Portland General Electric Co (POR) 2014 Q1 法說會逐字稿

Good morning, everyone, and welcome to Portland General Electric Company's first-quarter 2014 earning results conference call. Today is Tuesday, April 29, 2014. This call is being recorded; and, as such, all lines have been placed on mute to prevent any background noise. (Operator Instructions).

For opening remarks, I would like to turn the conference over to Portland General Electric's Director of Investor Relations, Mr. Bill Valach. Please go ahead, sir.

Thank you, Jessica, and good morning to everyone. We are very pleased that you are able to join us today. And 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 will be referencing throughout the call. And those slides were posted on our website this morning, at portlandgeneral.com.

Referring to slide 2, I'd also like to make our customary statements regarding Portland General Electric's written and oral disclosures and commentary: that 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 that could cause such differences, the Company -- we request that you read our most recent Form 10-K and Form 10-Q. Portland General Electric's first-quarter earnings were released via our earnings press release and our form 10-Q for the first quarter of 2014 before the market opened today. And our release is available at our website, portlandgeneral.com.

The Company undertakes no obligations to update publicly any forward-looking statements, whether as a result of new information, future events, or otherwise. And this Safe Harbor statement should be incorporated as part of any transcript of this call.

Moving to slide 3, leading our discussion today are Jim Piro, President and CEO; and Jim Lobdell, Senior Vice President of Finance, CFO, and Treasurer. Jim Piro will begin today's presentation by providing an update on our operational performance, our service area economy, and our growth initiatives, and finally our regulatory strategy. Then he will turn the call over to Jim Lobdell, who will provide more detail around our first quarter's results, and discuss our outlook for the full year of 2014. Following these prepared remarks, we will then open our lines up and welcome your questions.

Now it's my pleasure to turn the call over to Jim Piro. Jim?

Thanks, Bill. Good morning, and thank you for joining us. Welcome to Portland General Electric's first-quarter earnings call. As presented on slide 4, we recorded net income of $58 million, or $0.73 per diluted share, in the first quarter of 2014 compared with a net income of $49 million, or $0.65 per diluted share in the first quarter of 2013. We are seeing strong performance across the Company this year. Construction of our three new generating resources is proceeding on time and on budget. We have a clear regulatory strategy in place to recover our capital investment. And our continued focus on operational performance is delivering benefits for our customers and our shareholders.

Now, for an operational update on slide 5. For the first quarter, our generating plants operated efficiently, with PGE generation availability at 95%. We continue to maintain top quartile system reliability metrics, and our national rankings for customer satisfaction our top quartile for residential, and top decile for general business and key customers.

In 2014, we continue to focus on safe and efficient operations through leveraging new technology and refining business processes. We're making progress with our transmission and distribution transformation project, which includes replacing our work and asset management systems and preparing for the replacement of our mapping and outage management system, as well. These upgrades will allow us to operate more efficiently and improve how we meet our customers' needs.

Now for an update on the economy and our customers. Turning to slide 6, our operating area continues to show positive signs of economic growth and new development. In particular, we are seeing higher levels of new connects, strong multifamily construction, continued expansion of high-tech, and a new Oregon Health and Science University building, which is slated to open this Fall. Also, Portland continues to attract software companies that have created additional demand for office space in an already tight commercial real estate market.

Employment indicators also continue to be positive. Oregon created 7500 new jobs in March, the highest single month since November, 2005. The unemployment rate in our core operating area was 6.2% in March, well below the national average, and down from 7.2% a year ago. Over the last year, employment growth has been centered in the construction, leisure and hospitality, and manufacturing, which includes food, transportation, and computers and electronics.

Our forecast for weather-normalized load growth is approximately 1% over 2013 weather-adjusted results, when excluding one large paper customer. This forecast is net of approximately 1.5% of energy efficiency, which we continue to see throughout our service area. When including the large paper company, which is reducing production this year to implement a more efficient manufacturing process, our load forecast is approximately flat. However, this reduction has negligible margin impact, since the customer is primarily on daily pricing.

Now let me update you on the construction of our new generating resources, which were selected in 2013 through a competitive RFP process based on least-cost, least-risk standards. Slide 7 provides detail on Port Westward Unit 2, a 220 megawatt natural gas capacity plant being built next to our existing Port Westward plant in Clatskanie, Oregon. The project is progressing smoothly, with recent work on the central core building, the exhaust systems, and the erection of the cooling tower. With the recent delivery of the 12th engine, all major equipment is now on-site, and we expect the plant to be operational in the first quarter of 2015. Total capital costs are estimated at $300 million, excluding AFDC.

Slide 8 includes details on Tucannon River Wind Farm, a 267 megawatt wind farm located on 20,000 acres in Southeastern Washington. Progress is continuing at the site, including road design and construction, pouring concrete foundations for towers, and construction of the O&M building and the substation. As we disclosed on March 31, we now expect Tucannon River Wind Farm to be online between December of this year and the end of the first quarter of 2015. Total capital costs are estimated at $500 million, excluding AFDC.

Lastly, slide 9 summarizes the Carty Generation Station, a 440 megawatt baseload natural gas plant that is being constructed next to our existing Boardman plant. Land has been leveled at the site, and we have started foundation work for the gas turbine. We will continue with other foundations over the next few months as we prepare to receive the heat recovery steam generator in the third quarter, and the gas and steam turbines early next year. The plant is expected to be operational in mid-2016, with a total capital cost estimated at $450 million, excluding AFDC.

Slide 10 provides a summary of the Company's five-year capital expenditure forecast. The new generation projects are expected to result in an average rate base increase of $1.2 billion. This growth, along with the base business capital expenditures, should lead to a rate base of approximately $4.5 billion in 2017.

Now for a regulatory update on slide 11. In February, we filed a new general rate case with a 2015 test year, requesting an overall revenue increase of $81 million based on a 10% ROE; a capital structure of 50% debt and 50% equity; and rate base of $3.9 billion. The request includes a small increase in base business cost, which would be more than offset by several customer credits that we propose to begin amortizing in 2015.

The primary focus of this general rate case is cost recovery of Port Westward Unit 2 and Tucannon River Wind Farm. We are requesting customer price changes at the time these resources go online. Together, these projects represent a net incremental revenue requirement increase of $98 million, expected to be effective in the first quarter of 2015. The general rate case is currently in the discovery stage, as we respond to data requests from the OPUC and other intervenors.

In late May, we will participate in settlement conferences, with intervener testimony following in June. We anticipate that the Commission will issue a final order in mid-December. If the request is approved, the average overall price increase for all components, net of customer credits, would be 4.6%. In addition, on March 31, we filed a renewable adjustment clause, or RAC, to defer the net incremental revenue requirements for Tucannon River Wind Farm, in the event that the project comes online in December of 2014. This mechanism allows us to mitigate regulatory lag between the project online date and the date of customer price changes.

Now I'd like to turn the call over to Jim Lobdell, who will discuss our financial results for the first quarter, and update our forecast for the remainder of 2014. Jim?

Thank you, Jim. Turning to slide 12, as Jim mentioned, for the first quarter of 2014 we recorded net income of $58 million or $0.73 per diluted share compared to net income of $49 million or $0.65 per diluted share in the first quarter of 2013.

The increase in net income reflects closer alignment of revenues and operating expenses, as authorized in the 2014 general rate case, and an increase in the allowance for funds used during construction for the three new generating resources.

In addition, the increase in earnings per share was slightly offset by an increase in the average shares outstanding quarter-over-quarter, as a result of a total issuance of 2.4 million shares in June and August, in connection with our public offering of 2013.

Moving to slide 13, total revenues for the first quarter of 2014 increased $20 million to $493 million, driven by the price increase on January 1. This impact was partially offset by a $7 million decrease related to lower energy deliveries. A 2.5% decline in residential energy deliveries accounts for the majority of the revenue decrease.

However, since the decline was not weather-related, our decoupling mechanism enabled us to recover most of the lost margin. Purchased power and fuel expense decreased $8 million quarter-over-quarter, driven by a decline in total system load and a slight decrease in the average variable power cost per megawatt hour.

Below-normal hydro conditions early in this year turned around a wet March, and we are now forecasting to be at or slightly above normal.

For the first quarter of 2014, net variable power costs were $3 million below the annual power cost update tariff baseline, compared to $1 million below the baseline for the first quarter of last year.

PGE's sources of generation were comparable quarter-over-quarter. Energy received from PGE's owned and contracted hydro resources increased 4%. Energy received from PGE's owned wind resources decreased 11%. Coal generation was slightly down, as Colstrip Unit 4 was still offline during most of January 2014.

Moving on to slide 14, production, distribution, and administrative costs totaled $108 million for the first quarter of 2014, $3 million higher than a year ago. This increase was largely due to increased storm and service restoration costs and higher operations expense, due to an increase in our ownership of the Boardman coal plant from 65% to 80% as of December 31, 2013. Overall, we're on track to be within our full-year operations and maintenance forecast of $480 million to $500 million.

Depreciation and amortization expense increased $13 million quarter-over-quarter, driven primarily by two factors; $5 million, related to an overall increase in capital additions, and $8 million related to the timing of the deferral and amortization of costs of four capital projects.

Interest expense was comparable quarter-over-quarter. A $3 million increase from a higher average balance of long-term debt outstanding was entirely offset by an increase in AFDC from borrowed funds. Other income, net, increased $2 million quarter-over-quarter. The $4 million increase in AFDC from equity funds was partially offset by a decrease in earnings on our nonqualified benefits plan trust assets.

Lastly, income taxes increased $3 million quarter-over-quarter. In addition to higher expected taxable income in 2014, this increase was driven by a decrease in production tax credits.

Turning to slide 15, we continue to maintain a solid balance sheet, including adequate liquidity, and investment grade credit ratings. As of March 31, 2014, we had $764 million in cash and available credit, and a common equity ratio of 49.2%. Total capital expenditures for the first quarter of 2014 were $185 million, including $110 million for the three new generating resources.

On our fourth quarter earnings call in February, we disclosed that that while our guidance was based on issuing the remaining 10.4 million shares under the equity forward sale agreement in the first half of 2014, we were also exploring alternative financing opportunities. As a result, we are now pursuing a financing plan under which we delay equity issuances under the equity forward sale agreement until the first half of 2015.

In May, we expect to enter into an 18-month unsecured loan agreement to borrow approximately $305 million. We also anticipate executing a bond purchase agreement to issue approximately $280 million of first mortgage bonds, with draws delayed to the second half of 2014. These financings are subject to receiving OPUC approval to increase our authority to issue long-term debt by $300 million to a total of up to $700 million. This revised financing plan allows us to finance our new generating resources in a more cost-effective way.

Moving to slide 16, we are increasing our full-year 2014 earnings guidance by $0.05, to $2.05 to $2.20 per diluted share, driven by the delay in issuing equity under the forward sale agreement. All other guidance assumptions remain largely unchanged, as detailed on the slide.

Back to you, Jim.

Thanks. In 2014, we are focused on our initiatives that deliver value to our customers and our shareholders, including completing construction of our three new generating resources on time and on budget, achieving fair and reasonable results in our 2015 general rate case, and continually operating our system efficiently and effectively.

Now, operator, we are ready for questions.

(Operator Instructions). Lauren Duke, Deutsche Bank.

Can you talk a little bit about what happened with residential sales? You mentioned the paper customer hurting your industrial sales, but not hurting the margin. But what did you see on the residential side in the quarter, and what makes you feel more comfortable about the rest of the year?

Jim, you want to take that?

Yes. Lauren, as we looked at the residential customers, it's cyclical. It's weather-adjusted. You find the building cycles that are going on out there are delaying, so we're seeing a little bit less because of that. Energy efficiency continues to be an influence on seeing those loads. But we are continuing to see an increase in the new connects, especially as we look at multifamily. I was actually really surprised at the number of new connection, from a multifamily perspective.

So, you've got to keep in mind that we are decoupled, associated with residential load, and we're still seeing some relative growth associated with it. But as we have always pointed out in our earnings guidance, overall from a load perspective, we're not expecting much to come out of residential. But the majority is going to come out of the commercial and the industrial sector.

Okay, thanks. And then, lastly, can you just update us on some of the more generic proceedings at the Oregon PUC, on pension? And then the PCAM mechanism that you guys and PacifiCorp have been supporting?

Yes, I can do that. On the pension docket, not a lot has happened right now regarding that. We've got some pre-hearing briefs that are due later this month, and then some cross examination, so there's still a bit to be seen. But you've got to keep in mind, there's multiple utilities that are involved in that docket. I have to say, we don't always see everything in the same light.

And regarding the PCAM, we had asked the Commission about opening up a docket or an investigation regarding PCAM. And when we first approached that, we did it from the perspective of looking at the entire mechanism.

In talking to the stakeholders in the process, we have subsequently asked to narrow that discussion, at this particular point in time, to just looking at compliance associated with the RPS standard in the state (technical difficulty) of meeting that standard. So, more to come, as far as what's going on there. We did hold a workshop last month in regard to it, as well. But right now, there is no schedule set.

Do you think we could see resolution in either of those cases in 2014? Or should we be thinking of that more as a 2015 issue?

To be honest with you, Lauren, I'd say, let's look more at 2015 at this particular point in time, given the fact that there's no schedule set for it.

Okay, great. Thanks, guys.

Neil Mehta, Goldman Sachs.

This might be early here, but can you talk through the way you're thinking about capital allocations? You're going to start throwing off significant free cash flow in 2015, and that's going to accelerate in 2016. So, what are the different options you have, in terms of allocating that excess cash?

Good question, Neil. As we look through this cycle, we'll finish Carty in the 2016 timeframe; we will be starting another IRP -- integrated resource planning -- process, probably starting late this year and going into next year, that really deal with a couple issues. One is the replacement of Boardman, which retires in 2020. We have the next 5% renewable portfolio standard requirement that hits us in around 2020 to 2021. We're also looking at having to replace our billing system. We're working very closely with the Commission on getting alignment around that replacement of that billing system, which is getting over 12 years old.

So there's a number of projects still ahead of us to look at. Capacity is becoming more dear in the region, so we may need to add additional capacity resources. So those are all things that are on our radar screen at this point. Obviously we have to go through the process; go through the integrated resource plan like we did before; develop an action plan; likely have to do an RFP. But I think we have good options to potentially compete in those RFPs, and we'll just have to play that out.

So I think we're still committed to meeting our customers' energy needs with firm, long-term resources that control the cost and reduce volatility. We will have to go through the process. There will be of fair amount of conversation on how we replace Boardman. That's over 400 megawatts for us, on our share of it, so it's a big slog of energy that we're going to have to look at the replacing.

So those are the options ahead of us. So those will probably happen in the 2018 to 2021 timeframe. So I think as we look ahead, there is places where we can deploy capital that will add value for both our customers and our shareholders.

Got it. And in the guidance, you're still assuming normal hydro conditions. So can you talk about where you are versus normal, in terms of the hydro at the rivers and sites that matter to you, and what that could mean relative to the PCAM?

Yes, Neil. On the Grand Coulee, as you know, the river forecast [under it] is 110. Everybody was pointing out to us, earlier in the year, how that number was way down, especially at The Dalles at the lower end of the system, where we started out in January at 80%, and right now we're at 104% because of Miracle March. But, again, the mid-Columbia River is looking very healthy for the year. Clackamas is around 91%. It's looking pretty good. And then the Deschutes is almost up to 100%. It's at 97%.

As far as our generation, or our capability to take energy out of those river systems, everything looks good. We do have a bit of reduction coming out of the mid-Columbia because of the Wanapum facility, so we're down a little bit there. But, otherwise, everything else looks pretty healthy.

And the one thing you have to watch now is that we got a pretty healthy snowpack. The question is, how does that snowpack come off? We were actually seeing snow yesterday. So what we would like to see is a very slow warming, so that that shows up in July and August. But if you get a very heavy heat wave or something and it brings it off quicker, that obviously affects energy prices and the value that we get out of the system. So now we're just watching to see how the runoff comes off, which can affect the value of that.

Makes sense. And last question is on AFUDC. Embedded in guidance, how much AFUDC is in there this year? And can you talk about the trajectory, post-2014, as assets come into service?

Yes, Neil, we typically don't provide any guidance around AFUDC. But if you could just think about the amount of capital that we have got to add; if you look at the CapEx table that we've provided, that gives you some guidance. If you have to look inside AFUDC, then it's pretty much one-third debt, two-thirds equity. So, that's about all we can provide you at this particular point in time. The key is, is that these payments move around all over the place, and we've seen a bit of that. So that's why we particularly don't provide any type of guidance.

All right. Thanks, guys.

(Operator Instructions). Paul Ridzon, KeyBanc.

Can you just review how the assumption that has evolved around the drawdown of the equity? It was originally first half of 2014, correct?

Yes.

And then, in the --.

Go ahead.

And then the year-end call, you said that you might be able to delay that to the second half of 2014.

Yes. Well, what we've got going on there is, if you recall back to 2013, we had the write-off of the Cascade Crossing investment, which reduced our bonding capability. And so as a result of that, we decided that we were going to pull down the equity forward in the first half of 2014, and then go to the first mortgage bond market in the second half of 2014.

Based on -- back to the question Neil was asking -- movement of cash flows or CapEx expenditures, we've now been able to look at it and say there's a more cost-effective way to finance these resources, and mitigate some of our interest rate risk at the same time, by going out and doing an unsecured bank loan in the first half of 2014.

But what it looks like now is, instead of doing the equity (technical difficulty), we're actually going to push that out to the first half of 2015. And in order to be able to provide the financing associated with the capital expenditures for 2014, we'll do the bank loan in the first half of the year; first mortgage bonds in the second half. And then once we pull down on that equity forward in 2015, we'll use that to pay off the bank loan. Hopefully, that gives you the detail you're looking for.

So there will be no new equity issued in 2014?

No. We've got all the equity that we need under that equity forward agreement.

I just had it being a little more accretive than $0.05, particularly with the depreciation drop that you outlined. Are there other offsets?

Not that I'm aware of, no. Not in my math. There'd be lower AFUDC because of the fact that the interest costs associated with the bank line are going to be lower than what we would otherwise have incurred. But that's not $0.05.

And then was wind this quarter normal, or was it particularly strong last year? What were the dynamics?

Well, overall, last year, wind turned out to be pretty much on target as far as the volume. Now, the issue was the same thing that we're seeing this year, is the wind is just really not blowing at the right time. So we're ending up getting power out of the wind farms at the lower-cost hours, versus the higher-priced hours that we expected it.

(multiple speakers) They were lower than that.

But barely. We're not that much down (multiple speakers).

I think we're 11%.

Well, 11%.

We're 11% lower this year on the wind.

That's right.

So, we're down on wind a little bit in the first quarter, and we'll have to see how it turns out the rest of the year.

And then just after you filed your rate case, was there any notable public reaction, or anything in the press?

No, not really. I think when we went out and talked to customers and we did some survey work before we filed it, I think given that this was around adding new resources to meet our customers' needs; and adding two significant resources, one a renewable resource, plus the capacity resource to really support the wind resources. I think customers understand that new resources are going to cost a little bit more, and a 4.6% increase was not very large, considering we're adding two new large resources to our portfolio.

So I think, overall, the reaction has been very -- almost minimal in terms of customers' reactions. Obviously, we don't like to raise prices. It was nice having the credits to offset that price increase, to minimize the impact. So, no, we haven't had much reaction at all.

Great, great. Thank you very much.

Brian Russo, Ladenburg Thalmann.

Can you just remind us what the effective tax rate is in the 2014 guidance?

The effective tax rate in the guidance is about 25%. We're giving a range of around 25% to 30%, is what's in there.

Okay, great. And in terms of the PCAM, and how the capacity factors and timing of dispatch for wind, was there any negative impact on the PCAM due to the variability of wind in the first quarter?

Yes. Yes, because we were below our AUT filing, in terms of what we expected. So it goes to the calculation in terms of where we are. But we're still within the dead band, I think, is where we still are, right?

Yes, we're still in the dead band.

Yes. So, we're still in the dead band. But that does affect the calculation. As since we are below our AUT filing amount, that would have a negative effect on the results.

Is there any way to isolate the impact on that? I'm just trying to get a sense of the request for investigation into the PCAM with the wind costs, and what type of financial impact a favorable decision could actually have.

Well, there's a couple things there, Brian. First of all, in the last rate case we did adjust the forecast for wind, and went to an updated forecast using some historic average, as well as the forecasts from what we're seeing from the project. We would hopefully continue doing that, truing that forecast up over time, so there might be a lag effect to that. But we're asking for in the rate case and the PCAM related to the wind resources that track it directly.

Now, I think that would be on a forward basis. It probably wouldn't change this year's results. This year it would probably go through the PCAM, but it would affect 2015 if we were to get this mechanism. And so it would be a better match. I think argument is it's going to go through the result, either in the AUT filing or the actual setting of prices. But to do it on an actual basis in the year would be better matching of both the results.

So, I don't think you'll see anything this year, but it might affect 2015 in terms of getting better alignment around our generation and our cost.

The other thing I'll add to that, Brian, is that last year the lost value of energy -- because it blew at the wrong time -- was about $4 million, if I remember correctly. So, we would hope, in the future, if this mechanism was in place, we'd be able to recapture that; and then any adjustments in the production tax credits, as Jim pointed out.

Okay, great. And then lastly, it just seems with the delay and the settlement of the forward shares, in addition to $5 million of lower D&A, that there would be a little more upside sensitivity to the midpoint of your guidance. I'm just wondering, are you guys just being conservative because you're only one quarter into the year? Or are there any offsets that weren't noticeable by us?

The D&A has nothing to do with, actually, operations. It's actually just kind of a geographical change inside the financial statements. And, no, I don't know of any other offsets, other than what we've mentioned already.

Okay, thanks very much.

Brian Chin, Bank of America Merrill Lynch.

Just a general question on the IRP. If I understand the 2013 IRP, you'll likely get the acknowledgment from the OPUC sometime around September, or maybe a little after September of this year. In your slide deck comments, you've stated, well, usually the Commission gives considerable weight to actions that are consistent with the acknowledged IRP.

Is there a hard line there, where the Commission will likely give considerable weight to the IRP before it even acknowledges it? Or is there some sort of defining event? This September 14 acknowledgment -- is that defining event where we might get a lot more Commission formal approvals, or better weighting of the outlook for different projects, following the acknowledgment of this IRP?

So, this new IRP doesn't really relate to the last IRP, in the sense that the last IRP addressed the need for the new resources, which we went forward and did an RFP on, and we're now under construction. So that whole cycle is part of that action plan, which really goes back to 2009, when we filed that integrated resource plan. So that's all been completed. It will be a topic of the rate case that we currently have before the Commission, on prudency. But we believe that the Commission's order and acknowledgment represents a high standard for that prudency review. And the fact that we did an RFP, and the fact that we had an independent evaluator watching over the process, we feel pretty good about that entire process.

This latest IRP that we filed does not have many resource actions. It continues our commitment to energy efficiency, to a demand response program, to more distributed generation, and a commitment to do a lot of studies in preparation for the next IRP that is beyond this one.

So the Commission will hopefully reach a decision later this year -- September, we hope -- on acknowledging the action plan that is in that IRP. But it's pretty minimal in terms of financial impacts or opportunities for the Company. It's really continuing our commitment to energy efficiency and the things I mentioned, and doing the studies.

And so we will take that acknowledgment as guidance as we prepare for the next IRP, which we'll start working on later this year, and file probably in the 2015 timeframe. That IRP will have a lot of potential resource actions related to both new renewable resources and addressing the shutdown of Boardman, which will occur at the end of 2020.

So, that is kind of where we are in the cycle, so this isn't -- so we don't expect a lot out of this Commission order. We do expect them to acknowledge the action plan and comment on the studies we're doing. But I don't think it has any -- there's no major resource decisions in this IRP that's currently before the Commission. Is that helpful?

Okay. Yes, it is, and that makes a lot of sense. I guess as we look forward to the next draft IRP that you'll be filing, any lessons learned from the last RFP process? Obviously there's a little bit of a hiccup there on different stakeholders arguing different things in terms of the outcomes, and you guys defended your position very well. Does that give us any lessons in terms of how the Company should conduct future RFP processes, to make the process more smooth?

No, we actually feel really good about the RFP process that we conducted. I think it was an open and transparent process. If you read the independent evaluator's report, I think he showed that the Company was very fair in its evaluation, and it was a very balanced approach. So I feel like we did everything right, and the results prove themselves out through the process. There's always going to be disappointed bidders, but our job is to make sure that we run a process that is open and transparent, and that we have someone independently observing.

So I think that's what we learned through the entire process, that we should follow the process, because it is -- gives us credibility in what we're trying to do and ensures that we deliver the least-cost, lowest-risk project for customers. So, we'll probably follow the same process again.

Very good. Thank you very much.

(Operator Instructions). Andrew Weisel, Macquarie Capital.

Wanted to go back to the financing, real quickly. In terms of the interest expense from the bank loan and the first mortgage, what sort of ballpark rates are you assuming?

We're expecting kind of short-term rates as you look at the bank loan, so it's probably around 1%. In the first mortgage bonds, you're probably looking at probably around the 4.5% range.

Okay. And you said the bank loan, you plan to repay about a year from now, when you settle the equity, is that right?

Exactly.

Okay, great. My next question is the change to the CapEx plan for Carty. What was the reason for reducing -- or postponing, I guess, a lot of the spend from this year to next year?

Yes, Andrew, I'll have to get back to you. We have slight shifts in payments as things are transpiring at the project, but nothing material, or nothing outside of our projected plan.

Yes, we're still pretty much on budget and on schedule.

There was a shift of about $40 million or $50 million from year to year. Nothing specific you can call out now?

No. Well, we'll take a look at it and get back to you.

Okay, great. And then just my last question, after you increased your ownership of Boardman, I'm a little bit surprised that the generation mix was basically flat year-over-year. Any high-level thing you can call out, why coal wasn't a bigger share of the sources of power?

Well, in the first quarter, remember Colstrip Unit 4 was down for the first month in January, so that might have offset in the increase in Boardman. So that's probably why it seemed about the same.

That makes sense. Thank you very much.

Andy Levi, Avon Capital Advisors.

Just on the financing that you did, what are the benefits to customers? I believe there is some, as far as --.

We haven't done it yet. We're still getting approval, just to be clear. But the bottom line is we reduce our AFDC on the projects, which minimizes the cost to the overall rate base additions to our customers. So, it's going to be slightly lower; it's a benefit; basically have a lower interest expense that runs through AFDC.

Okay. So there should be some type of great benefit --.

The benefit there keeps our costs low and keeps our rate base impact from -- shows that we are being prudent in trying to take actions to keep costs down for customers. Which is why we have always been a real supporter of owning these projects, because we make our estimates in the projects, and then things turn out to be even better than what we expected.

One of our analysis assumes average cost, the long-term cast of capital, things like that. We've had a low interest rate environment, and we have been able to take advantage of that. For example, on Tucannon River Wind Farm, there was a huge tax reduction for sales tax, which we've been able to take advantage of and deliver to customers.

So there's things that come our way on these projects that we're able to take advantage of, and pass that benefit on to customers, and keep their prices lower. So, those are the things we all try to do to improve the impacts, or reduce the impacts for customers.

Great. And then just two more questions. What was the earnings impact, if there was anything significant on just the one month additional outage at Colstrip?

It was $1.5 million of replacement power cost.

And that's pre-tax, right?

Yes.

Right.

Yes.

And then, finally, just when do you think the Board should take a look at the dividend, relative to your construction program?

So, what we do at the Company is each May, at our May Annual Meeting, we do a dividend review and look at our dividends and relative to our earnings. That Board is committed to being competitive with the dividend. There is a restriction of equity forward agreement right now that doesn't allow us to change it more than what we've changed its historically. I would tell you the Board is committed to growing the dividend. And as we deliver earnings growth, we want to grow that dividend to reward our shareholders for being part of this opportunity.

So we will do that. This year, I would not expect anything out of the ordinary other than what we've done historic. But we are -- I will tell you, the Board is very interested in rewarding our shareholders, and having that dividend grow as we grow our earnings, and add value for both our customers and our shareholders.

So, the dividend -- I'm sorry, the equity forward has to be completely drawn down before the policy can change? Is that --?

Yes. We can make increases based on our historic actions, but nothing outside of that.

Okay. And then when will -- in your forecast, or what you've articulated, when will the forward be completely drawn down? Is that at the beginning of next year?

It will be completely drawn down by June of next year. We had a two-year window on it.

Okay. So, Jim, so you say, typically in May, but you may not be drawn down until the end of June. Is it possible, or should we not think this way, that as your two plants -- your peaker comes online and your wind plant comes online -- that we may see a deviation to the May timeframe on dividend consideration, considering that your June timeframe on drawing down the forward? Or will we have to wait until May of 2016?

No, I think -- well, we'll look at next year. My guess is we'll probably fully draw that by the time we make a dividend decision. We said by June; that's the requirement under the agreement, given our capital needs and our spend. It's going to be close; but I think we'll take that all into consideration as we make that decision. So, I can't handicap it for you, but I think we'll generally try to address that, and be in a place where we can address the dividend in May of next year.

Okay, so it's possible that you could have drawn down everything by the time the dividend decision comes up.

Yes.

Okay, cool. Thank you.

And it appears there are no further questions. I'll turn the conference back over to Jim Piro for any additional or closing remarks.

Thank you again. We appreciate your interest in Portland General Electric, and invite you to join us when we report our second-quarter 2014 results in late July. Thanks a lot, and have a great day.

This does conclude our presentation for today. Thank you for your participation.