Portland General Electric Co (POR) 2015 Q1 法說會逐字稿

Good morning everyone and welcome to Portland General Electric Company's first quarter 2015 earnings results conference call. Today is Tuesday, April 28, 2015. This call is being recorded and as such 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).

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

Thank you Jonathan, and good morning everyone. I am pleased that you are able to join us today. Before we begin our discussion this morning I would like to remind you that we have prepared a presentation slide deck to supplement our discussions and we will be referencing those slides as we go through the call. The slides are available on our website at 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. 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 the 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 requests 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 the Form 10-Q before the market opened today and the release is available at our Web site 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.

Moving to slide 3, as shown on that slide leading our discussion today are Jim Piro, President & CEO, and Jim Lobdell, Senior Vice President of Finance, CFO & Treasurer. Following these prepared remarks we will open our lines 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 earnings call. On today's call, I will provide an overview of our financial and operating performance, give an update on the economy in our operating area, and discuss construction progress on our new Carty Generating Station. I will then turn the call over to Jim Lobdell, who will provide more details on our financial performance, general rate case, and earnings guidance.

As presented on slide 4, we reported net income of $50 million, or $0.62 per diluted share, in the first quarter of 2015 compared with net income of $58 million, or $0.73 per diluted share, in the first quarter of 2014. Net income was down due to extremely mild weather conditions this winter which impacted retail loads and revenues.

As you can see on slide 5 this was unusual weather for our service areas, with Oregon experiencing the warmest winter season on record. Heating degree days, as measured at the Portland airport, were down more than 20% from the 15-year average. This compared to the first quarter of 2014 which experienced close to average weather. As a result first quarter 2015 energy deliveries to residential and commercial customers were down 11% and 1.2% respectively, while industrial deliveries were up 9% versus the first quarter of 2014. Overall this resulted in a quarter-over-quarter decrease in deliveries of 3.5%.

PGE is revising 2015 earnings guidance down by $0.15 from the previously reported range of $2.20 to $2.35 per diluted share to $2.05 to $2.20 per diluted share due to lower retail loads from warmer weather in the first quarter, which reduced earnings by $0.20 per share. This guidance reduction also include some temporary reductions in our operating cost related to economic dispatch of our power plant, lower weather-related activities, and other operations and maintenance. These temporary cost reductions, however, will not compromise our commitment to employee and public safety and we will continue to move forward with our capital projects to ensure we are well-positioned to meet our customers' long-term energy and reliability needs.

At the same time our continued strong operating performance, ongoing economic growth in our operating area, and the management of our operating cost has put us in a good position to end the year within our revised earnings guidance range. Jim will share further details on revised guidance during this update.

Now, for an operational update on slide 6 -- we delivered excellent operating performance in the first quarter of 2015. Our generating plant's availability was 98% and we effectively managed the cost of our power supply portfolio. Additionally, customer satisfaction remains high. Based on the latest survey results reported by market strategies and TQS research, PGE now ranks in the top decile in overall customer satisfaction across all categories -- residential, general business, and key customers.

Let's move on to slide 7 for an update on the economy. Oregon's economy remained strong. Oregon employment and population growth continue to outpace that of the US. As a result, the Portland metro region has become one of the fastest growing areas for software development companies in both the growth in numbers of local startups and large Silicon Valley companies locating offices in our region. PGE's average customer count increased approximately 1% over the past year.

Oregon's employment growth continues to outpace in the US. In the first quarter of 2015 Oregon employment grew at an average rate of approximately 3%, adding more than 56,000 jobs primarily in the manufacturing, professional, and business services and healthcare sectors. The unemployment rate in our service area for March was 4.8%, comparing favorably the 5.5% for the US and 5.4% in Oregon.

Although retail loads were down 3.5% quarter-over-quarter, when adjusted for weather energy deliveries were up approximately 4%. This increase in deliveries was driven primarily by strong growth in the industrial sector due to expansion in the high-tech industry with additional gains in transportation and equipment manufacturing. Based upon first quarter weather-adjusted load results and current economic indicators, PGE remains on track for projected year-over-year weather-adjusted load growth of 1%. This growth reflects an approximate 1.5% reduction due to energy efficiency.

On slide 8 I'd like to share progress on the construction of the Carty Generating Station, our 440 megawatt natural gas base load resource under-construction in Boardman, Oregon. Construction is on schedule and on budget, and the plant is expected to be placed into service during the second quarter of 2016 at an estimated cost of $450 million excluding AFDC. Carty's gas turbine and generator have been installed, the steam turbine and generator have been shipped, and welding on the heat recovery steam generator piping is ongoing. Overall, construction on the project is approximately 50% complete.

Slide 9 provides the summary of the Company's capital expenditures from 2013 to 1015. With the addition of Tucannon River Wind Farm and Port Westward Unit 2 in 2014, the Carty Generating Station in the second quarter of 2016 and other base capital spending, we expect a rate base increase of $1.4 billion, resulting in a rate base of approximately $4.5 billion in 2016.

As we plan to meet our customers' future energy needs we just kicked off the 2016 integrated resource planning process with a public meeting held earlier this month. As outlined on slide 10, this integrated resource plan will evaluate the need for additional energy efficiency, demand-side actions, energy resources to meet both customer growth and replacement of our Boardman plant which will cease the use of coal at the end of 2020, renewable resources to be Oregon's renewable portfolio standard of 20% by 2020, and capacity to meet our customers' winter and summer peak needs and integrate new renewable resources.

Now I'd like to turn the call over to Jim Lobdell who will provide more details on our financial results for the quarter, our 2016 general rate case, and revised guidance.

Thank you, Jim. Turning to slide 11, as Jim mentioned for the first quarter of 2015 we recorded net income of $50 million or $0.62 per diluted share compared with net income of $58 million or $0.73 per diluted share for the first quarter of 2014. The decrease in earnings was a result of significantly lower retail revenue due to lower energy deliveries. Decreased energy deliveries were driven by significantly warmer weather during the first quarter of 2015 compared to the first quarter of 2014. As a result, revenues did not fully cover expected increases in the operating expenses, thereby decreasing net income for the quarter when compared to the first quarter of 2014.

Moving on to slide 12, total revenue for the first quarter of 2015 decreased $20 million to $473 million. This decrease was primarily driven by a $22 million decrease in retail revenues resulting from a $16 million decrease from lower energy deliveries due to significantly warmer weather, and a $6 million decrease from various supplemental tariff changes relating to the amortization of regulatory liabilities.

Total actual energy deliveries for the first quarter of 2015 were 3.5% lower than the first quarter of 2014. An 11% decline in residential deliveries accounted for the majority of the decrease, and was primarily offset by a 9% increase in industrial deliveries. Commercial deliveries were lower than the first quarter of 2014 by 1%. We continue to expect full year 2015 weather adjusted load growth of 1% net of energy efficiency.

Purchased power and fuel expense decreased $23 million during the first quarter of 2015 compared with the first quarter of 2014 and consisted of $20 million from an 11% decrease in the average variable power cost per megawatt hour and $3 million from a 2% decrease in total system load which includes wholesale sales. Economic displacement of our thermal generating assets, favorable hydro conditions in the quarter, and increased wind generation as a result of the addition of the Tucannon River Wind Farm, all contributed to lower average variable power cost per megawatt hour. Through March energy received from wind resources fell short of the annual update tariff projected level by 36%, impacting both energy production and PTC's receipt.

Net variable power costs which consist of purchased power and fuel expense, net of wholesale sales decreased $25 million for the first quarter of 2015 compared to the first quarter of 2014. Net variable power costs were $2 million below the PCAM baseline this quarter, as lower wind production was offset by lower gas prices and economic displacement of our thermal plants. This compares to $3 million below the baseline for the first quarter of 2014.

Moving on to slide 13, generation, transmission distribution and administrative costs totaled $122 million for the first quarter of 2015, an increase of $14 million from the first quarter of 2014. The increase in operations and maintenance expense primarily consisted of four key items -- $6 million increase in information and technology expense, $3 million increase in expense due to the addition of the Port Westward 2, Tucannon River Wind Farm, and the increased ownership interest in the Boardman Plant, $2 million increase due to the change in timing of the annual maintenance outage at Boardman in 2015 combined with the unplanned outage at Colstrip Unit 4 in the first quarter of 2014, and a $2 million increase due to insurance settlements received in 2014, not present in 2015. These increases were in line with improved costs in our 2015 general rate case.

Depreciation and amortization was flat quarter-over-quarter and was impacted primarily by $6 million in higher expense in the first quarter of 2015 resulting from capital additions, offset by a $15 million reduction in amortization of regulatory liabilities which corresponded to a reduction in revenues. Total interest expense increased $5 million quarter-over-quarter, with $4 million from an increase in the average balance of debt outstanding and $1 million from the lower allowance for borrowed funds used during construction. Income tax expense decreased $10 million quarter-over-quarter. Lower pre-tax income contributed to a $7 million reduction in income tax expense in 2015 while the timing and recognition of state and federal tax credits primarily accounted for the remainder of the reduction.

Moving on to slide 14, in early February PGE filed its 2016 general rate case. The key items of the case are, a return on equity of 9.9%, a capital structure of 50% debt and 50% equity, a cost of capital of 7.67% and a rate base of $4.5 billion including Carty. The estimated net increase in annual revenues is $66 million, net of customer credits and supplemental tariff updates. This approximates a 3.7% overall increase in customer prices which includes a 1% price decrease in January of 2016 and a 4.7% increase when Carty is placed into service.

In May we will enter in the settlement conferences followed by staff and intervener testimony filed in June. PGE expects the OPUC issue a final order with approved price changes before the end of 2015.

Moving onto slide 15, we continue to maintain a solid balance sheet including adequate liquidity and investment-grade credit ratings. As of March 31, 2015 we had $483 million in cash, available short term credit, and letter of credit capacity, $826 million of first mortgage bond issuance capacity, and a common to equity ratio of 44.1%.

During the first quarter of 2015 we determined that $500 million in aggregate revolving credit is sufficient to meet the Company's liquidity needs. Accordingly in March we reduced our revolver capacity from $700 million to $500 million and extended the maturity to November 2019. The Company continues to maintain additional letter of credit facilities totaling $60 million.

During the first quarter of 2015 PGE had the following long-term debt transactions -- in January the Company issued $75 million of 3.55% first mortgage bonds due in 2030, repaid $70 million of 3.46% first mortgage bonds and in February PGE repaid $50 million of long-term bank loans. In April we priced $70 million of new 20-year first mortgage bonds at 3.5%. The bonds will be issued in May with proceeds used to redeem $67 million of existing bonds.

For 2015 PGE expects to fund estimated capital expenditures and maturity of long-term debt with cash from operations, issuance of debt securities of approximately $400 million and issuance of equity securities under the equity forward sale agreement, which can provide approximately $270 million in funding. We plan to have fully drawn on the equity forward sale agreement by the contract expiration of June 11, 2015.

In regards to the Company's quarterly dividend, we are in the process of evaluating both our dividend policy and payout and we will be presenting our recommendation to the board at the May 6 meeting for their consideration.

Moving on to slide 16, and earnings guidance -- PGE is lowering 2015 guidance from $2.20 to $2.35 per diluted share to $2.05 to $2.20 per diluted share. As Jim discussed earlier in the call the decrease in guidance is due to significantly lower retail revenues from warmer weather, which impacted first quarter 2015 financial results by approximately $0.20 per diluted share. This guidance reduction includes temporary reductions of operating costs and therefore we are not providing updated guidance on operating and maintenance expense for 2015.

This revised guidance is also based on the following additional assumptions -- remainder of the year load growth in line with annual weather-adjusted growth of 1% over 2014, below average hydro conditions due to near record low snow-pack resulting in current run-off forecasts of 79% of normal for all PGE-owned and purchased hydro, normal thermal plant and wind operations for the remainder of the year, depreciation and amortization expense between $300 million and $310 million, and capital expenditures of approximately $609 million.

Back to you Jim.

Thanks. In summary, while we were challenged by the impact of significantly warmer weather in the first quarter, we continued to focus on successful execution of initiatives that drive value for customers and shareholders, including delivering operational excellence by meeting our 2015 performance targets, continuing construction of the Carty Generating Station achieving on-time and on-budget results, achieving a fair and reasonable outcome in our 2015 general rate case, and working collaboratively with all of our stakeholders to prepare our 2016 integrated resource plan and its associated action plan to meet our customers' future energy needs using resources that provide the best long-term balance of cost and risk.

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

(Operator Instructions). Our first question comes from the line of Michael Weinstein, UBS. Your question, please.

Hi, good morning.

Good morning, Michael.

I have a couple questions. One is about the tax credits in the quarter. I'm just wondering if you could explain little bit more about that, what the assumption is for the rest of the year.

When we look at the -- are you talking about the PTCs Michael?

Yes, I guess I'm looking at the quarterly -- on slide 13, the income taxes went from $20 million to $10 million and I think you said something about tax credit.

Yes, the major driver has to do with the production tax credits and the fact that the wind is down. So when we're figuring out GAAP taxes we're taking that into consideration.

Got you, okay. So it affects that. And this is more of a broad question on, on the IRP and I am wondering if you can kind of give some color on how your thinking is starting to shape up on this.

I realize it's early -- but I am wondering if the ongoing drought condition that's been going on for several years has affected the variability of hydro to such an extent that it might need more backup thermal generation on the system than might have been previously anticipated. As you're putting to form up your ideas for the IRP, I am just wondering if that's something you are looking at.

Well it's always a consideration, we use the average hydro for the last 60 years in terms of trying to project what hydro is going forward with. The climate change impact, I think there is some view that hydro will be lower than what we have previously seen.

I don't know if we're addressing this specifically. Our reliance on hydro is somewhat declining as our contracts on the mid-Columbia become smaller. I mean it's not that we've considered but you know we've had this history of using long-term average. And we'll continue to trend and watch that. I don't think it would have a huge effect on our order load resource balance, but it's something we do need to consider as we go forward, as well as what the impacts of weather could be from those same climate issues.

All right. And on -- and similar vein, I've noticed that there's been a sharp increase in the amount of purchased power as a percentage of total resources in the quarter. Just looking at that, I am wondering if going forward if more purchased power is needed to support lower thermal or lower or even in the different wind condition. I am wondering if at some point you get more imputed rate base or imputed debt calculation from regulators for the credit for basically buying more purchased power and putting that to rate base.

Most of those purchased in the short-term market as we have economic displacement of our thermal resources and that was really primarily because of the warm weather in the first quarter. Loads just never materialized and so the market heat rate was lower, and what we saw lower gas prices in the market, so we were able to displace our thermal resources. So the short-term purchase don't tend to get imputed against us in terms of our debt calculation.

To the extent we entered into long-term purchase agreements, then the rating agencies do look at that as imputed debt -- and we have to take that into consideration when we look at our capital structure. But today those short-term purchased are really just economic displacement opportunities based on the conditions we've seen this year.

Well, thank you very much.

Thank you.

Thanks, Michael.

Thank you. Our next question comes from the line of Paul Ridzon from KeyBanc. Your question please.

Good morning.

Good morning, Paul.

Good morning, Paul.

Could you maybe give us a little flavor as to kind of what you are thinking with regards to the dividend policy? I guess you are going to formally discuss with the Board on May 6?

We've had this discussion quite a bit with many folks. And as you know we have a policy with a range in terms of guidance that's pretty consistent with what the marketplace is. We tend to be at the low end of that range and so that's the conversation we're going to have with our Board around whether we would even want to move the guidance given our increase in earnings and our low payout ratio.

So all those things have to be factored in as well as future capital expenditure. So just stay tuned till mid-May when we have our Board meeting and release our dividend. But clearly it's an important issue for the Board and we understand we want to reward our shareholders for investing in the Company and, and we will move our dividend accordingly.

Okay we will stay tuned. And then the can you give a little more detail on the refund, I guess it was $4 million in the quarter, is that kind of an out of period thing or is that non-recurring?

It's the refund or you're talking about the supplemental tariff changes?

I guess it was $6 million of tariff changes and $4 million of that was a refund or--?

Could be the Trojan decommissioning.

Yes, we had over accrued for Trojan decommissioning as part of the last rate case. We decided to amortize some of that overcollection back to customers and so that was part of our price change that occurred on January 1.

Is that ongoing?

Yes, it goes through this year and then a couple of years after that. I think it was a three-year amortization period, is that right Jim?

Yes.

Three-year amortization period of credit, now we even at current 2015 rate case have requested to accelerate that to two years and we'll see how the commission addresses that. But that was included in our 2016 rate case to accelerate that amortization back to customers.

And then on the wind was 36% below -- wind production was 36 below expectations -- 36%?

Yes. It was a terrible quarter for wind. First, January was off 60% against our budget forecast and February was like 35%, overall we were down 36%, which as Jim mentioned has two impacts. We have replace that lost wind in the marketplace and then we also lost the production tax credit. The combination of those two just by themselves in isolation was about $0.08 a share.

And is that, was that fully captured in the first quarter?

That was all part of the first quarter results, right. We offset some of that. As Jim mentioned on the power side we were able to offset some of that with the economic displacement of our plants and lower gas prices. The PTC reduction hit us right on the tax return in terms of what we recorded for tax. Had we had normal wind, our taxes would have been lower by roughly $3.7 million, something like that. So we had material impact on it in the first quarter.

So what again drove the income tax reduction by $10 million, if you had worse PTCs?

We had more PTCs because Tucannon River Wind Farm went into service then we had lower pre-tax income.

So Tucannon offset it volumetrically.

Yes, volumetrically, that's correct, but down from where -- it would have been lower we had normal wind.

Understood. Thank you very much.

Thank you. Our next question comes from the line of Brian Russo from Ladenburg Thalmann. Your question, please.

Hi, good morning.

Good morning, Brian.

Good morning, Brian.

Maybe you can just talk a little bit more about the guidance. It looked like you took a $0.20 hit on weather but you revised the guidance only by $0.15. Is that $0.05 offset the temporary O&M expense controls?

Yes.

Yes. Basically, that's it. We tried to look at our operating cost and we had some economic displacement of our plants and just trying to be conscious of our operating costs during the year, just given the very warm weather we saw in the first quarter.

Okay. And then just to confirm, the revised guidance assumes the below normal hydro upcoming season from April to September?

Yes, it does Brian.

Okay. So can we just talk a little bit more about what the PCAM assumption is? Or it seems I think you're going to be below the baseline and maybe just talk a little bit more about the kind of dynamics of net variable power cost in the PCAM and why you are able to manage those costs so effectively this year?

Let me take a couple. Look, in the first quarter we actually had above normal hydro. We have lot of rain instead of snow so we actually had a benefit from hydro in the first quarter, that was offset by lower wind and then with the warmer weather in the first quarter and lower gas prices we were able to economically displace our resources. So that helped us to optimize our power supply portfolio and as a result we were under the PCAM.

As we look through the rest of the year a lot of it will depend on how the hydro shows up, kind of what are the market prices, what kind of loads we see in California, whether there is any heat this summer. So there is a lot of variability as we go into the summer season, but right now we've assumed the hydro conditions that are forecasted going forward and just kind of normal power supply activity.

Yes, to give a little bit more color on the hydro situation. So we are mostly dependent on the mid-Columbia system versus some of the smaller systems. I mean, mid-C almost provides 50% of the hydro that we have.

While the snow-pack in down for the region in the Pacific Northwest it actually was at more normal levels up in Canada and while we had little snow-pack, we had a normal year, if not above normal year for precipitation. So the rain, the precipitation is all sitting in the hydro system. So that allowed the reservoir levels to be a little bit higher.

So while 79% sounds like a big number or a big change, there are still some benefits. And as Jim pointed out the wildcard for us really is what are the Canadians going to do with their reservoirs when you consider the critical hydro conditions in California because that water has to flow downstream. So it will go through the dams that we're dependent on.

Understood. And can you just talk about gas reserve acquisition opportunities and the timing and amount of those opportunities?

We're still looking at it. We've been talking to a number of consultants looking at where gas prices are, and whether there is an opportunistic chance to acquire natural gas. We've had some conversations with the commission in terms of what the process might look like. It's still very much in the formative stage.

Any decision probably wouldn't occur on that until later in the second half of the year as we continue to look at it. We're really looking closely at what other utilities have done, what the ups and downs are. Obviously Northwest Natural has done a transaction in that space. We've talked to number of the people who supported that transaction to understand it.

So we haven't made a firm decision. We're still looking at the economics. We think it's a favorable time to do that, but we haven't finished our due diligence and just trying to understand the economics and the value for our customers of acquiring gas, given where natural gas prices are.

So we're still positive on the idea. We haven't discontinued any work in that area and still moving forward. But my guess is just given the process we have to go through with both internally and with the regulators, it will be in the second half of the year where we get more formal. We have introduced the topic in the integrated resource plan, but I don't think that will be the decision making process we'll use.

So no target of percentage owned versus --

No, not at this point.

Okay.

We're trying to find what's the right strategy and how to layer it in and how would you do that best. And what we're trying to do is manage the volatility of natural gas for the benefits of our customers and trying to figure out that the right volumes and amounts to do that is what we're really working on right now, and as I said discussing with stakeholders and people who put those kinds of transactions together.

Okay. Thank you very much.

Thanks Brian.

Thank you. Our next question comes from the line of Andrew Weisel from Macquarie. Your question, please.

Hey, good morning guys.

Good morning, Andrew.

Good morning, Andrew.

On the last conference call there were a bunch of questions about CapEx in 2017 and 2018 and obviously your last question addressed that, but there are also a few other buckets of potential spending. When might we get some more visibility into that spending in the years after Carty? Would that not come until the next 10-K or might we see more details on some of those other programs throughout the year?

The process as we've discussed before is, we have to get through the integrated resource plan and agree on what the action plan is for new resources. The action plan will clearly address the need for new -- for more energy efficiency, demand-side management. Then the questions, what are the additional resources we need to be both customer growth as well as replace Boardman in 2020.

All that will be included in the action plan that would have to be acknowledged by the commission, probably not until 2017 timeframe. Once that action plan is acknowledged and to the extent there are new resources to be added which we think, for sure will have to add more renewable resources to meet the 2020 target, we think we may need to add both energy and capacity resources. To the extent those are acknowledged then we would conduct an RFP, a request for proposals like we did before.

And as I've mentioned on these calls before, the Company would likely enter its own self-build options for both renewable resources as well as capacity and energy resources. And then to the extent we are successful and we were the lowest-cost option for customers, then we have more visibility to additional capital expenditures. So it is much of a process similar to what we went through before.

And I know there is a little frustration there wasn't clarity right away, but that's the process we follow in Oregon. We think that produces the best result for customers, ensures that we produce resources with least cost/lowest risk. And then when we go through the regulatory process for cost recovery as we've gone with Tucannon and for Port Westward 2 and likely with Carty, we really have met the standard around prudency.

So it is a process. I think you have to just kind of work through the process and so there won't really be real visibility on precisely what those capital expenditures look like until -- maybe first glimpse of that will be in 2016 when we show that proposed action plan that the commission might acknowledge. But even there, there won't be clarity of whether the Company would make those investments or are they provided by the market place. It's not until we complete the RFPs, where we'll have real clarity on what those resources are.

Now I would just say that in the last bid we have produced three very, very good resources for customers -- least cost/lowest risk and they're coming in both on-time and below budget. So I think we've demonstrated to our consumer groups that we can effectively compete with the market and provide great resources that provide long-term value for our customers and shareholders.

All right. I appreciate the detailed recap to the RFP, but that's not quite what I was asking about. I meant during the bridge years in between, like between now and then. So things like you talked about the customer information system, smart meters, the ownership of some gas assets, I meant more in terms of those 2017-2018 potential projects.

Fill the hole between the two, so those are -- we are looking at that right now. The gas resource is a potential opportunity there. We are looking at smart grid options. We're going to be discussing with the Board in June at our retreat about where those market investments might be and how we can do them.

We're looking at putting a new radio system which is not insignificant in terms of capital cost. We've got to deal with the transformers that have PCBs and replace those. So, probably later this year we'll have more clarity on those middle years in terms of capital expenditure programs.

So what we're trying to do is look at this timeframe and take the opportunity to look at our transmission and distribution system and where we can provide additional reliability for our customers or address issues that we think need to be improved. So we don't really have exact clarity, but we're looking at the capital expenditures during that period. And we'd hope to have clarity probably in the third quarter, I would guess, probably third or maybe fourth quarter as we put our budgets together and take them to the Board.

Okay, great. That's helpful. Thank you. And then combining that with the dividend conversation certainly we're expecting a near-term update in the next week or two. But how much will the longer term dividend policy depend on those types of CapEx opportunities? In other words, should we expect to see more than one year of an update in next month or will the longer term growth rate or whatever it might look like not come until a year from now?

I think we're going to provide clarity obviously on the one year, whether we provide longer term guidance on the growth I just don't think we're going to get there. We're still trying to balance what the capital needs are. We'd like to be able to finance our capital problem with internally generated capital.

So as we look at our multiyear capital programs, we're trying to size the dividend to fit there to keep our capital structure at 50% debt, 50% equity. So all those are being taken into account I do not expect that we will give long-term guidance on the growth rate of the dividend but more just clarity on the dividend for the year and then readjust that each year as we move forward.

Makes sense. Thank you very much. One very quick accounting or bookkeeping one, the PTC impact, the effect on the effective tax rate, I think last quarter you talked about 20% for the year. If I heard you right, you said $3.7 million? So should we think more or like 22%, 23% for the year, for the full year?

I think we're actually looking at about 20% effective tax rate for 2015.

So, no impact from the PTCs?

No, there is an impact but that's factored in. There's a lot of moving parts in there.

Okay. Thanks a lot.

Thank you.

Thank you. Our next question comes from the line of Sarah Akers from Wells Fargo. Your question please.

Hi, good morning.

Good morning, Sarah.

Good morning, Sarah.

A couple of questions on O&M, I think I missed the explanation for the absence of O&M guidance. I know you, you are baking in some temporary cost cuts but can you just go over that again why wouldn't have a number this year or this quarter?

Yes Sarah. Given the fact that we've got a lot of year ahead of us and we're not quite sure how the weather is going to play out for us, whether it would be hydro, power supply, loads and so on and so forth -- we're just not feeling comfortable getting out guidance at this particular point in time for O&M. We're going to focus on the cost structure of the Company, and as Jim had pointed earlier, try and make sure that we're doing all the right things to be able to deliver value and reliability to our customers but at the same time being very prudent about our expenditures given the fact that loads are down so much.

Okay got it. And then looking Q1 there is a 13% or so increase versus last year in O&M and I know that's quite a bit above the original O&M guidance trend. But you talked through some of the puts and takes. I guess generally speaking where it was Q1 O&M, was that in line with your original expectations or is that 13% unexpected?

That was in line with the cost coming out of the general rate case -- the 2015 case.

Okay and then last (multiple speakers)

Because you've got to keep in mind we've got Boardman, we've got Tucannon, so we've added new resources.

Port Westward 2.

And we have Port Westward 2 as well.

But those would all have an impact on the full year, correct? So there must be other offsets that would bring up 13% down to, to a more normalized level for the remainder of the year?

They are all factored in there.

Okay. And then just one clarifying question on the PCAM -- so even with the below average hydro forecast you're not expecting a negative PCAM impact for the full year, is that correct?

That's correct.

Okay, great. Thanks a lot.

Thank you. Our next question comes from the line of Mark Barnett from Morningstar. Your question please.

Hey, good morning everyone.

Good morning, Mark.

Thanks for the guidance around the PCAM, that's certainly helpful. I am just curious in terms of operations given the commodity situation -- the hydro situation, where did you see your gas capacity factors run during the first quarter?

The capacity factors associated with the plants, I don't have those specific ones with me. But obviously we're constantly looking at the opportunity as to where the heat rate is in the market place compared to our resources. So I would anticipate that it would be pretty low, given the displacements that had occurred during the quarter.

Okay.

Because the availability associated with those facilities was high.

Right, okay. Then you talked some about the different factors influencing hydro for the rest of the year, but with your runoff projections for the rest of 2015 can you may be give us a sense for how those compared with 2013 -- I mean 2014 and 2013?

Well 2014 would have been an above normal hydro year.

Slightly above.

Slightly above normal, so we would have seen higher capabilities. One of things that people need to keep in mind and when they are thinking about the hydro system is the first quarter is really the high value quarter as far as the value of hydro coming through. Then you end up in the shoulder in the spring and then once you get to the July beyond period it's really just about regulation. So you're going to move water through the system. So it's less of an impact at that particular point in time as you move through.

When we look at the hydro that we have, as I said earlier the bulk of it is on the mid-C with about 18% of it coming from Clackamas and 27% coming from the Deschutes, and both those river systems are down quite a bit. So -- but overall we think they are manageable.

And the other thing to keep in mind is you know in a good hydro year the capacity of a dam has to run pretty high. The generators have to run, otherwise you would be spilling it over. When you don't have a good hydro year a benefit that comes out of the system is you've got a lot of flexibility in the system, so more capacity. So that creates more opportunity for managing variable energy resources and other fluctuations in the system. So it's a Rubik's Cube, that's for sure.

All right, thanks for your comments on that.

Thank you. Our next question is a follow up from the line of Paul Ridzon from KeyBanc. Your question please.

Thank you. Do you have any visibility on the wind resource thus far in the second quarter?

No, Paul I don't, do not have that at this particular point.

Have you issued any shares under the Board this year?

No, no we have not -- not since the original issuances that we did. We are going to pull down the full amount by the June 11 date this year.

And then are you kind of thinking that the timing of that pull down, can be levered, preserve some earnings power?

It would probably be closer to the June 11 date.

Got it.

There's about 10.4 million shares left.

And then I just want to make sure I'm clear that you're going to be on the shareholder good side of the PCAM?

Yes.

Despite the -- I think you said, $2.7 million PTC headwind you hit in the first quarter?

The PTC doesn't go through the PCAM. But the impact of wind, which basically was about $4.5 million in the first quarter, that's incorporated into the PCAM. That was the lost wind generation due to the 36% under production.

So the lost wind generation forced you to buy $4.5 million worth of power?

Approximately correct.

Replacement for our costs.

Against our AUT forecast.

Thank you for the clarification.

Thank you.

Okay, I guess there aren't any more calls. So we want to appreciate your interest in Portland General Electric and we invite you to join us when we report our second quarter 2015 results in late July. Thanks again and have a great day.

Thank you, ladies and gentlemen for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.