Portland General Electric Co (POR) 2021 Q3 法說會逐字稿

Good morning, everyone, and welcome to the Portland General Electric Company's Third Quarter 2021 Earnings Results Conference Call. Today is Friday, October 29, 2021. This call is being recorded. (Operator Instructions)

For opening remarks, I'd like to turn the conference call over to Portland General Electric's Senior Director of Investor Relations, Treasury and Risk Management, Jardon Jaramillo. Please go ahead, sir.

Thank you, Jonathan. Good morning, everyone. I'm pleased that you're able to join us today. Before we begin this morning, I'd like to remind you that we have prepared a presentation to supplement our discussion, which we'll be referencing throughout the call. The slides are available on our website at investors.portlandgeneral.com.

Referring to Slide 2. Some of our remarks this morning will constitute forward-looking statements. We caution you that such statements involve inherent risks and uncertainties, and actual results may differ materially from our expectations. For a description of some of the factors that could cause actual results to differ materially, please refer to our earnings press release and our most recent periodic reports on Forms 10-K and 10-Q, which are available on our website.

Leading our discussion today are Maria Pope, President and CEO, and Jim Ajello, Senior Vice President of Finance, CFO, and Treasurer. Following their prepared remarks, we will open the line for your questions.

Now, it's my pleasure to turn the call over to Maria.

Good morning, and thank you, Jardon, and thank you all for joining us. Hot summer weather and power market volatility had a significant impact on our region and on our results this quarter.

Turning to Slide 4. We reported net income of $50 million or $0.56 per share for the third quarter of 2021. This compares with a loss of $17 million or $0.19 per share for the third quarter of 2020. Year-to-date, financial performance is on track. And despite third quarter volatility in the energy markets and higher O&M, we are reaffirming our 2021 earnings guidance of $2.70 to $2.85 per share. Our long-term outlook remains unchanged, and we are reaffirming our 4% to 6% long-term earnings growth guidance.

Overall, our business is strong, driven by load growth from the technology and digital sectors as well as elevated residential use due in part to the hot summer weather and continued COVID constraints. Year-to-date revenue is up 12% versus 2020 and for the quarter, up 17% versus last year. Jim will cover third quarter results in more detail, provide regulatory and capital updates and discuss the outlook for the rest of the year.

The ongoing impacts of climate change underscore the importance of investments and actions that we are taking to rapidly transition to a clean energy future, and meet our 2030 decarbonization goals, while also ensuring that we have sufficient capacity. We estimate that our 2030 targets will require approximately 1,500 to 2,000 megawatts of additional carbon-free resources and approximately 800 megawatts of non-emitting capacity resources in addition to removing coal from our portfolio.

We're seeking approximately 1,000 megawatts of renewables and non-emitting capacity resources as part of our RFP, which will be issued in December. As part of this procurement, we plan to add 375 to 500 megawatts of renewables to our portfolio. We will also bring on approximately 375 of non-emitting dispatchable capacity. We will work with the OPUC and parties to evaluate opportunities to procure additional resources so the types of projects submitted in the IRP process -- excuse me, the RFP process, make sense for customers, and are attractively priced. We could see procuring about 1/3 of our clean energy resources needed to meet the 2030 emissions target reductions with this RFP.

We not only need more renewables, we need to upgrade the grid to integrate these resources, making it easier for customers to participate in demand response and distributed energy programs helping to keep service reliable and affordable. In our recent distributed resource -- excuse me, distributed system plan, we lay out plans for the grid of the future that supports robust 2-way energy flows and better manages energy use, especially during peak periods. We estimate that as much as 25% of flexibility needed to meet our decarbonized future would come from customers and distributed energy resources such as solar panels, batteries, electric vehicles.

During the 2021 summer heat dome, we worked with customers to save 62 megawatts of power equivalent to powering 25,000 homes. We're working to significantly grow this program to 500 megawatts by the end of 2023. We are very pleased to have been selected by the Department of Energy as part of their Connect Communities Program and are working with local DE&I groups on the placement of resources such as batteries, 2-way EV charging, and solar panels to ensure that our customers in underserved communities participate in this clean energy transition.

As one of the early participants in the western energy imbalance market, we have been a leader in advocating for the expansion and strengthening of wholesale markets to increase reliability, accelerate decarbonization, and lower costs for customers. PGE and our utility partners across the West are working to bolster reliability planning, advance integrated markets, and examine the benefits of a western regional transmission organization. Throughout these processes, we will continue to advocate for rigorous resource adequacy standards.

Sustainability is foundational to our business. In September, we published our ESG report, building upon our #1 ranked voluntarily -- voluntary renewable program. Sustainability is part of the fabric of everything we do, including financing. We recently adopted a green financing framework under which we successfully placed $150 million in green bonds. Yesterday, we filed a rate case with the Federal Energy Regulatory Commission to review our third-party transmission revenue. The revenue that we receive from these new prices will offset retail customer prices through a revenue credit. We continue to make progress on our 2022 general rate case and have reached settlements with stakeholders in October that resolves the cost of equity and gives 9.5% as well as a 50-50 cash structure. We look forward to working with stakeholders on the remaining items.

Finally, I'm pleased to welcome Dawn Farrell to our Board of Directors. Dawn retired as President and CEO of TransAlta in March. Her deep experience in the energy sector as well as her leadership in transforming a thermal-based generation company to a leading clean renewable energy company will be important as we advance our own transformation.

Now, I'd like to turn the call over to Jim.

Thank you, Maria, and good morning, everyone. Our third quarter results reflect the ongoing opportunity and the challenge as the economy enters a new normal. We experienced strong load growth from higher demand and hotter weather. At the same time, volatility in the power markets was evident throughout the summer.

The fundamentals of our economy remain strong and are fueling strong growth in energy demand and a growing labor market with continued job growth in the region. This quarter, we had strong deliveries across our customer segments with additional benefit from favorable weather. Our high-tech and digital services sectors continue to grow at a rapid pace, 9% higher when compared to Q3 2020. Customers are expanding capacity, and we've seen an uptick in site selection activity by data center developers and others. Residential usage remained significantly elevated as remote work continues. We anticipate these trends to continue, and this has contributed to our strong year-over-year load growth.

Turning to Slide 5. We reported GAAP income of $0.56 per share in the third quarter of '21 compared to a GAAP loss of $0.19 per share in the third quarter of 2020. Non-GAAP income for the third quarter of 2020 is $0.90 after removing the negative impact of the energy trading losses.

I'll cover our financial performance quarter-over-quarter on Slide 6. Beginning with the loss of $0.19 per share for the third quarter of 2020, we will add back the $1.09 one-time impact of the energy trading losses. We experienced a $0.37 increase in total revenues, primarily due to the strong economy driving growth in our service territory, with the balance due to warmer weather. This represents a 17% year-over-year increase in total revenues. Offsetting this was a $0.39 of unfavorable power cost. We experienced substantially higher market prices due to warmer weather and increased regional demand for capacity as well as lower renewable generation. As a result, we are forecast to be above the $30 million threshold to begin customer cost sharing pursuant to our power cost adjustment mechanism.

Through the quarter, we have deferred $27 million, which represents 90% of the variance above that threshold. We anticipate the regulatory process related to this deferral will begin in 2022 after the pending rate case concludes. Our power costs this summer were not materially impacted by rising natural gas prices. Our portfolio is well positioned and a bit long to balance gas price fluctuation, and we have significant gas storage at the 4.1 billion cubic foot North Mist facility that we can draw on as needed.

There was an $0.11 decrease to EPS from costs associated with our fixed operating expenses, including $0.03 for enhanced wildfire mitigation, $0.04 of additional vegetation management, including work that was delayed as we focused on storm restoration during the second quarter, $0.02 of service restoration costs, and $0.02 of miscellaneous other expenses. There was an $0.18 decrease to EPS from administrative expense. Half of the year-over-year increase is attributed to items that were unique to 2020 including $0.07 in adjustments to incentive programs following the energy trading losses in the prior period, and $0.02 from the deferral of bad debt following the approval of the COVID-19 deferral. The remaining administrative expense can be attributed to $0.06 for outside services to support improvements to our customer experience, a $0.02 increase in employee benefit expenses, and $0.01 from miscellaneous other expenses.

While O&M was higher this quarter when compared to Q3 2020, on a year-over-year basis, our costs have increased only 2% annually since 2019. The fact that we have reduced planned outages by 29% year-over-year, stood up a large wildfire prevention program and greatly increased vegetation management is a testament to the efficiency we built into the O&M program. Managing costs consistent with inflation while increasing wildfire resiliency, improving our customer experience, and growing our digital capabilities demonstrates the effectiveness and efficiency of our workforce as well as the use of technology. Finally, there was a $0.03 decrease to EPS from the following items: $0.03 benefit from lower depreciation and amortization due to planned retirements, $0.04 of higher tax expense due to the timing difference of asset retirements in 2020, and $0.02 from other unfavorable miscellaneous items.

Turning to Slide 7. Last month, we reached an agreement with stakeholders on cost of capital in our 2022 general rate case. Our agreement supports a capital structure of 50% debt, 50% equity, and a 9.5% allowed ROE. We see this as a constructive outcome and look forward to discussing remaining unsettled issues with parties in the case. As you saw earlier this month, we made several regulatory filings, which we shared -- in which we shared our plans to advance the strategy to meet our targets for reducing greenhouse emissions in the power we serve to customers.

Maria discussed our RFP plans earlier in this call. We still plan to bid in benchmark resources into the RFP process. To support our bids, we filed for an affiliated interest entity that will help support our decarbonization interests. Our proposal is intended to address certain structural tax disadvantages encountered by utilities due to the unintended consequences of tax normalization requirements. The affiliate interest would provide a greater price benefit to our customers as PGE decarbonizes its generation portfolio.

Turning to Slide 8, which shows our updated capital forecast through 2025. We increased our capital expenditure forecast by over $100 million this quarter. This increase is concentrated in 2022 and is primarily associated with grid-based investments. With our recent settlement in the GRC assuming approval by the OPUC, this affirms that we will not need to issue equity in 2022 to meet our capital requirements unless there is a significant renewable addition stemming from the aforementioned RFP. We continue to maintain a solid balance sheet, including strong liquidity and investment-grade ratings accompanied by a stable credit outlook. Total available liquidity at 9/30 is just over $1 billion.

At PGE, sustainability is woven into the fabric of who we are as a company, and we stand behind that through our actions as an organization including in our financing plans. This quarter, we renewed and increased by $150 million our revolving credit facility to include sustainability-linked performance metrics. We also refinanced the Wheatridge Renewable Energy facility with low-cost debt under a green bond in alignment with our green financing framework. The demand for this was evident as it was nearly 6x oversubscribed. Our investors are keen to purchase debt linked to sustainable investments. Going forward, we will seek out opportunities to tie our long-term debt toward our sustainability strategy through capital investments. Not only are these actions good for our business, but they are also good for society.

Turning to Slide 9. Our year-to-date 2021 performance remains on track, and we reaffirm our guidance range of $2.70 to $2.85 and remain on track to achieve long-term earnings growth guidance of 4% to 6% from the 2019 base year. The picture for 2021 and beyond remains clear: strong growth in customer demand for clean, affordable, safe, reliable, and equitable energy paves the way for us to execute on our long-term financial targets and deliver value for customers and investors alike.

And now operator, we're ready for questions.

(Operator Instructions) Our first question comes from the line of Insoo Kim from Goldman Sachs.

My first question, I think, is more financial in nature. Just, Jim, for the year as we think about the year-to-date results and you're reiterating the midpoint of the -- or I guess the guidance range that you raised last year seems to imply a pretty healthy fourth quarter earnings relative to if you look at 2019 fourth quarter or 2020 fourth quarter results. Can you just help us generally piece together some of the moving parts that gets us there?

Yes. Thanks, Insoo. As I understood your question, you're trying to, in effect, walk from where we are today to the result of the 2021 guidance and, in effect, what we might do in the fourth quarter. So let me try to -- do I get that right?

Yes, that's correct.

Okay. Perfect. Okay. So let's look back to the fourth quarter of 2020. There, the earnings were $0.57 per share, you may recall, but also we recorded an asset retirement obligation for our Sullivan hydro facility, a facility that's well over 100 years old in fact, and that was $0.17 a share. We also adjusted incentives for that fourth quarter as non-GAAP earnings were picking up speed in the fourth quarter. So in reality what happened was the way I look at the fourth quarter and I walk to the fourth quarter of this year, we had about $0.22 between the ARO and the incentive adjustment added to the $0.57 to normalize the fourth quarter of 2020, which gets you to about $0.79. And that in fact gets you to about the midpoint, if that were to reoccur again in 2021 of the present range. Does that help?

Okay, so the ARO is a pretty big component of this?

Yes. The ARO is $0.17 a share, incentive adjustment is $0.05, $0.22, add that to $0.57, you would normalize fourth quarter of $0.20 to $0.79 a share. And we're at $1.98, as you would know, for the year-to-date presently, right?

Right. Okay. That definitely helps. Second question, Maria, just the broader picture, I think it's no question that the state of Oregon has been a leader in proposing and advocating, and acting on the clean energy transformation and Portland is a big component of that. When we think about the pending reconciliation package that is out there and the potential for extensions of tax credits and some changes to how those mechanisms will work, how does that -- how do you think about that impacting or creating incremental opportunities maybe even over the next 5 years in terms of different clean energy investments that could come about for you guys?

Sure. First of all, it's a great question, and we were very pleased to see the announcements yesterday with significant investments that will help us and others transition to a clean energy economy. The structure of the tax credits in the Bill were particularly important to us. As you know, we've worked with Senator Wyden on tech-neutral tax credits. Those are reflected in what was discussed yesterday by the President. And also important to us is tax normalization that's included in -- we're still working very focused on normalization for transmission and in particular for storage. And so that -- those remain goals of ours. Should that not take place, the affiliate filing that Jim talked about will give us the level playing field to continue to move forward with important components from a utility standpoint for our customers around battery storage and others so that we can get the very lowest cost for customers as we make this important transition.

Our next question comes from the line of Julien Dumoulin-Smith from Bank of America.

Congrats to Dawn as well. I don't know if she's there, but well done on bringing on more talent here. But if I could just jump into the rate case just real quickly here, 2 quick clarifications. So first off, just following the earlier settlement obviously on cap structure and ROE, how you frame the potential to settle other outstanding items and just the process therein? And then related to that, if you could clarify, given the capital structure and the 50-50 authorized, does that change any equity dynamics as far as you're concerned here?

Julien, it's Jim. I'll kick off. So to take your last question first, yes, it does and it gives me confidence that we could go into 2022 without the issuance of any equity. We're in very good shape from a balance sheet standpoint. Our cost of financing is able to fund even that increased capital program that I spoke of a moment ago, we changed that from $550 million next year to $655 million. And I'll just go further, and Maria may want to add in in a moment. But we received comments earlier this week. We're evaluating those. I would say that this is a normal part of the process.

Just want to remind everyone that we deferred filing a bit here earlier this year in consideration of the community impacts on COVID. So I think we were -- we respected everybody's interest in terms of timing. We feel we put forward a pretty modest proposal, frankly, about 3.9%. 2% of that was in the AUT itself. It's largely a capital case. We added $993 million of capital, between the last time rates were filed we have kept, as I mentioned in the remarks a moment ago, our O&M pretty tight over that period of time. So -- and as you would know, the company has a history of settling. So we are about to get into a process where we will exchange information and hopefully get to that outcome. But it's too soon to predict anything at all. Maria, anything to add?

Well, I want to emphasize that as we've made decisions around our rate case, we have been particularly cognizant of the economy and particularly on those most impacted by the pandemic and we, as the result, delayed filing our rate case. I would also say we were able to do that because of all of the tremendous work that our colleagues here at Portland General have done. In Jim's prepared remarks he talked about the efficiencies that we have gotten from better use of technology, digital, driving efficiencies across our entire company. As a matter of fact, our planned outages are down significantly over 20%. We have seen better utilization of our assets, better work management flow, and there's no question that we are getting more work done than we have in the past.

And I'm really encouraged that we were able to keep through all of the ups and downs of the last 18 months to 2 years, O&M increasing at only 2% annually. And this focus on cost, but more importantly, on efficiency and driving outcomes for customers has allowed us to have the flexibility to delay our rate cases. We brought on really important reliability capital, capital also in the compliance area. As Jim mentioned, we have really focused on vegetation management, wildfire protection. And then as you know, people are moving to Oregon, and we have quite a bit of expansion in our digital and high-tech areas. And so we have built a number of new substations, we've expanded some other of our infrastructure, and it's really because of the good work of people at Portland General that we've been able to keep our prices as low as we are particularly in light of all of that's going on in our economy today.

Got it. Excellent. And just if I can pivot here to the affiliate dynamic just real quickly. You brought this up; it seems somewhat novel. Can you speak a little bit more as to just how that might expand the opportunity or why pivot to this opportunity now given that you haven't used it in the past? I understand that tax normalization, obviously, has been an impediment out there and then maybe your level of confidence there, and now that you're pivoting to this strategic focus here on winning.

Sure. So first of all, we remain hopeful, and the industry is focused on resolving the tax normalization issues. And those discussions as you've seen Senator Wyden quoted in Politico and whatnot are very much in play. This is not -- this affiliate filing is not new. We've been talking about it for a long time and debating it. So it's very similar to many other affiliate filings that you see across the country. It'll allow us to utilize tax advantages to reduce renewable costs from customers -- for customers to allow for more competition. And really so that our customers can have the very lowest cost energy that's reliable as we transition to ever-increasing amounts of new renewables. We have -- we, as well as many others, have very aggressive 2030 and 2040 goals, and we think this is an important tool in that toolbox.

Julien, I think I hear you asking the question why now and why us, and in addition to the structural disadvantages compared to the way independent power producers can accelerate those tax credits, and we have to normalize them over the life of the asset 30 years let's say, we're about to enter into and pivot into a very significant growth plan in renewables. We want to be an extremely active benchmark and owner of those assets, and we need to level the playing field and have the tools to do that. We need a couple of thousand megawatts between now and the end of the decade, and we want to be in that mix. I don't expect to win everything, but we expect to be very competitive, and we need the tools to do that. And that's really the framework and why now we're doing that.

Our next question comes from the line of David Peters from Wolfe Research.

The question -- first question I just have is just on that variable power costs. Obviously, the magnitude of that seems fairly unprecedented and then the deferral of $27 million. Just curious how you expect this to play out exactly just because I think this is the first time you expect to kind of breach that. And then just kind of, particularly with the backdrop that you have several other kind of sizable deferrals pending that are outstanding along with the rate case, so are there any creative ways to kind of mitigate potential bill impacts for customers here going forward?

Dave, I would agree with your observations. My time here is fairly short, but I look back and I think you're right about the nature of the levels here. But so was the weather and the markets that we experienced over the summer time. So I look at the mechanism itself as -- and our deferral under that mechanism is highly formulaic. It's -- there are deferrals, and there are deferrals. This one, I believe, is -- can be objectively calculated at the level that we have recorded it. And so I believe that this particular deferral is very straightforward, very verifiable. And the way it would work, typically I would say, but subject to discussion with OPUC is we would amortize that over a couple of year period starting, as I mentioned in the remarks, after we adjudicate this pending GRC that we have at the moment. So that's that one. And you refer to the other deferrals, which are substantial.

As you could calculate, they're nearly $150 million altogether, but they're very different in nature. There's the COVID deferral, which again is subject to I think a pretty straightforward calculation around debt -- bad debt. And then there are the more complex deferrals around the wildfires of 2020. And the last one being the biggest of all, which is the February storm cost. So I think I described these in terms of both size and ascending complexity. And I fully expect, since we don't have a securitization capability in the state, at least not yet, we will have to sit down and agree on an amortization schedule. And as I described those deferrals, they will go from shorter to probably a longer period of time. So the latter deferrals that I mentioned probably over a number of years, maybe many years. So that's how I look at it, Dave, and that's how I would think about it going forward.

Dave, let me add a couple of things to that. We have gone through an extraordinary period of time. We obviously had the pandemic, we had wild -- very destructive wildfires, we had a once in 40-year ice storm where more than half of our customers were out of power, and we had over 700,000 distinct customer outages. We also had the high heat dome events, and it really has been an unusual point in time. Most utilities would use a securitization structure. And that I think is something that we will explore with parties. It's very important as well because we're able to take advantage of very low-cost debt rate. And so that will certainly be something that we will pursue. I think it's really important as we look going forward around power costs that we -- that the PCAM is really just one link in the chain of power cost recovery. I think of this as kind of a 4 or 5-step process.

The first one is our forecasting methodologies. And earlier this year, late last year, we made changes to some of our modeling assumptions with discussions with parties and the OPUC. And those changes allow for more volatility to be reflected in our modeling. And that's particularly important with the variability of hydro and wind. The second would be our AUT or our power cost filing that we do each year. We're able to true-up market prices for power as we go into the prompt year. And then third, really our procurement strategy and derisking through our power operations, and they have done an excellent job at that. And I'd say they're working very closely. This would be my fourth area in terms of plant operation and making sure that our plants have the utmost reliability on the most challenging days of the year, whether those be ice storms and freezing temperatures or high heat events.

And then finally, the PCAM comes in and provides a regulatory backstop for our extraordinary volatilities as we've experienced this summer. So I think these are really unusual times. As we look forward into 2022, and you can see -- we have been in discussions with parties around the AUT, we're about to -- we'll be locking down those numbers as we move forward. But about half of the $60 million increase that we're roughly forecasting is directly related to higher load. And so that's a good variance. And we couldn't be more pleased with the expansion that we're seeing in the industrial commercial sector as well as with customer growth as people are still moving into our service territory into Oregon.

And then, we're seeing about the other half related to either derisking the portfolio with capacity and making sure that we have adequate reserves going into the year, and then also just higher prices that are reflected. One of the things that I'm really pleased with is our hedging strategy with regards to natural gas, which has been in place for almost a decade, and is really meeting -- our customers are not experiencing the volatility of natural gas prices. And so it's nice to see when these practices make a bottom line difference to every bill we send out to our customers, and we're able to insulate them from the -- some of the volatility that we're seeing across markets in the energy space.

Great. Thank you for that detail. Second question I had just back to the rate case. We saw staff's testimony earlier this week and obviously, a big delta versus your guys' ask, which I don't think is inconsistent with history, but could you maybe just comment on what you saw in their understanding? Do you think there's still a good chance of settlement? And then just chances on getting some of those proposed changes approved around the storm accrual and decoupling?

Yes, Dave. I'll start, and Maria may want to add to it. You're right. I mean, I appreciate your comment, not inconsistent with history. We don't overreact to these things either. These are the kinds of things that happen in cases like this. I will tell you that I think we should pursue the GRC in all of its detail. We desire to get to a settlement. But the deferrals are on separate tracks in separate dockets and therefore, should be separated from the case, and that's our view, and that's the way it's set up to go forward here. And as you know, the settlement prospects here are always something that we try to do, and we will deal with the deferrals in due course, but they'll be on a separate track.

Yes. I don't think I have anything to add. We'll work collaboratively with parties, we'll be transparent, and I think help everyone understand the magnitude of the past year to 18 months and the good work that we have done to address the issues the -- that Mother Nature has brought us and to create a more reliable and resilient utility as we go forward.

Our next question comes from the line of Shar Pourreza from Guggenheim Partners.

Maybe just starting at a higher level. You guys obviously laid out some pretty substantial energy and capacity needs through 2030, and I understand it won't necessarily all be utility-owned as Maria obviously you highlighted it in the prepared remarks, but how should we sort of think about maybe this opportunity in the context of your guided 4% to 6% growth? In the past, we've talked about the current RFP pushing higher in that range. So would the size of the overall need be enough to get you to consider maybe guiding even higher?

Shar, it's Jim. So I will tell you our setup for the guidance range here is not including any generation facilities that we may be fortunate enough to compete and win for in this next round. In fact, I would anticipate a couple of IRPs in this decade, maybe 2 or 3 and successive calls for more resources. We've recently upped our expectations, and we've been encouraged to up our expectations given the march that we're on here. So just to make it clear, none of that ownership would be in the 4% to 6%.

And also let's not forget here we're backing out, as soon as practicable, our interest in the Colstrip plant, right? And we have accelerated depreciation that's been agreed to. It still needs to be approved finally by the Oregon PUC in the context of this rate case, but we have a settlement there to accelerate depreciation in 2025. So we're making a really strong pivot to a significant purchase and perhaps ownership program. But in terms of ownership, that's not in the guidance. Nor is the capital that we've laid out that -- to operate the system including any of the capital that we would need to build those assets.

Got it. So just maybe this brings a follow-up. So is the current process, is that supportive of how you guide as in extending the runway? Or could it actually be accretive?

If I understand your question correctly, any additional -- as Jim mentioned, any additional ownership opportunities through the IRP, should those be the least costliest risk projects would be accretive to our 4% to 6% growth.

Yes, for sure. And you can expect, Shar, that we will capitalize those appropriately. But at the end of the day, will be accretive. Sure.

Okay, that's -- and then just on the RFP process, right in the event you were successful, when would you be looking to do associates equity? Would you automatically be eligible for an associate rider for recovery, or would you have to go back in for another GRC?

So we do have a renewable adjustment mechanism that allows us to track in renewable energy. So that's very favorable and it's a mechanism that we've used on numerous occasions and most recently with the Wheatridge Energy facility.

And I'll add, Shar, that we wouldn't know about the award periods until probably the spring and early summer. Construction would take place -- design and construction would take place later that year into '23 and '24, so financing would happen in that time frame. And we have such a terrific liquidity position that we could leg into any ownership without immediately needing to go into the market for much in the way of financing, certainly, equity financing.

Our next question comes from the line of Peter Bourdon from Mizuho.

Just to follow up on the power cost side of things. Is there any more color you can give on what drove the volatility that you saw this quarter? And then secondly, what gives you comfort that that volatility is not I guess the new normal going forward?

Sure. Well, in the West, and maybe even in the rest of the country as you look at scorched trees all over the place, I think it's really important that we recognize the high heat events that we had. And so that created -- we're able to forecast those events, but not too far out into the future. We also had quite a bit less hydropower in the region, and aligned with hydropower is actually wind generation as well. And that created quite a bit of volatility in market prices throughout the West and those that we were exposed to. I would say that we particularly saw run-ups before the day-ahead markets would have some of the highest prices. And then they would -- frequently would fall off during -- in real time. As we think about working across the West, we've seen additional liquidity as we're more integrated.

And I would say, power and energy trading leaders are really looking at how we expand the integration and pooling of resources across the entire West, whether that's to day-ahead markets and the expansion of the EIM with CAISO, whether that is through reliability discussions with the Northwest Power Pool or whether that's through other forums where people are really looking at how we manage going forward. We're fortunate to have, as I walked through, the ability to update our power costs and -- every year through the annual update mechanism. So we are able to reflect the learnings year-to-year into our future power costs and the reality of these market conditions. As you know, we've -- across the West have reduced a number of significant thermal plants and that's having an impact on -- as we get into scarce periods of time, there are less resources in standby that could come back on to the market. And as a result, I think we will continue to see volatility and we are learning and managing through it.

Our next question comes from the line of Travis Miller from Morningstar.

You answered a lot of my questions in detail, I appreciate that. I want to go back to the CapEx increase. Can you talk a little bit more about that? What types of projects led you to increase that 2022 number, and what was the factor or factors during the quarter in the last 3 months that led you to raise that $100 million or so?

So let me build a little bit, Travis, on the answer I just gave to the prior question around reliability and markets. One of the things that's also really important is a tool in our toolbox. And I mentioned it in my prepared remarks, was that being able to use essentially 25% of the capacity and sort of shock absorber of markets in the distribution system. And so as we move forward, we have accelerated our plans, around our distributed resource plans whether that's our DERs, could be solar, battery storage, electric vehicles and their ability to charge and create a buffer, but also demand response programs.

We have had one of the most robust energy conservation programs in the country, in fact, we lead in those areas. And so all of this together combined with the infrastructure that needs to support a really smart, flexible grid as we integrate more renewables and try and reduce the impact of volatility is important. It's not just important to pricing, it's important to overall reliability. I'll let Jim talk to you a little bit more about the specific buckets of capital that we have, but please know that we are moving quickly to reflect the new realities of our markets and the need for greater sustainability in a carbon-free future.

Travis, I'll add that largely we don't think of CapEx as something that is temporal. We -- in the short term, we think of it as a long-term matter. So just looking at the '22, the reference to the higher CapEx at $655 million versus $550 million, so largely that 60% -- 65% in fact grid-related just proves the point that Maria was making. About $25 million of that really is from our integrated operations center, which we're finishing up. We're adding some facilities out there that's about a $200-plus million investment. A little bit of that carries over into the new year 2022.

We've got some work on the generation side as you would imagine as everyone would have maintenance CapEx there. And then, we're investing a great deal in technology. That's the other chunk or part of that digitization, more customer service activities, improved work into -- flow, and how we manage massive amounts of data that we're collecting. Some of our systems are older, need to be replaced, operating systems, administrative systems, and what have you. So -- and then as you look to the out years 2023 to 2025, again those exclude as does anything in '22 for generation that we may build. It's largely grid-related work. You could really see the technology investments continuing, the $85 million, but then it's close to $400 million in all of the topics that Maria just mentioned. So it's really about grid and resiliency other than any generation, which is not included here.

Okay. Great. That's helpful. One higher-level question. Obviously, you've talked about a lot of capacity needs relative to energy needs, how do you think about capacity in a 80% carbon reduction world or even 100% clean energy world these days? We typically think about capacity as a fossil fuel source type of resource. How do you...

So we're -- we start out blessed to be in the Pacific Northwest where overall hydro generation makes up about 50%, 55% of the generation in the region. So I think it's important to acknowledge that we have a natural competitive advantage from that standpoint and much of that in addition is low cost. We also do have capacity factor from both wind and solar, and the diversity of being able to use those combined and then adding battery storage. And our Wheatridge facility is a great example of not only that since it combines all 3 of those technologies and at scale, but it also better utilizes a very scarce resource of transmission. So that's important. I would also say I'd mentioned about being able to use the distribution system as a shock absorber and really a source of capacity across our area. And that will grow very rapidly, and it is a really important component for us. I would also say that we have a number of partnerships.

We've announced a partnership with Douglas PUD, one of the hydro operators on the Mid-C. We provide energy services, they provide capacity to us. And you can see a renewal of a contract we have with the Confederated Tribes of the Warm Springs along those same lines on the Deschutes River as well as many others. We take, what I would call, an all-and-above set of solutions including all of the integrated aspects of West-wide markets and the need to move much faster and accelerate the pace of change across the entire West. So it's an exciting time. These are challenging problems. I don't want to underestimate or sound like we have all the answers, we're going to be learning and growing through this with every year. And it really is going to be the challenge of the next decade around reliable sources of capacity that supports ever-increasing uses of electricity, and we're excited to be leading in this clean energy future.

Yes, Travis, I'll just wind up here by saying that in the 2021 RFP that we're talking about launching here in the near term, about 375 megawatts of non-emitting capacity is being called for. And I'm going to be very interested to see how battery technology and the cost curves show up in terms of that auction. I can't pre-judge it right now, but that's a pretty big purchase for a system of this size. So we'll see where that goes. And it may not only be batteries. But the sense we have from the market is that they will show up. And of course, pricing will be very, very important.

Our next question comes from the line of Andrew Levi from HITE Hedge.

A couple of questions. First on kind of what's going on in Congress and Direct Pay, I assume you guys are kind of familiar with that and looked at that. Is that correct?

Yes.

Yes.

Okay. Before I ask my question. So how does that kind of play in, so assuming you win a portion of this capacity that's needed, I guess that's both good for you guys and for the rate payers, it brings in more cash immediately, it maybe affects rate base a little bit as well. But if what you're saying is a situation where you may need to issue some equity eventually to pay for these capacity additions, how would that kind of offset that equity need and maybe change your outlook as far as growth? And then additionally, I would think it would also make you more competitive as a bidder for these assets too by being able to use something like that in your calculations?

So Andy, first of all, thank you for the question. And you're absolutely right. Our ability to deploy all of the tools that we have whether it be tax equity, whether it be through PTCs, ITCs, Direct Pay, grants from Department of Energy, as I mentioned we received a grant for some projects in our distribution system targeting low-income areas, all of these things are incredibly important tools as we deliver cost-effective, renewable and reliable energy to our customers. What we call it here is leveling the playing field, but it's really important that customers do not see price shocks and that we're able to use all of these tools competitively and effectively for our service territory, the state of Oregon, and all the customers that we serve. There's no question that Direct Pay would offset needs for equity and give us more optionality as we move forward. As with many other aspects in the reconciliation plan as well as all of the tax issues still being worked out.

I'm a fan of the Direct Pay PTC, Andy, because -- well, I think it's probably pretty obvious, but it's a significant gain for our customers, a significant gain for the company. The thing that I would add to Maria's explanation is that this could help us eliminate some of the unutilized credits that we have carrying forward, right. So you'd have more efficiency in that regard as well. So the cash benefits, the cash flow, the lack or the lessened equity requirements are all benefits. And I hope we get that just to be honest.

Okay. And then kind of continuing on, then you have this like regulatory -- structural regulatory lag. That's a fairly fixed cost if I'm not mistaken, it doesn't really grow a lot as far as the actual cost of the lag. So as your rate base grows by definition that lag -- especially if you end up adding significant capacity in CapEx, that lag theoretically should shrink, shouldn't it?

Yes. Absolutely right. And yet another reason why we're benefiting from the growth in our territory. That sort of growth should benefit us in a number of ways including that lag, right. We -- as you know I mean, the OPUC calculates our equity returns differently than we would from an accounting standpoint. We punch over 9% on an accounting standpoint. So we do relatively well I think with investors. In terms of the allowed ROE, of course, they take out the short-term debt here. So we actually have a bit higher ratio on equity as calculated by OPUC standards than we would on an accounting basis, but our returns are better on an accounting basis there. But you're right, we're -- it's the concept of spreading those expenses over a larger base that's fundamentally right.

It also reduces the volatilities. You have a larger, more stable base to start with.

Got it. And one last question. So this is kind of circling back to the beginning. So just on the PCAM. So this -- your strategy as far as kind of eliminating that risk for both the shareholder and for the rate payer by adding this capacity over time and whether it's -- whether you own it or you contract for it, that obviously will help on the volatility especially if we get extreme weather. But I'm just curious just for 2023 -- 2022, excuse me, I'm jumping ahead. Every year matters to me as I get older, so I should take my time here, I guess for all of us, but for 2022, again without divulging anything that you may not want to divulge as far as how you're going to go into the market, what's kind of the strategy as far as trying to eliminate -- if we got extreme weather again, we don't know what the weather's going to be, but to try to eliminate some of that volatility into next year for both you, the shareholder and the company?

Yes. Well, so first of all, we take a -- what I call sort of an all-and-above set of strategies. And really, it starts with how we run our generation facilities and ensuring that they are 100% reliable during the most challenging days of the year. The next is how we integrate those generation facilities across our power operations area, and ensuring that we have the right amount of capacity procured and the right reserve margins for the increased volatility that we are seeing as we move forward. And clearly, all of those things we've taken actions on. We also have adjusted and worked with parties and the commission on modeling techniques to make sure that our modeling is reflecting the current market reality of having less, quite frankly, thermal resources that can just be turned on and off.

And so those things are really important. As we look further out, I -- better integration of renewables into our distribution system. And so we have accelerated in '20 -- starting now and through 2022 and 2023, our distributed resource plan. And that's really important to be able to use the distribution system essentially as a circuit breaker and a source of generation. And we found that this was particularly helpful during the high heat dome events where we were able to move around some of our distributed resources in the system as well as manage transformer outages and others, and really manage more reliability at that time.

And then finally, working with all of our utilities across the West to ensure that we're working on day-ahead markets, we're working on further integration and other areas around reliability, and then finally, looking at all the way down to assessing RTOs and other mechanisms that will help us move forward. So we're taking a layered approach starting with ourselves and corrective actions we can do, things that we can do that are new and different using technology, and then things that we can deal with through partnerships and others. So I hope that this is really important work and it is unique work of a regulated utility, and we're fortunate to be vertically integrated and to be able to serve our customers. There's no question that our customers want ever-increasing amounts of clean energy, but they're not going to trade off cost and reliability.

Andy, we learned a lot this summer from the extreme conditions that we found ourselves in. Our system worked very well, generation as well as the T&D system, very limited impacts on the customer. So I think we were battle-tested in that regard. But at the same time, those more extreme conditions, I think someone said it earlier on the call, are those the new normal or not. And we don't know. But -- and I won't say much more than this. We've already prepared very well for next summer in terms of our positioning and I think we're going to be extremely well prepared as we go into the season next year.

Got it. That's terrific. And yes, I think the main thing is you kept the lights on, which is the most important thing.

Yes. I was very proud of the group, both on the generation side and the T&D side under extreme -- very extreme conditions.

At each point in time, whether it be fires or ice storms or heat domes or whatnot, we are rapidly iterating and learning faster than we ever have before.

Our next question comes from the line Brian Russo from Sidoti.

Just curious when you set the AUT and the net variable power cost, do you assume normal hydro condition? Or do you utilize NOAA forecasts when setting that? And when is the actual date in which the AUT is set?

So we use a long-standing hydro forecast. And sometimes we're a little bit above them, sometimes we're below them. Those hydro forecasts go back decades. And believe it or not, but in the early part of the '30s and '40s and I have to go back and look at that exact date, we had tremendous droughts across the West. So that data is actually reflected in the hydro forecast as well. And then for the wind forecast, which is just as important, we use 5-year rolling averages. And we've had pretty tough wind conditions as well. So that's reflected in the history that's used. All of that data also goes into how the market is pricing, both electricity and gas. And that -- those prices are trued up. And that we will -- in the next couple of days and weeks, we will be setting the AUT and then that will be what we'll use for 2022, combined with the new modelings that we've worked together on with the parties.

Right, because I know that the forecasts are for wet and cold weather in the Pacific Northwest and I was wondering if that's captured in the tariff or if that creates the benefit that you potentially retain under the PCAM?

So the current weather conditions or the current forecast is not necessarily used in how we are setting. We use -- it goes into the calculations of the longer-term or in the case of wind 5-year averages. And I can tell you, we -- if we are expecting a full year of wet and cold weather, we're off to a good start in that instance. And that will be very helpful for hydro conditions as well as restocking not only reservoirs but also in some instances the water table. So all of that is good and will be a benefit this next year.

I would also note though, with those wet and cold temperatures also comes a lot of wind that not only helps with energy generation but can create additional outages. And so that sometimes is a negative hit to our T&D cost. So we can see weather go both ways. And we are -- it's one of the reasons that we're hardening our system so that we can reduce outages, especially as people continue to work at home and kids are sometimes going to school still at home, making sure that our reliability is higher than ever.

Understood. And then just real quickly on EV infrastructure. Is that a sizable investment opportunity in addition to owning, building, or owning more supply for your portfolio?

Sure. So first of all, from a legislative enabling standpoint, we've got great decisions on the books in support of utility infrastructure to accelerate the pace of electric vehicle adoption whether it is infrastructure that's needed within our systems, transformers, substations, lines, whether it is make-ready, so the additional cabling and infrastructure to get to the charging stations or whether it's the charging stations themselves. It's very clear that the State of Oregon and the Commission expect the Portland General to be a leader and an enabler in clean transportation.

And so we see it as a tremendous opportunity. It will -- obviously smaller size now but we'll increase substantially with each year. And the forecast for electric vehicles are very high, and Oregon has some of the highest penetration, highest amounts of electric vehicles already to start with. But I -- the other is that the more electric vehicles there are, the more sort of off-peak periods of charging we can do, which enhances reliability, lowers cost for customers overall. And so we see it as really a synergistic sort of goodness for the entire system as we move forward. Not only is it a cleaner environment, better reliability, but also we're able to lower costs as electricity as a fuel is less expensive than fossil fuels.

Right. It will show up in load growth, I would say, tending in the second half of the decade here, but starting to ascend in the next couple of years in addition to the CapEx implication. So I think there's goodness on both sides. There'll be additional CapEx to support, as Maria said, but also I would estimate more and more load growth coming out of that as we get to the second half of the decade.

We see each electric vehicle essentially equivalent to a new residential customer.

Our final question for today comes from the line of Paul Patterson from Glenrock Associates.

And so listen, so much of my questions have been answered. Just I really appreciate your comments, Maria, about your focus on customer costs, et cetera and I was just a little surprised, and maybe you can sort of explain if you can, the disconnect in the staff testimony, which seems to highlight right upfront if they're concerned that there is some sort of trade-off between this and an environmental focus? At least that they seem to be somewhat concerned about that. And I'm just wondering if you could sort of explain where you think they might be coming from or if this is a communications issue or what do you think? Because I know you guys are just the opposite or at least that's my impression so --.

So first of all, I don't think I'm going to take a stab at where staff's coming from. I would reiterate all the comments that Jim has made that we work collaboratively together. They're the regulators. We're the regulated. We, as a company, are really proud of the investments we have made. I believe we got it right in terms of seeing the future and the increased volatility, the pressure around reliability, and we have been investing to be able to weather the storms that come at us, whether it's high heat or ice or whatnot and to be able to deliver affordable, reliable energy to our customers that is increasingly carbon-free.

And if you look at the overall price increases that we have proposed, they're quite modest, and it's -- really hats off to everyone who works at Portland General day in and day out at driving efficiency across our system, better use of technology on digital solutions, putting the customer first in everything that we do. And I'm really proud that we were able to keep our customer prices as low as we've proposed in the general rate case and that we were able to hold off on our rate case during the worst days of the pandemic. So I think there's a lot of goodness between our filing, and we look forward to working collaboratively with parties as we move forward.

Sure. But sort of outside the context of the rate case itself and the back and forth and what have you on that, is there sort of -- when you guys are making -- you guys are forward-thinking and you're looking at all this, are there ways perhaps of using technology and renewables to actually lower cost for customers? Or I mean, do you see any of these things as perhaps being from a -- sort of a cost reduction perspective perhaps in terms of delivering this? I mean, in other words, it seemed to me from reading it that they felt that there was some sort of trade-off, at least in terms of focus. And that's why I was sort of just wondering, strategically speaking, just in general how should we think of that when you're looking at all this? Or is it just, look, if we're going to be going green, we're going to have to pay a lot more for it. Do you follow what I'm saying?

No, I don't believe we're going to have to pay a lot more for it. But I do think we're going to need to be smarter. We're going to need to use technology in different ways. We're going to need to be integrated with partners, not only in our distribution system, many of whom are our customers, but also across the West. And you can see that continually through the work that we have done to keep our costs low. Renewable energy today -- new renewable energy, in most instances, costs less than new thermal operations, but it's going to create additional challenges around technology. I'm really pleased that we've gotten after our distributed resource systems, we have an ADMS system that's just about to go live. And we will continue focusing in on the technologies that will allow us to reduce costs for customers and the renewable energy that we are taking on. This is a huge transition, and we're all learning together, and we're going to be transparent and collaborative.

This does conclude the question-and-answer session of today's program. I'd like to hand the program back to Maria Pope for any further remarks.

Great. Thank you all for joining us today, and for those of us that we will see at the EEI Financial Conference in just a couple of weeks or 10 days. We appreciate your interest in Portland General, and we hope to connect with you in the future. Thank you.

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