Thank you, Justin. Good morning, everyone.

I’m happy you can 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 will be referencing throughout the call.

The slides are available on our website at investors.portlandgeneral.com. Referring to slide two.

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 Trpik, Senior Vice President of Finance and CFO.

Following their prepared remarks, we will open the line for your questions. Now it is my pleasure to turn the call over to Maria.

Thank you, Jardon, and good morning. Before I jump into our results, I would like to introduce and welcome Joe Trpik, who joined the company in June as our new CFO.

Joe brings a wealth of financial, risk management and capital markets experience. Joe’s over 20 years in senior finance roles at Exxon.

So welcome. Beginning with slide four, I’ll discuss our results for the quarter and speak to key drivers.

In the second quarter, we reported GAAP net income of $39 million or $0.39 per diluted share. After adjusting for the impact of Boardman, non-GAAP net income was $44 million or $0.44 per share.

This compares with second quarter results of $64 million or $0.72 per share. The drivers this quarter include, regional hydro conditions, which have adversely unusually high and impacted power markets with extreme volatility.

Our load growth and higher energy usage, particularly by the semiconductor and digital sectors. Investments in long-term capital projects, including the 2021 RFP projects such as Clearwater Wind and Eastern Montana.

And the prioritization of system maintenance and expenses to address ongoing reliability and resiliency. I will touch on each in turn.

First, quarter-over-quarter changes to our power costs were significant. I commend our team for how well they have managed the market volatility.

Last year, hydro conditions in the Columbia River Basin were about 110% to normal. This year, conditions at 80% are significantly below normal.

The year-to-date impact of our power cost adjustment mechanism or PCAM, was $51 million compared to this time last year, including $23 million in the first quarter and $28 million this past quarter. As we head into the third quarter, these large variances are expected to moderate given the seasonally low hydro generation of July, August and September.

Second, we saw solid load growth. We’re seeing continued growth in high-tech sectors with increasing demand from semiconductor manufacturing, data centers and cloud computing.

We’re pleased to see that during this past session of the Oregon legislature, they passed historic investments to support the semiconductor sector. These include $200 million for grant and loan programs, $255 million for R&D tax credits and $73 million foreign innovation complex at Oregon State University.

Among other incentives, they also are supporting streamlined environmental land use and permitting to support the construction of new high-tech manufacturing. We recently, in addition to Intel’s expansion, we have seen significant investments from Microchip, Lam Research and just this last week, Analog Devices announced a $1 billion investment in their operations in Beaverton, Oregon.

Turning to slide five. At the end of May, we announced an agreement to procure the Evergreen battery energy storage system, a new 75 megawatt facility located in Hillsboro, Oregon.

Between Clearwater Wind, the Seaside Battery project and now Evergreen, the company is investing approximately $925 million in renewable and dispatchable capacity resources as part of the 2021 RFP. In addition to these investments, we’re also looking at a number of transmission projects within our service territory and existing rights of way to help meet strong customer growth and the new manufacturing that I just noted.

In addition to cash from operations, debt and equity financing and the monetization of production and investment tax credits, we are leveraging federal IRA and IIJA funding in partnership with local communities, technology companies, tribal partners and other stakeholders. As of today, we’re pursuing over $450 million in grants to support approximately $1.1 billion in total projects for grid resiliency, cybersecurity, hydro project improvements, transportation electrification, transmission upgrades, among many other projects.

As we look to the future, the 2024 general rate rise is squarely in focus. Some of our discussions have been productive and we are pleased with the constructive and collaborative progress that we’ve made to-date.

PGE and parties have arrived at several agreements in principle that settle a number of items in the rate case, including a portion of PGE’s transmission and distribution capital requests, a capital structure of 50% debt and 50% equity, several business issues, such as the transfer and sale of PTCs and ITCs, and a portion of 2024 net variable power costs. We expect to file stipulations covering these items with the OPUC in the coming weeks.

And their next settlement conference is next week and we are optimistic for continued progress. As we look to the balance of the year, I’m grateful to our PGE colleagues who are working very hard every day to control costs, as we appreciate the impact we have on customer prices.

We continue to expect largely flat O&M for the full year, excluding the impact of wildfire mitigation work and major deferrals. While we have much more work to do, it’s worth noting that we have front-loaded certain costs in order to reduce operating risks.

Joe will touch on this more in detail in his remarks. We’re also executing on our wildfire mitigation program, which includes long-term investments and vegetation management.

We’re pleased to see the introduction of new federal legislation that would allow the U.S. foreign service to approve the removal of hazardous trees, their power lines on several florist lands.

The progress that we’re making to mitigate the risk of wildfire in our service territory underscores the importance of the OPUC’s recent approval of an automatic adjustment cause for wildfire mitigation costs, enabling faster recovery. Looking ahead, execution is our watch word in 2023 and beyond, as we position the company for a period of accelerated growth.

We remain confident in our 2023 guidance range of $2.60 per share to $2.75 per share, as well as our long-term earnings growth rate of 5% to 7%. With that, I’ll turn it over to Joe, who will walk you through our financial results.

Thank you.

Thank you, Maria, for the warm welcome, and good morning, everyone. I’ve hit the ground running in my first four weeks at PGE and I’m excited for the challenges and opportunities that lie ahead.

Now I’ll cover our Q2 results before providing updates on our capital investments and liquidity and financing outlook. Moving to slide six.

Our second quarter results reflect strong load growth trends in our region, less favorable power market conditions, prioritization of system reliability and resiliency efforts and execution of our long-term capital plan. The economy in our service territory continues to hold steady as unemployment in our region was 3.4% as of June.

Demand growth among our industrial customer class remains strong and we continue to see sizable development in a healthy pipeline of upcoming projects, especially among data centers and semiconductor customers. Q2 2023 load totals increased by 3% weather-adjusted as compared to 2022.

On a non-weather-adjusted basis, total load increased 4.1% year-over-year, as we witnessed less cold weather in the early parts of the quarter, but a more warm weather later in the quarter. Residential load increased by 0.3% year-over-year but decreased 0.3% weather-adjusted as we saw warmer weather, but also more moderate population growth and increased energy efficiency and DER penetration compared to 2022.

Residential customer count growth increased 0.7% compared to the second quarter of 2022. Commercial load increased 3.7% year-over-year or 1.7% weather-adjusted as general economic growth continues.

Industrial load remained strong, growing at 9.1% or 8.3% weather-adjusted as semiconductor, high-tech and digital customers continue on their growth trajectory. We also observed a shift in power market conditions relative to last year, along with continued demand growth in our service territory.

You may remember last year, our region saw more favorable market dynamics driven primarily by hydro conditions that were 10% above average, enabling the realization of power and fuel cost benefits. Current year conditions were more challenging, with regional hydro performance being 20% below historical averages.

These factors impacted the price and availability of market power, making PGE’s generation fleet the most economic option throughout much of the quarter. As a result, we purchased 23% less power from the market and our thermal generation plants produced 40% more power compared to the second quarter of 2022.

More scares market power also limited our flexibility to capture benefits from gas and power resale as we did in 2022. Despite these dramatically different market and circumstances year-over-year, we continue to dampen the effects of volatile energy markets through effective risk management and we are working towards constructive regulatory solutions to address evolving market dynamics.

I’ll now cover our financial performance quarter-over-quarter. We experienced a $0.16 increase in total revenues driven by the 4.1% increase in total deliveries, particularly among our industrial customers.

As I highlighted earlier, Q2 2022 power cost conditions were more favorable and $0.19 of the quarter-over-quarter earnings changes attributable to those tailwinds not recurring in 2023. Current year power costs were also higher than anticipated in our annual update tariff, driving a $0.04 EPS decrease in the quarter.

There was a $0.09 decrease in EPS from higher operating expenses, net of deferral-related items, O&M drivers for the second quarter of 2023 include $0.03 related to increased generation maintenance as part of our multiyear maintenance cycle as we prepare our gas and wind portfolio for reliable operations during summer demand peaks, $0.03 related to increased system resiliency, grid inspection and vegetation management costs, $0.02 related to higher bad debt expense as normal credit and collection activities have resumed post-pandemic and $0.01 due to higher labor and benefit costs. We saw a $0.05 impact from depreciation and amortization expense due to higher plant balances year-over-year, a $0.03 decrease from the impact of higher interest expense due to higher long-term debt balances and short-term debt balances carried during the second quarter, a $0.06 decrease due to the dilutive impact of draws on the equity forward sale completed in the first two quarters.

We also had a $0.02 increase from other items, including $0.03 from higher returns on nonqualified benefit trust as a result of improved market conditions, partially offset by a $0.01 decrease due to higher property taxes and other miscellaneous expenses. Finally, we had a $0.05 decrease due to the previously disclosed $6.5 million Boardman revenue requirement settlement reached in May, which resolved the last of our major deferrals.

This impact is adjusted from our non-GAAP results for the quarter. 2023 results continue to reflect the firming of our foundation for long-term growth.

Depreciation from continued capital investment, interest expense to fund those investments and near-term dilution impacts created an incremental $0.14 of impact compared to the second quarter of 2022. On slide seven, which shows our latest capital forecast through 2027, including $105 million increase is estimated 2023 base capital expenditures, largely from customer growth related to items such as incremental customer connections and road widenings.

This also includes estimated CapEx for all of the assets stemming from the 2021 RFP, including $415 million for the Clearwater Wind project, $360 million for the Seaside Battery and $150 million for the Evergreen battery. The 786 megawatts of renewable generation and non-emitting capacity resources secured during the recent procurement cycle will provide additional flexibility in our system and represents a sizable step forward in our decarbonization journey.

We look forward to seeing these assets serving customers starting late later this year and into the coming years. With the 2021 RFP behind us, our attention now shifts to future resource opportunities that will facilitate further progress in our clean energy transition, enable customer growth and optimize system capabilities.

An addendum to our combined Clean Energy Plan and IRP filing was recently filed with the OPUC, which sharpened modeling inputs to reflect the estimated needs in our service territory. Refinement will continue in coming years as assumptions underpinning these estimates will come into focus.

The 2023 RFP is expected to be issued later in the third quarter with additional milestones anticipated throughout 2024. As Maria highlighted earlier, transmission resources are being considered in addition to generation and capacity investments.

We will be engaging with local and regional partners to evaluate projects that will provide optimal benefits for our growing customer base and support our decarbonization plans. As a result, you may see the attribution of these bars continue to evolve in coming years as resource planning efforts move ahead.

Turning to slide eight. Our liquidity position and balance sheet remains strong, along with our investment-grade credit ratings and stable credit outlook.

Total available liquidity as of June 30, 2023, $651 million. We issued $92 million under the existing Equity Forward Sale Agreement in June and completed the issuance of the remaining $92 million under the facility in July as we deploy equity in support of our investments.

Looking to the balance of 2023, we anticipate debt issuances of up to $500 million later this year to finance capital projects, which we plan to issue under our green financing framework where possible. We continue to have equity market availability under our recently filed ATM program, which will be strategically timed to fund capital investments when conditions are optimal.

Careful dilution management remains an important focus and we will continue to align equity issuance with cash payments for capital projects. We remain confident in our ability to access the capital markets and continue to track towards our authorized 50-50 capital structure over time.

As Maria previously noted, we are pleased to see constructive progress in the 2024 GRC proceedings and we look forward to continued engagement with parties, including the next settlement conference, which will take place in early August. Our results in the second quarter reflect continued service territory strengths, as well as challenges we intend to manage thoughtfully through the balance of 2023.

We anticipate 2023 load growth in line with expectations, led by robust growth among our digital and high-tech customer group and maintain our confidence in full year weather-adjusted load growth guidance of 2.5% to 3%. Diligent power cost management through the second half of 2023, including continued leveraging of our risk management programs to limit the impacts of volatile power markets will be key.

The third quarter has been critical for the overall annual power cost performance and given the weather in markets we’ve observed through July, particularly the participation of additional renewable and storage assets in the region, we believe we are well positioned to continued solid performance through the summer. You’ll remember -- also remember, the fourth quarter of 2022 was particularly challenging, driven by colder weather, national pipeline constraints and lower-than-average regional gas storage.

Current indicators point to a more normal fourth quarter and we will continue to employ all available strategies to minimize the impacts of market volatility. Managing operating costs remains a critical priority, as Maria discussed, and I look forward to applying my previous experience on this topic at PGE.

Due to these efforts and load expectations, we are reaffirming our full year adjusted earnings guidance of $2.60 per diluted share to $2.75 per diluted share. 2023 represents an important inflection point for PGE’s long-term trajectory and we remain focused on the execution that strengthens PGE’s foundation for sustained growth and value.

Our solid service territory fundamentals, highlighted by continued industrial demand growth, a healthy capital investment profile, including emerging transmission opportunities and the continuation of our operating improvements will enable our achievement of our long-term earnings growth guidance of 5% to 7%. As we turn to the remainder of 2023, we remain rooted in our ongoing commitment to provide clean, reliable and affordable energy that enables strong financial results and value for customers.

I am optimistic about our outlook and look forward to continuing the longstanding collaboration between our coworkers, customers, shareholders and stakeholders to achieve our goals. And now, Operator, we are ready for questions.

Hi, Julien.

Hi. Good morning and congrats Joe again here.

I wanted to flag that here, too. Look, I would love to chat briefly, Joe, on some of the financing considerations.

Obviously, raising CapEx, again, a great sign on the customer front. Just wanted to -- just elaborate a little bit.

How are you thinking about financing needs here a little bit more specifically in the medium-term? I know you had some nearer-term commentary about HCM, et cetera.

But just to elaborate, especially as this CapEx budget literally quarter-over-quarter sequentially continues to get higher. And then in parallel with that, maybe this is more of a Maria question, can you talk about, especially what this elevated industrial and data center outlook looks like for your resource procurement.

Obviously, you guys came out with this IRP earlier on and we’ve been talking about procurement for you all as a consequence of that. But how are you thinking about just your ability and your needs in terms of megawatt development and how that fits into the CapEx and financing plan too?

Sure. So let me just start with the business and the customer side is, obviously, that will drive our financial needs, and Joe will take it from there.

So we are really fortunate to be located in an area that’s growing. We continue to see in-migration into many of the counties where we operate and in particular, we’re seeing growth of electrification.

But our most significant growth is coming from the semiconductor industry, as well as from cloud computing and data centers. And to meet that growth, we are -- many of those customers, I should also say, are focused on clean energy.

So their views towards sustainability and carbon reductions are consistent with the state and consistent with Portland General strategy. And so we’re looking at not only some additional renewable procurement, both in the energy and on the capacity side, up about 14% or so from what we initially had filed with our Clean Energy Plan.

But we’re also looking at some upgrades to existing transmission lines, repowering those too largest voltage levels and building transmission adjacent to added connection with some of the Bonneville Power Administration on recent announcements that they’ve also had. So, again, transmission, it would be in our service territory adjacent, largely repowering, re-conductoring and within existing right subway.

As we look to load growth overall, I think, we are really pleased with the legislative changes that were made in Salem this past session and the support for semiconductors overall. It’s an important sector to the state of Oregon to the kinds of jobs that we want to have in our state to our educational system and the financial support, as well as permitting and environmental issues and land use was a very important step.

And you can see from the announcement that Analog just made what an important sector this is to our overall economy. So, with that, Joe, you want to a little bit more about financing.

Sure. Thanks, Julien and good morning.

As it relates to our financing plan, we’re clearly committed to working towards our 50-50 cap structure. You had asked about midterm.

Obviously, I’ve mentioned what we’re looking financing here for the rest of the year. And the way I’m thinking about this is, we clearly want to have -- continue to have trajectory towards that 50-50 structure.

But I want to make sure here as we move forward that we’re evaluating all of our, what I’ll call, cash flow and financing opportunities that exist, the potential for the securitization of certain of our deferrals, the ability to monetize certain of our ITCs and PTCs, as well as the changing cash flows that are coming from as our rate base has grown. And I’ll honestly take that into a calculus here, but make sure at the end of the day, that’s our trajectory towards 50-50 and we continue to move towards that.

So truly as we work into 2024 and those items come into clarity really start to define how it is that we move that path forward towards 50-50.

Got it. Maybe if I press a little bit, just a time line to get to 50-50, and also, Maria, just to clarify this.

I know you’ve been very fixated. It seems like a late on transmission opportunities as well.

Some commentary in your remarks here, very curious to hear, I mean, how meaningful could that be when we think about the future of the company, obviously, you’ve articulated a good number of renewables here, but it sounds as if the transmission angle is actually probably the incremental piece to really be watching here as you do your planning, particularly in the back half of the decade here?

As we think about transmission, it also is how we think about the entire grid. And as you know, Julien, we are looking at 25% of our resources by the end of the decade coming from distributed energy resources.

And clearly, as I articulated in my prepared comments, we’re focused on federal dollars through the IRA and IIJA coming into company projects along with partners, but we also expect to have substantial amount of IRA dollars in particular going to customers, whether that’s rooftop solar, battery storage, electric vehicles. And so we look at this as sort of a continuum of mix.

It will certainly -- we will have more procurement from the resource side, but it doesn’t necessarily going to necessarily mean the traditional kinds of projects that we’ve seen in the past. It will be a mix and the transmission will be part of that.

And Julien, just to answer your timing question to refresh a little bit, we clearly will have significant opportunities as these major projects come along to line ourselves up to 50-50 here. We want to -- I want to be thoughtful here, but just clearly lay out a path that will really be tied to RFP results in the future, as well as some of our incremental investments.

But I mean, my real point here is a trajectory in a clear and direct movement, which will really align to the availability of what I’ll call the incremental project.

Yeah. Absolutely.

Best of luck guys, and again, Joe, congrats speaking here too [ph].

Thanks.

Thanks, Julien.

Hi, Shahriar.

Hey, guys. How are you?

Good morning. If you could start with the case.

Obviously, I appreciate all the color you guys provided on the settlement discussions. But can we get a little bit more on the prospects for the Faraday recovery?

What do you see as the pathway forward from here for that spend? And then, secondarily, can you speak maybe at a high level to the discussions around your proposed PCAM modifications, have the parties at least been receptive to some of the items you put forward?

Sure. So, first of all, we’re really pleased with the progress to-date.

Our team and parties have met several times and they’ve settled a number of items as I outlined. Faraday is no different than any of the other capital projects that we have put forward.

I would say that, whether you’re in the northern parts of British Columbia to the southernmost parts of South America and other projects in the United States, there’s nothing easy about hydro projects. The replacement that we did was a facility that had been operating and generating power for our customers for over 100 years, and I would estimate that with, the refurbished Faraday facilities, it will operate for another 100 years and this consistent low cost power, it’s clean and reliable as we move forward.

As we look at the PCAM and the rate case issues going forward, clearly, we have some more capital to sell, as we noted, O&M costs. We also have ROE.

And then PCAM has a number of important components. And I think a little history is also helpful here.

The PCAM mechanism we have was put in place on 15 years ago, really to address what some of the leaders at that time called skin in the game on the company side for plant operations, in particular, our coal plant operations at Boardman. And today, many of those circumstances are really very different.

Our volatility in energy prices and in the market is generated really as we move more towards renewables as our markets are much more integrated and we’re balancing more renewables across the entire West and so the mechanism needs to be updated to reflect the current reality as we transition to a higher percentage of renewables but a more integrated West wide set of markets. And so we’re proposing that we remove the dead band and that we have 90-10 sharing sort of out of the gate off of the baseline that we set through the annual update tariff every fall.

And that we exclude what I would call sort of the market excursions that generally come from significant events, which are not even related to our own operations. Those are often trigger energy electric alerts across the Western Interconnect and so they’re pretty well known and able to be established.

We’re also looking to establish a 2.5% price cap in any given year. So the balance should there be excursions that exceed that would roll to future years and that would also be on a plus and minus basis.

So that’s a lot of complexity. The issues, I think, are really around how do we work through the changing market conditions and understanding the dynamics with parties and come to agreements as we move forward.

But so far, the discussions have been collaborative and will certainly be ongoing. There’s nothing easy about these topics.

Got it. That’s helpful.

And Maria, just -- there’s been a lot of noise in recent weeks on wildfires. There’s no inverse condemnation in Oregon.

But one of your neighboring utilities has been dealing with negligent. Can you just speak to the conditions across the territory at the moment and any other procedural or legal color since your most recent plan was approved?

Sure. So, first of all, we don’t comment on any litigation, whether it be ours or our peer utilities in this region or in other places.

I would say that we couldn’t be more pleased with our automatic adjustment clause approval that took place just this May, allowing us the prudent recovery of wildfire costs, both on O&M and on capital. And then as we move forward, we do have very dry conditions across the Pacific Northwest.

You’ve seen a lot of the news on wildfires in Canada very early in the season. That’s unusual.

And we’re probably as a company, I’d say, on heightened alert. We look at wildfire and I start to think of it several major buckets.

The first one is ongoing prevention and mitigation of wildfire and that’s everything from vegetation management to how we run our distribution system and our transmission system, to how we deploy technologies, high-definition, AI-focused cameras that have made a big difference, weather monitoring, all of those sorts of aspects. And we work hand in glove with our local communities, first responders, firms to make sure that we have the best information.

We’re also working with the Oregon Department of Forestry, U.S. Forest Service and BLM on a regular basis.

Yeah.

The next bucket is really around the detection and that’s where in the quick response. That’s where those relationships and that technology really come to bear.

And then on the rapid response to make sure that if there are any sparks that we’re able to put them out quickly. So it’s a lot of work.

It’s definitely a year-round process and is a changed operating environment that we have today and we’ll have as we move forward.

Perfect. Thank you, guys.

It is taking enough time, and Joe, congrats on the spot. I appreciate it.

All right. Thank you.

Thanks, Shahriar.

Hi. Good morning.

Can you hear me?

Yeah. We can.

Good morning.

Yeah.

Great. Thank you.

Just cleaning up a few items here. You passed a little bit of the CapEx raise in the prepared comments.

Curious, those trends should they continue relative to what you’ve budgeted for 2024 and beyond. Is that bias in CapEx upside as well in the forward years versus the latest 2023 rate?

Yeah. I’ll let Joe take up and handle this one.

I think one of the things that we should recognize is that the CapEx that we have is reflective of customer needs. We have been impressed with the number of new connects that have continued as interest rates have gone up, as well as the amount of municipal work, in particular, road-widening, Joe meant in his prepared remarks.

But in addition to our large digital and semiconductor customers, we continue to see growth in our region. Joe, do you want to address a little bit more on that one?

Sure. Richard, good morning.

Our long-term capital has an amount as you look further out of $800 million that is for what we’ll call base capital. To Maria’s comment and we will continue -- continually reevaluate here, as we see, what I’ll call it, our customer demand or customer growth-related items that could be incremental to that $800 million.

We will look to do an adjustment here to our long-term plans. We’re going to continue to watch to see where customer growth goes.

Of course, we include within our forecast at a volume of connections, road widening, things like that for customers. Those type of items can be variable and to the extent that trend continues to hold at a higher rate, we will evaluate either is there room in the budget to displace something else or if we do need to take a look at that long-term trend of $800 million if it needs to be at a higher rate.

And we will continue to do that. We’ll do that with our next annual update that we do here and then, obviously, that will be something we’re keeping a watch on as we go forward.

Understood. Understood.

Very helpful there. And then just switching gears to the NVPC outlook.

I think the commentary was very clear, but I just wanted to drill down a little bit further on kind of 3Q to-date versus 4Q. So it sounds like the 3Q dynamics have been a lot better versus 1H and then if you kind of normalize 4Q versus the challenges last year, you get to your outlook relative to baseline versus where things came in in the first half of the year.

Is that effectively in or I guess what I’m curious about is what you’ve seen so far in 3Q and how much that gets you there versus what you need to see on 4Q?

So this is an area where we have seen rapid change over the last couple of years. I think more than any of us would have expected in a short period of time and while we forecasted the underlying issues, they’ve come at us much faster.

I’ve been really impressed with how our folks have learned and how with each period of time, we are better prepared with more flexible capacity and more tools. Clearly, the change in hydro conditions from this time last year to this year has had a big impact.

But going into the third quarter, you almost never have any excess hydro, because it’s all run down through the river systems with a few exceptions maybe in Northern British Columbia. The -- I would say that as we look at where we’re going into third quarter.

We’re well set up. We clearly have event risk, whether that would be our own plant operations, which are particularly hard to keep online with extreme weather conditions, particularly heat, but also just overall of the region.

But we feel and as one of our leaders quoting the other day, we have more pep in our step as we are moving into the third quarter. And certainly hope not to repeat the truly unusual $40, $50 natural gas prices we saw and extreme issues in the last two weeks of December this past year.

Got it. Very clear.

Thanks for the time today, and Joe, congrats as well.

Thanks.

Thank you.

Hey. Good morning.

Joe, congrats on the new job. I just -- a couple of quick questions here.

I guess, first, previous slides, you guys highlighted an 8.5% rate base CAGR. In this slide deck, that’s removed.

I mean, our -- when do you expect to get an update on the rate base growth?

Good morning, Anthony. So we will update on a -- the slide you’re talking to and we have given an illustrative guidance on what rate base growth could look like long-term.

We’ll update that as we come into our next year or both on what we’ll call our -- what our base case is, I believe, with a -- we’ve reflected with a 25% win rate on the RFP and then also what a potential case is as it relates to a more favorable outcome. We’ll continue to update that, Anthony.

Nothing has changed up in what we are thinking that would cause us to reduce that. But then as a reminder, in our materials, there is a second set of materials out there, Anthony, where we do have what I’ll call a soft update that really just reflects the small changes.

And you will see in that -- in the -- what we label as the investor presentation, which was also distributed. We do have an update in there to reflect the -- both the, what I’ll call, the base and the periodic.

But again, I will call those soft updates for small changes that we’ve made here without any type of longer term adjustment. Hopefully, you can see that attachment.

Apologize, is it likely to get another update this like EEI our third quarter call or a hard update is more going to be an end of the year update?

We will do a hard update when we do our full -- when we issue our new -- our capital forecast for 2024. Historically, we have done that in the October period.

Okay. Great.

And then, I guess, jumping around, Maria, when you spoke about the PCAM and the changes to maybe the power markets that have impacted your region with more renewables, the Western zone and everything else. Are the intervenors kind of highlighting that the PCAM is not as volatile as it once was and maybe that’s some of the struggles already including that partial settlement or that the issues have become even a higher hurdle and maybe more challenging to maybe modify and include in the settlement?

I think that the conversations are ongoing and I think it’s too early to read any conclusions into them. There’s no question that market volatility is higher today than it was in the past and certainly higher than when the PCAM was conceived when there was plentiful excess energy through the system, particularly hydro energy and less reliance on renewables that fluctuate with wind and solar conditions.

I would say that overall, there’s a pretty good understanding at a high level of the transformation of energy markets. They’re clearly West wide.

We have a lot of offsets given the different temperatures and operating conditions between ourselves and the Desert Southwest. You see a lot of work towards market -- further market integration, either with the California Independent System Operator or with SPP’s Markets Plus.

And most importantly, there is a tremendous consensus around resource adequacy needs and the leadership of the Western Power Pool in this regard is exceptional. And one of the reasons that you can see some additional capacity in the region as we head into the August period is that entities are really working towards more transparent and coordinated resource adequacy.

It’s making a big difference. But there’s no question that there’s a lot of work to do with intervenors.

We do this every day. They don’t necessarily do it and the financial issues are significant.

Great. And then just lastly, maybe, Joe, I believe that the capital structure has already -- the capital structure in the rate proceeding has already been settled.

But assuming that rate -- you reach a full settlement whatever that case is litigated, would the outcome of the case accelerate maybe the company’s target to achieve a 50-50 ratio?

I don’t think so. Obviously, a constructive outcome is always positive to us financially.

I mean we are going to stay on a long-term path and keep our eye on a consistent movement towards 50-50 aligned to what I’ll call our major capital. So I mean I don’t think a short-term item would deviate us one way or the other from what I think is really a long-term structure that we’re trying to go towards.

Thanks, again. Congratulations on this spot, Joe, and thanks for taking my questions.

Thank you.

Thank you.

Thank you all for joining us today. We appreciate your interest in Portland General Electric.

We look forward to further conversations and I believe many of you are meeting actually with Joe and others next week. So thank you very much and look forward to seeing you between now and then or at least at EEI.

Thank you.