earned ROEs on a GAAP basis. When you think about it on a regulated basis, our electric companies earned at or close to it's allowed regulated ROE, but there are some items that, for regulatory purposes, are not recoverable. And we're always working on trying to close that gap, and we've done a decent job over the last couple of years in all of our companies to do that, and we'll continue to work to close the differential between sort of our earned and our allowed.

And going to SPS settlement you have here, didn't provide a clear opportunity to materially close the gap that has been there previously?

So when you're talking about the wind settlements in both Texas and New Mexico, if you remember, we were very adamant with our respective commissions around needing, what we called, concurrent recovery. And I think that in principle in both jurisdictions, we received that in order to put the wind farms in. The wind investment represents almost 40% of the capital base of those companies. And so getting concurrent recovery or near-concurrent recovery on 40% of your asset base will rise the earned ROE for the rest of the business and that's -- just mathematically, it's actually accurate.

Okay. one last thing. When will we know -- or when do you expect to be able to tell us whether, in fact, you have a settlement that defers the rate filing? Or you're unable to achieve that and you'll have to accelerate the filing?

Yes, I think in my prepared remarks we said in 1 month or 2. So I'd expect some time in September, we'll have a better idea, and we'll be able to talk about it either in a press release or in conferences or in our third order -- third quarter earnings call.

At this time, I would like to turn the conference over to Bob Frenzel, Chief Financial Officer, for closing remarks.

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

Thanks, everyone.

Thank you, ladies and gentlemen. This concludes today's teleconference. You may now disconnect.