Portland General Electric Company (POR) Q4 2017 Earnings Report, Transcript and Summary

Good morning, everyone, and welcome to the Portland General Electric Company's Fourth Quarter 2017 Earnings Results Conference Call. Today is Friday, February 16, 2018. This call is being recorded. [Operator Instructions]. For opening remarks, I will now turn the conference over to Portland General Electric's Manager of Investor Relations and Corporate Finance, Chris Liddle. Please go ahead, sir.

Thank you, Kevin. Good morning, everyone. I'm pleased that you're able to join us today. Before we begin our discussion this morning, I'd like to remind you that we have prepared a presentation to supplement our discussion, which we'll be referencing throughout the call, and those slides are available on our website at investors.portlandgeneral.com. Referring to Slide 2, I'd like to make our customary statements regarding Portland General Electric's written and oral disclosures. There will be statements in this call that are not based on historical fact, and as such, constitute forward-looking statements under current law. These statements are subject to factors that may cause actual results to differ materially from the forward-looking statements made today. For a description of some of the factors that may occur and could cause such differences, the company requests that you read our most recent Form 10-K. Portland General Electric's fourth quarter and full year 2017 earnings were released via our earnings press release and the Form 10-K before the market opened today, both of which are available on our website. The company undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. This safe harbor statement should be incorporated as part of any transcript of this call. Leading our discussion today are Maria Pope, President and CEO; and Jim Lobdell, Senior Vice President of Finance, CFO and Treasurer. Following their prepared remarks, we will open the lines for your questions. Now it's my pleasure to turn the call over to Maria Pope.

Thanks, Chris. Good morning, and thank you for joining us. Welcome to Portland General Electric's 2017 earnings call. During the year, we achieved several key objectives, and I'm pleased to share our results with you as well as discuss 2018 earnings guidance, provide updates on our operating performance, the economy in our service area, our participation in the Energy Imbalance Market and Integrated Resource Planning. Jim will then provide details on our upcoming rate case, tax reform, financial results and end with key assumptions supporting our outlook for 2018. On Slide 4, excluding adjustments for tax reform, our full year 2017 financial results were slightly ahead of the midpoint of our guidance with net income of $204 million or $2.29 per diluted share. When including the impacts of tax reform, we reported net income of $187 million or $2.10 per diluted share. Looking ahead, we are initiating 2018 full year guidance of $2.10 to $2.25 per diluted share, which reflects lower retail load this winter. Jim will provide more details later in the call. Turning to Slide 5. I'm proud to share that employees across the company did an excellent job in 2017 of serving our growing customer base. During -- according to the J.D. Power 2017 Electric Utility business customer satisfaction study, which was released just this last December, we were ranked highest in the West in business customer satisfaction. Our customers gave us high marks for customer service, billing and payment, power quality and reliability, communications, corporate citizenship and price. Additionally, our latest MSI research and TQS Research results reflect strong customer satisfaction, trust and favorability across all customer groups. In 2010, our T&D operations responded proactively to some of the largest storms in more than a decade. As a result, we experienced material increases in our strong restoration expense and customer outages. These types of events reinforce the need to invest in the reliability and resiliency of our system. We made solid progress on system improvements in 2017, including increasing system automation; replacing aging cables; upgrading, expanding and adding several substations; seismic upgrades at our hydro operations; and joining the Energy Imbalance Market. Turning to Slide 6. The economic fundamentals in our service area remained strong. Oregon's average unemployment rate for 2017 was 4%, the lowest full year rate on record. Oregon also had one of the nation's highest percent increases in gross domestic product for the second straight year, and this is on top of a 3.3% GDP growth over the past 2 decades. These and other factors, including Oregon's continued year-over-year population growth, supported a 1.3% increase in our customer base. At the same time, energy efficiency contributed to declining use per residential customer, resulting in a decrease of deliveries of 0.6% on a weather-adjusted basis. This was partially offset by the continued industrial strength from a high-tech sector. In 2018, we expect weather-adjusted energy deliveries to decrease just under 1% as a result of energy efficiency, the closure of a large paper customer in late 2017 and continued slow commercial growth due to challenges in brick-and-mortar retail. We are forecasting flat low growth for the next few years followed by a transition back to longer-term low growth of about 1%. This expectation is based on the Oregon Office of Economic Analysis' 10-year economic and population forecast, our outlook for high-tech and other large customers and the energy efficiency forecast from the Energy Trust of Oregon. Turning to Slide 7. On December 31, we completed our first full quarter of buying and selling power in 5-minute increments as a participant in the Western Energy Imbalance Market. By capturing more cost-effective resources available throughout the 6 participating states, we are able to better manage the variations of customers' load and variable generation. This is an important step as we continue to invest in reliable clean energy. With the implementation complete, we are now focused on market enhancements, including the potential participation in the expansion of the California ISO's day-ahead market. Turning to Slide 8. In December, the OPUC acknowledged our revised proposal to acquire 100 average megawatts of RPS-compliant renewable resources. This acknowledgment is another important step in helping our customers achieve their clean energy goals and aligns with the 20% of our customers who are already participating in our nationally recognized renewables program as well as the proclamation of several of our cities to move to a 100% renewable power. During 2018, we will be moving forward with the acquisition of these resources and then prepare an RFP solicitation that will enable the capture of expiring federal tax credits. The solicitation will be overseen by an independent evaluator and reviewed by the OPUC. We will consider proposals for RPFs qualified resources from multiple structures, including PPAs and utility ownership. As previously discussed, we have identified a potential benchmark as a resource option. In 2017, we delivered the proposal to the commission that calls for 39 megawatts of energy stores to be developed over the next several years at various locations across our systems. The capital cost of these projects is estimated to be between $50 million and $100 million, and it is not included in our capital expenditure forecast. In regards to our acknowledged need for capacity, we have now executed contracts for 300 megawatts. These agreements include 200 megawatts of annual capacity with 5-year terms and 100 megawatts of seasonal peak capacity during the summer and winter period. We expect our remaining capacity needs to be filled by acquisition of energy storage, capacity contributions from renewables procured through the RFP, contracts of qualifying facilities and market purchases. And now I'm pleased to turn the call over to Jim.

Thank you, Maria. Turning to Slide 9. Yesterday, we filed our 2019 General Rate Case with the Oregon Public Utility Commission. This filing requests an overall price increase of 4.8% after adjusting for the effects of tax reform, which is effective January 1, 2019. The request is based on return of -- return on equity of 9.5%, a capital structure of 50% debt and 50% equity and a rate base of 4.86 billion. The filing fixed recovery of costs related to better serving our customers and building a smarter, more resilient system and includes the expectation of higher net variable power cost in 2019. Some of the primary elements of this filing include upgrading our customer information and meet our data management systems to provide better and more secure service, replacing and upgrading electrical equipment that poses reliability risk, equipping our substations and distribution lines with technology that will help shorten outages, strengthening safeguards to protect against cyber attacks and other potential threats and adding infrastructure to support rapid growth in the region while helping to maintain reliability for all of our customers. We are respectful of the impact price increases have on our customers, and we are committed to protecting affordability and reliability. Regulatory review of the 2019 GRC will occur throughout 2018, with a final commission order expected to be issued by the end of 2018. Turning to Slide 10. In response to the Tax Cut and Jobs Act, we filed a deferral application with the OPUC on December 29. The intent of the filing is to defer all regulatory items with 2017 and 2018 financial impacts for a future refund to customers. If the deferral application is approved as requested, any refund to customers associated with the tax reform would be subject to an earnings test and limited by the company's previously authorized regulated return on equity. More specifically, the change in the federal corporate tax rate from 35% at 21% in 2017 results in a reduction to net deferred tax liabilities of $340 million. This reduction is composed to the following, a $357 million reduction to deferred tax liabilities that, as previously mentioned, has been deferred as a regulatory liability and is expected to be refunded to customers over time; a $17 million reduction to net deferred tax assets, which is associated with other business items increasing income tax expense by $17 million for 2017. We do not -- we do expect some impact to cash flow. Our credit metrics, however, remained strong with our FFO to debt metric in the middle upper teens and expected to improve over time. On to Slide 11, which shows earnings drivers for the year. First, favorable weather results in a $0.46 increase earnings that is composed of $0.24 for favorable weather in 2017 and a $0.22 increase over the previous year due to mild weather in 2016. Next, major storm restoration in the first half of the year decreased earnings by $0.08. Production tax credits represented a decrease of $0.08 as well due to lower wind generation. Carty added a decrease of $0.05 related to depreciation incurring cost for the capital spending above $514 million in customer prices and litigation expense. Next, a $0.05 decrease due to higher depreciation and amortization expense resulting from capital additions, a $0.07 decrease related to employee benefits and other items and finally, a $0.19 decrease resulting from additional income tax expense caused by that Tax Cuts and Jobs Act. On to Slide 12, we have provided the summary of the company's current capital expenditure forecast from 2018 to 2022. These expenditures are related to investments we are making in order to build and operate a more efficient, reliable and secured grid. These investments include upgrading, replacing aging generation, transmission and distribution infrastructure, strengthening the power grid to better prepare for earthquakes, cyber attacks and other potential threats and implementing new customer information systems and technology tools. We have not included any capital expenditures on this slide related to potential projects pursuant to our renewable RFP or energy storage proposals. As previously noted, we are pursuing legal action against Liberty Mutual and Zurich north America, the 2 sureties who provided the performance bond in connection with the Carty construction agreement. On July 10, the Ninth Circuit Court of Appeals held at the International Chamber of Commerce tribunal will decide whether the lawsuit is arbitrable in the International Court of Arbitration. An evidentiary hearing on this issue is scheduled for April 9 and 10 of 2018. For more details, you can refer to our 10-K. On to Slide 13. We continued to maintain a solid balance sheet, including strong liquidity investment-grade credit ratings. As of December 31, 2017, we had cash available short-term credit and letter of credit capacity totaling $692 million, first mortgage bond issuance capacity of $1.1 billion and a common equity ratio of 49.4%. The company has $500 million -- has a $500 million revolving credit facility to meet company's liquidity needs, which has a maturity date of November 2021, and letter of credit facilities totaling $220 million. In 2017, we issued a total of $225 million of first mortgage bonds at an interest rate of 3.98%. In 2018, we expect to fund estimated capital requirements with cash from operations, the issuance of debt securities of up to $100 million and commercial paper as needed. As shown on Slide 14, we are initiating full year 2018 guidance of $2.10 to $2.25 per diluted share, which includes the impacts of significantly warmer-than-normal weather in January of 2018. Additional assumptions include the following, a decline in retail deliveries between 0 and 1% weather-adjusted, average hydro conditions for the year, wind generation for the year based on 5 years of historical levels or forecast studies when historical data is not available, normal thermal plant operations, operating and maintenance costs between $575 million and $595 million, and depreciation and amortization expense between $365 million and $385 million. Our guidance includes $0.12 per share related to the ongoing Carty litigation, depreciation and carrying cost, which is included in the O&M and D&A ranges I mentioned a moment ago. Additionally, we plan to file a deferral application with the OPUC to capture the revenue requirement associated with our customer information system replacement project, which is expected to be placed into service during the second quarter of 2018. Our 2018 guidance assumes OPUC approval of the deferral application. Also please note that the equity return portion of the approved deferral would not be recognized on the income statement until we begin amortizing any amount approved by the commission. Back to you, Maria.

Thank you, Jim. Although seasonably warm weather has significantly impacted our lows as we start 2018, we are focused on initiatives to drive value for customers and shareholders. On Slide 15, this includes enhancing system reliability and investments to better serve customers, investing in clean energy and building a smarter, more resilient grid. And now, operator, we're ready for questions.

[Operator Instructions]. Our first question comes from Julien Dumoulin-Smith with Bank of America Merrill Lynch.

So quick question, if I can follow up on the guidance here. Can you quantify in the '18 numbers what the onetime effects are of weather? And perhaps also just help us understand what the trajectory of O&M inflation should be and perhaps to whatever extent this could be sort of onetime-ish in terms of the upticks. Or how structural is the inflation that we're seeing and given the greater lag?

Well, Julien, the things to consider is for weather, weather is about $0.11. It means we had the second-warmest January on record. So significantly impact our revenues going into the beginning of the year, and we are starting -- we have seen a pretty warm start to the month of February. So we'll just have to continue to watch that and see what the rest of the year looks like. From an O&M perspective, there is some growth. We've seen -- associated with some of the power plants and the distribution operations is where we're out there, trying to deal with all the growth that's occurring in the service territory. So I don't see it trajectory that's going to continue to increase. If anything, we're going to be spending a lot of time this year as we do in other years, trying to be able to maintain or reduce that as much as possible, especially given what we have seen from our current low forecast. Hopefully, that answers the question for you.

Absolutely. So just going forward, can you give us a sense of how you think about lag in the subsequent years? Obviously, you have a pretty meaningful rate case in front of you here. Any kind of shifts in your expectations? I know it's always tough to talk about sort of a multiyear view here.

No, not really. As I pointed out in my points, one of the things that we do have going on in 2018 is we're expecting our customer information system to come online. And when that comes online, obviously, we've got the revenue requirement associated with that we are filing a deferral application, and we're assuming that based on, historically, the support that we've been receiving from the commission that they will be able to defer those costs. So that could be a onetime item.

Got it. And then quickly, following up on the procurement activities. Where are you in these negotiation activities for the thermal side potentially or the capacity side?

Sure. So Julian, coming out of our IRP were three main areas. The first was capacity projects, and those contracts total about 300 megawatts. They have been finished up, and we've announced those. They go largely through 2025 a little bit beyond. Second is the RFP for wind, and we will be issuing a draft RFP shortly that will be overseen by the independent evaluator and the PUC, and that is for an average of 100 megawatts. And then thirdly was a series of studies. The first and most important of which is the Deep Decarbonization study, which has been done by Evolved Energy Research. It was just recently rolled out this past week to parties within the state, and really talks about the rapid increases in uses of the electricity as we see more fuel switching, continued grid modernization and leveraging technologies away to overall reduce the carbon impact of our sectors as well as other sectors in the economy.

Got it. And ownership potential on those pieces, just to be clear here.

Sure. As I mentioned in our prepared remarks, we are preparing and have been working collaboratively with a partner on an ownership option for the renewable RFP, and we continue to work collaboratively with that party.

The next question comes from Christopher Turnure with JPMorgan.

You certainly gave a bunch of details in the press release and in your comments, Jim, on kind of the rate case filing and a lot of the components of it, but I just wanted to make sure I understood the broad strokes. So you're asking for, I think, close to a 5% hike in rates, but that already includes the benefits to customers of tax reform in line ROE to what you currently have, and the deferral for the CIS system would not be part of that ask. But it's still a pretty big number. Is there something I'm missing there? Or are there other kind of costs or deferrals that will be taken off your balance sheet that might be driving up that number that we might not kind of see it flow through to your bottom line?

No, I think you've got the items right. The deferral associated with the CET when we go into 2019, we would expect the costs associated with that deferral to start amortizing that point. It really depends on what agreement we come with the -- or come to with the commission associated with it.

Okay. So there would be a little bit of an impact on the ask at least in that number from the customer perspective?

Indeed.

Have you disclosed how much that's hurting you versus not existing at all in 2018 in your guidance?

Are you talking about the revenue requirement associated with the customer information system?

Yes, I guess, it would be equivalent to the revenue requirement for that. So basically, how much are you getting hurt by that in 2018?

Well, we're deferring it, so we're not assuming that we're getting hurt by it. We're assuming we'll get the deferral application approved by the Commission. And so...

I misspoke, I wanted to see how much that would be even though, as you're saying, you are not getting hurt by the 2018 [indiscernible]?

You got me -- let me address it this way. There's about -- with the customer information system, we have assumed that it is included in our earnings guidance as a deferral. So we're not being harmed by it. There's no drag associated with it. The amount associated with that deferral is probably about $0.10.

Okay. Great, that's what I was driving at. Perfect. And then if we just assume your current CapEx plan, it looks like you are not anticipating any equity needs this year. Do you have a sense as to whether or not ex IRP success you might need to [up the] [ph] equity markets next year?

You're correct that absent anything associated with the RFP, we don't need any equity needs, and it's to be seen as to what comes out of the RFP process.

Okay. So without RFP success, let's say, in 2019 and 2020, you're still comfortable with the current ratings from the credit agencies in your balance sheet that you would not need equity?

Yes.

Our next question comes from Mike Lapides with Goldman Sachs.

A couple of questions. First, can you quantify the impact on cash flow from tax reform in 2018? I know you talked a little bit about it, I just -- I'm not sure I captured the numbers around it.

Mike, we didn't provide a number around it, but it's pretty minor.

Got it. So sub-$25 million or $30 million or something in that, south of that number?

Seems reasonable.

Okay. Second, Maria, you've had a couple of months now in the new role. How are you thinking strategically? How are you thinking about what your strategic imperatives, what you want the company to do differently under your leadership over the next 3 to 5, 3 to 7 years?

Sure. Thank you, Michael. It will really focus on a number of areas. As Jim outlined, our current capital expenditure forecast is weighted very heavily to reinforcing the resiliency and reliability of our distribution system as well as enhancing our transmission assets. We also are, right now, serving a very rapidly growing customer base that's transforming from largely an industrial type of colony based on natural resources to much more high-tech focus. We will be focusing a lot more on Smart Grid initiatives, and you'll see more announcements of that to come in future quarters as well as continuing our trajectory of delivering customers the green energy that they want. Being in Oregon and serving our customer base, we've been very successful in meeting their needs to date, and they are rapidly changing in their expectations. Also, we're seeing quite a bit of additional interest in our regulatory processes and wanting us to speed up in delivery of many of the things that we have been working on. So I think you'll see much more rapid execution as we move forward.

Got it. And if I think about your cash flow, and you have talked some about your cash flow coming up this year and what your cash for operation was in 2017. Given your CapEx needs and if you layer on the fact that you can issue secured debt you need to keep, you don't want to become over advertised, it seems that like you're going to be a significant cash generator over the next couple of years. If you don't win something in their renewable RFP, how do you think about the uses of that cash?

So as we look at the opportunities that we have in our underlying capital needs, we are really optimistic about the opportunities that we'll see, and I think those are all highly aligned with what customers want to see us doing over the next 5-plus years. Additionally, we're also mindful of making sure that we're returning adequate returns to our shareholders not only in the form of our underlying growth, but in terms of dividends as well.

Our next question comes from Paul Fremont with Mizuho.

This is Agustina [ph]. So our first question is you mentioned that you're expecting the RFP to be completed in '18. So would that include the commission approval?

That's our hope. And it's important because we're also expecting that we will be able to enable the use of existing production tax credits, which obviously have a shelf life and expire, and we all want to make sure that we capture those benefits for customers given that they're substantial.

Okay, great. So the other thing would be after remeasuring the deferred tax liabilities, you identified that $340 million to be deferred as the regulatory liability so based off of your filing, your recent December filing, where the estimated 2018 defer would be $60 million to $70 million, the amortization period would be roughly 5 to 6 years, is that correct?

The amortization period would be based on the underlying assets. So it would be 30 years for that matter, it just depends on what physical asset the deferral was associated with.

With the annual benefit from the -- just from the tax change?

I'm talking about the deferral associated with the underlying revaluation of the deferred asset -- or the deferred tax liability.

Yes. And the $60 million to $70 million, what was it concerning?

2017 and 2018 deferral amounts. In our customer prices, we have a statutory tax rate...

Of 39%.

Or effectively charging customers for the 35%, but you had the liabilities going to beat the 21%. So it has to do with that.

Okay. Perfect. And does the $4.86 billion rate base included includes the tax reform adjustments?

Yes.

Okay. All of them. So a possible increase in rate base coming from the deferred income taxes plus the refunds from the change in tax rate, right?

Yes. The reduction and the deferred tax liability causing the increase in rate base -- net rate base.

The next question comes from Steve Fleishman with Wolfe Research.

It's Steve Fleishman. Was that me? I couldn't hear.

Yes. It's you Steve.

Yes.

Okay, great. So apologize for clarifications. So the deferral that you're booking in 2018, obviously it protects you in terms of costs for the system. But just in terms of return like debt and equity return, could you just clarify whether you get any debt or equity return in the deferral?

When we file the deferral, we're filing it without the equity return. It doesn't show up until you start amortizing the amount. [Indiscernible] in the deferral, the amortization of the underlying asset.

Okay, great. And then just -- I may have missed this, but in the past, you've talked about continuing to invest more in the core capital plan and the system kind of reviewing that pretty much once a year or so. So is there another chance that we'd see the capital plan come up when you do that review of the kind of core distribution system?

Yes, I would expect so. In addition, where you're investing in the core to where you're adding in automation and additional resiliency, there's some differences between the two, but the net difference would be an increase probably in capital expenditures.

And when would that kind of happen? Usually, like third quarter or something? Or...

Yes, exactly. Right about the third quarter.

And the third quarter is when we meet with the board and go over the annual capital plan and operating plans for the upcoming year. So at that particular point in time is we have those discussions with the board, and then we updated our CapEx table.

Our next question is a follow-up question from Michael Lapides with Goldman Sachs.

Just curious can you touch a little bit what the biggest drivers of higher O&M cost in 2018 over '17 were and how you think about the trajectory there longer term?

The '17 over '18, what we're seeing is continued growth in the service territory that is driving up some of our O&M costs. We're spending a lot of money on the cybersecurity side of the house, so IT is a big driver. I don't see these things as being a trajectory, a perpetual trajectory, it will be over the next couple of years. As I mentioned earlier, we're spending a great deal of time as we have in the past, but even digging even deeper into our O&M expense over the 2018 time period to try and see how much of the January results that we'll be able to offset -- the January warm weather, that is.

Got it. Okay. And just curious could you talk about the growth kind of in the service territory leading to some higher O&M, but you're not really seeing demand growth. I'm just struggling to kind of tie up those 2 points.

Sure. Michael, what we saw near term was from a higher levels of energy efficiency than we have seen in the past. In particular, as we look forward to 2018, we're looking at energy efficiency roughly of about 1.6%. So when you look at the pretty dramatic increases in our population, about 1.3% to 1.4%, that's driving a lot of construction growth in our distribution system. It isn't necessarily translating into higher loads near term. But as we look at longer term, we're seeing substantial expansions at places like Nike, not only in terms of office, but in terms of manufacturing. We're seeing substantial expansion across the tech sector in semiconductor manufacturing with 3 new Amazon fulfillment centers being built in our service area over the next few years, and then, of course, rapidly expanding data centers. What we're going through short term is really a transformation. As I mentioned in prepared remarks, we've seen a very large paper company ceased its operations. We've also seen capacity reductions and other traditional industries such as metal manufacturing and then obviously the solar sector has been hit hard. So we're going through in a short period of time with transformation. But longer term, we feel very confident in our growth numbers, and our team in the operation are doing work to support that and build that in terms of line and substation extensions.

Got it. And then last thing, Maria. Just curious for your thoughts, kind of big picture, utility sector M&A and your views on whether tax reform impacts utility sector M&A broadly.

As you know, every quarter, we tell you that we don't comment on M&A. And so I'll probably keep it to that. And probably the tax experts who will know about interest deductibility at the holdco level better than we do

Our next question comes from Paul Ridzon with KeyBanc.

Just follow up on the CIS kind of in this period where it's doing nothing. Is it earning a return or building the rate base associated with?

No, it's accumulating AFUDC as we're continuing to finish the system.

Okay. And when will it be finished?

It will be finished in the second quarter.

And then I assume you're not going to entertain it. But in this rate case or feature rate cases, would you bring up decoupling? Or is that just a nonstarter in Oregon?

Well, we have decoupling currently, and we are -- as part of the 2019 General Rate Case, we've asked for an extension of it. It's supposed to expire at the end of 2019, and we're asking for some additional improvements in the determination of the decoupling as well.

I'm sorry. I should be more clear, weather-based decoupling?

We are doing a couple of things. Yes, a little bit more on the weather in decoupling fund mechanism. But also in the General Rate Case, we are looking at trended weather versus just going back and mitigate some of the historical. If you look at some of the weather trends that we've been seeing recently, we think that they are more impactful than what we have seen as far as some of the long-term history and the metrics that have been used to determine some of the weather that we've included in the General Rate Case.

Our next question comes from Greg Orrill with UBS.

Just a clarification in the rate case you filed, what's the test year there?

2019.

Our next question comes from Travis Miller with Morningstar.

I wanted to go back to the storage element. And I think I heard you correctly, you talked before the $50 million to $100 million. Can you just talk about some of the variables in that range? Is that cost side? Is there a variable here in the number of megawatts? Just wonder if you could talk about that range.

I think there'll be variables in all of that. We'll go out for competitive solicitations. We're looking for energy storage in roughly 3 different categories. The first would be customer side. The second would be connected to our substations and the distribution system. And the third would be located next to some of our generation facilities. In particular, the number of projects will vary as well the outcome of the competitive process.

Okay. And you kind of answered my second question on the large scale versus small scale. How much do you see that break down, in those three? Would the customer side be any greater or smaller and any of the other two that you mentioned?

So we're going to be looking at the economics and the value to the system of each. And so at this point in time, it's too early to forecast.

Okay. And then real quick clarification again. The $86 million rate case, did that include the amortization of the tax benefits or not included?

It does include.

Our next question comes from [indiscernible] with Avon Capital Advisors.

It's Andy Levi. So just on the $0.11 of the weather, is that versus normal or is that versus last year?

Versus normal.

Okay. So is it fair to say everything else equal that weather took down your guidance by $0.10, or not?

Yes, it took down our guidance.

Okay. So absent that, you would have been in the $2.20 to $2.35 range, is that kind of the way we think about it?

Absent that, we would have been higher. A few other moving pieces out there, but that was the big driver associated with it.

Okay, I got that. And then just on the wind RFP, is there any way to quantify -- I didn't get, you may not win it, but how much CapEx we're talking about there if that were to come to fruition?

Obviously, the amounts are known for how much their capacity cost. And on our last experience at Tucannon and Biglow is known out there. At this point in time, it's too preliminary for us just to say we haven't forecast any numbers of what it might be.

Okay. And then just again, obviously, you just gave '18 guidance. But just kind of looking at '19, just to understand. So that $0.10 that you talked about as far as for the customer information system? I'm sorry if I didn't hear enough, that was not part of the rate case? Or is part of the rate these?

It is. The $0.10 has to do with the deferral application for the revenue requirement associated with the system in 2018. In 2019, the entire cost of the system is included in our filing, and also I would assume that the deferral is as well.

Our next question comes from Paul Ridzon with KeyBanc.

Just on the wind RFP, you said 100 average megawatts, right?

Yes, absolutely.

And that in local capacity factors, that probably translates to, what, 300 megawatts?

That's kind of rough rule of thumb that we use.

Our next question comes from [indiscernible].

I was wondering, it would be really helpful as you present next time whenever you are at the conference or anything, that if you could share with us a walk-through slide from '17 to '18, because it's very hard to kind of see how the things are moving. You've talked a little bit about it on the call, but it would be really helpful for disclosure purposes that we have a walk-up slide that walks us through from '17 actual to the '18 guidance. So if you can think about it, I would really appreciate it as an investor.

Okay. Thank you for the feedback.

And I'm not showing any questions at this time.

Okay. Thank you. For those of you attending the Bank of America Merrill Lynch Conference in February or the Williams Conference in March, Jim and I look forward to seeing you. We appreciate everyone's interest in Portland General Electric, and invite you to join us when we report our first quarter 2018 results in late April. Thank you very much for joining us today.

Ladies and gentlemen, that concludes today's presentation. You may now disconnect, and have a wonderful day.