Portland General Electric Co (POR) 2015 Q2 法說會逐字稿

Good morning, everyone, and welcome to the Portland General Electric Company's second-quarter 2015 earning results conference call. Today is Tuesday, July 28, 2015. This call is being recorded. (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, Ashley, and good morning, everyone. We're pleased that you can join us today. Before we begin our discussion this morning I would like to remind you that we have prepared a presentation to supplement our discussion today, which we'll be referencing throughout the call. The slides are available also on our website at portlandgeneral.com.

Referring to slide 2, I'd 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 requests that you read our most recent Form 10-K and Form 10-Q.

Portland General Electric's second-quarter earnings were released via our earnings press release and our Form 10-Q before the market opened today. And the release and the Form 10-Q are available on our website 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 Pyro, President and CEO; and Jim Lobdell, Senior Vice President of Finance, CFO, and Treasurer. Following their 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, everyone, and thank you for joining us. Welcome to Portland General Electric's second-quarter earnings call.

On today's call I'll provide an overview of our financial and operating performance, give you an update on the economy in our operating area, and discuss construction progress in our new Carty Generating Station. I'll then turn the call over to Jim Lobdell, who will provide more details on our financial performance and general rate case.

As presented on slide 4, we reported net income of $35 million or $0.44 per diluted share in the second quarter of 2015, compared with net income of $35 million or $0.43 per diluted share in the second quarter of 2014. Overall, PGE continues to demonstrate strong operational performance across the Company in 2015.

Construction on our Carty Generating Station is proceeding on budget and is expected to be completed in the second quarter of 2016. Our 2016 general rate case has made significant progress, and we are affirming our full-year 2015 earnings guidance of $2.05 to $2.20 per diluted share.

Moving to slide 5, we continue to see strong performance in our generating plants, distribution system, and power supply portfolio during the second quarter of 2015. However, offsetting some of the operating performance from these areas was lower than forecasted wind and hydro generation.

Regarding customer satisfaction, according to the latest published national rankings PGE continues to maintain top-quartile system reliability metrics, top-decile customer satisfaction metrics for key customers, and top-quartile customer satisfaction metrics for residential and business customers. Earlier this month, PGE was named a 2015 Most Trusted Business Partner among utilities by Market Strategies International.

In June, PGE received the 2015 Smart Grid Customer Education Award from the Smart Grid Consumers Collaborative for our Salem Smart Power Center. The center and its related research were PGE's contribution to the Pacific Northwest's Smart Grid Demonstration Project, part of a national initiative that officially ended this month.

Through the project, PGE successfully piloted large-scale battery storage to the benefit of customers and the grid. We will continue to operate the Salem Smart Power Center using battery storage to integrate renewables and strengthen the local microgrid.

PGE was also recognized in the second quarter for its voluntary renewables program. According to the Department of Energy's National Renewable Energy Laboratory, the renewable programs in 2014 were once again recognized as having the most customers, the highest participation rate among customers, and the greatest total sales of renewable energy among the nation's utilities. We're very proud of our commitment to generating renewable energy and providing our customers with sustainable power options.

Let's move to slide 6 for an update on the economy and our customers. Oregon continues to exhibit positive economic trends, with employment growth continuing to outpace that of the US. The unemployment rate of 4.8% in our service area for June compared favorably to both the US at 5.3% and Oregon at 5.5%.

Oregon's economy is also performing well in other areas. Oregon ranked second in the nation for 2014 personal income growth, at 5.8% according to the US Bureau of Economic Analysis. The State of Oregon's gross domestic product expanded by 3.6% in 2014, ranking sixth in the nation for GDP growth. And Portland moved up one spot to the nation's 28th most populous city, according to the 2014 Census data released in May.

At PGE, our average customer account increased approximately 1% year-over-year. And energy deliveries, weather adjusted, are up 5.8% for the second quarter of 2015 over second-quarter 2014. The increase in deliveries was driven primarily by strong growth in the industrial sector due to high tech expansions, with additional gains in paper, food, and transportation equipment manufacturing.

Weather continued to be historically warm. Oregon experienced the warmest June on record in 2015 and the third warmest second quarter on record. While warming temperatures were unfavorable to energy deliveries in April and May, they transitioned to favorable as we made the switch from heating to cooling-driven loads in June.

Based upon the results of second-quarter energy deliveries and current economic indicators, PGE now expects 2015 weather-adjusted load growth to be approximately 1.5%, excluding one large paper customer, and net of approximately 1.5% in energy efficiency.

Slide 7 provides an update on the Carty Generating Station, our 440-megawatt natural gas baseload resource under construction near Boardman, Oregon. Construction is 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.

The 500 kV Grassland Substation serving the site is now complete; and in June TransCanada Gas Transmission Northwest started construction on the 24-mile, 20-inch lateral pipeline that will transport natural gas to the plant. Overall, construction on the Carty project is approximately 60% complete.

On slide 8 we have provided a summary of the Company's capital expenditure forecasts from 2015 to 2019, and we are currently evaluating additional opportunities to invest in projects that provide value to our customers.

As outlined on slide 9, the need for new resources to meet our customers' future energy needs will be evaluated through the 2016 Integrated Resource Planning process and detailed in a resulting action plan. This planning process involve stakeholders, stakeholder engagement, research, and analysis and will evaluate many issues, including the need for additional energy efficiency, energy resources, and demand-side actions to meet customers' growth and to replace the output of our Boardman plant, which will cease the use of coal at the end of 2020.

In addition, the process will also address the need for capacity resources for the integration of new renewable resources to meet Oregon's Renewable Portfolio Standard of 20% by 2020 and to meet our customers' winter and summer peaks. We will file the Integrated Resource Plan and the associated action plan with the Oregon Public Utility Commission in 2016, and we are targeting the plan to be acknowledged by the Commission in the first quarter of 2017.

Now I'd like to turn the call over to Jim Lobdell, who will discuss our financial results for the second quarter, provide an update on the 2016 general rate case. Following these prepared remarks, we will open the lines up for your questions. Jim?

Thank you, Jim. Turning to slide 10, as Jim mentioned, for the second quarter of 2015 we recorded net income of $35 million or $0.44 per diluted share, compared with net income of $35 million or $0.43 per diluted share for the second quarter of 2014. These comparable quarter-over-quarter earnings were the result of the following items: increased energy deliveries for all customer classes' the incremental earnings contribution of Port Westward 2 and the Tucannon River wind farm and customer prices in 2015; and an increased AFUDC earnings on the construction costs of the Carty generating plant. These increases were offset by higher power supply costs in the second quarter of 2015 compared to the second quarter of 2014.

Moving to slide 11, total revenues for the second quarter of 2015 increased $27 million to $450 million. This increase was primarily driven by growing demand in the industrial sector, an increase to customer prices from the 2015 general rate case, which included the addition of the Tucannon River wind farm and the Port Westward 2 generating station.

Energy deliveries for the second quarter of 2015 were 5.6% higher than the second quarter of 2014, with a 4.9% increase in residential deliveries, a 3.6% increase in commercial deliveries, and a 9.8% increase in industrial deliveries. For the full year of 2015, we expect a weather-adjusted load growth of approximately 1.5%, net of energy efficiency and excluding one large paper company. This is a 0.05% increase from our previously disclosed load growth estimate.

Now on to power supply. Lower than expected hydro and wind generation in the second quarter of 2015 were offset by effective power supply management, which resulted in net variable power costs at approximately the baseline of the annual update tariff for the second quarter of 2015. This is in contrast to the second quarter of 2014, when net variable power costs were $11 million below the baseline for the annual update tariff.

Moving on to slide 12, generation, transmission, distribution, and administrative and general costs totaled $126 million for the second quarter of 2015, an increase of $3 million from the second quarter of 2014. Generation, transmission, and distribution decreased $1 million due to a $3 million decrease from the timing of the annual planned maintenance outage at Boardman, offset by higher operating and maintenance expenses from the addition of Port Westward Unit 2 and Tucannon River, and higher information technology expenses.

Administrative expenses increased $4 million due to a combination of higher expenses including legal and environmental services, information technology, pension, and other miscellaneous items, partially offset by a lower provision for bad debt expense. Depreciation and amortization increased $3 million quarter-over-quarter and was impacted primarily by $6 million in higher expense in 2015 resulting from capital additions, $2 million in higher asset retirement obligations, offset by a $5 million reduction related to the amortization of deferred regulatory liabilities for the Trojan spent fuel settlement and related tax credits in 2015.

Interest expense increased $5 million quarter-over-quarter, with $3 million from an increase in the average balance of debt outstanding and $2 million from lower allowance for borrowed funds used during construction.

Moving on to slide 13. In early January PGE filed its 2016 general rate case. In June a partial stipulation was filed with the Commission covering agreements reached by PGE, OPUC staff, and other parties on a variety of issues related to the 2016 GRC, including the cost recovery of the Carty Generating Station. In addition, PGE filed updated 2016 load and power cost forecasts. The table on slide 13 displays an annualized revenue and climate update for the June stipulation and load and power cost updates.

Also in June, PGE filed motions to suspend the power cost and nonpower cost procedural schedules, based on reaching a settlement with parties on all remaining issues in the case, except for one power cost issue which has its own procedural schedule. Details on the new settlement will be available when the stipulation is filed in the coming weeks.

All stipulations remain subject to the OPUC approval. PGE expects a final order from the Commission before the end of 2015.

On to slide 14, we continue to maintain a solid balance sheet including adequate liquidity and investment-grade credit ratings. As of June 30, 2015, we had $585 million in cash, available short-term credit, and letter of credit capacity; $924 million in first mortgage bond issuance capacity; and a common equity ratio of 49.6%. The Company has $500 million revolving credit facilities to meet the Company's liquidity needs, which has a maturity date of November 2019. The Company also continues to maintain adequate letter of credit facilities totaling $60 million.

In May, PGE issued $70 million of 3.5% series first mortgage bonds, which were used to fund an early redemption of $67 million of 6.8% series first mortgage bonds. In June, PGE physically settled in full its equity forward sale agreement, with the issuance of the remaining 10.4 million shares of common stock available under the agreement in exchange for net proceeds of $271 million.

Also, the Company has repaid in full its $305 million of long-term bank loans with payments of $50 million in February, $200 million in June, and $55 million in July.

Regarding the Company's quarterly dividend, on July 23 the Board of Directors approved a quarterly dividend of $0.30 per share. Assuming PGE's ability to achieve current estimates for earnings and cash flow, and depending on other factors influencing dividend decisions, PGE management anticipates sustainable annual dividend increases of 5% to 7%.

Over the long term, PGE targets a dividend payout ratio of 50% to 70%. The next annual review of the dividend will be completed in April of 2016.

Moving on to slide 15 and earnings guidance, PGE is affirming its 2015 revised guidance of $2.05 to $2.20 per diluted share based on the following additional assumptions: annual weather-adjusted load growth of approximately 1.5% over 2014; below-average hydro conditions; 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 $598 million.

Back to you, Jim.

Thanks. We continue to focus on successful execution of our initiatives that deliver value for our customers and shareholders by achieving operational excellence, by meeting our 2015 performance targets, completing construction of the Carty generation station in the second quarter of 2016 and on budget, achieving a fair and reasonable outcome in our 2016 general rate case, and working collaboratively with all our stakeholders to prepare our 2016 Integrated Resource Plan and its associated action plan to meet our customer's 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) Paul Ridzon, KeyBanc.

Good morning. Congratulations on a solid quarter. Just a quick question. You updated your sales forecast. Just wondering if there is any particularly bright spot in the economy, or if it's just kind of broad-based.

When you look at the numbers, as we looked at the second quarter, again we're seeing strong growth in the industrial sector driven by the high tech, and also in the commercial sector has been a really bright spot for us. We've seen a lot of growth in the commercial sector, more than we had anticipated, which those have been the two bright spots.

Residential continues to be about flat. Most of that's driven by energy efficiency, which is offsetting our growth in that sector.

So really the growth in the commercial sector and the industrial sector are really the bright spots. If you look around Portland in the metro area you see a fair amount of cranes up, which is always a good sign that the economy is growing.

The housing market is definitely picking up as we see permits starting to rise and we continue to see construction in multifamily. So all in all, it's a positive sign in the economy, more people going back to work, and we feel really good about what's going on in our service area.

So you're seeing underlying growth of 3%, half of which is eaten away by efficiency?

Yes. We typically use about -- have about 1.5% reduction in our load due to energy efficiency. We run those programs through the Energy Trust of Oregon, and they produce about 30 average megawatts or so of reduction in energy efficiency each year.

That tends to be weatherization, lighting. We've been doing a big program throughout our service area on LED lighting for the streets and so forth, and that's been a real successful program in using our product more efficiently.

How much of that low-hanging fruit has already been harvested?

You know, as you look at the curves -- and we're right now in the Integrated Resource Plan. If you look at what's existing in the pipeline, it's starting to run out. So I think as we look to the future, we don't see necessarily as much energy efficiency opportunity with the current technology.

You always have to wonder what the new technologies are going to be, and it does start to taper off. But as you look at the forecast, the Energy Trust says: Well, there may be new technologies out there that might produce additional efficiency.

But much of it is starting to become part of codes and standards. So it's kind of baked into the new appliances and the new construction standards.

So it is starting to tail off. We've been doing this for -- I think if you think back to all the way back to 1980 we've been doing efficiency. So it is starting to, if you will, run out in terms of that opportunity.

Did you say weather was a help, hurt, or was a push given the mix, April and May (multiple speakers)?

Jim will give you the numbers, but it's yes and yes. April and May were warmer, and that tends to be a heating month; so we kind of got hurt in April and May due to warmer weather. Then June went the other direction, which was it was warmer in June. And Jim, you want to talk about the financial impact

of that?

Yes, Paul, the impact of weather for the second quarter was about $0.07. As Jim pointed out, the first two months were a real drag and then June really helped out with the hot weather.

Is that $0.07 versus normal or year-over-year?

It's $0.07 quarter -- year-over-year negative.

Negative, okay. Then how is the wind resource in the quarter?

It was down again. I think if you look year to date, wind is down about 30% overall for the year. And it was down again in the second quarter.

Paul, actually, the $0.07 was just for Q2 2015.

Versus normal?

Yes.

Then looking forward, there are some generation opportunities. Is it basically wrapped up with you have to get 20% by 2020, so probably more wind, some backup gas behind that wind, and then by 2020 you have to backfill for the Boardman retirement. Is that the way to look at it?

Yes, as you look at it, that is the whole purpose of the Integrated Resource Plan. We will do all the analysis. We will look at what's the best balance of cost and risk.

We're going to have to add additional renewable resources, about 110 roughly average megawatts of new renewable resources, to meet the 2020 objective. And then we have an overall energy pull of around 450 megawatts when you look at 2020 after Boardman -- 2021 after Boardman shuts down.

So we're trying to address what's the least cost, lowest risk way of doing that and replacing those resources. So it will be a combination of -- likely we will do an RFP for the renewable resources; I think wind tends to be the lowest cost resource for us. And then on the baseload side we'll look at gas resources and we'll also look at peaking-type resources like our Port Westward 2 unit to back up the new renewable resources.

The way it will play out, just so you can understand, we get acknowledgement of the action plan, which we're targeting for the first quarter of 2017. Then we would go through what's called an RFP process, a request for a proposal, to solicit bids for resources to meet the action plan.

We intend, as we did in the last plan, to probably include self-build options. And we will work through that process after the action plan is acknowledged.

Thank you. Then lastly, is there any discussion in Oregon about expanding the RFP or the RPS?

There's lots of discussions in Oregon around carbon and global warming and climate change and a number of issues around that. I think we're all waiting to see what 111(d) produces and how that will impact our decisions around resources.

So we, like many utilities, are waiting for the new rules to come out from the EPA around 111(d), and then we can assess whether that would by itself require us to add more renewable resources or just exactly what actions we'd have to take. So I think everyone is pausing right now until we see the results of that.

Then I think there will be additional discussions in the state around those kinds of items. But right now there is nothing being proposed to increase the RPS standard.

Thank you very much for the time.

And just for clarification, the final standard is 25% by 2025. So we've still got a couple more steps to go before we visit the next ideas.

Got it. Thank you.

Brian Chin, Merrill Lynch.

Hi, good morning. I apologize if I missed this earlier in your comments. I think the CapEx numbers on slide 8 are a little bit higher than where you had projected them earlier. Can you give a little bit more color there?

Sure. Jim, you want to go through those numbers?

Yes, they're up about $60 million. And the reason is because we've got a customer service system effort that's going on. Our CET or customer engagement trans --

Transformation.

Transformation, thank you; I keep getting stuck on that one. So that's the real driver plus a few other small items.

Yes, we have a pretty significant project we hope to kick off in October with final Board approval. But we need to replace our customer information system and our meter data management system. Both those systems drive our billing to our customers.

Our systems were put in back in 2001, and so they've reached the end of their useful life, so we need to replace those. We're in the process of negotiating contracts and getting the work plan put together.

We've got tentative approval from the Board. We'll get final approval in October.

In the past when you guys have talked about improving more centralized communications and a greater building out of the T&D assets, it seemed to me as though there was a lot of little pieces that you guys were looking at. I guess the question I have is, when we're looking at this raise of $60 million here, is that your sense that this is probably more of a final level kind of number? Or are we still in the midst of trying to assess what other types of spending could happen, where there is further potential upside to those numbers?

I think we're still assessing other potential opportunities. We've been looking at -- some people call it the smart grid; we're calling it the integrated grid. But really, where can we add technology to improve the throughput of the system and the performance of the system?

So we just -- at our Board retreat this year we spent a half a day talking to our Board about smart grid technologies, and how you can improve the throughput of the system. So things like conservation voltage reduction, smart switches, all those technologies that can improve reliability and performance of the grid.

So we are -- we have run some pilots. We're looking at expanding that, and that's really what we're in right now. So in the next year or so we're trying to solidify those plans, ensure that we have the bandwidth and that the technologies are working to our satisfaction.

So I think there are some other opportunities there, but we haven't run them to ground yet in terms of actual capital expenditures and numbers yet.

Got you. One last question and I'll hop back. If I understand it correctly, there aren't really any like discrete dockets or anything like that or proceedings related to this extra amount? This would just be enveloped the base CapEx? Is that the right assumption going forward?

That's the right way to think about it. We would let our rate base either grow or shrink based on those investments. And then they would just be part of our general rate cases going forward.

Excellent. Thank you very much.

Chris Turnure, JPMorgan.

Good morning, guys. I wanted to follow up more on your dividend increase and your plans going forward there. Obviously, you're pretty low in your payout target range right now. I wanted to understand if that 5% to 7% that you want to recommend to the Board next year going forward is a loose guidance range, where in some years you could be higher than that, or if that's pretty hard and fast and you might reconsider doing a buyback or something of that nature given your cash flows especially in 2017.

I would call it loose guidance. I think it's generally what we're comfortable with right now. Every year you have to reevaluate; as we get closer to the date we will get a better picture of our CapEx spending and cash flows of the Company. And then we'll revisit that issue.

But we generally feel that's an acceptable range. As we look at the runway towards new capital projects to meet our customer's energy needs, we want to preload the equity structure so that we can have the ability to ride through that without having to issue new equity. So that all goes into the decision-making process.

As we get through the Integrated Resource Plan we'll get a little more visibility on where the parties want to go with new resources and the timing of those resources. 111(d) will also inform us.

So it's what we know today. We're comfortable in that range. That doesn't mean we couldn't go out of that range, but I think right now given the CapEx forecast we have and how we think about new resources, that's where we likely would land.

We do want to retain a sustainable pattern and not just jerk it around each year. But again that's all the things we take into account when we sit down with our finance committee and the Board to talk about the dividend.

Okay, got you. Then could you give us a little bit more detail on the power cost issue? I'm not sure if that was in your general rate case or outside of it.

But was that something that went back to the PCAM]reform that we heard something about late last year or earlier this year? Or was that separate?

Yes, the one issue we have that we pulled out of the settlement on the rate cases, what's called Port Westward Unit 1 extended maintenance outage that's scheduled for next year. We had a problem with the turbine this year; there was an error made during the maintenance outage, and so we're going to have to go back next year and pull the rotor and look at that and do some work on it, just get it back up to snuff.

So there's some discussion between the Company and Commission and the parties about whether we should be allowed to recover for that extended maintenance. I don't think it's that much money. I don't know if we filed in the case what the dollars were. It's not a huge number, but it is something we want to visit with the Commission.

It's fairly new information. So we didn't really -- the parties weren't ready to settle that issue, and so we decided to pull it out and brief it.

We were filing -- did we file testimony last week, I think it was? Last Friday. Friday we filed the testimony on that case, on that issue; and you could probably find that out on the docket to get more color on what it is.

Okay. But as of now, you've pulled it and you're going to eat those costs?

Well, no, we're going to work through -- we filed our testimony why we think we should recover that cost. We believe we were prudent, that the contract we had with the vendor who did the work was a good contract. But we do have the slippage or the extension of the maintenance outage, and we're asking to get recovery of those dollars.

We didn't put it in the settlement because it was a fairly new issue and the parties weren't ready to settle it. So we all agreed we would brief the issue and then work it through the process.

Okay. That makes sense. Thanks, guys.

Michael Lapides, Goldman Sachs.

Hey, guys. A couple of questions. Real quick, just with the revised capital spending numbers, how are you thinking following this year's rate case what the timing or cycle is for any future or follow-on cases?

We're right now in the budgeting process, Michael, and getting the 2016 budgets completed; and then we will also ask our operators to do a 2017 budget. We're going to try to take a holiday for rate cases.

We can't guarantee that at this point. We have to look at the numbers, make sure there's nothing in 2017 that would cause us to have to file a rate case.

Right now, we typically like to go every other year just to deal with inflation. The big driver is, obviously, load growth and to see what happens in 2016 and 2017, to provide some margin to cover our general increase in inflationary costs.

So we'll look at 2017. I think we've gone through three rate cases in a row, and I think it's time for a one-year hiatus.

But again, we will complete the budget process. We will look at the results, and see if we can manage through 2017.

So that's where we are right now. We'll know probably more probably in the third quarter call whether that's the indication.

We wouldn't have to file a 2017 rate case till February of next year, so we do have time. But we want to complete the budgeting process, look at the numbers, see what it would mean to try to manage through 2017.

Got it. When I look at slide 13, I just want to make sure I'm understanding this correctly. When I think about what drops to the bottom line on a pretax -- I guess drops to the earnings before taxes line, it's that $41 million? Or is it a different number?

Well, the supplementals are usually offset by amortization. So you typically -- and I have to look at each of the supplemental tariffs. But the supplemental tariffs usually are a refund of a prior credit to customers; and Jim can give you the detail behind the supplementals.

But those are typically just amortizations of credits that we have. The biggest is the fuel, the spent fuel pool or the fuel credit from the Department of Energy.

The base business is really what flows -- base business and Carty are the two numbers that flow to the bottom line. Obviously, they are offset by cost, which has -- you have depreciation costs, you have other cost increases.

So the end of the day, it's essentially rate base times return on equity that gets to the bottom line. So there's lots of moving parts in these numbers, including power cost and O&M and a lot of other changes.

So it's not easy to say what drops to the bottom line, so -- because of the offset to costs. Again I always look at -- go look at the rate base for the case times the 50% capital structure times an ROE, and that really is what we would project for earnings, less certain costs that we don't get recovery for.

Yes. Can you remind us: what's the amount of cost you don't get -- normally in historical rate cases that you didn't get recovery of?

The amount from an ROE perspective, we put it out there at approximately 8 basis points.

Got it. Okay; thanks, guys. I have one or two others; I can follow up off-line.

Thanks, Michael. Appreciate it.

Brian Russo, Ladenburg Thalmann.

Hi, good morning. I'm just curious. With the upward revision to your load growth forecast, will that change the revenue requirements that we see on page 13?

Well, when we did the GRC and we updated our load forecast as part of that filing, that did increase the load expected. So it's actually going to increase it a little bit.

Okay; got you. The stipulation that you mentioned was filed in June and details will be out soon, is that -- if I heard you correctly, it's all (multiple speakers)?

Brian, there's two stipulations. One we did file with the Commission. That's the one that's on record to date.

There is another one we just recently reached agreement with the parties. That has not yet been filed with the Commission. We're still working through the paperwork to make sure everyone agrees, get everyone to sign off on it; then we will then file that stipulation.

It deals with almost all the remaining issues other than the Port Westward 1 project that we talked about earlier on the call. So we haven't been able to provide those details to you because the parties haven't signed off, and until they sign off it's not done.

So we don't want to pre-jump the results. But the hope is to get that completed the next couple weeks and get it filed with the Commission.

All remaining issues mean return parameters as well?

Yes, everything. Everything except for the PW 1 issue.

Okay, great. Then encompassed in the guidance, can you give us a sense of -- does the midpoint of your guidance assume a zero balance on the PCAM?

I don't think we get that.

We don't get into that much detail, Brian.

We are generally within the guidance. There's all kinds of things moving on, and a lot of it will depend on wind generation.

I think we have a pretty good runway on hydro. We see what that's going to produce. But we still have the end of the year, and that can have a hydro impact also, which has still not yet happened.

So there's a lot of moving parts between the load forecast and power cost and wind forecasts. There is just a lot moving on right now. So we generally feel comfortable within that guidance, but we still have a whole half-year left to go.

Yes, I'd say that for the full year we anticipate being within the deadband of the PCAM. And right now, as I mentioned earlier, we are effectively at the AUT level, the baseline level.

Got it. I think you ended the first-quarter 2015 $2 million below. That assumes you lost that $2 million in the second quarter and you're flat year-to-date?

Well, we're down $2 million year-to-date underneath the baseline. We're flat on Q2 only.

Understood. Thank you very much.

Mark Barnett, Morningstar.

Hey, good morning, everyone. Thanks for all the commentary so far. Just a couple of quick questions.

Is there -- would you be able to disclose the impact of -- you said that the load growth excluded one large paper customer. Was that a closure, or just a major delta in their usage for the quarter?

One of our large customers is a paper customer, and they get a variable rate from the Company. So we essentially buy and sell for them, or buy power for them when they need it at the market rate.

So their consumption really doesn't impact our results, and it can be very volatile. In fact they've had self-generation out there, which can change the overall result. So because they're a variable load customer and we just sell to them in a margin, they are not one of our, what I'd call cost of service customers on a long-term basis.

So we try to take them out, because the volatility in their loads just can impact the growth numbers and it doesn't reflect the base growth in our business. So we've just excluded them for purposes of clarification and clarity of our load growth numbers.

Okay, yes. I thought that that would be the same customer; I just wanted to make sure.

Yes, same customer.

Okay. Then, second, could you give just a little bit of color? When you talk about the rest of the year being below average for hydro conditions, I know you have a pretty good idea by this point what the next few months will look like. Could you maybe just comment on that a little bit?

Sure, Jim, you want to answer the hydro?

Yes, when we look at the three basins that we are sourcing our generation from, which is the [Midsea], the Clackamas and the Deschutes, all those basins are below normal in the April through September forecasts. So as we're looking out for the balance of the year we're expecting that to continue to be down at a less than normal level. If you look at it from a composite perspective, we're expecting it to be about 73% of normal.

Okay. All right. Thanks for the color.

Andy Levi, Avon Capital.

Hi, good morning. Hey, just a quick follow-up on the PCAM. Could you just describe to us -- you had some verbiage in the release, so you mentioned it also on the call that you did a very good job offsetting the hydro conditions and the low wind conditions. Can you just give us some more detail on that, if possible?

I think part of that is just due to changes in the market and market opportunities. California is obviously going through a pretty significant drought down there, and so we try to take advantage of those opportunities when they make themselves available.

They are random. You never can predict them. But we try to always optimize our power supply in the market when there are opportunities to sell power into that market. So because of what's going on in California, the severe drought, the market heat rate has gone up, which provides us an opportunity to sell some of our excess generation into that market.

Okay. So just if I understand it correctly, your fossil units ran very well. That provided, even with the heat, excess generation that you were able to sell into the California market and offset the lower hydro and wind conditions. Is that correct?

Jim?

Yes, that's basically correct. Along with the first two months of the quarter we had lower loads, so we had lower power cost, so that's a fair point as well.

And was hedging or pre-hedging have anything to do with it? Or was it really just the dynamics of the market and good production from your fossil units?

It's the latter. It's not hedging, because we typically go into the year fairly flat, so we don't take risk positions going into the year. So we essentially buy the gas, buy the power, buy the other fuels that we need to run our power plants in anticipation of what we think -- how they are going to run.

And then everything else changes: hydro changes, wind changes, California hydro conditions change. And that's where we try to optimize our power supply. And because of the unique situation in California, the market heat rate has been up a little bit.

I know it's a quarter that you haven't released yet, but those dynamics continue in July?

Yes, they should. We'll have to see how it all works out. You never know how Californians set themselves up. Whether we get heat in California will make a difference.

And whether we get heat in the Pacific Northwest will make a difference as well.

Yes, whether our thermals are committed to meet load in the Northwest, or loads are moderate here and then there is an opportunity there. So there's lots of things that move around on a daily basis in terms of the markets.

Great. Thank you very, very much and great quarter.

You're welcome. Thanks.

Ashar Khan, Visium.

Great quarter. Wanted to just go over -- could you just repeat? I just wanted to make sure: what is the contribution of the weather, positive or negative, year to date, and if you could just repeat for the quarter versus normal?

Well, for the quarter versus normal, it was $0.07.

Okay. Negative?

Negative, yes.

And again, just to be clear (multiple speakers)

And year to date?

We'll get back to you on that.

Sorry?

We'll get back to you on that. I don't have that with me right now on a year-to-date basis.

Okay, okay. Then I just wanted to get a sense, Jim, on the -- strategically one thing which has happened since last call. M&A in the small-cap space has been in the forefront, and I just wanted to check in. How does the Board look at M&A and strategic things generally in this space, or just for shareholders long-term?

We don't really comment on mergers and acquisitions. I would tell you just like any Board, you have responsibility to observe what's going on in the market. We brief our Board on what's going on in the market related to M&A. That's all I'd like to say on that issue.

Ashar, on the weather-adjusted we were able to look that number up. So year-to-date, weather compared to normal has driven down EPS about $0.20.

$0.20? Okay; great. I appreciate it.

$0.27 year-to-date.

$0.27? Okay.

$0.20 in Q1; $0.27 Q2.

Okay. I'm just trying to make sense how we should try to forecast next year, take the weather out or normalize it as we do our numbers. Thank you.

Michael Lapidus, Goldman Sachs.

Hey, guys. I know you're a ways away from thinking about longer-term EPS, but is the best way directionally, if I'm an investor, just think about rate base in 2016, assume the authorized capital structure, and maybe a slight discount to the authorized ROE? Let's say we use the [nine nine], but some slight discount to it. Is that ballpark the right way to be thinking about this?

In terms of the earnings performance of the Company, if you take your rate base times 50%, you always have to add CWIP into it. So you have to add rate base plus CWIP; and then you take your cap structure times what you think the allowed ROE is going to be, and then reduce it by roughly 80 basis points or so for disallowances and other costs that are not recovered. And that gets you to the earnings power of the Company.

Got it. And I want to make sure the comments -- I asked that question earlier about the GRC and the detail at the bottom of slide 13. The supplemental tariff updates, so that $62 million, that's a reduction in revenue; but it's also a reduction in amortization. So it doesn't impact EBIT or earnings. It impacts cash flow, but not earnings necessarily?

Right. That's correct.

Got it. Okay, guys. Thank you. Much appreciated.

Thank you. I'm not showing (multiple speakers)

Okay, looks like we have no further calls, so let's conclude. It looks like we have no further calls. We appreciate your interest in Portland General Electric, and we invite you to join us when we report our third-quarter 2015 results in late October. Thanks again and have a great day.

Ladies and gentlemen, thank you for participating in today's conference. This concludes today's program. You may all disconnect. Everyone have a wonderful day.