Portland General Electric Co (POR) 2013 Q1 法說會逐字稿

Good morning, everyone, and welcome to Portland General Electric Company's First Quarter 2013 Earnings Results Conference Call. Today is Wednesday, May 1, 2013. This call is being recorded, and all lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer period. (Operator Instructions) And now for opening remarks, I'd like to turn the conference over to Portland General Electric's Director of Investor Relations, Mr. Bill Valach. Please go ahead, sir.

Thank you, Vicki, and good morning, everyone. We're very pleased that you're able to join us today. And before we begin our discussion this morning, I'd like to remind you that we have prepared a PowerPoint presentation to supplement the discussion today, and we'll be referencing slides throughout the call. For those of you accessing the call over the phone, the slides are available at our website at investors.portlandgeneral.com.

Referring to slide 2, I would also like to make our customary statements regarding Portland General Electric's written and oral disclosures and commentary that there will be statements on this call that are not based on historical facts 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 discussion of some of the factors that may occur that could cause such differences, the Company requests that you read our most recent Form 10-K and Form 10-Qs.

Portland General Electric's first quarter earnings were released before the market opened today, and the release is available at PortlandGeneral.com. The Company undertakes no obligation 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.

As shown on 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 discussion by providing an overview of our performance in the first quarter and an update of our strategic initiatives. Then Jim Lobdell will provide more detail around the quarterly results and our expectations for 2013. Following these prepared remarks, we will open the line up for your questions. And now it's my pleasure to turn the call over to Jim Piro.

Thanks, Bill. Good morning and thank you for joining us. Welcome to Portland General Electric's First Quarter 2013 Earnings Call. As slide 4 shows, on today's call I'll provide an overview of our financial and operational performance, give an update on the economy in our operating area, discuss the progress on our strategic initiatives, and provide you an update on our general rate case. Then Jim Lobdell will give you a financial update discussing the quarter's results and our outlook for 2013. So let's begin.

As you can see on slide 5 our financial performance in the first quarter was solid with net income of $49 million, or $0.65 per diluted share. This is equivalent to what we earned in the first quarter of 2012. We are affirming full-year 2013 earnings guidance of $1.85 to $2.00 per share.

Now into operational excellence on slide 6 -- we delivered excellent operating performance in the first quarter of 2013. Our delivery system and generating facilities operated well with the average duration and frequency of outages in the top quartile and generation plant availability factors exceeding our goals. Our overall customer satisfaction also remains very strong. PG ranked in the top quartile for residential customer satisfaction and the top decile for business customer satisfaction in Market Strategies International most recently available surveys. We also ranked second nationally for large key customer satisfaction in the TQS, Incorporated, annual survey.

As you know, we've been implementing new technology systems in several areas of the Company including transmission and distribution, human resources, and finance and accounting to help improve processes and reduce operating costs, which are critical to our efforts to keep customer prices as low as possible in the face of increases in regulatory and inflationary costs.

Now let's move on to slide 7 for the economic outlook in our operating area. Oregon's economy continues to improve. We've seen a turnaround in the residential housing market as well as steady employment growth in high tech, manufacturing, business services, and leisure and hospitality. Oregon's unemployment has dropped to 8.2% compared with 8.3% at the end of the last quarter and 8.8% a year ago.

The unemployment rate in our core operating area is 7.3%, down from 7.4% at the end of the last quarter, and 7.5% last year. The state continues to be ranked second in the nation for in-migration, which helped PG continue to add customers. While we're seeing positive economic indicators, our energy deliveries in the first quarter did not reflect this improvement. Adjusting for weather and the 2012 leap day, deliveries were about flat quarter-over-quarter with declines in the residential and commercial loads offset by increases in the industrial load. Jim will address this in more detail later in the call.

Now please refer to slides 8 and 9 for an update on our progress executing our integrated resource action plans. We are nearing the completion of the RFP processes, and I will cover where we are with the four resources we are seeking.

First, capacity -- we will break ground on Port Westward 2, our new 220 megawatt natural gas plant this month. The plan is expected to cost between $300 million and $310 million excluding the allowance of funds used during construction and will create up to 200 construction jobs in the area. The in-service date is currently slated for the first quarter of 2015.

Second, seasonal peaking capacity -- these resources will be power purchase agreements, and we're in negotiations with the bidders.

Finally, the energy and renewable resources. Negotiations are underway to secure both of these resources from their respective final short lists, which includes both purchased power agreements and PG ownership options. We expect to announce the outcomes midyear.

The RFP processes have been thorough, and we are pleased that the independent evaluator representing the Oregon Public Utility Commission confirmed that the RFPs were conducted in a fair, unbiased, and transparent manner.

LET'S turn to slide 10 for an update on Cascade Crossing. PG signed a memorandum of understanding with the Bonneville Power Administration in January to explore a collaborative regional solution that could provide up to 2,600 megawatts of transmission capacity. The full project scope as described in the MOU would cost at least $800 million. The project is still preliminary and subject to reaching an agreement with BPA.

The current negotiations involve complex issues, include consideration of various transmission options. The expected scope and timing as well as the estimated costs will become clearer by the end of 2013.

Now on to slide 11. As we discussed last quarter, PG filed a general rate case in February with a 2014 test year. Our filing supports an average overall price increase of about 6% starting on January 1, 2014, and includes an ROE of 10% and a capital structure of 50% debt and 50% equity. We are currently in the discovery phase, and the schedule anticipates settlement conferences with the OPUC staff and other interveners at the end of this month. Following that, OPUC staff and interveners will file their first round of testimony by mid-June.

We expect to complete the 10-month regulatory process in mid-December, with a final order from the Commission at that time.

Now I'd like to turn the call over to Jim Lobdell, our Chief Financial Officer, who will discuss our financial and operating results for the first quarter and review our expectations for 2013.

Thank you, Jim. Turning to page 12, net income for the first quarter of 2013 was $49 million, or $0.65 per share, equivalent to earnings in the first quarter of 2012. Net income was positively impacted by reduced power costs, lower storm restoration costs, and decreased interest expense. However, these items were offset by lower retail energy deliveries and higher income taxes.

Moving to page 13, total revenues for the quarter were $473 million, down $6 million for the same period last year driven by a decrease in price and volume of retail energy deliveries. Average retail prices decreased 3% quarter over quarter based on a price decrease on January 1st of this year to reflect lower expected power costs. Although retail deliveries decreased approximately 1% quarter over quarter, the revenue impact was partially offset by the decoupling mechanism, which under we recorded a collection from customers of $4 million in the first quarter of this year.

As Jim mentioned, energy deliveries adjusted for weather and a leap day in 2012 were flat quarter over quarter. During the first quarter of this year, we've seen lower-than-expected residential and commercial deliveries. While the high-tech industry continues to grow, we experienced decline in the solar industry, the partial closer of a paper mill, and reduced usage in the government sector.

Based on deliveries this quarter, we are guiding to the lower end of our initial load growth forecast of 0.5% to 1% over 2012 levels.

As we move through the second quarter and complete our regular load forecast updates, we will provide more information on our expectations, going forward.

For the quarter, purchased power and fuel expense decreased $3 million to $192 million with a 2% decrease in the average variable power cost. Hydrogeneration from PG-owned and mid-Columbia hydro resources decreased 12% this quarter compared to above-average conditions a year ago. Generation at our Biglow Canyon Wind Farm was about the same quarter over quarter, representing 5% of PGE's retail load requirement in both periods. Thermal generation increased quarter over quarter, accounting for 47% of PGE's retail load requirement.

Overall, PGE's net variable power costs were $1 million below the annual power cost update tariff baseline for the first quarter of this year compared with $5 million below the baseline a year ago.

Moving on to slide 14, production, distribution, and administrative costs totaled $105 million this quarter, a slight decrease from the first quarter of 2012. While pension expense increased, we saw a lower delivery system expense as a result of no major storms in the first quarter of this year.

Depreciation and amortization for the quarter was $62 million, equivalent to the first quarter a year ago. Just as we did last year, we will continue to record a deferral for capital projects from 2011 and 2012 as a reduction to depreciation. While there was no increase quarter over quarter, we expect approximately $3 million of incremental deferral throughout 2013 for a total depreciation and amortization reduction of about $18 million.

Interest expense decreased quarter over quarter due to a $100 million first mortgage bond that matured in 2012. Offsetting these savings was a $2 million increase in income taxes quarter over quarter as our effective tax rate rose from 23.4% to 26.2%. This increase is largely due to lower forecasted wind generation in 2013 resulting in a reduction in expected production tax credit but was partially offset by an increase in the PTC rate.

Now on to slide 15. We continue to maintain the solid financial position including investment grade credit ratings and strong liquidity. As of March 31, 2013, we had $681 million in cash and available credit and an equity percentage of 51.8. On April 1st, we repaid $50 million of maturing first mortgage bonds with cash, bringing our equity ratio to 52.6%. We expect to issue a $50 million to $100 million of long-term first mortgage bonds during the second quarter to meet our cash needs. In addition, we still plan to fund the construction of the Port Westward 2 unit with cash from operations and debt issuances.

Depending on the outcome of the energy renewable RFPs that Jim Piro just covered, we may access the capital markets in the near term for equity and/or additional debt. As Jim also noted, we are affirming our 2013 guidance of $1.85 to $2.00 per share. As you can see on slide 16, this range is based on load growth towards the lower end of our initial range of 0.5% over weather-adjusted 2012 levels, slightly below normal hydro conditions, normal plant operations, and wind generation based on an updated forecast that more closely reflects historical performance.

A full year O&M expense between $440 million and $460 million including approximately $10 million of increased pension expense year-over-year; depreciation expense between $240 million and $250 million, including a minor increment of D&A reductions from the capital deferral projects; capital expenditures between $505 million and $525 million, which does not include any potential expenditures for resources related to the energy and renewable RFPs; and we've had capital expenditures of $108 million so far in 2013.

And, finally, approximately $5 million to $6 million in noncash AFUDC for Port Westward 2.

Jim, back to you.

Thanks. Our operating and financial performance for 2013 is on track, and we're looking forward to continued progress on our strategic initiatives in 2013 including building Port Westward 2, selecting energy and renewable resources, and completing the 2014 general rate case.

And now, Operator, we're ready for questions.

Thank you. (Operator Instructions) Neil Mehta, Goldman Sachs.

On O&M, you did a terrific job in the quarter there. The $105 million came in well below the $110 million to $115 million run rate that you set out on a quarterly basis at the beginning of the year. Was there anything unusual to take into consideration? And is it fair to assume that you're tracking towards the bottom end of the $440 million to $460 million range that you laid out in that same guidance?

I would say that what we're seeing, Neil, is just more of a timing difference at this particular point. We are gaining savings through a lot of the efforts that Jim Piro had mentioned earlier, and then as we point out, there was a little bit of improvement because of no major storms. But we seem to be online for our projections for the range that we had given in guidance at this point.

Fair enough. And then on hydro, conditions, as you said, are slightly below normal. But even in years where you've had slightly negative hydro, you've still been able to break even on the PCAM through other components of the PCAM. Do you still think that's the case, or will the PCAM impact be negative in 2013 as you look at it?

No, I think that we'll still be where we need to be. There's a lot of moving parts going on out in the wholesale power marketplace this year including hydro down in California is down significantly, so -- but we could see some improvements in the value of the holdings that we have.

Okay, got it. And so then can you comment on the potential for you to ultimately acquire the assets that you didn't win in the RFPs?

On that one, we can't tell you. We're in the negotiations right now, and when we reach the end of those negotiations, we'll let you know. And as we mentioned, it could be either a purchased power agreement or an ownership option for the Company. So, hopefully, we'll have more to report in the next few months.

Sarah Akers, Wells Fargo.

As a follow-up to Neil's last question, I know the RFP conversations are confidential, but can you tell us if it's still a matter of identifying that winning bid or is it safe to say that the top bid's been identified, and you're just negotiating the final contract details?

The way the process works is we get the short list, and we start with the one on the top of the list based on our business judgment, and then we start the negotiations. And if we can reach the finish line with those negotiations within the context of the bid, then that's what we'll execute. If we can't, then we go to the next one on the list. So we're in negotiations right now. We can't tell you whether we're still at the top or the bottom or where we are, but that's the process we go through.

Got it. And then on sales, you mentioned that sales growth is not necessarily reflecting the improvements that you're seeing in the economy. Do you think there's just a natural lag time there, or is it more of a structural issue with conservation and efficiency?

You know, as we looked at it, we were looking really hard at this issue, and there's a whole bunch of things going on in the marketplace. The economy is still relatively fragile, people are being relatively conservative. I think we'll start seeing a pickup later this year, and that's why we're watching it pretty carefully. People have instituted efficiency measures, they try to be more efficient in their operations -- all those things kind of impact usage -- some of it's conservation. So there's just a whole host of things that add to that. And as businesses get stronger, we would expect to see a recovery in those sectors. But there have been some changes, as Jim mentioned, when the paper customers shut down one of their lines of operation. So, you know, there are some structural changes also that are going on in the marketplace.

Great, and then will you be able to update the rate case to reflect the downwardly revised sales expectations? Can you capture that in the test year?

As we go through the process in the rate case, we have various options -- various timings which we update the rate case load forecast. I think September is the time we -- we do it in June, and I think we also do it in September. So there's a couple, three times we update the load forecasts -- capturing the latest state economic data and the latest trends in what we're seeing in the loads themselves.

And just to recall -- on the residential side, that sector is decoupled, and a small portion of our commercial sector is decoupled for specific energy efficiency measures. And so if we get it wrong on the residential side, either way, that tends to go back to decoupling, and that change in use per customer can be due to a variety of things including efficiency.

Brian Russo, Ladenburg Thalmann.

In the past you guys have kind of alluded to, like, 100 basis points of lag for just unrecovered costs. And I'm just wondering can you give us an absolute dollar value for that, because I would assume as your rate base grows the percent basis point lag will decline.

Right. That's a great question, Brian, and you're right that it does change as the rate base grows. Right now we have about a $3 billion rate base. As we add more to rate base then the fixed amount of the disallowances will be a smaller percentage overall. And the major area of disallowances are things like corporate contribution, image advertising, and some of the incentives for officers.

So those are the typical numbers. If you go back to previous rate cases and look at that, it's in the $13 million range in terms of what's disallowed in the regulatory filings for cost recoveries, and that can be a little bit more or less, but the major items are the ones I discussed.

And so you are correct -- as rate base grows, then that becomes a smaller percentage of the ROE and would cause less of a drag on ROE as we go forward.

Okay, and I guess on that topic, that your rate base really isn't growing with the 2014 test year. So the narrowing of that lag would probably occur in 2015 after adding the Port Westward 2 plant to base rates, correct?

Right, and that will be somewhere in the $300 million range, which will add to rate base in 2015 when that plan goes into service, but that's correct.

Okay, and then, correct me if I'm wrong, but I think in the past, you also had unrecovered interest costs related to some debt that falls outside of your regulatory debt of, roughly, $12 million. Is that captured in the lag on the corporate costs you just talked about? Or is that in addition? Or is that taken care of already?

No, that's just the imprecision in the capital structure. I think it's different than the overall, what's allowed in the regulatory filings including CWIP, and so some of that is just timing issues and some of it's just the difference between the regulatory weighted cost of capital and our actual weighted cost of capital.

So does that create lag in addition to that historical 100 bips of lag?

It can in some cases; in some other cases, it may not. So I think it's hard to really quantify that precisely.

Lauren Duke, Deutsche Bank.

Good morning. I was hoping I could get you guys to give us an update on your thoughts for timing of reaching a definitive agreement with the BPA on Cascade Crossing? Just when we might get a -- be able to have a better sense of the timing of the capital spend associated with that?

At this point, the best we can tell you is probably by the end of this year we'll have better clarity on what this project is going to look like. We've gone through various iterations with BPA on trying to look at this as a single utility project. As you recall, we started with a kind of we will build this line from the Boardman area down to Salem. That project was kind of independent of Bonneville and provided us the 2,600 megawatts of capacity we thought we needed.

The regional economics continues to change, and so as we've been working with Bonneville on this single utility solution, many factors have come into play around how we would integrate and get 2,600 megawatts of capacity. So we're doing a lot of transmission studies right now in cooperation with BPA to figure out what are the reinforcements? Where are the capital adds that need to be made? You know, the MOU contemplated a line that went from Coyote Springs to a new substation called Pine Grove, at which point we would interconnect with BPA.

So we're now trying to work through all that with the transmission planners and the latest forecast of new generation in the region and trying to figure out what is the right way to plan this on a single utility basis. I would tell you, we're doing a lot of transmission studies, and we're in detailed discussions with BPA on how to bring this all together to create the best benefits for both BPA and our customers and do this in a single utility sense.

So -- our hope is by the end of this year we should have real clarity on what this project will look like. But it's still all subject to our negotiations with BPA and reaching agreement with them on the right kind of split and allocation of resources.

Okay, and I guess the kind of updated thoughts on your sales forecast outlook would also potentially impact this as well.

It has some effect, although I think this is a small blip in the curve. I still see us having continued economic growth, we're going to need to continue to add resources, and the line will provide long-term reliability. Transmission takes a long time to build, and you have to look at it over a 20- to 30-year time horizon. Our general view is we'll continue to see demand growth throughout the region, and transmission is a necessary component to meet that growing demand.

Our current view is it's better to do it now than to wait until the very last minute just because the complexity of building transmission. And so that's part of the other conversation with Bonneville is the time horizon of which we would need to add strategic assets to increase the capability of the transmission system.

So I will tell you, we've got a lot of focus on it. I really appreciate what Bonneville is doing in terms of working with us on this single utility. It's got a lot of traction in terms of other support, and the environmentalists appreciate that we're trying to think about this holistically. So that's kind of where we are.

Okay, and then, secondly, can you just quickly quantify the impact of weather versus normal on an EPS basis for the quarter?

Jim, do you want to cover that one?

Yes. On a quarter over quarter, we had about a $0.01 impact associated with that, Lauren.

Pretty close to normal.

Yes.

This year was pretty close to normal?

Yes.

Maury May, Wellington Shields.

A question for the CFO Jim. It's a little confusing now, we've got two Jims.

Ask Jim.

And Jim won't answer.

Okay, so for the CFO Jim -- just, again, on your comments on the working of the PCAM for the rest of the year -- did I hear you say that a slightly below average hydro year will lead to a slightly negative PCAM?

No, no. It won't lead to a negative PCAM. I mean, we are down a bit in our average variable power costs. We hedged pretty much everything that we have got going into the year. Loads are down but, at the same time, I think that the power markets are going to be picking up here as we move further into the year. The hydro is -- well -- the hydro in California, as I mentioned earlier, is down significantly, so I think that's going to have an impact on the Pacific Northwest. But I think, overall, we'll just be slightly lower than the baseline, but about $1 million at this point -- so pretty much in line.

Okay, so pretty much in line, but really the first quarter is where you think you'll stand by the end of the year?

Maury, it's really too hard to project that at this point, a lot of things can change -- the operation of our plant, gas prices in the regions, California demand --

Yes, I know, I know, I know, okay.

There are tons of factors, so to tell you that it's going to be $1 million by the end of the year, it's just too early to make that projection.

Okay, but you're looking at it being pretty close to in balance, I guess.

As we're looking right now, but as Jim pointed out, there's a lot that can change between now and the end of the year.

Yes, okay, okay. Second of all, can you review once again the equity levels that you discussed currently? And then the equity levels versus planned debt and equity issuance?

I think Jim discussed that in his remarks, and I think we're at about 52.6%. We're at -- yes -- right now -- we repaid the $50 million of maturing first mortgage bonds, and that brings us to 52.6% as Jim pointed out.

Okay, and that's at the end of March or now?

That is April 1st.

Okay, okay.

That's pretty much where we are right now.

And then you mentioned a bond offering coming. Can you discuss that again?

Yes, in the second quarter we are looking at the potential of going out from -- anywhere from $50 million to $100 million of first mortgage bonds. Just trying to maintain the liquidity of the Company; try and make sure that we're not dipping into any additional short-term debt at this particular point in time given all the activity that's going to be going on with Port Westward 2 -- so just kind of positioning ourselves in that perspective.

And then the big question, the equity question -- are you still looking at 2014 for possibly an equity issuance?

We don't know what we're going to be doing at this particular point in time because we don't know what the outcome will be of the renewable and the equity -- or not equity but energy RFPs are. If they are power purchase agreements, we'll take a very close look at it to see what the impact of power purchase agreements are on the capital structure of the Company. If it turns out there are ownership opportunities, then, obviously, we'll be looking very closely at the debt and equity markets.

Okay, and final question really has to do with those RFPs -- the base load and the renewable. A couple of months ago you were saying that you thought it would be late June and early July that you would get the results of both of them, and I notice in the slide deck also you're talking midyear. So are you really still talking late June, early July, for both of those RFPs?

Yes, we're still looking in the second quarter. I think that's our plan right now. Negotiations are going well, and we should be able to announce the winning bidders in that timeframe.

Okay, so it will be probably in June -- probably in late June for both of them.

In the second quarter (laughs).

(Operator Instructions) Paul Ridzon, Keybanc.

Good morning, can you hear me?

Yes, got you. Good morning, Paul.

Good morning. Can you just give some order of magnitude of the megawatt hour annual basis delta between your new wind normal versus the old wind normal? Or the capacity factor?

I still need to look in the rate case. In the rate case what we did is we looked at it as a five-year rolling average, and that's what we've done with our thermal plants in terms of availability factors and (inaudible) values. And so in the rate case we did project, based on a five-year rolling average, what the wind would be. We'll try to use that for the forecast compared to what the original design was, which was a certain number. Jim, do you have the exact numbers on what that would look like in terms of difference in megawatts?

No, I don't. I was just thinking another way to look at it is there was -- I mean, the wind farm is 450 megawatts. We were looking at -- these are approximate numbers -- around 30%, a little bit north of that originally in our first profile, and now we're down to oh, approximately, 25% as far as the capacity factor expectation for the wind farm.

We can get you the exact -- or Bill can get that for you, because in the rate case we did show the five-year rolling average for wind generation based on actual results, and that's what we're using for our forecast, going forward. And then we'll just true that up, over time -- similar to what we've done with hydro to determine normal. Prior to that, we were using kind of a theoretical number that was based on studies for that site, and that study's -- those studies may still be valid, but because of just the timing issue, we're going to a five-year rolling average. And so Bill can get you those numbers offline, but they're in the rate case so they can be discussed.

And then on the RFP, assuming it's a PPA, did I hear you, in response to Maury's question, suggest that maybe the imputed debt would drive an equity raise?

Something we're really concerned about, just given the new accounting standards and how a purchase power agreement would show up on the balance sheet and affect our ratios. So generally S&P takes a view that purchased power creates a debt-like obligation to a company and therefore they view an imputed debt to look at our overall ratios, and that's a concern to us. And with the new accounting standards potentially coming forward we might actually have to put the obligation on the balance sheet, which we then have to balance.

So we believe that if we entered into purchase power agreements, we might have to increase our equity ratio to offset that obligation. And we're looking at it pretty closely. Our goal is to maintain investment grade credit ratings and anything that would put downward pressure on that would be a concern in terms of raising our costs and raising the cost to customers. So we are factoring that in, and we'll have to make some decisions around that based on the obligation and the nature of the negotiations and the contractual kind of arrangement.

So you mean you could do an equity raise either way, depending -- either outcome? So I guess there's --

No, we're not going to say one way or the other, but we'll clearly evaluate it and include it in our decision-making and look at that, if it were a purchase power agreement what that obligation would look like.

And are both the energy and renewable -- could those go either way -- PPA or cell phone?

At this point we've said either way it could go, and we're not tipping our hand, if you will, which way it will go.

So there's four potential outcomes -- two PPAs, two cell phone, and then flip one of each?

It could be any combination of those potentially.

Got it, okay, thank you very much.

David Paz, Wolfe Research.

A few follow-up questions -- in your rate case, I think you mentioned you will be filing updates, I think it was in the context of sales forecast. Will you also be updating any impacts on bonus depreciation in 2013?

We made a projection in the rate case for our tax depreciation. As I recall, we have not exercised bonus depreciation just because we don't have the capacity to utilize it. So we continue to evaluate that, going forward, to see if it still makes sense to or to not do it.

So we'll likely not update it, but if there was a decision to do something that was different than the rate case, it would probably come through the discovery process. But right now I think our plan is not to move forward and exercise bonus depreciation just because we don't have the tax capacity.

Got it, okay. And so the last time you exercised bonus D&A was in 2011?

I think that's about right. We did 50% in 2013 -- so yes, it was 2010.

And the reason for that is we're generating so many production tax credits is that we don't have the tax capacity to utilize the bonus depreciation. So we're just going to normal taxes.

Great. Also, I noticed that you updated your ongoing CapEx. I think you raised '13 projections slightly and then slightly lowered '14-'17. Just curious -- are those changes just due to timing or changes in assumed escalation rates -- or what is driving those slight tweaks?

Mostly just regulatory updates that's going on. But I'll get back to you.

No problem, all right, and then just on what you discussed earlier on the higher equity layer or potential higher equity layer under a PPA scenario for the base load and renewable RFPs. Would you request a higher authorized equity layer or would you need to seek approval from the LPC? And could that be done in the current rate case?

So the way you would do it is the regulators typically want to see real equity on the balance sheet as opposed to theoretical (inaudible) structure. I think if we were to enter into purchased power agreements, we would have to look at the effect of that on the balance sheet and how it would work and if we believed there was a requirement for extra equity to offset that obligation, we'd have to have a plan to issue it, and then we would reflect that in a future rate case. It probably wouldn't hit us in the 2014 rate case because likely the purchase power agreements, if they were to go that way, wouldn't be hitting our balance sheet probably until later beyond that period.

So it might be a subject of a 2015 rate case potentially, but it would be something we'd have to demonstrate the prudency of and why we would need that, especially as it would impact our bond ratings and our cost of capital.

So in the interim you would still target 50-50?

Well, at this point we're targeting 50-50 at least for the 2014 rate case. 2015 is a whole different game depending on what the outcome of the RFPs would be.

(Operator Instructions) Lauren Duke, Deutsche Bank.

A follow-up on the equity ratio comments. Given that you're already at 40 -- I mean, given that you're already over-equitized right now, and if you didn't win more RFPs, you might continue down that path, is it possible that you could ask for an equity ratio increase without actually having to issue market equity?

That's a possibility. I don't know if you'd be able to build your equity balance enough to offset a purchased power obligation. But, again, it depends on the nature of the PPA obligation and the contractual arrangement. And then in discussion with the rating agencies how they would do that as well as the accounting treatment on our balance sheet.

So there's a whole bunch of things that get factored in there. I doubt if you could build it just summarily over time just by retained earnings so that would obviously factor into the analysis as you grew your equity and really didn't have any need to issue debt.

Andy Levi, Avon Capital.

Just a couple of things, I guess, to clear up. Just back on the equity and the PPA -- so if it ends up being PPAs, the equity wouldn't -- assuming you would have to issue equity -- that wouldn't be issued until the PPAs came online? Is that kind of the way to think about it?

Well, I think you have to look at the obligation of when you're entering into the obligation and when the rating agencies would include that. So it usually starts when they start delivering, if you will, and you have the obligation to pay it.

Okay, so I guess the goal would be kind of to get that equity ratio higher in conjunction with an equity raise/PPA. Is that kind of the way to look at it?

That's correct.

That's correct. Again, we will work closely with the rating agency so that -- we work with them to understand what that, in fact, is on our ratios and ensure that we maintain credit worthiness.

If I recall correctly, as you look at a PPA, you're not looking at the full value of a PPA, but you're looking at a subset of that.

Right, right, right, right. I just wanted to clear that up because that's, obviously, an important detail. The second thing is, which I was happy to hear, was that as your rate base grows and, in particular, I guess, if the renewable/baseload ends up being a build and purchase type thing or if someone else builds and you purchase, that that regulatory lag comes down, over time. So I think that's probably fairly significant and I guess something new to investors. Is that -- because I don't remember you guys talking about that.

Well, I think it's just the basic math of the equation. You have certain dollars that you don't necessarily get recovery on, and those dollars just become a smaller percentage as your rate base grows. So I think that's just math. If you look at other utilities that have a much larger rate base, they probably have about the same amount of dollar disallowances. But with a larger rate base, it's just a smaller percentage for them.

So if you look at our rate base per customer, we tend to be at the lower end of the range for utilities, and that's because we are basically short on generation. As we add more generation, and get ourselves more in line with where others are in terms of reserve margins, et cetera, then that unrecovered cost becomes a smaller percentage.

I think that's significant because I think most sell side analysts really just take your rate base and assume 100 basis point rise, and that's how they come up with the rest of it. So --

It's better to look at the dollar amount and watch that change, over time, as rate base can grow.

Yes, you've got to build a real model. Okay, thank you very much.

Thank you, Andy, I appreciate it.

Thanks, Andy.

I think that's all the questions we have, and we appreciate your interest in Portland General Electric and invite you to be joining us when we report our second quarter 2013 results in August. Thanks a lot and have a great day.

And thank you very much. That does conclude our conference for today. I'd like to thank everyone for your participation, and you may now disconnect.